PUC FM050 (Rev. 8/25/11) e-FILING REPORT COVER SHEET REPORT NAME: FERC Form 1 Annual Report COMPANY NAME: Idaho Power Company DOES REPORT CONTAIN CONFIDENTIAL INFORMATION? No Yes If yes, please submit only the cover letter electronically. Submit confidential information as directed OAR 860-001-0070 or the terms of an applicable protective order. If known, please select designation: RE (Electric) RG (Gas) RW (Water) RO (Other) Report is required by: OAR 860-027-0070 Statute Order Other Is this report associated with a specific docket/case? No Yes If Yes, enter docket number: Key words: If known, please select the PUC Section to which the report should be directed: Corporate Analysis and Water Regulation Economic and Policy Analysis Electric and Natural Gas Revenue Requirements Electric Rates and Planning Natural Gas Rates and Planning Utility Safety, Reliability & Security Administrative Hearings Division Consumer Services Section PLEASE NOTE: Do NOT use this form or e-filing with the PUC Filing Center for: Annual Fee Statement form and payment remittance or OUS or RSPF Surcharge form or surcharge remittance or Any other Telecommunications Reporting or Any daily safety or safety incident reports or Accident reports required by ORS 654.715.
Transcript
PUC FM050 (Rev. 8/25/11)
e-FILING REPORT COVER SHEET
REPORT NAME: FERC Form 1 Annual Report
COMPANY NAME: Idaho Power Company
DOES REPORT CONTAIN CONFIDENTIAL INFORMATION? No Yes
If yes, please submit only the cover letter electronically. Submit confidential information
as directed OAR 860-001-0070 or the terms of an applicable protective order.
If known, please select designation: RE (Electric) RG (Gas) RW (Water)
RO (Other)
Report is required by: OAR 860-027-0070
Statute
Order
Other
Is this report associated with a specific docket/case? No Yes
If Yes, enter docket number:
Key words:
If known, please select the PUC Section to which the report should be directed:
Corporate Analysis and Water Regulation
Economic and Policy Analysis
Electric and Natural Gas Revenue Requirements
Electric Rates and Planning
Natural Gas Rates and Planning
Utility Safety, Reliability & Security
Administrative Hearings Division
Consumer Services Section
PLEASE NOTE: Do NOT use this form or e-filing with the PUC Filing Center for:
Annual Fee Statement form and payment remittance or
OUS or RSPF Surcharge form or surcharge remittance or
Attention: Filing Center Public Utility Commission of Oregon 550 Capitol Street NE, Suite 215 P. O. Box 2148 Salem, OR 97308-2148
Re: Idaho Power Company’s Annual FERC Form 1 Report
Dear Sir or Madam:
Idaho Power Company herewith transmits for electronic filing its FERC Form 1 report for the year ended December 31, 2011, previously mailed in hard copy to Judy Johnson, Program Manager of Revenue Requirements, on April 13, 2012. Idaho Power is filing this report again, but in electronic format, per the notice received from the Commission dated June 18, 2012.
If you have any questions, please call me at 208-388-5825.
FERC FINANCIAL REPORTFERC 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 notconsider these reports to be of confidential nature
OMB No.1902-0021
OMB No.1902-0029
OMB No.1902-0205
(Expires 12/31/2014)
(Expires 12/31/2014)
(Expires 05/31/2014)
Form 1 Approved
Form 1-F Approved
Form 3-Q Approved
FERC FORM No.1/3-Q (REV. 02-04)
Exact Legal Name of Respondent (Company) Year/Period of Report
End of 2011/Q4Idaho Power Company
IDENTIFICATION
FERC FORM NO. 1/3-Q:REPORT OF MAJOR ELECTRIC UTILITIES, LICENSEES AND OTHER
Ken Petersen
1221 W Idaho St, P.O. Box 70 Boise, Id 83707-0070
2011/Q4
1221 W Idaho St, P.O. Box 70 Boise, Id 83707-0070
01 Exact Legal Name of Respondent
(1) An Original (2) A ResubmissionX
02 Year/Period of ReportEnd ofIdaho Power Company
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)
05 Name of Contact Person 06 Title of Contact Person
07 Address of Contact Person (Street, City, State, Zip Code)
08 Telephone of Contact Person,IncludingArea Code
09 This Report Is 10 Date of Report(Mo, Da, Yr)
01 Name
02 Title
03 Signature 04 Date Signed(Mo, Da, Yr)
Title 18, U.S.C. 1001 makes it a crime for any person to knowingly and willingly to make to any Agency or Department of the United States anyfalse, fictitious or fraudulent statements as to any matter within its jurisdiction.
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 statementsof the business affairs of the respondent and the financial statements, and other financial information contained in this report, conform in all materialrespects to the Uniform System of Accounts.
FERC FORM No.1/3-Q (REV. 02-04) Page 1
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
LIST OF SCHEDULES (Electric Utility)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
Title of Schedule ReferencePage No.
Remarks
(c)(b)(a)
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported forcertain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
101General Information 1
102Control Over Respondent 2
103Corporations Controlled by Respondent 3
104Officers 4
105Directors 5
106(a)(b)Information on Formula Rates 6
108-109Important Changes During the Year 7
110-113Comparative Balance Sheet 8
114-117Statement of Income for the Year 9
118-119Statement of Retained Earnings for the Year 10
120-121Statement of Cash Flows 11
122-123Notes to Financial Statements 12
122(a)(b)Statement of Accum Comp Income, Comp Income, and Hedging Activities 13
200-201Summary of Utility Plant & Accumulated Provisions for Dep, Amort & Dep 14
None202-203Nuclear Fuel Materials 15
204-207Electric Plant in Service 16
None213Electric Plant Leased to Others 17
214Electric Plant Held for Future Use 18
216Construction Work in Progress-Electric 19
219Accumulated Provision for Depreciation of Electric Utility Plant 20
224-225Investment of Subsidiary Companies 21
227Materials and Supplies 22
None228(ab)-229(ab)Allowances 23
None230Extraordinary Property Losses 24
None230Unrecovered Plant and Regulatory Study Costs 25
231Transmission Service and Generation Interconnection Study Costs 26
232Other Regulatory Assets 27
233Miscellaneous Deferred Debits 28
234Accumulated Deferred Income Taxes 29
250-251Capital Stock 30
253Other Paid-in Capital 31
254Capital Stock Expense 32
256-257Long-Term Debt 33
261Reconciliation of Reported Net Income with Taxable Inc for Fed Inc Tax 34
262-263Taxes Accrued, Prepaid and Charged During the Year 35
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd ofIdaho Power Company X
04/13/20122011/Q4
Line No.
Title of Schedule ReferencePage No.
Remarks
(c)(b)(a)
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported forcertain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
269Other Deferred Credits 37
272-273Accumulated Deferred Income Taxes-Accelerated Amortization Property 38
274-275Accumulated Deferred Income Taxes-Other Property 39
276-277Accumulated Deferred Income Taxes-Other 40
278Other Regulatory Liabilities 41
300-301Electric Operating Revenues 42
304Sales of Electricity by Rate Schedules 43
310-311Sales for Resale 44
320-323Electric Operation and Maintenance Expenses 45
326-327Purchased Power 46
328-330Transmission of Electricity for Others 47
None331Transmission of Electricity by ISO/RTOs 48
332Transmission of Electricity by Others 49
335Miscellaneous General Expenses-Electric 50
336-337Depreciation and Amortization of Electric Plant 51
350-351Regulatory Commission Expenses 52
352-353Research, Development and Demonstration Activities 53
354-355Distribution of Salaries and Wages 54
None356Common Utility Plant and Expenses 55
None397Amounts included in ISO/RTO Settlement Statements 56
None398Purchase and Sale of Ancillary Services 57
400Monthly Transmission System Peak Load 58
None400aMonthly ISO/RTO Transmission System Peak Load 59
401Electric Energy Account 60
401Monthly Peaks and Output 61
402-403Steam Electric Generating Plant Statistics 62
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd ofIdaho Power Company X
04/13/20122011/Q4
Line No.
Title of Schedule ReferencePage No.
Remarks
(c)(b)(a)
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported forcertain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
424-425Transmission Lines Added During the Year 67
426-427Substations 68
429Transactions with Associated (Affiliated) Companies 69
450Footnote Data 70
Stockholders' Reports Check appropriate box:X Two copies will be submitted
No annual report to stockholders is prepared
FERC FORM NO. 1 (ED. 12-96) Page 4
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of
GENERAL INFORMATION
Idaho Power Company X04/13/2012 2011/Q4
Idaho, June 30, 1989
Ken Petersen Coporate Controller and CAO, Idaho Power Company
1221 W. Idaho Street, P.O. Box 70, Boise, Idaho 83707-0070
1. Provide name and title of officer having custody of the general corporate books of account and address ofoffice where the general corporate books are kept, and address of office where any other corporate books of accountare kept, if different from that where the general corporate books are kept.
2. Provide the name of the State under the laws of which respondent is incorporated, and date of incorporation.If incorporated under a special law, give reference to such law. If not incorporated, state that fact and give the typeof organization and the date organized.
3. If at any time during the year the property of respondent was held by a receiver or trustee, give (a) name of receiver or trustee, (b) date such receiver or trustee took possession, (c) the authority by which the receivership ortrusteeship was created, and (d) date when possession by receiver or trustee ceased.
4. State the classes or utility and other services furnished by respondent during the year in each State in whichthe respondent operated.
5. Have you engaged as the principal accountant to audit your financial statements an accountant who is notthe principal accountant for your previous year's certified financial statements?
(1) Yes...Enter the date when such independent accountant was initially engaged: (2) NoX
Not Applicable
Class of Utility Service State Electric Idaho Electric Oregon
FERC FORM No.1 (ED. 12-87) PAGE 101
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of
CONTROL OVER RESPONDENT
Idaho Power Company X04/13/2012 2011/Q4
1. If any corporation, business trust, or similar organization or a combination of such organizations jointly heldcontrol over the repondent at the end of the year, state name of controlling corporation or organization, manner inwhich control was held, and extent of control. If control was in a holding company organization, show the chainof ownership or control to the main parent company or organization. If control was held by a trustee(s), state name of trustee(s), name of beneficiary or beneficiearies for whom trust was maintained, and purpose of the trust.
Idaho Power Company is a subsidiary of IDACORP, INC
IDACORP owns 100% of Idaho Power Company's Common Stock.
IDACORP is a public utility Holding Company incorporated effective 10-1-1998
Page 102FERC FORM NO. 1 (ED. 12-96)
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
CORPORATIONS CONTROLLED BY RESPONDENT
Idaho Power Company X04/13/2012
2011/Q4
Line No.
Name of Company Controlled Kind of Business Percent VotingStock Owned
(c)(b)(a)
FootnoteRef.(d)
1. Report below the names of all corporations, business trusts, and similar organizations, controlled directly or indirectly by respondentat 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, namingany 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.
Definitions1. 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 thevoting control is equally divided between two holders, or each party holds a veto power over the other. Joint control may exist by mutualagreement or understanding between two or more parties who together have control within the meaning of the definition of control in theUniform System of Accounts, regardless of the relative voting rights of each party.
1 Direct Control
Coal mining and mineral 100% 2 Idaho Energy Resources Company
development 3
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FERC FORM NO. 1 (ED. 12-96) Page 103
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
OFFICERS
Idaho Power Company X04/13/2012
2011/Q4
Line No.
Title Name of Officer Salaryfor Year
(c)(b)(a)
1. Report below the name, title and salary for each executive officer whose salary is $50,000 or more. An "executive officer" of arespondent 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 previousincumbent, and the date the change in incumbency was made.
Vice President, Regulatory Affairs (2) 165,000Gregory Said 34
35
(1) Retirement 6/30/2011 36
(2) Title/Position Change effective 1/8/2011 37
(3) Title changes effective 1/1/2012 38
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44
FERC FORM NO. 1 (ED. 12-96) Page 104
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
DIRECTORS
Idaho Power Company X04/13/2012
2011/Q4
Line Name (and Title) of Director Principal Business Address(b)(a)No.
1. Report below the information called for concerning each director of the respondent who held office at any time during the year. Include in column (a), abbreviatedtitles 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.
12786 Glenmorrie Dr. Lake Oswego, Oregon 97034Judith A Johansen 2
3Standard Microsystems CorporationChristine King 480 Arkay Dr, Hauppauge, NY 11788 5
6P.O. Box 1718, Boise, Idaho 83701 Gary Michael *** 7
84642 W Dawson Dr Meridian, Id 83646Stephen Allred 9
10900 W. Bogus View Drive, Eagle, Idaho 83616Jan B. Packwood 11
12Idaho Power Company, 1221 W. Idaho Street,J. LaMont Keen, President and Chief Executive Officer** 13P.O. Box 70, Boise, Idaho 83707-0070 14
15Pacwest Center, 1211 SW Fifth Ave., Suite 1600Richard G. Reiten 16Portland, Oregon 97204 17
182309 S.W. First Avenue, No. 1141, Portland, Oregon 97201Joan Smith 19
204433 W. Quail Point Court, Boise, Idaho 83703Robert A. Tinstman *** 21
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
INFORMATION ON FORMULA RATES
Idaho Power Company X04/13/2012
2011/Q4
Line No. FERC Rate Schedule or Tariff Number FERC Proceeding
Does the respondent have formula rates? Yes
NoX
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.
FERC Rate Schedule/Tariff Number FERC Proceeding
FERC Docket No. ER06-787-002,003FERC Electric Tariff 1
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FERC FORM NO. 1 (NEW. 12-08) Page 106
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd ofIdaho Power Company X
04/13/20122011/Q4
Line No. \ Filed DateAccession No.
DateDocket No. Description
Formula Rate FERC RateSchedule Number orTariff Number
INFORMATION ON FORMULA RATES
Does the respondent file with the Commission annual (or more frequent) Yes
NoX
2. If yes, provide a listing of such filings as contained on the Commission's eLibrary website
FERC Rate Schedule/Tariff Number FERC Proceeding
filings containing the inputs to the formula rate(s)?
Document
09/01/2011201109025016 ER09-1641-000 Idaho Power Company'sFERC Electric Tariff 12011-2012 Annual 2informational filing 3under ER09-1641 4
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd ofIdaho Power Company X
04/13/20122011/Q4
Line No. Page No(s). Schedule Column Line No
INFORMATION ON FORMULA RATES
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
Formula Rate Variances
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.
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report Year/Period of ReportEnd of
IMPORTANT CHANGES DURING THE QUARTER/YEAR
Idaho Power Company X04/13/2012
2011/Q4
PAGE 108 INTENTIONALLY LEFT BLANKSEE PAGE 109 FOR REQUIRED INFORMATION.
Give particulars (details) concerning the matters indicated below. Make the statements explicit and precise, and number them inaccordance with the inquiries. Each inquiry should be answered. Enter "none," "not applicable," or "NA" where applicable. Ifinformation 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 thefranchise 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 ofcompanies involved, particulars concerning the transactions, name of the Commission authorizing the transaction, and reference toCommission authorization.3. Purchase or sale of an operating unit or system: Give a brief description of the property, and of the transactions relating thereto, andreference to Commission authorization, if any was required. Give date journal entries called for by the Uniform System of Accounts weresubmitted to the Commission.4. Important leaseholds (other than leaseholds for natural gas lands) that have been acquired or given, assigned or surrendered: Giveeffective dates, lengths of terms, names of parties, rents, and other condition. State name of Commission authorizing lease and givereference to such authorization.5. Important extension or reduction of transmission or distribution system: State territory added or relinquished and date operationsbegan or ceased and give reference to Commission authorization, if any was required. State also the approximate number of customersadded or lost and approximate annual revenues of each class of service. Each natural gas company must also state major newcontinuing sources of gas made available to it from purchases, development, purchase contract or otherwise, giving location andapproximate 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-termdebt and commercial paper having a maturity of one year or less. Give reference to FERC or State Commission authorization, asappropriate, 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 suchproceedings 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 knownassociate 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 areapplicable in every respect and furnish the data required by Instructions 1 to 11 above, such notes may be included on this page.13. Describe fully any changes in officers, directors, major security holders and voting powers of the respondent that may have occurredduring 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 30percent please describe the significant events or transactions causing the proprietary capital ratio to be less than 30 percent, and theextent to which the respondent has amounts loaned or money advanced to its parent, subsidiary, or affiliated companies through a cashmanagement program(s). Additionally, please describe plans, if any to regain at least a 30 percent proprietary ratio.
FERC FORM NO. 1 (ED. 12-96) Page 108
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 agreementprovides 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 betweenIdaho 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 transmissionproject.Idaho Power's interest in the Gateway West project applies to four of ten segmentsinvolved in the project, referred to as segments 6 (which Idaho Power had previouslyconstructed and is included only for purposes of federal permitting related to the GatewayWest project), 8,9,and 10. Each party is responsible for its pro rata share, based on itsrespective federal and state permitting ownership interest, of the costs incurred underthe agreement.Idaho Power's state permitting interest in its segments is 100 percent forsegment 6 and 33 percentfor each of segments 8,9, and 10, with a federal permittinginterest in the project of 11 percent. Segment #6 is from Borah to Midpoint, segment #8 isfrom Midpoint to Hemingway, Segment #9 is from Cedar Hill to Hemingway and segment #10 isfrom Midpoint to Cedar Hill.
6. As of December 31,2011, $300 million remained on Idaho Power's shelf registration forthe issuance of first morgage bonds and debt securities. State Commission order number isthe 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
11. None
12. None
13. Refer to pages 104 & 105 for changes in officers and directors. There were a couple ofchanges in the major security holders for 2011. The top ten institutional shareholderslist saw 2 changes from 3rd quarter to 4th quarter. In the 4th quarter Zimmer LucasPartners, LLC and Thompson, Siegel & Walmsley LLC replaced Artisan Partners LimitedPartnership and Fisher Investments.
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
FERC FORM NO. 1 (ED. 12-96) Page 109.1
14. Idaho Power and its unregulated parent, IdaCorp have seperate cash managementprograms. (Seperate bank accounts, liquidity facilities, short-term debt and investmentprograms). No money has been loaned or advanced from Idaho Power to IdaCorp through a cashmanagement program.
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
FERC FORM NO. 1 (ED. 12-96) Page 109.2
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
XDate of Report(Mo, Da, Yr)
Year/Period of Report
End ofCOMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
591,474,855 416,949,593200-201Construction Work in Progress (107) 35,065,322,040 4,756,079,991TOTAL Utility Plant (Enter Total of lines 2 and 3) 41,840,782,085 1,771,654,529200-201(Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115) 53,224,539,955 2,984,425,462Net Utility Plant (Enter Total of line 4 less 5) 6
0 0202-203Nuclear Fuel in Process of Ref., Conv.,Enrich., and Fab. (120.1) 70 0Nuclear Fuel Materials and Assemblies-Stock Account (120.2) 80 0Nuclear Fuel Assemblies in Reactor (120.3) 90 0Spent Nuclear Fuel (120.4) 100 0Nuclear Fuel Under Capital Leases (120.6) 110 0202-203(Less) Accum. Prov. for Amort. of Nucl. Fuel Assemblies (120.5) 120 0Net Nuclear Fuel (Enter Total of lines 7-11 less 12) 13
3,224,539,955 2,984,425,462Net Utility Plant (Enter Total of lines 6 and 13) 140 0Utility Plant Adjustments (116) 150 0Gas Stored Underground - Noncurrent (117) 16
OTHER PROPERTY AND INVESTMENTS 172,081,420 2,074,996Nonutility Property (121) 18
0 0(Less) Accum. Prov. for Depr. and Amort. (122) 190 0Investments in Associated Companies (123) 20
78,529,519 72,561,774224-225Investment in Subsidiary Companies (123.1) 21(For Cost of Account 123.1, See Footnote Page 224, line 42) 22
0 0228-229Noncurrent Portion of Allowances 231,852 2,511Other Investments (124) 24
0 0Sinking Funds (125) 250 0Depreciation Fund (126) 260 0Amortization Fund - Federal (127) 27
25,644,107 29,306,774Other Special Funds (128) 280 0Special Funds (Non Major Only) (129) 29
359,418 0Long-Term Portion of Derivative Assets (175) 300 0Long-Term Portion of Derivative Assets – Hedges (176) 31
106,616,316 103,946,055TOTAL Other Property and Investments (Lines 18-21 and 23-31) 32CURRENT AND ACCRUED ASSETS 33
0 0Cash and Working Funds (Non-major Only) (130) 3419,178,288 73,015,293Cash (131) 35
0 2,802,631Special Deposits (132-134) 3637,350 44,850Working Fund (135) 37
42,015,731 42,221,176227Plant Materials and Operating Supplies (154) 480 0227Merchandise (155) 490 0227Other Materials and Supplies (156) 500 0202-203/227Nuclear Materials Held for Sale (157) 510 0228-229Allowances (158.1 and 158.2) 52
FERC FORM NO. 1 (REV. 12-03) Page 110
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
XDate of Report(Mo, Da, Yr)
Year/Period of Report
End ofCOMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
688,757,435704,757,436Premium on Capital Stock (207) 600Other Paid-In Capital (208-211) 7 25300Installments Received on Capital Stock (212) 8 25200(Less) Discount on Capital Stock (213) 9 254
-9,567,515-11,622,052Accumulated Other Comprehensive Income (219) 15 122(a)(b)1,405,228,8211,524,219,175Total Proprietary Capital (lines 2 through 15) 16
3,439,7533,113,413(Less) Unamortized Discount on Long-Term Debt-Debit (226) 231,609,350,7021,488,613,405Total Long-Term Debt (lines 18 through 23) 24
OTHER NONCURRENT LIABILITIES 2500Obligations Under Capital Leases - Noncurrent (227) 2600Accumulated Provision for Property Insurance (228.1) 27
1,881,7761,924,461Accumulated Provision for Injuries and Damages (228.2) 28268,433,659366,648,491Accumulated Provision for Pensions and Benefits (228.3) 29
229,485,266177,058,652Total Current and Accrued Liabilities (lines 37 through 53) 54DEFERRED CREDITS 55
23,054,01719,747,984Customer Advances for Construction (252) 5671,972,33670,840,400Accumulated Deferred Investment Tax Credits (255) 57 266-267
00Deferred Gains from Disposition of Utility Plant (256) 5826,668,26927,530,572Other Deferred Credits (253) 59 26955,279,90296,483,245Other Regulatory Liabilities (254) 60 278
00Unamortized Gain on Reaquired Debt (257) 6100Accum. Deferred Income Taxes-Accel. Amort.(281) 62 272-277
707,009,348933,326,224Accum. Deferred Income Taxes-Other Property (282) 6399,627,160137,438,695Accum. Deferred Income Taxes-Other (283) 64
983,611,0321,285,367,120Total Deferred Credits (lines 56 through 64) 654,536,153,7084,898,451,229TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65) 66
FERC FORM NO. 1 (rev. 12-03) Page 113
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
STATEMENT OF INCOME
Idaho Power Company X04/13/2012
2011/Q4
Line
(c)(b)(a)Title of Account
No.Total
Current Year toDate Balance for
Quarter/Year(d)
(Ref.)Page No.
Quarterly1. 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 thedata 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 (l) thequarter 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 applicable5. 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 toa 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.
336-337Depreciation Expense for Asset Retirement Costs (403.1) 7
6,764,513 6,857,301336-337Amort. & Depl. of Utility Plant (404-405) 8
-22,723 -22,723336-337Amort. of Utility Plant Acq. Adj. (406) 9
Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407) 10
Amort. of Conversion Expenses (407) 11
28,099 21,955Regulatory Debits (407.3) 12
(Less) Regulatory Credits (407.4) 13
28,894,715 24,046,035262-263Taxes Other Than Income Taxes (408.1) 14
-57,754,420 5,967,393262-263Income Taxes - Federal (409.1) 15
-803,160 3,057,226262-263 - Other (409.1) 16
116,679,418 83,335,948234, 272-277Provision for Deferred Income Taxes (410.1) 17
99,841,847 80,939,819234, 272-277(Less) Provision for Deferred Income Taxes-Cr. (411.1) 18
-1,131,934 -1,533,190266Investment Tax Credit Adj. - Net (411.4) 19
-17,392 34,607(Less) Gains from Disp. of Utility Plant (411.6) 20
Losses from Disp. of Utility Plant (411.7) 21
398,050 444,212(Less) Gains from Disposition of Allowances (411.8) 22
Losses from Disposition of Allowances (411.9) 23
Accretion Expense (411.10) 24
814,535,732 842,631,754TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24) 25
207,049,410 190,420,366Net Util Oper Inc (Enter Tot line 2 less 25) Carry to Pg117,line 27 26
FERC FORM NO. 1/3-Q (REV. 02-04) Page 114
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
STATEMENT OF INCOME FOR THE YEAR (Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line Previous Year to Date(in dollars)
(k)(j)(g)
ELECTRIC UTILITY
No.Current Year to Date
(in dollars)
OTHER UTILITY
(l)
GAS UTILITYPrevious Year to Date
(in dollars)Current Year to Date
(in dollars)Previous Year to Date
(in dollars)Current Year to Date
(in dollars)(h) (i)
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 bemade 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 thegross 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 theutility 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 rateproceeding affecting revenues received or costs incurred for power or gas purches, and a summary of the adjustments made to balance sheet, income,and expense accounts.12. If any notes appearing in the report to stokholders are applicable to the Statement of Income, such notes may be included at page 122.13. Enter on page 122 a concise explanation of only those changes in accounting methods made during the year which had an effect on net income,including the basis of allocations and apportionments from those used in the preceding year. Also, give the appropriate dollar effect of such changes.14. Explain in a footnote if the previous year's/quarter's figures are different from that reported in prior reports.15. If the columns are insufficient for reporting additional utility departments, supply the appropriate account titles report the information in a footnote tothis schedule.
1
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
FERC FORM NO. 1 (ED. 12-96) Page 115
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
STATEMENT OF INCOME FOR THE YEAR (continued)
Idaho Power Company X04/13/2012
2011/Q4
Line
Previous Year(c)(b)(a)
Title of Account
No.
Current Year
TOTAL
(d)
(Ref.)Page No.
Current 3 MonthsEnded
Quarterly OnlyNo 4th Quarter
(e)
Prior 3 MonthsEnded
Quarterly OnlyNo 4th Quarter
(f)
207,049,410 190,420,366Net Utility Operating Income (Carried forward from page 114) 27Other Income and Deductions 28Other Income 29Nonutilty Operating Income 30
1,142,767 802,483Revenues From Merchandising, Jobbing and Contract Work (415) 31 974,498 625,141(Less) Costs and Exp. of Merchandising, Job. & Contract Work (416) 32 51,602 58,915Revenues From Nonutility Operations (417) 33 -18,126 657,070(Less) Expenses of Nonutility Operations (417.1) 34 -3,285 -6,040Nonoperating Rental Income (418) 35
5,967,745 7,546,332119Equity in Earnings of Subsidiary Companies (418.1) 36 2,178,296 2,167,147Interest and Dividend Income (419) 37
25,484,071 16,551,145Allowance for Other Funds Used During Construction (419.1) 38 1,428,531 1,928,056Miscellaneous Nonoperating Income (421) 39
57,199 122,735Gain on Disposition of Property (421.1) 40 35,350,554 27,888,562TOTAL Other Income (Enter Total of lines 31 thru 40) 41
Other Income Deductions 42 3,355Loss on Disposition of Property (421.2) 43
1,167,810 1,098,260 Exp. for Certain Civic, Political & Related Activities (426.4) 48 6,579,000 5,601,967 Other Deductions (426.5) 49 8,138,492 6,783,533TOTAL Other Income Deductions (Total of lines 43 thru 49) 50
Taxes Applic. to Other Income and Deductions 51 23,238 19,582262-263Taxes Other Than Income Taxes (408.2) 52
-638,707 -2,812,996262-263Income Taxes-Federal (409.2) 53 -112,459 -559,924262-263Income Taxes-Other (409.2) 54 511,882 1,739,465234, 272-277Provision for Deferred Inc. Taxes (410.2) 55
1,327,221 1,420,220234, 272-277(Less) Provision for Deferred Income Taxes-Cr. (411.2) 56Investment Tax Credit Adj.-Net (411.5) 57(Less) Investment Tax Credits (420) 58
-1,543,267 -3,034,093TOTAL Taxes on Other Income and Deductions (Total of lines 52-58) 59 28,755,329 24,139,122Net Other Income and Deductions (Total of lines 41, 50, 59) 60
Interest Charges 61 79,348,955 80,490,049Interest on Long-Term Debt (427) 62 1,653,291 1,487,918Amort. of Debt Disc. and Expense (428) 63 911,000 915,215Amortization of Loss on Reaquired Debt (428.1) 64
(Less) Amort. of Premium on Debt-Credit (429) 65(Less) Amortization of Gain on Reaquired Debt-Credit (429.1) 66Interest on Debt to Assoc. Companies (430) 67
2,474,590 1,707,178Other Interest Expense (431) 68 13,332,724 10,675,095(Less) Allowance for Borrowed Funds Used During Construction-Cr. (432) 69 71,055,112 73,925,265Net Interest Charges (Total of lines 62 thru 69) 70
164,749,627 140,634,223Income Before Extraordinary Items (Total of lines 27, 60 and 70) 71Extraordinary Items 72Extraordinary Income (434) 73(Less) Extraordinary Deductions (435) 74Net Extraordinary Items (Total of line 73 less line 74) 75
262-263Income Taxes-Federal and Other (409.3) 76Extraordinary Items After Taxes (line 75 less line 76) 77
164,749,627 140,634,223Net Income (Total of line 71 and 77) 78
FERC FORM NO. 1/3-Q (REV. 02-04) Page 117
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
STATEMENT OF RETAINED EARNINGS
Idaho Power Company X04/13/2012
2011/Q4
Line
CurrentQuarter/YearYear to Date
Balance(c)(b)(a)
ItemContra Primary
No.Account Affected
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 unappropriatedundistributed 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. Followby 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 berecurrent, 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.
PreviousQuarter/YearYear to Date
Balance(d)
UNAPPROPRIATED RETAINED EARNINGS (Account 216) 483,599,149 558,128,446 1 Balance-Beginning of Period
2 Changes 3 Adjustments to Retained Earnings (Account 439) 4 5 6 7 8 9 TOTAL Credits to Retained Earnings (Acct. 439)
10 11 12 13 14 15 TOTAL Debits to Retained Earnings (Acct. 439)
133,087,891 158,781,882 16 Balance Transferred from Income (Account 433 less Account 418.1) 17 Appropriations of Retained Earnings (Acct. 436)
-178,017215.1 18 Earnings on Hydro( 54,644) 19 Reserve for excess Earnings for Cascade Project 2010
( 433,060)215.1 20 Reserve for excess Earnings for Twin Falls & American Falls 21
( 58,070,890) -59,704,738 36 TOTAL Dividends Declared-Common Stock (Acct. 438) 37 Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings
558,128,446 657,027,573 38 Balance - End of Period (Total 1,9,15,16,22,29,36,37)APPROPRIATED RETAINED EARNINGS (Account 215)
39 40
FERC FORM NO. 1/3-Q (REV. 02-04) Page 118
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
STATEMENT OF RETAINED EARNINGS
Idaho Power Company X04/13/2012
2011/Q4
Line
CurrentQuarter/YearYear to Date
Balance(c)(b)(a)
ItemContra Primary
No.Account Affected
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 unappropriatedundistributed 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. Followby 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 berecurrent, 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.
APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Account 215.1) 2,031,670 2,209,688 46 TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Acct. 215.1) 2,031,670 2,209,688 47 TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46)
560,160,116 659,237,261 48 TOTAL Retained Earnings (Acct. 215, 215.1, 216) (Total 38, 47) (216.1)UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (AccountReport only on an Annual Basis, no Quarterly
62,552,348 70,098,680 49 Balance-Beginning of Year (Debit or Credit) 7,546,332 5,967,745 50 Equity in Earnings for Year (Credit) (Account 418.1)
51 (Less) Dividends Received (Debit) 52
70,098,680 76,066,425 53 Balance-End of Year (Total lines 49 thru 52)
FERC FORM NO. 1/3-Q (REV. 02-04) Page 119
(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 asinvestments, 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 andCash 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 bereported 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 Notesto 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 ofthe dollar amount of leases capitalized with the plant cost.
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
STATEMENT OF CASH FLOWS
Idaho Power Company X04/13/2012
2011/Q4
Line Description (See Instruction No. 1 for Explanation of Codes) Current Year to DateQuarter/Year
(b)(a)No.
Previous Year to DateQuarter/Year
(c) 1 Net Cash Flow from Operating Activities:
140,634,223 164,749,627 2 Net Income (Line 78(c) on page 117) 3 Noncash Charges (Credits) to Income:
109,099,197 113,001,742 4 Depreciation and Depletion 12,120,185 11,025,871 5 Amortization of
13,653,023 -2,125,936 10 Net (Increase) Decrease in Receivables 539,767 -21,207,643 11 Net (Increase) Decrease in Inventory
12 Net (Increase) Decrease in Allowances Inventory -5,534,463 22,896,607 13 Net Increase (Decrease) in Payables and Accrued Expenses 34,996,161 23,708,446 14 Net (Increase) Decrease in Other Regulatory Assets 11,513,932 44,336,626 15 Net Increase (Decrease) in Other Regulatory Liabilities 16,551,145 25,484,071 16 (Less) Allowance for Other Funds Used During Construction 7,546,282 5,967,745 17 (Less) Undistributed Earnings from Subsidiary Companies
-41,492,468 27,407,254 18 Other (provide details in footnote): 19 20 21
325,912,762 292,794,961 22 Net Cash Provided by (Used in) Operating Activities (Total 2 thru 21) 23 24 Cash Flows from Investment Activities: 25 Construction and Acquisition of Plant (including land):
-327,576,965 -324,431,776 26 Gross Additions to Utility Plant (less nuclear fuel) 27 Gross Additions to Nuclear Fuel 28 Gross Additions to Common Utility Plant 29 Gross Additions to Nonutility Plant
10,675,095 13,332,724 30 (Less) Allowance for Other Funds Used During Construction 25,390,083 6,314,273 31 Other (provide details in footnote):
32 33
-312,861,977 -331,450,227 34 Cash Outflows for Plant (Total of lines 26 thru 33) 35 36 Acquisition of Other Noncurrent Assets (d) 37 Proceeds from Disposal of Noncurrent Assets (d) 38 39 Investments in and Advances to Assoc. and Subsidiary Companies 40 Contributions and Advances from Assoc. and Subsidiary Companies 41 Disposition of Investments in (and Advances to) 42 Associated and Subsidiary Companies 43
-7,000,000 44 Purchase of Investment Securities (a) 45 Proceeds from Sales of Investment Securities (a)
FERC FORM NO. 1 (ED. 12-96) Page 120
(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 asinvestments, 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 andCash 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 bereported 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 Notesto 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 ofthe dollar amount of leases capitalized with the plant cost.
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
STATEMENT OF CASH FLOWS
Idaho Power Company X04/13/2012
2011/Q4
Line Description (See Instruction No. 1 for Explanation of Codes) Current Year to DateQuarter/Year
(b)(a)No.
Previous Year to DateQuarter/Year
(c) 46 Loans Made or Purchased 47 Collections on Loans 48
333,525 208,367 49 Net (Increase) Decrease in Receivables 50 Net (Increase ) Decrease in Inventory 51 Net (Increase) Decrease in Allowances Held for Speculation 52 Net Increase (Decrease) in Payables and Accrued Expenses
8,541,146 -493,891 53 Other (provide details in footnote): 54 55 56 Net Cash Provided by (Used in) Investing Activities
-310,987,306 -331,735,751 57 Total of lines 34 thru 55) 58 59 Cash Flows from Financing Activities: 60 Proceeds from Issuance of:
200,000,000 61 Long-Term Debt (b) 62 Preferred Stock 63 Common Stock 64 Other (provide details in footnote): 65 66 Net Increase in Short-Term Debt (c)
50,000,000 16,000,000 67 Other (provide details in footnote): Capital Infusion from IDACORP 68 69
250,000,000 16,000,000 70 Cash Provided by Outside Sources (Total 61 thru 69) 71 72 Payments for Retirement of:
-3,183,141 -1,207,914 76 Other (provide details in footnote): 77 78 Net Decrease in Short-Term Debt (c) 79 80 Dividends on Preferred Stock
-58,070,890 -59,704,738 81 Dividends on Common Stock 82 Net Cash Provided by (Used in) Financing Activities
187,682,333 -165,976,288 83 (Total of lines 70 thru 81) 84 85 Net Increase (Decrease) in Cash and Cash Equivalents
202,607,789 -204,917,078 86 (Total of lines 22,57 and 83) 87
21,624,929 224,232,718 88 Cash and Cash Equivalents at Beginning of Period 89
224,232,718 19,315,640 90 Cash and Cash Equivalents at End of period
FERC FORM NO. 1 (ED. 12-96) Page 121
Schedule Page: 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
Schedule Page: 120 Line No.: 13 Column: bCash paid during the period for: Income taxes (1,033,185) Interest (net of amount capitalized) 70,490,892 Schedule Page: 120 Line No.: 18 Column: bCash Flow from Operating Activities (Other) Twelve Months
Ended 12/31/11
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 noncash adjustments to net income 1,762,799 Accrued interest (2,000,069)Customer deposits 9,432,385 Other assets and liabilities (6,048,439)
27,407,254 Schedule Page: 120 Line No.: 26 Column: bNon-cash investing activities: Additions to PP&E in accounts payable 26,330,730 Schedule Page: 120 Line No.: 31 Column: bOther Cash Flows from Plant Twelve Months
Ended 12/31/11
Sale of emission allowances and renewable energy certificates 6,314,273 6,314,273
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)
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87) Page 450.1
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report Year/Period of ReportEnd of
NOTES TO FINANCIAL STATEMENTS
Idaho Power Company X04/13/2012 2011/Q4
PAGE 122 INTENTIONALLY LEFT BLANKSEE PAGE 123 FOR REQUIRED INFORMATION.
1. Use the space below for important notes regarding the Balance Sheet, Statement of Income for the year, Statement of RetainedEarnings 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 ofany action initiated by the Internal Revenue Service involving possible assessment of additional income taxes of material amount, or of aclaim for refund of income taxes of a material amount initiated by the utility. Give also a brief explanation of any dividends in arrears oncumulative preferred stock.3. For Account 116, Utility Plant Adjustments, explain the origin of such amount, debits and credits during the year, and plan ofdisposition contemplated, giving references to Cormmission orders or other authorizations respecting classification of amounts as plantadjustments 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 anexplanation, 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 suchrestrictions.6. If the notes to financial statements relating to the respondent company appearing in the annual report to the stockholders areapplicable 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 notmisleading. Disclosures which would substantially duplicate the disclosures contained in the most recent FERC Annual Report may beomitted.8. For the 3Q disclosures, the disclosures shall be provided where events subsequent to the end of the most recent year have occurredwhich have a material effect on the respondent. Respondent must include in the notes significant changes since the most recentlycompleted 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; andchanges resulting from business combinations or dispositions. However were material contingencies exist, the disclosure of such mattersshall 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 areapplicable and furnish the data required by the above instructions, such notes may be included herein.
FERC FORM NO. 1 (ED. 12-96) Page 122
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
Idaho Power (IPC), a wholly-owned subsidiary of IDACORP, Inc., is an electric utility with a service territory coveringapproximately 24,000 square miles in southern Idaho and eastern Oregon. Idaho Power is regulated by the Federal EnergyRegulatory Commission (FERC) and the state regulatory commissions of Idaho and Oregon. Idaho Power is the parent of IdahoEnergy Resources Co. (IERCo), a joint venturer in Bridger Coal Company (BCC), which mines and supplies coal to the Jim Bridgergenerating plant owned in part by Idaho Power. IERCo is accounted for using the equity method.
Basis of ReportingThe financial statements include the assets, liabilities, revenues and expenses of the Company and have been prepared in accordancewith the accounting requirements of the FERC as set forth in its applicable Uniform System of Accounts and published accountingreleases, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States ofAmerica (U.S. GAAP). As required by the FERC, the Company accounts for its investment in its majority-owned subsidiary on theequity 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 resultingfrom its interest in jointly owned plants. In addition, under the requirements of the FERC, there are differences from U.S. GAAP inthe presentation of (l) current portion of long-term debt, (2) assets and liabilities for cost of removal of assets, (3) regulatory assetsand liabilities, (4) deferred income taxes, (5) income tax expense and (6) non-utility revenues.
Management EstimatesManagement makes estimates and assumptions when preparing financial statements in conformity with generally accepted accountingprinciples (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 reportedamounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements, and thereported amounts of revenues and expenses during the reporting period. These estimates involve judgments with respect to, amongother things, future economic factors that are difficult to predict and are beyond management’s control. As a result, actual resultscould differ from those estimates. System of AccountsThe accounting records of Idaho Power conform to the Uniform System of Accounts prescribed by the FERC and adopted by thepublic utility commissions of Idaho, Oregon, and Wyoming. Regulation of Utility OperationsIdaho Power’s financial statements reflect the effects of the different ratemaking principles followed by the jurisdictions regulatingIdaho Power. The application of accounting principles related to regulated operations sometimes results in Idaho Power recordingexpenses and revenues in a different period than when an unregulated enterprise would. In these instances, the amounts are deferredas regulatory assets or regulatory liabilities on the balance sheet and recorded on the income statement when recovered or returned inrates. Additionally, regulators can impose regulatory liabilities upon a regulated company for amounts previously collected fromcustomers and for amounts that are expected to be refunded to customers. The effects of applying these regulatory accountingprinciples to Idaho Power’s operations are discussed in more detail in Note 3. Cash and Cash EquivalentsCash and cash equivalents include cash on hand and highly-liquid temporary investments that mature within 90 days of the date ofacquisition. Receivables and Allowance for Uncollectible AccountsCustomer receivables are recorded at the invoiced amounts and do not bear interest. A late payment fee of one percent may beassessed on account balances after 30 days. An allowance is recorded for potential uncollectible accounts. The allowance is reviewedperiodically and adjusted based upon a combination of historical write-off experience, aging of accounts receivable, and an analysisof specific customer accounts. Adjustments are charged to income. Customer accounts receivable balances that remain outstanding
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88) Page 123.1
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 thatIdaho Power will be unable to collect all amounts due according to the contractual terms of the agreement, an allowance is establishedfor 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 tobe impaired, any further interest income recognized is fully reserved. Derivative Financial InstrumentsFinancial instruments such as commodity futures, forwards, options, and swaps are used to manage exposure to commodity price riskin the electricity and natural gas markets. All derivative instruments are recognized as either assets or liabilities at fair value on thebalance sheet. Idaho Power’s physical forward contracts qualify for the normal purchases and normal sales exception to derivativeaccounting requirements with the exception of forward contracts for the purchase of natural gas for use at Idaho Power’s natural gasgeneration facilities. The objective of the risk management program is to mitigate the price risk associated with the purchase and saleof electricity and natural gas. Because of Idaho Power’s regulatory accounting mechanisms, Idaho Power records the changes in fairvalue of derivative instruments related to power supply as regulatory assets or liabilities. RevenuesOperating revenues related to Idaho Power’s sale of energy are recorded when service is rendered or energy is delivered tocustomers. Idaho Power accrues estimated unbilled revenues for electric services delivered to customers but not yet billed atyear-end. Idaho Power collects franchise fees and similar taxes related to energy consumption. None of these collections are reportedon the income statement. Beginning in February 2009, Idaho Power is collecting in base rates a portion of the allowance for fundsused during construction (AFUDC) related to its Hells Canyon relicensing project. Cash collected under this ratemaking mechanismis not recorded as revenue, but is instead recorded as a regulatory liability. Property, Plant and Equipment and DepreciationThe cost of utility plant in service represents the original cost of contracted services, direct labor and material, AFUDC, and indirectcharges for engineering, supervision, and similar overhead items. Repair and maintenance costs associated with planned majormaintenance are expensed as the costs are incurred, as are maintenance and repairs of property and replacements and renewals ofitems determined to be less than units of property. For utility property replaced or renewed, the original cost plus removal cost lesssalvage is charged to accumulated provision for depreciation, while the cost of related replacements and renewals is added toproperty, plant and equipment. All utility plant in service is depreciated using the straight-line method at rates approved by regulatory authorities. Annualdepreciation provisions as a percent of average depreciable utility plant in service approximated 2.83 percent in 2011 and 2.84 percentin 2010. Long-lived assets are periodically reviewed for impairment when events or changes in circumstances indicate that the carryingamount of an asset may not be recoverable. If the sum of the undiscounted expected future cash flows from an asset is less than thecarrying value of the asset, impairment must be recognized in the financial statements. There were no material impairments of theseassets in 2011 or 2010. Allowance for Funds Used During ConstructionAFUDC represents the cost of financing construction projects with borrowed funds and equity funds. With one exception, cash is notrealized currently from such allowance; it is realized under the ratemaking process over the service life of the related property throughincreased revenues resulting from a higher rate base and higher depreciation expense. The component of AFUDC attributable toborrowed funds is included as a reduction to interest expense, while the equity component is included in other income. Idaho Power’sweighted-average monthly AFUDC rates for 2011 and 2010 were 7.8 percent and 8.0 percent, respectively. Idaho Power’s reductionsto interest expense for AFUDC were $13 million for 2011 and $11 million for 2010. Other income included $25 million and $17
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88) Page 123.2
million of AFUDC for 2011 and 2010, respectively. Income TaxesIdaho Power accounts for income taxes under the asset and liability method, which requires the recognition of deferred tax assets andliabilities 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 andliabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. The effect of a change in taxrates 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 principaljurisdiction over Idaho Power’s Idaho service territory, Idaho Power’s deferred income taxes for plant-related items (commonlyreferred to as normalized accounting) are primarily provided for the difference between income tax depreciation and bookdepreciation used for financial statement purposes. Unless contrary to applicable income tax guidance, deferred income taxes are notprovided for those income tax timing differences where the prescribed regulatory accounting methods direct Idaho Power to recognizethe tax impact currently for rate making and financial reporting. Regulated enterprises are required to recognize such adjustments asregulatory 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 onregulated assets are deferred and amortized to income over the estimated service lives of the related properties. Credits earned onnon-regulated assets or investments are recognized in the year earned. Income taxes are discussed in more detail in Note 2.
Comprehensive IncomeComprehensive income includes net income, unrealized holding gains and losses on available-for-sale marketable securities, andamounts related to a deferred compensation plan for certain senior management employees and directors called the SeniorManagement Security Plan. The following table presents and Idaho Power’s accumulated other comprehensive loss balance atDecember 31 (net of tax):
2011 2010 (thousands of dollars)Unrealized holding gains on available-for-sale securities $ 2,569 $ 2,969Senior Management Security Plan (14,191) (12,537)Total $ (11,622) $ (9,568)
Other Accounting PoliciesDebt 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 yearsbeginning after December 15, 2011:
• In May 2011, the FASB issued guidance to provide a consistent definition of fair value and ensure that the fair valuemeasurement and disclosure requirements are similar between generally accepted accounting principles in the United Statesand International Financial Reporting Standards. The guidance changes certain fair value measurement principles andenhances the disclosure requirements, particularly for Level 3 fair value measurements. Idaho Power is currently assessingthe impact of the guidance but do not believe that the adoption of this guidance will have a material effect on their
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88) Page 123.3
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 $ 51,614Change 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) 2,233Total 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
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88) Page 123.4
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 232,671 182,307Deferred 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 1,075,459 831,597Net 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 separatecompany basis. Amounts payable or refundable are settled through IDACORP.
Tax Credits CarryforwardsAs of December 31, 2011, Idaho Power had $8.5 million of Idaho investment tax credit carryforward. Idaho investment tax creditexpires from 2023 to 2025. Uncertain Tax PositionsA reconciliation of the beginning and ending amount of unrecognized tax benefits for Idaho Power is as follows (in thousands ofdollars): 2011 2010Balance at January 1, $ 74,436 $ 1,138Additions for tax positions of the current year — 2,822Additions for tax positions of prior years — 71,614Reductions for tax positions of prior years (66,379) (1,138)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 2011and interest expense of $0.2 million in 2010. Accrued interest was was zero as of December 31, 2011and $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
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88) Page 123.5
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 CAPprogram for all subsequent years. The CAP program provides for IRS examination and issue resolution throughout the current yearwith 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 (discussedbelow), the 2009 tax year is now closed for federal purposes. In 2011, the IRS also completed its examination of IDACORP's 2010tax year with no unresolved income tax issues. Idaho Power believes there are no remaining material tax uncertainties for 2011 andprior 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 currentincome tax deduction for repair-related expenditures on its utility assets that are currently capitalized for financial reporting and taxpurposes. In September 2010, Idaho Power adopted this method following the automatic consent procedures with the filing ofIDACORP's 2009 consolidated federal income tax return. The method was subject to audit under IDACORP's 2009 CAPexamination. For the year ended December 31, 2010, Idaho Power recorded a $44.5 million tax benefit related to the filed deduction for thecumulative method change adjustment and an additional $11.7 million tax benefit for the annual deduction estimate included in its2010 income tax provision. As of December 31, 2010, Idaho Power had a current uncertain tax position liability of $14.7 millionrelated 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 JointCommittee on Taxation (Joint Committee) for review. Idaho Power considers the capitalized repairs method effectively settled andbelieves that no material income tax uncertainties remain for the method. As such, Idaho Power recognized $3.4 million of itspreviously 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 taxprovision 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 fromprior 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 thistype. A regulatory asset is established to reflect Idaho Power's ability to recover increased income tax expense when such temporarydifferences 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 audittechniques related to the allocation of mixed service costs in the uniform capitalization methods of electric utilities. WithinIDACORP's 2009 CAP examination, the IRS and Idaho Power worked through the impact the IDD guidance had on Idaho Power'suniform capitalization method and reached agreement during 2010. The agreement provided that Idaho Power change its uniformcapitalization method to the agreed upon method under the IDD with the filing of IDACORP's 2009 consolidated federal income taxreturn. While Idaho Power had an agreement with the IRS for examination and return filing purposes, the agreement required JointCommittee approval to be final. The resulting tax deductions available under the agreed upon uniform capitalization method were significantly greater than IdahoPower's prior method. For the year ended December 31, 2010, Idaho Power recorded a tax benefit of $65.3 million related to the
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88) Page 123.6
cumulative method change adjustment (tax years 1986 through 2009) for this method and $5.6 million of tax expense from thereversal of this temporary difference. As of December 31, 2010, Idaho Power had a current uncertain tax position liability equal tothe $59.7 million net tax benefit recorded for the method change. Due to the method change agreement with the IRS, Idaho Powerreversed the uncertain tax position liability for its 2009 uniform capitalization deduction, resulting in a $1.1 million tax benefit for theyear 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 andapproved the uniform capitalization method agreement. Idaho Power considers the uniform capitalization method effectively settledand believes that no material income tax uncertainties remain for the method. Accordingly, Idaho Power recognized $56.9 million ofits 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 incometax provision produced a $6.6 million tax benefit. The amount of this annual tax deduction will vary depending on a number offactors, but most directly by the amount and type of Idaho Power's annual capital additions. The reversal of this temporary differencefrom prior years will offset a portion of the ongoing annual benefit. The prescribed regulatory accounting treatment for this method isthe 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 examinationagreement. There were no 2011 cash impacts related to the uniform capitalization method settlement as income tax refunds for themethod change were received in 2010. In 2010, Idaho Power realized federal and state cash benefits associated with the 2009 capitalized repairs and uniform capitalizationmethod changes of $42 million. The majority of this cash benefit was realized through reductions to cash payments that would haveotherwise 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 topreviously deferred income tax expense being flowed through the income statement, which does not deliver any cash benefits. Inaddition, federal tax credits of $17 million previously recognized were restored due to the reduction of 2009 taxable income by thetwo method changes. The restored credits were a reduction to cash received in 2010, but will be available to deliver cash benefits infuture periods.
3. REGULATORY MATTERS Regulatory Assets and Liabilities Regulatory assets represent incurred costs that have been deferred because it is reasonably expected they will be recovered throughfuture rates collected from customers. Regulatory liabilities represent obligations to make refunds to customers for previouscollections, except for cost of removal (which represents the cost of removing future electric assets). The following table presents asummary of Idaho Power’s regulatory assets and liabilities (in thousands of dollars):
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88) Page 123.7
Remaining Earning a Not EarningAmortization Return (1) a Return Total as of December 31,
(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 theevent that recovery of Idaho Power’s costs through rates becomes unlikely or uncertain, regulatory accounting would no longer applyto some or all of Idaho Power’s operations and the items above may represent stranded investments. If not allowed full recovery ofthese 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 powersupply costs and provide for annual adjustments to the rates charged to its retail customers. The PCA mechanisms compare IdahoPower's actual and forecast net power supply costs (primarily fuel and purchased power less off-system sales) against net powersupply 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 costsincluded in retail rates are recorded as a deferred charge or credit on the balance sheets for future recovery or refund through retailrates. The power supply costs deferred primarily result from changes in wholesale market prices and transaction volumes, changes incontracted power purchase prices and volumes, and the levels of hydroelectric and thermal generation.
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88) Page 123.8
Idaho Jurisdiction Power Cost Adjustment Mechanism: In the Idaho jurisdiction, the annual PCA adjustments are based on (a) aforecast component, based on a forecast of net power supply costs in the coming year as compared to net power supply costs in baserates; and (b) a true-up component, based on the difference between the previous year’s actual net power supply costs and theprevious year’s forecast. The latter component also includes a balancing mechanism so that, over time, the actual collection or refundof 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 PURPA power purchases, which areallocated 100 percent to customers;
• a load change adjustment rate (LCAR), which is intended to eliminate recovery of power supply expenses alreadycollected in rates associated with load changes resulting from changing weather conditions, a growing customer base, orchanging customer use patterns; and
• third-party transmission expenses (paid to third parties to facilitate wholesale purchases and sales of energy) as acomponent 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, 2011and 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 energyefficiency rider deferral balance that the IPUC authorized for recovery in Idaho Power’sIdaho PCA rates.
June 1, 2010 $ (146.9) The IPUC’s order was made in conjunction with a January 2010 rate settlement agreementdescribed 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 baserates, $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 twocomponents: an annual power cost update (APCU) and a power cost adjustment mechanism (PCAM). The APCU allows IdahoPower to reestablish its Oregon base net power supply costs annually, separate from a general rate case, and to forecast net powersupply costs for the upcoming water year. The PCAM is a true-up filed annually in February. The filing calculates the deviationbetween actual net power supply expenses incurred for the preceding calendar year and the net power supply expenses recoveredthrough the APCU for the same period. Under the PCAM, Idaho Power is subject to a portion of the business risk or benefitassociated with this deviation through application of an asymmetrical deadband (or range of deviations) within which Idaho Powerabsorbs cost increases or decreases. For deviations in actual power supply costs outside of the deadband, the PCAM provides for90/10 sharing of costs and benefits between customers and Idaho Power. However, collection by Idaho Power will occur only to theextent that Idaho Power’s actual return on equity (ROE) for the year is no greater than 100 basis points below Idaho Power’s lastauthorized ROE. A refund to customers will occur only to the extent that Idaho Power’s actual ROE for that year is no less than 100basis 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 2010were as follows:
Year andMechanism APCU or PCAM Adjustment2011 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.
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88) Page 123.9
Idaho Regulatory Matters 2011 Idaho General Rate Case and Settlement: On June 1, 2011, Idaho Power filed a general rate case and proposed rate scheduleswith the IPUC, Case No. IPC-E-11-08. The filing was based on a 2011 test year and requested approximately $82.6 million inadditional 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 theIPUC resolving most of the key contested issues in the Idaho general rate case. On December 30, 2011, the IPUC issued an orderapproving the settlement stipulation. The settlement stipulation approved by the December 30, 2011 order provides for a 7.86 percentauthorized rate of return on an Idaho-jurisdictional rate base of approximately $2.36 billion. The approved settlement stipulationresulted in a 4.07 percent, or $34.0 million, overall increase in Idaho Power's annual Idaho jurisdictional base rate revenues, effectiveJanuary 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 IdahoPower's PCA mechanism. The LCAR adjusts power supply cost recovery within the Idaho PCA formula upwards or downwards fordifferences between actual load and the load used in calculating base rates. The settlement stipulation provides for a LCAR of $18.16per 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 pilotprogram, described below, as a permanent rate mechanism for residential and small commercial class customers. Neither theDecember 30, 2011 order nor the settlement stipulation resolves whether the fixed cost adjustment pilot program should be madepermanent. Neither the order nor the settlement stipulation imposes a moratorium on Idaho Power's filing a general revenue requirement case at afuture date. January 2010 and December 2011 Idaho Settlement Agreements: On January 13, 2010, the IPUC approved a settlement agreementamong Idaho Power, several of Idaho Power’s customers, the IPUC Staff, and others. Significant elements of the settlementagreement included:
• a specified distribution of the reduction in 2010 PCA that would reduce customer rates, provide up to a $25 milliongeneral increase in annual base rates, and reset base power supply costs for the PCA, effective with the June 1, 2010 PCArate 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 returnon 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'sIdaho-jurisdiction rate of return on year-end equity (Idaho ROE) is below 9.5 percent in any calendar year from 2009 to2011. Idaho Power was permitted to amortize additional ADITC in an amount up to $45 million over the three-yearperiod, but could use no more than $15 million in any one year unless there is a carryover. Carryover amounts wereadded 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, 2010through 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 10.5 percent in 2009 and 2010, the sharing and amortization
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88) Page 123.10
provisions of the January 2010 settlement agreement were not triggered. However, recognition of income tax benefits in 2011 had asignificant impact on Idaho Power's actual Idaho ROE and contributed to the triggering of the sharing mechanism for 2011. Inaccordance with the terms of the settlement agreement, Idaho Power recorded a $27.1 million reduction in revenue and regulatoryliability in 2011, reflecting 50 percent of Idaho Power's 2011 Idaho-jurisdictional earnings above a 10.5 percent Idaho ROE to beshared with Idaho customers. The sharing and ADITC amortization provisions of the January 2010 settlement agreement terminated on December 31, 2011. OnDecember 27, 2011, the IPUC issued an order, separate from the general rate case proceeding, approving a settlement stipulation thathad been executed by Idaho Power, the IPUC Staff, and one large industrial customer of Idaho Power and filed with the IPUC onDecember 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 amortizeadditional ADITC to help achieve a minimum 9.5 percent Idaho ROE in the applicable year. Idaho Power would bepermitted to amortize additional ADITC in an aggregate amount up to $45 million over the three-year period, but could useno 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 Idahojurisdictional earnings exceeding a 10.0 percent, but less than a 10.5 percent, Idaho ROE for the applicable year would beshared 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 Idahojurisdictional earnings exceeding a 10.5 percent Idaho ROE for the applicable year would be allocated 75 percent to IdahoPower'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 beautomatically adjusted prospectively in the event the IPUC approves a change to Idaho Power's authorized return on equity as part ofa general rate case proceeding seeking a rate change effective prior to January 1, 2015. The automatic adjustments would be asfollows: (a) the 9.5 percent return on year-end equity trigger in the settlement stipulation would be replaced by the percentage equal to95 percent of the new authorized return on equity, (b) the 10.0 percent return on year-end equity trigger in the settlement stipulationwould be re-established at the new authorized return on equity amount, and (c) the 10.5 percent return on year-end equity trigger inthe 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 ofIdaho Power's own share of 2011 Idaho jurisdictional earnings over a 10.5 percent Idaho ROE. As a result, Idaho Power recorded in2011 a $20.3 million pre-tax charge to pension expense and an associated decrease in deferred pension regulatory asset, representingthe 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 servicecustomers, running from 2007 through 2009. The FCA is designed to remove Idaho Power’s disincentive to invest in energyefficiency programs by separating (or decoupling) the recovery of fixed costs from the variable kilowatt-hour charge and linking itinstead 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 theIPUC requesting that the FCA pilot program become permanent for residential and small general service customer classes effectiveJanuary 1, 2012; a determination from the IPUC is pending. The following table summarizes recent FCA rate adjustments:
FCA Year Period rates in effectAnnual Amount
(in millions)2010 June 1, 2011-May 31, 2012 9.32009 June 1, 2010-May 31, 2011 6.3
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88) Page 123.11
2008 June 1, 2009-May 31, 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 regulatoryasset until recovered from Idaho customers. As of December 31, 2011, Idaho Power's deferral balance was $58.0 million. Deferredpension costs are expected to be amortized to expense to match the revenues received when contributions are recovered throughrates. 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 contributionto 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 cashcontributions to the plan. In September 2010, Idaho Power elected to make a $60 million contribution to its defined benefit pension plan, rather than theminimum required funding amount, to bring the defined benefit pension plan to a more funded position, potentially reducing futurerequired contributions and Pension Benefit Guaranty Corporation premiums. On October 1, 2010, Idaho Power filed an applicationwith the IPUC requesting an order accepting Idaho Power's 2011 retirement benefits package, but not requesting recovery throughrates of additional pension plan contributions. On April 28, 2011, the IPUC issued an order accepting Idaho Power's 2011 retirementbenefits package. On March 15, 2011, Idaho Power filed an application with the IPUC requesting an increase in the amount included in base rates forrecovery of the Idaho-allocated portion of Idaho Power's cash contributions to its defined benefit pension plan from the then-currentamount 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 definedbenefit pension plan. Transmission Revenue Shortfall Filing: On January 15, 2009, the FERC issued an order that required Idaho Power to reduce itstransmission service rates to FERC jurisdictional customers and refund to transmission customers transmission revenues that IdahoPower had received starting in 2006. This refund ultimately resulted in under-recovery of transmission costs by Idaho Power, and inOctober 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 orderedthat Idaho Power advise the IPUC when the FERC has issued its order on rehearing, following which Idaho Power may request acommencement date for the amortization period for the regulatory asset. On December 7, 2011, the FERC issued an order denyingrehearing. Accordingly, on February 15, 2012, Idaho Power submitted an application to the IPUC seeking to include the $2.1 milliontransmission revenue shortfall in customer rates, recoverable over a three-year period beginning June 1, 2012. As of the date of thisreport, 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 opportunitiesfor 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 designateIdaho Power's 2010 Idaho energy efficiency rider expenditures of approximately $42 million as prudently incurred expenses. IdahoPower’s 2010 expenditures for rider-funded energy efficiency and demand response initiatives in its Idaho and Oregon jurisdictionstotaled $44.2 million. On March 16, 2010, Idaho Power filed an application with the IPUC requesting an order designating energyefficiency expenditures of $50.7 million incurred in 2008 and 2009 as prudently incurred expenses. On November 16, 2010, theIPUC issued an order designating all $50.7 million of energy efficiency expenditures as prudently incurred and approved forratemaking purposes.
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88) Page 123.12
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 energyefficiency rider and into the Idaho PCA on a prospective basis beginning on June 1, 2011, and thus subject to a true-up under the PCAmechanism; (b) establish a regulatory asset for the direct incentive payments associated with Idaho Power's energy efficiency programfor large commercial and industrial customers, beginning January 1, 2011, so that Idaho Power may capitalize the direct incentivepayments associated with the program, include the costs associated with the program incentive payments in its rate base, and thus earna rate of return on a portion of its DSR activities; and (c) change the carrying charge on the existing energy efficiency rider balancingaccount (from the then-current interest rate of 1.0 percent to Idaho Power's authorized rate of return). On April 1, 2011, the IPUCissued 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 inexpenditures that have been previously approved by the IPUC for recovery, and thus authorized recovery of $10 million of the riderbalance in Idaho Power's Idaho PCA rates, beginning June 1, 2011. In that order, the IPUC did not approve a change to the energyefficiency 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 paymentsassociated with Idaho Power's energy efficiency program for large commercial and industrial customers as a regulatory assetbeginning 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 aspower supply costs and establish a base or "normal" level of cost recovery of approximately $11.3 million for those demand responseincentive payments in rates. The Idaho general rate case settlement stipulation approved by the IPUC in December 2011 provides thatthe $11.3 million of base level demand response incentive payments would be tracked as part of the Idaho PCA mechanism. TheDecember 2011 IPUC general rate case settlement order also reset Idaho Power's energy efficiency rider rate at 4.0 percent of the sumof 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 Ratemaking Treatment: On September 1, 2009, Idaho Power received pre-approval from the IPUC toinclude $396.6 million of construction costs in Idaho Power’s rate base when the Langley Gulch power plant achieves commercialoperation. Idaho Power may request recovery of additional costs if they exceed $396.6 million, provided that the additional costswere 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 theOPUC, 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 anauthorized rate of return on equity of 10.5 percent with an Oregon retail rate base of approximately $121.9 million, and a rate ofreturn on capital of 8.17 percent. Idaho Power, the OPUC Staff, and other interested parties executed and filed a partial settlementstipulation with the OPUC on February 1, 2012, which resolves all matters in the general rate case other than the prudence of costsassociated with pollution control investments at the Jim Bridger coal plant. The settlement stipulation provides for a return on equityof 9.9 percent and an overall rate of return of 7.757 percent. If the stipulation is approved by the OPUC, Idaho Power expects thatnew rates will become effective on March 1, 2012. As of the date of this report, Idaho Power is unable to determine the outcome ofthe proceeding. 2009 Oregon General Rate Case: On February 24, 2010, the OPUC approved a $5 million, or 15.4 percent, increase in base rates inthe Oregon jurisdiction. The new rates were effective March 1, 2010, and were based on a return on equity of 10.175 percent and anoverall rate of return of 8.061 percent. Idaho Power’s previously authorized rate of return in Oregon was 7.83 percent. Advanced Metering Infrastructure (AMI) The AMI project provides the means to automatically retrieve energy consumption information, eliminating manual meter reading
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88) Page 123.13
expense. On February 12, 2009, the IPUC approved Idaho Power’s application requesting a Certificate of Public Convenience andNecessity for the deployment of AMI technology and approval of accelerated depreciation for the existing metering equipment. TheIPUC subsequently clarified that Idaho Power can expect to include in rate base the Idaho portion of prudent capital costs ofdeploying AMI as it is placed in service up to the capital cost commitment estimate of $70.9 million, plus certain costs that thecompany could not quantify with precision at the time of the application. The IPUC also clarified, as requested by Idaho Power, thatit does not anticipate that the immediate savings derived from the implementation of AMI throughout Idaho Power’s service territorywill 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 IdahoPower’s actual investment in AMI through the then-current date, annualized through December 31, 2009. The IPUC also allowedIdaho Power to begin three-year accelerated depreciation of the existing metering equipment on June 1, 2009. The order reflectsannualized depreciation expense relating to AMI of $9.2 million. Actual depreciation expense recorded in 2011and 2010 was $10.6million and $10.6 million respectively. On May 28, 2010, the IPUC approved Idaho Power’s March 15, 2010 application requestingauthorization to implement a $2.4 million base rate increase for identified customer classes to recover costs relating to the AMIproject, 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 an18-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 millionannually due to the removal of accelerated depreciation expense associated with non-AMI metering equipment. As of the date of thisreport, 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, IdahoPower filed an application with the IPUC seeking to institute revised depreciation rates for electric plant-in-service, based uponupdated net salvage percentages and service life estimates for all plant assets, and adjust Idaho-jurisdictional base rates to reflect therevised depreciation rates. Idaho Power's application requested a $2.7 million increase in Idaho-jurisdictional base rates, with newrates 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 OATT, which allowstransmission rates to be updated annually based on financial and operational data Idaho Power files with the FERC. Idaho Power'sOATT rates submitted to the FERC in Idaho Power's three most recent annual OATT Final Informational Filings were as follows:
Applicable PeriodOATT Rate (per
KW-year)*October 1, 2009 to September 30, 2010 $ 15.83October 1, 2010 to September 30, 2011 $ 19.60October 1, 2011 to September 30, 2012 $ 19.79
* In September 2010, Idaho Power made corrections to its OATT 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.
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88) Page 123.14
4. LONG-TERM DEBT The following table summarizes long-term debt at December 31 (in thousands of dollars):
2011 2010First mortgage bonds:
6.60% Series due 2011 $ — $ 120,0004.75% Series due 2012 100,000 100,0004.25% Series due 2013 70,000 70,0006.025% Series due 2018 120,000 120,0006.15% Series due 2019 100,000 100,0004.50% Series Due 2020 130,000 130,0003.40% Series Due 2020 100,000 100,0006% Series due 2032 100,000 100,0005.50% Series due 2033 70,000 70,0005.50% Series due 2034 50,000 50,0005.875% Series due 2034 55,000 55,0005.30% Series due 2035 60,000 60,0006.30% Series due 2037 140,000 140,0006.25% Series due 2037 100,000 100,0004.85% Series due 2040 100,000 100,000
Total first mortgage bonds 1,295,000 1,415,000Pollution control revenue bonds:
5.15% Series due 2024(1) 49,800 49,8005.25% Series due 2026(1) 116,300 116,300
Variable Rate Series 2000 due 2027 4,360 4,360Total pollution control revenue bonds 170,460 170,460
American Falls bond guarantee 19,885 19,885Milner Dam note guarantee 6,382 7,446Unamortized 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 (in thousands of dollars):
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88) Page 123.15
In May 2010, Idaho Power registered with the SEC the issuance of up to $500 million of first mortgage bonds and debt securities. OnJune 17, 2010, Idaho Power entered into a selling agency agreement with ten banks named in the agreement in connection with thepotential issuance and sale from time to time of up to $500 million aggregate principal amount of first mortgage bonds. As ofDecember 31, 2011, $300 million remained on Idaho Power’s shelf registration for the issuance of first mortgage bonds and debtsecurities. On March 2, 2011, Idaho Power repaid at maturity $120 million of first mortgage bonds using proceeds from first mortgage bondsissued in August 2010. On August 30, 2010, Idaho Power issued $100 million of 3.40% First Mortgage Bonds, Secured Medium-Term Notes, Series I due2020 and $100 million of 4.85% First Mortgage Bonds, Secured Medium-Term Notes, Series I due 2040 under the shelf registrationstatement. Mortgage: As of December 31, 2011, Idaho Power could issue under its Indenture of Mortgage and Deed of Trust, dated as ofOctober 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 firstmortgage bonds based on retired first mortgage bonds and total unfunded property additions. These amounts are further limited bythe 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. Firstmortgage bonds issued in the future will also be secured by the Mortgage. The lien of the indenture constitutes a first mortgage on allthe properties of Idaho Power, subject only to certain limited exceptions including liens for taxes and assessments that are notdelinquent 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. TheMortgage does not create a lien on revenues or profits, or notes or accounts receivable, contracts or choses in action, except aspermitted by law during a completed default, securities, or cash, except when pledged, or merchandise or equipment manufactured oracquired for resale. The Mortgage creates a lien on the interest of Idaho Power in property subsequently acquired, other thanexcepted property, subject to limitations in the case of consolidation, merger, or sale of all or substantially all of the assets of IdahoPower. The Mortgage requires Idaho Power to spend or appropriate 15 percent of its annual gross operating revenues formaintenance, retirement, or amortization of its properties. Idaho Power may, however, anticipate or make up these expenditures orappropriations 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 theMortgage for the purpose of increasing the maximum amount of first mortgage bonds issuable by Idaho Power from $1.5 to $2.0billion. The amount issuable is also restricted by property, earnings, and other provisions of the Mortgage and supplementalindentures to the Mortgage. Idaho Power may amend the Mortgage and increase this amount without consent of the holders of thefirst mortgage bonds. The Mortgage requires that Idaho Power's net earnings be at least twice the annual interest requirements on alloutstanding debt of equal or prior rank, including the bonds that Idaho Power may propose to issue. Under certain circumstances, thenet earnings test does not apply, including the issuance of refunding bonds to retire outstanding bonds that mature in less than twoyears 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. IdahoPower's credit facility consists of a revolving line of credit, through the issuance of loans and standby letters of credit, not to exceedthe aggregate principal amount at any one time outstanding of $300 million, including swingline loans in an aggregate principal
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88) Page 123.16
amount at any time outstanding not to exceed $30 million. Idaho Power has the right to request an increase in the aggregate principalamount 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 certainconditions. 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 primerate, federal funds rate plus 0.5 percent, or LIBOR rate plus 1.0 percent, or (2) the LIBOR rate, plus, in each case, an applicablemargin. 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. Thecompany 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 hadregulatory authority to incur up to $450 million of short-term indebtedness. Balances and interest rates of short-term borrowings ofcommercial paper were as follows at December 31 (in thousands of dollars):
Idaho Power2011 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. Noadditional 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 toconsolidated total capitalization, as defined therein, of no more than 65 percent at the end of each fiscal quarter. Idaho Power’s abilityto pay dividends on its common stock held by IDACORP is limited to the extent payment of such dividends would violate thecovenants in their respective credit facilities or Idaho Power’s Revised Code of Conduct. At December 31, 2011, the leverage ratiofor Idaho Power was 49 percent. Based on these restrictions, Idaho Power’s dividends are limited to $723 million atDecember 31, 2011. There are additional facility covenants, subject to exceptions, that prohibit certain mergers, acquisitions, andinvestments; restrict the creation of certain liens; and prohibit entering into any agreements restricting dividend payments to thecompany 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 anydividends to IDACORP that will reduce Idaho Power’s common equity capital below 35 percent of its total adjusted capital withoutIPUC approval. Idaho Power’s articles of incorporation also contain restrictions on the payment of dividends on its common stock ifpreferred 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 ofdividends from "capital accounts." The term "capital accounts" is undefined in the Federal Power Act, but if conservativelyinterpreted 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 itsbooks to IDACORP.
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88) Page 123.17
7. STOCK-BASED COMPENSATION Through its parent company IDACORP, Idaho Power has two share-based compensation plans -- the 2000 Long-Term Incentive andCompensation Plan (LTICP) and the 1994 Restricted Stock Plan (RSP). These plans are intended to align employee and shareholderobjectives related to IDACORP’s long-term growth. The LTICP (for officers, key employees, and directors) permits the grant of nonqualified stock options, restricted stock, performanceshares, and several other types of stock-based awards. The RSP permits only the grant of restricted stock or performance-basedrestricted stock. At December 31, 2011, the maximum number of shares available under the LTICP and RSP were 1,503,861 and15,796, 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 isbased on the market price of common stock on the grant date and is charged to compensation expense over the vesting period, basedon 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 sharesare restricted as to disposition, subject to forfeiture under certain circumstances, and subject to meeting specific performanceconditions. Based on the attainment of the performance conditions, the ultimate award can range from zero to 150 percent of thetarget 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) relativeto 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 intime-value of the estimated future dividend payments. The fair value of the TSR portion is estimated using a statistical model thatincorporates the probability of meeting performance targets based on historical returns relative to the peer group. Both performancegoals are measured over the three-year vesting period and are charged to compensation expense over the vesting period based on thenumber of shares expected to vest.
A summary of restricted stock and performance share activity is presented below.
Number of Weighted-AverageShares Grant Date
Fair ValueNonvested shares at January 1, 2011 329,501 $26.35 Shares granted 135,016 30.30Shares forfeited (11,451) 27.32Shares vested (115,883) 25.28Nonvested 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 nonvestedshare-based compensation that was expected to vest. These costs are expected to be recognized over a weighted-average period of1.68 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 deferreceipt of 5,960 of these shares, which are being held as deferred stock units with dividend equivalents reinvested in additional stockunits.
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88) Page 123.18
Stock Options: No stock options have been granted since 2006. The remaining unexercised stock option awards were granted withexercise 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-yearvesting period. The fair value of each option was amortized into compensation expense using graded vesting and, as ofDecember 31, 2011, all compensation costs have been recognized. Idaho Power uses IDACORP’s uses original issue and/or treasuryshares to satisfy exercised options. Idaho Power’s stock option transactions are summarized below.
Number Weighted-WeightedAverage Aggregate
of Average Remaining IntrinsicShares Exercise Contractual Value
Price Term (Years) (000s)Outstanding at December 31, 2010 202,634 $ 38.05 1.13 $ 314 Exercised (90,945) 35.54 Expired (102,233) 39.89 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 (in thousands of dollars):
2011 2010Fair value of options vested $ — $ 96Intrinsic value of options exercised 535 1,475Cash received from exercises 3,838 5,394Tax benefits realized from exercises 209 577
Compensation Expense: The following table shows the compensation cost recognized in income and the tax benefits resulting fromthese plans, as well as the amounts allocated to Idaho Power for those costs associated with Idaho Power’s employees (in thousandsof dollars):
2011 2010Compensation cost $ 4,082 $ 3,489Income tax benefit 1,596 1,364 No equity compensation costs have been capitalized.
8. COMMITMENTS Purchase Obligations At December 31, 2011, Idaho Power had the following long-term commitments relating to purchases of energy, capacity, transmissionrights, and fuel (in thousands of dollars):
2012 2013 2014 2015 2016 ThereafterCogeneration and power production $ 165,693 $ 196,261 $ 209,295 $ 214,960 $ 218,220 $ 3,687,810Power and transmission rights 10,772 4,243 3,188 2,210 1,879 4,401
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88) Page 123.19
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 rangingfrom 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 end2014. The majority of the new facilities will be wind resources which will generate on an intermittent basis. During 2011, IdahoPower 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 industryrelated fees (in thousands of dollars):
2012 2013 2014 2015 2016 ThereafterOperating leases $ 2,005 $ 2,875 $ 2,768 $ 2,199 $ 1,203 $ 15,711Equipment, maintenance, and service agreements 38,553 15,271 6,169 4,897 3,700 8,254FERC 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 IERCoowns a one-third interest. This guarantee, which is renewed each December, was $63 million at December 31, 2011, representingIERCo's one-third share of BCC's total reclamation obligation of $189 million. BCC has a reclamation trust fund set asidespecifically for the purpose of paying these reclamation costs. As of December 31, 2011, the value of the reclamation trust fundtotaled $80 million. BCC periodically assesses the adequacy of the reclamation trust fund and its estimate of future reclamationcosts. To ensure that the reclamation trust fund maintains adequate reserves, BCC has the ability to add a per-ton surcharge to coalsales. Starting in 2010, BCC began applying a nominal surcharge to coal sales in order to maintain adequate reserves in thereclamation trust fund. Because of the existence of the fund and the ability to apply a per-ton surcharge, the estimated fair value ofthis guarantee is minimal. Idaho Power enters into financial agreements and power purchase and sale agreements that include indemnification provisionsrelating to various forms of claims or liabilities that may arise from the transactions contemplated by these agreements. Generally, amaximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of theobligation under such indemnification provisions cannot be reasonably estimated. Idaho Power periodically evaluates the likelihoodof incurring costs under such indemnities based on their historical experience and the evaluation of the specific indemnities. As ofDecember 31, 2011, management believes the likelihood is remote that Idaho Power would be required to perform under suchindemnification provisions or otherwise incur any significant losses with respect to such indemnification obligations. Idaho Powerhas 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 othercontingent matters, including the items described in this Note 9. Some of these claims, controversies, disputes, and other contingentmatters involve litigation and regulatory or other contested proceedings. Idaho Power intends to vigorously protect and defend theirinterests and pursue their rights. However, the ultimate resolution and outcome of litigation and regulatory proceedings is inherentlydifficult to determine, particularly where (a) the remedies or penalties sought are indeterminate, (b) the proceedings are in the earlystages or the substantive issues have not been well developed, or (c) the matters involve complex or novel legal theories or a largenumber of parties. In accordance with applicable accounting guidance, Idaho Power establishes an accrual for legal proceedingswhen those matters proceed to a stage where they present loss contingencies that are both probable and reasonably estimable. In such
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88) Page 123.20
cases, there may be a possible exposure to loss in excess of any amounts accrued. Idaho Power monitors those matters fordevelopments 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 thematter will continue to be monitored for any developments that would make the loss contingency both probable and reasonablyestimable. As of the date of this report, Idaho Power's accruals for legal proceedings are not material to their financial statements as awhole; however, future accruals could be material in a given period. Idaho Power's determination is based on currently availableinformation, and estimates presented in financial statements and other financial disclosures involve significant judgment and may besubject to significant uncertainty. As available information changes, the matters for which Idaho Power is able to estimate the lossmay 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 lossthat may result from those matters. Depending on a range of factors, such as the complexity of the facts, the unique nature of thelegal theories, the pace of discovery, the timing of court decisions, and the adverse party's willingness to negotiate towards aresolution, it may be months or years after the filing of a case before Idaho Power may be in a position to estimate the possibleloss 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 ofsuch matters, an adverse outcome in certain of these matters could have a material adverse effect on Idaho Power's financialcondition, results of operations, or cash flows in particular quarterly or annual periods. For matters that affect Idaho Power’soperations, Idaho Power intends to seek, to the extent permissible and appropriate, recovery of incurred costs through the ratemakingprocess. Western Energy Proceedings High prices for electricity, energy shortages, and blackouts in California and in western wholesale markets during 2000 and 2001caused numerous purchasers of electricity in those markets to initiate proceedings seeking refunds or other forms of relief and theFERC to initiate its own investigations. Some of these proceedings remain pending before the FERC or are on appeal to the UnitedStates Court of Appeals for the Ninth Circuit (Ninth Circuit). Except as to the matters described below under “Pacific NorthwestRefund,” Idaho Power and IDACORP Energy (IE) believe that settlement releases they have obtained will restrict potential claimsthat might result from the disposition of the pending Ninth Circuit review petitions and predict that these matters will not have amaterial adverse effect on their consolidated financial positions, results of operations, or cash flows. Pacific Northwest Refund: On July 25, 2001, the FERC issued an order establishing a proceeding to determine whether there mayhave been unjust and unreasonable charges for spot market sales in the Pacific Northwest during the period December 25, 2000through 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 theproceeding 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 considerwhether evidence of market manipulation would have altered the agency's conclusions about refunds and directed the FERC toinclude sales originating in the Pacific Northwest to the California Department of Water Resources (CDWR) in the scope of theproceeding. The Ninth Circuit officially returned the case to the FERC on April 16, 2009. On October 3, 2011, the FERC issued itsorder on remand. The FERC ordered that the record be re-opened to permit parties seeking refunds to submit seller-specific evidencein support of their claims for sales made during the period confined to December 25, 2000 through June 20, 2001. The seller-specificclaims must show that a seller engaged in unlawful market activity with a causal connection to have directly affected the negotiationof the specific contract or contracts to which the seller was a party. Neither claims of general dysfunction in the California marketsnor in the Pacific Northwest market will be sufficient to support claims. While directing a trial-type hearing, the FERC also directedthat the hearings be held in abeyance so that the matter may be presented to a settlement judge. On November 2, 2011, each of theCity of Seattle, Washington, the City of Tacoma, Washington, the Port of Seattle, and the California Parties (consisting of theCalifornia Attorney General and the California Public Utilities Commission) filed requests for rehearing, seeking to expand the scopeof the October 3, 2011 order. The designated settlement judge has met with the parties and convened a settlement conference to
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88) Page 123.21
establish settlement procedures. The FERC's Chief Administrative Law Judge memorialized certain settlement procedures to whichthe 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 thedate of this report, it is difficult to predict the outcome of this matter. Idaho Power does not believe that claims conforming to therequirements of the FERC's October 3, 2011 order have been submitted, and the FERC's order remains subject to rehearing andreconsideration. Idaho Power and IE are unable to predict when and how the FERC will act on the rehearing requests, whichcontracts would be subject to refunds, whether the FERC will order refunds, or how the refunds would be calculated. As a result ofthese factors, as of the date of this report Idaho Power and IE are unable to estimate the reasonably possible loss or range of lossesthat Idaho Power or IE could incur as a result of this matter. However, based on the status of settlement discussions with one party tothe proceedings, for that portion of the matter Idaho Power reserved for a contingent liability an amount immaterial to Idaho Power'sfinancial 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 ElectricCompany (PGE), alleging that PGE had violated the New Source Performance Standards (NSPS) and operating permit requirementsunder the Clean Air Act (CAA) as a result of modifications made to the Boardman coal-fired plant in 1998 and 2004. PGE is theoperator of the Boardman plant, and Idaho Power has a 10 percent ownership interest in the plant. The Notice of Violation states themaximum 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 allegedviolations. It is difficult to meaningfully predict the eventual outcome of this matter given the complexity of the environmentalstatutes and claims cited in the Notice of Violation and the matters at issue, the unspecified nature of the penalty or other remedysought, and the absence of factual information given the early stage of the proceedings. As of the date of this report, based onavailable information and the status of this matter, Idaho Power is unable to estimate the reasonably possible loss or range of lossesthat Idaho Power could incur as a result of this matter. However, PGE, the plant operator, has stated that based on its understandingof 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 holdswater rights for domestic, irrigation, commercial, and other necessary purposes related to project lands and other holdings within thestates of Idaho and Oregon. Idaho Power's water rights for power generation are, to varying degrees, subordinated to future upstreamappropriations 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 flowsof the Snake River. In the late 1970's and early 1980's these reduced flows resulted in a conflict between the exercise of IdahoPower's water rights at certain hydroelectric projects on the Snake River and upstream consumptive diversions. The Swan FallsAgreement, signed by Idaho Power and the State of Idaho on October 25, 1984, resolved the conflict and provided a level ofprotection for Idaho Power's hydropower water rights at specified projects on the Snake River through the establishment of minimumstream flows and an administrative process governing future development of water rights that may affect those minimum streamflows. In 1987, Congress enacted legislation directing the FERC to issue an order approving the Swan Falls settlement together witha finding that the agreement was neither inconsistent with the terms and conditions of Idaho Power's project licenses nor the FederalPower 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 WaterPlan provided a sound comprehensive plan for management of the Snake River watershed. The Swan Falls Agreement alsorecognized, however, that in order to effectively manage the waters of the Snake River basin, a general adjudication to determine thenature, extent, and priority of the rights of all water uses in the basin was necessary. Consistent with that recognition, in 1987 theState of Idaho initiated the Snake River Basin Adjudication (SRBA), and pursuant to the commencement order issued by the SRBA
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88) Page 123.22
court that same year, all claimants to water rights within the basin were required to file water rights claims in the SRBA. Idaho Powerhas filed claims to its water rights and has been actively participating in the SRBA since its commencement. Questions concerningthe effect of the Swan Falls Agreement on Idaho Power's water rights claims, including the nature and extent of the subordination ofIdaho Power's rights to upstream uses, resulted in the filing of litigation in the SRBA in 2007 between Idaho Power and the State ofIdaho. This litigation was resolved by the Framework Reaffirming the Swan Falls Settlement (Framework) signed by Idaho Powerand the State of Idaho on March 25, 2009. In that Framework, the parties acknowledged that the effective management of Idaho'swater resources remains critical to the public interest of the State of Idaho by sustaining economic growth, maintaining reasonableelectric rates, protecting and preserving existing water rights, and protecting water quality and environmental values. The Frameworkfurther provided that the State of Idaho and Idaho Power would cooperate in exploring approaches to resolve issues of mutual concernrelating to the management of Idaho's water resources. Idaho Power continues to work with the State of Idaho and other interestedparties on these issues. One such issue involves the management of the Eastern Snake Plain Aquifer (ESPA), a large underground aquifer in southeasternIdaho that is hydrologically connected to the Snake River. House Concurrent Resolution No. 28, adopted by the Idaho Legislature in2007, directed the Idaho Water Resource Board to pursue the development of a comprehensive management plan for the ESPA, toinclude measures that would enhance aquifer levels, springs, and river flows on the eastern Snake River plain to the benefit of bothagricultural development and hydropower generation. In May of 2007, the Idaho Water Resource Board appointed an advisorycommittee, charged with the responsibility of developing a management plan for the ESPA. Idaho Power was a member of thatcommittee. In January 2009, the Idaho Water Resource Board, based on the committee's recommendations, adopted a ComprehensiveAquifer Management Plan (CAMP) for the ESPA. The Idaho Legislature approved the CAMP that same year. Idaho Power is amember 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 SRBA in seeking to ensure that its water rights are protected and that theoperation of its hydroelectric projects is not adversely impacted. While Idaho Power cannot predict the outcome, Idaho Power doesnot 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, asof the date of this report the company believes that resolution of these matters will not have a material adverse effect on theconsolidated 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 onyears of service and the employee’s final average earnings. Idaho Power’s policy is to fund, with an independent corporate trustee, atleast the minimum required under the Employee Retirement Income Security Act of 1974 (ERISA) but not more than the maximumamount deductible for income tax purposes. In 2011 and 2010 Idaho Power elected to contribute more than the minimum requiredamounts in order to bring the plan to a more funded position, to reduce future required contributions, and to reduce Pension BenefitGuaranty Corporation premiums. The market-related value of assets for the plan is equal to the fair value of the assets. Fair value isdetermined by utilizing publicly quoted market values and independent pricing services depending on the nature of the asset, asreported by the trustee/custodian of the plan. In addition, Idaho Power has a nonqualified, deferred compensation plan for certain senior management employees and directorscalled the Senior Management Security Plan (SMSP). At December 31, 2011 and 2010, approximately $41.2 million and $46.2million, respectively, of life insurance policies and investments in marketable securities, all of which are held by a trustee, weredesignated to satisfy the projected benefit obligation of the plan but do not qualify as plan assets in the actuarial computation of thefunded status.
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88) Page 123.23
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 $ 52,719Service cost 20,478 17,671 1,950 1,541Interest cost 30,322 29,119 3,094 3,004Actuarial loss 55,535 35,909 4,251 5,186Benefits paid (20,830) (19,509) (3,378) (3,324)Benefit obligation at December 31 655,439 569,934 65,043 59,126Change 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 positionconsist 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 comprehensiveincome consist of:
Net loss $ 245,632 $ 161,855 $ 21,799 $ 18,840Prior service cost 1,335 1,855 1,502 1,744Subtotal 246,967 163,710 23,301 20,584Less amount recorded as regulatory asset (246,967) (163,710) — —Net amount recognized in accumulated other comprehensive income $ — $ — $ 23,301 $ 20,584Accumulated benefit obligation $ 549,503 $ 482,448 $ 59,836 $ 54,213
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88) Page 123.24
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 $ 1,541Interest cost 30,322 29,119 3,094 3,004Expected return on assets (32,322) (26,463) — —Amortization of net loss 8,673 7,675 1,293 931Amortization of prior service cost 519 650 242 233Net periodic pension cost 27,670 28,652 6,579 5,709Adjustment to cost recognized due to theeffects of regulation(1) 6,662 (24,104) — —Net periodic benefit cost recognized for
(1) Net periodic benefit costs for the pension plan are recognized based on the authorization of each regulatory jurisdiction Idaho Power operates within. Under IPUCorder, 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 2012, Idaho Power expects to recognize as components of net periodic benefit cost $15.9 million from amortizing amountsrecorded in accumulated other comprehensive income (or as a regulatory asset for the pension plan) as of December 31, 2011, relatingto the pension and SMSP plans. This amount consists of $13.9 million of amortization of net loss and $0.3 million of amortization ofprior service cost for the pension plan, and $1.5 million of amortization of net loss and $0.2 million of amortization of prior servicecost for the SMSP. The following table summarizes the expected future benefit payments of these plans (in thousands of dollars):
2012 2013 2014 2015 2016 2017-2021Pension Plan $ 22,360 $ 24,001 $ 25,684 $ 27,597 $ 29,761 $ 186,450SMSP 3,578 3,707 3,899 4,063 4,084 22,797 As of December 31, 2011, Idaho Power's minimum required contributions to the defined benefit pension plan are estimated to beapproximately $34 million in 2012, $44 million in 2013, $44 million in 2014, $42 million in 2015, and $42 million in 2016. IdahoPower 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 allemployees 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 IdahoPower. Benefits for employees who retire after December 31, 2002 are limited to a fixed amount, which has limited the growth ofIdaho Power’s future obligations under this plan.
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88) Page 123.25
The following table summarizes the changes in benefit obligation and plan assets (in thousands of dollars): 2011 2010Change in accumulated benefit obligation: Benefit obligation at January 1 $ 68,048 $ 62,647Service cost 1,323 1,276Interest cost 3,434 3,578Actuarial loss (2,850) 3,291Benefits paid(1) (2,968) (3,373)Plan amendments (318) 629Benefit obligation at December 31 66,669 68,048Change in plan assets: Fair value of plan assets at January 1 33,176 30,892Actual return on plan assets 1,065 3,381Employer contributions 628 2,276Benefits paid(1) (2,968) (3,373)Fair value of plan assets at December 31 31,901 33,176Funded 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 subsidyreceipts for 2011 and 2010, respectively. Amounts recognized in accumulated other comprehensive income consist of the following (in thousands of dollars): 2011 2010Net loss $ 14,112 $ 15,963Prior service credit (323) (426)Transition obligation 2,040 4,080Subtotal 15,829 19,617Less 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 2010Service 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
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88) Page 123.26
in accumulated other comprehensive income as of December 31, 2011 relating to the postretirement benefit plan. This amountconsists 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 December2003 and established a prescription drug benefit, as well as a federal subsidy to sponsors of retiree health care benefit plans thatprovide 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 Dsubsidy receipts (in thousands of dollars): 2012 2013 2014 2015 2016 2017-2021Expected benefit payments $ 4,176 $ 4,261 $ 4,415 $ 4,543 $ 4,620 $ 23,849Expected 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 allIdaho Power-sponsored pension and postretirement benefits plans:
(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 increasecomponent 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 IdahoPower-sponsored pension and postretirement benefit plans:
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 was7.0 percent and 7.5 percent in 2011 and 2010, respectively. The assumed health care cost trend rate for 2011 is assumed to decreasegradually to 4.9 percent by 2083. The assumed dental cost trend rate used to measure the expected cost of dental benefits covered bythe plan was 5.0 percent in both 2011 and 2010. The assumed dental cost trend rate for 2011 is assumed to decrease gradually to 4.9percent by 2083. A one percentage point change in the assumed health care cost trend rate would have the following effects at
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88) Page 123.27
December 31, 2011 (in thousands of dollars):
One-Percentage-Point Increase DecreaseEffect 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 byasset class is set forth below.
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 andrealized and unrealized gain or loss in market price) consistent with prudent parameters of risk and the liability profile of theportfolio. Emphasis is placed on preservation and growth of capital along with adequacy of cash flow sufficient to fund current andfuture 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 growthinstruments (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, privateequity funds, and cash and cash equivalents. With the exception of real estate holdings and private equity, investments must bereadily 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 isthe historical risk premium each asset class has delivered versus the return on 10-year U.S. Treasury Notes. This historical riskpremium is then added to the current yield on 10-year U.S. Treasury Notes, and the result provides a reasonable prediction of futureinvestment performance. Additional analysis is performed to measure the expected range of returns, as well as worst-case andbest-case scenarios. Based on the current low interest rate environment, current rate-of-return expectations are lower than the nominalreturns generated over the past 20 years when interest rates were generally much higher.
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88) Page 123.28
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 timeperiods. 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 followinghierarchy:
• 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 levelinput (Level 3 being the lowest) that is significant to the fair value measurement of the security. The following table sets forth bylevel 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
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88) Page 123.29
Total pension assets $ 184,533 $ 160,469 $ 52,001 $ 397,003 Postretirement assets(2) $ — $ 33,176 $ — $ 33,176 (1) 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 significantunobservable inputs (Level 3):
PrivateEquity
RealEstate Total
Beginning balance - January 1, 2010 $ 20,202 $ 20,783 $ 40,985Realized losses — (47) (47)Unrealized gains 1,284 2,211 3,495Purchases, issuances, and settlements, net 8,446 (878) 7,568Ending balance - December 31, 2010 29,932 22,069 52,001Realized gains — 598 598Realized losses (133) — (133)Unrealized gains 1,425 1,854 3,279Purchases, 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 andother contractual claims to commodity holdings. The U.S. government and agency bonds, as well as the corporate bonds, are nottraded on an exchange and are valued utilizing quoted prices for similar assets or liabilities in active markets. The commingled fundsthemselves are not publicly traded, and therefore no publicly quoted market price is readily available. The value of these investmentsis calculated by the custodian for the fund company on a monthly basis, and is based on market prices of the assets held by thecommingled fund 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 propertyinterests held in these real estate funds are not frequently traded, establishing the market value of the property interests held by thefund, and the resulting unit value of fund shareholders, is based on unobservable inputs including property appraisals by the fundcompany, property appraisals by independent appraisal firms, analysis of the replacement cost of the property, discounted cash flowsgenerated 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 theinformation provided. Level 3 Private Market Investments: Private market investments represent two categories: fund of hedge funds and venture capitalfunds. These funds are valued by the fund company based on the estimated fair value of the underlying fund holdings divided by thefund shares outstanding. Some hedge fund strategies utilize securities with readily available market prices, while others utilize lessliquid investment vehicles that are valued based on unobservable inputs including cost, operating results, recent funding activity, orcomparisons with similar investment vehicles. Venture capital fund investments are valued by the fund company based on estimatedfair value of the underlying fund holdings divided by the fund shares outstanding. Some venture capital investments have progressedto the point that they have readily available exchange-based market valuations. Early stage venture investments are valued based onunobservable inputs including cost, operating results, discounted cash flows, the price of recent funding events, or pending offersfrom other viable entities. These private market investments furnish annual audited financial statements that are also used to further
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88) Page 123.30
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 coverssubstantially all employees (the Employee Savings Plan). Idaho Power matches specified percentages of employee contributions tothe 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 employmentbut before retirement. These benefits include salary continuation, health care and life insurance for those employees found to bedisabled under Idaho Power’s disability plans, and health care for surviving spouses and dependents. Idaho Power accrues a liabilityfor such benefits. The post employment benefit amounts included in other deferred credits on Idaho Power’s consolidated balancesheet 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 apercent of average depreciable balance, and accumulated provision for depreciation for the years 2011 and 2010 (in thousands ofdollars):
2011 2010 Balance Avg Rate Balance Avg Rate
Production $ 1,832,287 2.22% $ 1,792,305 2.23 %Transmission 871,784 2.06% 855,202 2.03 %Distribution 1,434,925 3.12% 1,377,239 3.13 %General and Other 327,877 7.32% 307,308 7.41 %Total in 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 operatingagreements, each participating utility is responsible for financing its share of construction, operating, and leasing costs. IdahoPower’s proportionate share of related fuel expenses as well as direct operation and maintenance expenses applicable to the projects isincluded in the Consolidated Statements of Income. These facilities, and the extent of Idaho Power’s participation, were as follows atDecember 31, 2011 (in thousands of dollars):
Name of Plant Location Utility Plant Construction Accumulated Ownership MW(1)
in Service Work in Provision for % Progress Depreciation Jim Bridger Units1-4
Rock Springs,WY
$539,294 $8,334 $276,375 33 771
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88) Page 123.31
Boardman Boardman, OR 79,714 940 53,843 10 64Valmy Units 1 and2 Winnemucca, NV 350,582 7,352 202,811 50 284
(1) 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 venturewere $65 million and $76 million in 2011 and 2010, respectively. Idaho Power has contracts to purchase the energy from four PURPA qualified facilities that are 50 percent owned by Ida-West. IdahoPower’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 andequipment be recognized as a liability at fair value when incurred and when a reasonable estimate of the fair value of the liability canbe made. Under the guidance, when a liability is initially recorded, the entity increases the carrying amount of the related long-livedasset to reflect the future retirement cost. Over time, the liability is accreted to its present value and paid, and the capitalized cost isdepreciated over the useful life of the related asset. If, at the end of the asset’s life, the recorded liability differs from the actualobligations paid, a gain or loss would be recognized. As a rate-regulated entity, Idaho Power records regulatory assets or liabilitiesinstead of accretion, depreciation, and gains or losses, as approved by Order No. 29414 from the IPUC. The regulatory assetsrecorded under this order do not earn a return on investment. Idaho Power’s recorded AROs relate to the removal of polychlorinated biphenyls-contaminated equipment at its distribution facilitiesand the reclamation and removal costs at its jointly owned coal-fired generation facilities. In 2011, changes in estimates at itsdistribution facilities and at the coal-fired generation facilities resulted in a net increase of $3.9 million in the recorded AROs. Theprimary 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 associatedliabilities can be estimated, ARO amounts related to the Boardman decommissioning are being recognized in the consolidatedfinancial statements. Idaho Power also has additional AROs associated with its transmission system, hydroelectric facilities, and jointly owned coal-firedgeneration facilities; however, due to the indeterminate removal date, the fair value of the associated liabilities currently cannot beestimated 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 regulatoryliabilities 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 2010Balance at beginning of year $ 16,952 $ 16,240Accretion expense 936 819Revisions in estimated cash flows 3,930 929Liability settled (451) (1,036)Balance at end of year $ 21,367 $ 16,952
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88) Page 123.32
13. INVESTMENTS IN DEBT AND EQUITY SECURITIES The table below summarizes Idaho Power’s investments as of December 31 (in thousands of dollars).
Investments in available-for-sale securities are reported at fair value, using either specific identification or average cost to determinethe cost for computing gains or losses. Any unrealized gains or losses on available-for-sale securities are included in othercomprehensive income. The table below summarizes investments in equity securities (in thousands of dollars)
December 31, 2011 December 31, 2010Gross Unrealized Gross Unrealized Fair Gross Unrealized Gross Unrealized Fair
Gain Loss Value Gain Loss ValueAvailable-for-sale Securities $ 4,220 $ 1 $ 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 adecline in market value that is considered other-than-temporary. At December 31, 2011, one security was in an immaterial unrealizedloss position. No other-than-temporary impairment was recognized for this security due to the limited severity and duration of theunrealized loss position. At December 31, 2010, no securities were in an unrealized loss position. There were no sales ofavailable-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 heavilyinfluenced by supply and demand. Market risk may also be influenced by market participants’ nonperformance of their contractualobligations 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
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88) Page 123.33
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 accountingare recorded at fair value on the balance sheet. Because of Idaho Power's PCA mechanisms, unrealized gains and losses associatedwith the changes in fair value of these derivative instruments are recorded as regulatory assets or liabilities. With the exception offorward contracts for the purchase of natural gas for use at Idaho Power’s natural gas generation facilities, Idaho Power’s physicalforward 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 andsales, though none of these instruments have been designated as cash flow hedges under derivative accounting guidance. IdahoPower offsets fair value amounts recognized on its balance sheet related to derivative instruments executed with the samecounterparty 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 onthe balance sheets at December 31, 2011 and 2010 (in thousands of dollars).
Location Value Location ValueDecember 31, 2011Current:
Financial swaps Other current assets $ 4,361 Other current assets $ 1,036Financial swaps Other current liabilities 1,526 Other current liabilities 4,755Forward contracts Other current assets 70 Other current liabilities 1,370
Long-term: Financial swaps Other assets 359 Other liabilities 108
Total $ 6,316 $ 7,269December 31, 2010Current:
Financial swaps Other current assets $ 930 Other current assets $ 356Financial swaps Other current liabilities 2,440 Other current liabilities 4,172Forward contracts Other current liabilities 508
Long-term: Financial swaps Other liabilities 100 Other liabilities 138Total $ 3,470 $ 5,174
The table below presents the gains and losses on derivatives not designated as hedging instruments for the year endedDecember 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 2010Financial 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 -
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88) Page 123.34
Forward contracts Fuel Expense - (721)(1) 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 powerdepending on the forecasted position being economically hedged by the derivative contract. Settlement gains and losses on bothfinancial and physical contracts for natural gas are reflected in fuel expense. Settlement gains and losses on diesel derivatives arerecorded in other operations and maintenance expense. See Note 15 for additional information concerning the determination of fairvalue 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 forthin the table below.
December 31,Commodity Units 2011 2010
Electricity purchases MWh 225,600 347,400Electricity sales MWh 1,298,420 338,200Natural gas purchases MMBtu 7,928,311 647,900Natural gas sales MMBtu 352,129 —Diesel purchases Gallons 1,273,997 1,061,969 Credit Risk At December 31, 2011, Idaho Power did not have material credit exposure from financial instruments, including derivatives. IdahoPower monitors credit risk exposure through reviews of counterparty credit quality, corporate-wide counterparty credit exposure, andcorporate-wide counterparty concentration levels. Idaho Power manages these risks by establishing appropriate credit andconcentration limits on transactions with counterparties and requiring contractual guarantees, cash deposits, or letters of credit fromcounterparties or their affiliates, as deemed necessary. Idaho Power’s physical power contracts are under Western Systems PowerPool agreements, physical gas contracts are under North American Energy Standards Board contracts, and financial transactions areunder International Swaps and Derivatives Association, Inc. contracts. These contracts all contain adequate assurance clausesrequiring collateralization 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 aninvestment grade credit rating from Moody's Investors Service and Standard & Poor's Ratings Services. If Idaho Power's unsecureddebt were to fall below investment grade, it would be in violation of these provisions, and the counterparties to the derivativeinstruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivativeinstruments in net liability positions. The aggregate fair value of all derivative instruments with credit-risk-related contingent featuresthat were in a liability position at December 31, 2011, was $7.0 million. Idaho Power posted no collateral related to this amount. Ifthe credit-risk-related contingent features underlying these agreements were triggered on December 31, 2011, Idaho Power wouldhave 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 tothe valuation technique. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets orliabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). If the inputs used to measure the financial instrumentsfall within different levels of the hierarchy, the categorization is based on the lowest level input that is significant to the fair value
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88) Page 123.35
measurement of the instrument. Financial assets and liabilities recorded on the consolidated balance sheet are categorized based on the inputs to the valuationtechniques as follows:
• Level 1: Financial assets and liabilities whose values are based on unadjusted quoted prices for identical assets orliabilities 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; andd) 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, observablemarket 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 ownassumptions 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 onthe Intercontinental Exchange with quoted prices in an active market. Natural gas and diesel derivative valuations are performedusing New York Mercantile Exchange (NYMEX) pricing, adjusted for location basis, which are also quoted under NYMEX. Tradingsecurities 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 equityfunds 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 ofDecember 31, 2011 and 2010 (in thousands of dollars). Idaho Power’s assessment of the significance of a particular input to the fairvalue measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within thefair value hierarchy. There were no transfers between levels for the years presented.
Quoted Prices in Significant SignificantActive Markets Other Unobservable
The table below presents the carrying value and estimated fair value of financial instruments that are not reported at fair value, as ofDecember 31, 2011 and 2010, using available market information and appropriate valuation methodologies. The use of differentmarket assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts. Cash and cashequivalents, deposits, customer and other receivables, notes payable, accounts payable, interest accrued, and taxes accrued arereported at their carrying value as these are a reasonable estimate of their fair value. The estimated fair values for long-term debt arebased 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)
16. RELATED PARTY TRANSACTIONS IDACORP: Idaho Power performs corporate functions such as financial, legal, and management services for IDACORP and itssubsidiaries. Idaho Power charges IDACORP for the costs of these services based on service agreements and other specificallyidentified costs. For these services Idaho Power billed IDACORP $0.8 million in 2011and 2010. Ida-West: Idaho Power purchases all of the power generated by four of Ida-West’s hydroelectric projects located in Idaho. IdahoPower paid $9 million and $8 million to Ida-West in 2011 and 2010, respectively.
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88) Page 123.37
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
Idaho Power Company X04/13/2012
2011/Q4
Line No.
1. Report in columns (b),(c),(d) and (e) the amounts of accumulated other comprehensive income items, on a net-of-tax basis, where appropriate. 2. Report in columns (f) and (g) the amounts of other categories of other cash flow hedges. 3. For each category of hedges that have been accounted for as "fair value hedges", report the accounts affected and the related amounts in a footnote.4. Report data on a year-to-date basis.
OtherAdjustments
(e)
Foreign CurrencyHedges
(d)
Minimum PensionLiability adjustment
(net amount)(c)
Unrealized Gains andLosses on Available-for-Sale Securities
(b)
Item
(a)
1,820,172 ( 10,086,835)Balance of Account 219 at Beginning ofPreceding Year
1
708,772Preceding Qtr/Yr to Date Reclassificationsfrom Acct 219 to Net Income
2
1,149,129 ( 3,158,753)Preceding Quarter/Year to Date Changes inFair Value
3
1,149,129 ( 2,449,981)Total (lines 2 and 3) 4
2,969,301 ( 12,536,816)Balance of Account 219 at End of PrecedingQuarter/Year
5
2,969,301 ( 12,536,816)Balance of Account 219 at Beginning ofCurrent Year
6
934,902Current Qtr/Yr to Date Reclassificationsfrom Acct 219 to Net Income
7
( 400,010) ( 2,589,429)Current Quarter/Year to Date Changes inFair Value
8
( 400,010) ( 1,654,527)Total (lines 7 and 8) 9
2,569,291 ( 14,191,343)Balance of Account 219 at End of CurrentQuarter/Year
10
FERC FORM NO. 1 (NEW 06-02) Page 122a
Other Cash FlowHedges[Specify]
(g)
Other Cash FlowHedges
Interest Rate Swaps
(f)
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS
Idaho Power Company X04/13/2012
2011/Q4
Line No. (b)(a)
Classification Electric(c)
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Total Company for the Current Year/Quarter Ended
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 incolumn (h) common function.
Utility Plant 1
In Service 2
4,467,327,227 4,467,327,227Plant in Service (Classified) 3
Property Under Capital Leases 4
Plant Purchased or Sold 5
Completed Construction not Classified 6
Experimental Plant Unclassified 7
4,467,327,227 4,467,327,227Total (3 thru 7) 8
Leased to Others 9
6,974,407 6,974,407Held for Future Use 10
591,474,855 591,474,855Construction Work in Progress 11
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
Account Balance Additions
(c)(b)(a)Beginning of Year
1. Report below the original cost of electric plant in service according to the prescribed accounts.2. In addition to Account 101, Electric Plant in Service (Classified), this page and the next include Account 102, Electric Plant Purchased or Sold; Account103, 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 andreductions 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 includedin column (c) are entries for reversals of tentative distributions of prior year reported in column (b). Likewise, if the respondent has a significant amount ofplant retirements which have not been classified to primary accounts at the end of the year, include in column (d) a tentative distribution of suchretirements, on an estimated basis, with appropriate contra entry to the account for accumulated depreciation provision. Include also in column (d)
1. INTANGIBLE PLANT 1(301) Organization 5,703 2(302) Franchises and Consents 23,165,537 5,855 3(303) Miscellaneous Intangible Plant 32,983,581 6,847,330 4TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4) 56,154,821 6,853,185 52. PRODUCTION PLANT 6A. Steam Production Plant 7(310) Land and Land Rights 1,604,032 111,368 8(311) Structures and Improvements 139,165,207 5,928,618 9(312) Boiler Plant Equipment 549,065,614 29,667,912 10(313) Engines and Engine-Driven Generators 11(314) Turbogenerator Units 148,799,889 3,873,534 12(315) Accessory Electric Equipment 59,886,756 613,770 13(316) Misc. Power Plant Equipment 15,486,549 151,084 14(317) Asset Retirement Costs for Steam Production 3,515,987 4,489,239 15TOTAL Steam Production Plant (Enter Total of lines 8 thru 15) 917,524,034 44,835,525 16B. Nuclear Production Plant 17(320) Land and Land Rights 18(321) Structures and Improvements 19(322) Reactor Plant Equipment 20(323) Turbogenerator Units 21(324) Accessory Electric Equipment 22(325) Misc. Power Plant Equipment 23(326) Asset Retirement Costs for Nuclear Production 24TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24) 25C. Hydraulic Production Plant 26(330) Land and Land Rights 30,109,969 22,901 27(331) Structures and Improvements 155,425,385 829,675 28(332) Reservoirs, Dams, and Waterways 250,750,878 2,241,359 29(333) Water Wheels, Turbines, and Generators 194,277,265 3,939,061 30(334) Accessory Electric Equipment 43,762,085 2,219,556 31(335) Misc. Power PLant Equipment 18,088,684 1,048,665 32(336) Roads, Railroads, and Bridges 7,521,793 590,698 33(337) Asset Retirement Costs for Hydraulic Production 34TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34) 699,936,059 10,891,915 35D. Other Production Plant 36(340) Land and Land Rights 2,599,695 90,311 37(341) Structures and Improvements 7,169,595 38(342) Fuel Holders, Products, and Accessories 4,445,866 39(343) Prime Movers 100,801,636 773,156 40(344) Generators 31,681,900 41(345) Accessory Electric Equipment 25,027,598 49,984 42(346) Misc. Power Plant Equipment 3,118,644 19,793 43(347) Asset Retirement Costs for Other Production 44TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44) 174,844,934 933,244 45TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45) 1,792,305,027 56,660,684 46
Page 204FERC FORM NO. 1 (REV. 12-05)
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued)
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd ofIdaho Power Company X
04/13/20122011/Q4
Line No.
Account Balance Additions
(c)(b)(a)Beginning of Year
3. TRANSMISSION PLANT 47(350) Land and Land Rights 34,253,938 877,421 48(352) Structures and Improvements 55,667,437 2,493,112 49(353) Station Equipment 349,451,391 8,846,585 50(354) Towers and Fixtures 144,723,540 2,767,876 51(355) Poles and Fixtures 101,621,493 7,282,014 52(356) Overhead Conductors and Devices 169,165,595 4,102,430 53(357) Underground Conduit 54(358) Underground Conductors and Devices 55(359) Roads and Trails 318,351 94,995 56(359.1) Asset Retirement Costs for Transmission Plant 57TOTAL Transmission Plant (Enter Total of lines 48 thru 57) 855,201,745 26,464,433 584. DISTRIBUTION PLANT 59(360) Land and Land Rights 4,745,189 683,210 60(361) Structures and Improvements 29,485,862 2,881,866 61(362) Station Equipment 182,593,962 12,192,049 62(363) Storage Battery Equipment 63(364) Poles, Towers, and Fixtures 225,059,905 5,449,895 64(365) Overhead Conductors and Devices 120,135,601 3,972,582 65(366) Underground Conduit 48,215,714 -143,831 66(367) Underground Conductors and Devices 191,494,213 6,029,113 67(368) Line Transformers 414,782,133 19,583,109 68(369) Services 57,319,909 149,486 69(370) Meters 95,697,525 17,507,437 70(371) Installations on Customer Premises 2,750,899 84,107 71(372) Leased Property on Customer Premises 72(373) Street Lighting and Signal Systems 4,370,514 58,890 73(374) Asset Retirement Costs for Distribution Plant 587,980 55,659 74TOTAL Distribution Plant (Enter Total of lines 60 thru 74) 1,377,239,406 68,503,572 755. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT 76(380) Land and Land Rights 77(381) Structures and Improvements 78(382) Computer Hardware 79(383) Computer Software 80(384) Communication Equipment 81(385) Miscellaneous Regional Transmission and Market Operation Plant 82(386) Asset Retirement Costs for Regional Transmission and Market Oper 83TOTAL Transmission and Market Operation Plant (Total lines 77 thru 83) 846. GENERAL PLANT 85(389) Land and Land Rights 11,123,762 5,004,896 86(390) Structures and Improvements 77,278,614 7,882,958 87(391) Office Furniture and Equipment 39,375,541 5,791,888 88(392) Transportation Equipment 60,957,305 1,751,643 89(393) Stores Equipment 1,459,340 205,305 90(394) Tools, Shop and Garage Equipment 5,567,522 682,923 91(395) Laboratory Equipment 11,946,695 669,571 92(396) Power Operated Equipment 9,922,182 904,660 93(397) Communication Equipment 29,214,145 3,918,370 94(398) Miscellaneous Equipment 4,762,597 759,121 95SUBTOTAL (Enter Total of lines 86 thru 95) 251,607,703 27,571,335 96(399) Other Tangible Property 97(399.1) Asset Retirement Costs for General Plant 98TOTAL General Plant (Enter Total of lines 96, 97 and 98) 251,607,703 27,571,335 99TOTAL (Accounts 101 and 106) 4,332,508,702 186,053,209 100(102) Electric Plant Purchased (See Instr. 8) 101(Less) (102) Electric Plant Sold (See Instr. 8) 102(103) Experimental Plant Unclassified 103TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103) 4,332,508,702 186,053,209 104
Page 206FERC FORM NO. 1 (REV. 12-05)
(f)
Transfers Balance atEnd of Year
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd ofIdaho Power Company X
04/13/20122011/Q4
Line No.(g)
Adjustments
(e)
Retirements
(d)
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 theseamounts. Careful observance of the above instructions and the texts of Accounts 101 and 106 will avoid serious omissions of the reported amount ofrespondent’s 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 accountclassifications arising from distribution of amounts initially recorded in Account 102, include in column (e) the amounts with respect to accumulatedprovision for depreciation, acquisition adjustments, etc., and show in column (f) only the offset to the debits or credits distributed in column (f) to primaryaccount 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 showingsubaccount 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
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of
ELECTRIC PLANT HELD FOR FUTURE USE (Account 105)
Idaho Power Company X04/13/2012
2011/Q4
Line Description and Location Date Originally Included Balance atEnd of Year
(c)(b)(a)Of Property in This Account
Date Expected to be usedin Utility Service
(d)No.
1. Report separately each property held for future use at end of the year having an original cost of $250,000 or more. Group other items of property heldfor 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 toother required information, the date that utility use of such property was discontinued, and the date the original cost was transferred to Account 105.
Land and Rights: 112/31/82Boise Operations Center 655,550 2
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
Description of Project Construction work in progress -
(b)(a)Electric (Account 107)
1. Report below descriptions and balances at end of year of projects in process of construction (107)2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (seeAccount 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.
323,852,696LANGLEY GULCH POWER PLANT CONS 1
53,428,991ROLLUP RELIC COST BROWNLEE 2
36,542,791ROLLUP RELIC COST HELLS CANYON 3
26,168,054BOARDMAN - HEMINGWAY 500 KV LI 4
17,858,788GATEWAY WEST 500KV LINE 5
16,825,380ROLLUP RELIC COST OXBOW 6
13,681,208HELLS CANYON RELICENSING OUTSI 7
6,478,737CIAC LIABILITY RECLASS 8
6,447,317LANGLEY GULCH 138/230 KV LINE 9
6,289,342WQ - ONGOING HELLS CANYON RELI 10
6,060,641LANGLEY GULCH SWITCHYARD 11
4,670,643BRIDGER 2008C123LP U1 TURBINE 12
4,342,017RIVER ENG.-HELLS CANYON CONTIN 13
4,129,634LANGLEY GULCH PP CONST: WATER 14
3,368,213LANGLEY GULCH PP CONST: GAS PI 15
2,861,799CHQ MASTER PLAN - NEW PRIMARY 16
2,807,084LANGLEY GULCH 230 KV DOUBLE CI 17
2,557,141MPSN0802 INCREASE CAPACITY OF 18
2,536,812FISHERIES-HCC RELICENSING REDB 19
2,527,557ROLLUP RELIC COST SWAN FALLS 20
2,390,747HCC RELICENSING, FISH2004 INST 21
2,118,048FISHERIES-HCC RELICENSING ANAD 22
1,957,851VALMY 98278700 V1BOTTOM ASH PU 23
1,803,202BOBN REPLACE C233 AND C234 SER 24
1,780,523B2H TLINE CONSTRUCTION COSTS 25
1,754,771AERATION FOR UNIT #5 TO IMPROV 26
1,527,841LEGAL DEPT. LABOR FOR RELICENS 27
1,515,520BRIDGER UNDISTRIBUTED WORK ORD 28
1,480,417REL-HCC OREGON REAUTHORIZATION 29
1,399,168VALMY UNDISTRIBUTED WORK ORDER 30
1,339,913SWAN FALLS RELICENSING 31
1,201,965HC LOCAL SERVICE UPGRADE 32
1,143,001342 COST CENTER DELIVERY CAPIT 33
1,120,680314 DESIGN TEAMS - CAPITAL - C 34
1,089,301PAYROLL & IBNR ACCRUAL 35
24,417,062OTHER MINOR PROJECTS UNDER $1,000,000 36
37
38
39
40
41
42
FERC FORM NO. 1 (ED. 12-87) Page 216
43 TOTAL 591,474,855
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT (Account 108)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
Item Total(c)(b)(a) (d)
Section A. Balances and Changes During Year
(c+d+e)Electric Plant in
ServiceElectric Plant Held
for Future UseElectric Plant
Leased to Others(e)
1. Explain in a footnote any important adjustments during year.2. Explain in a footnote any difference between the amount for book cost of plant retired, Line 11, column (c), and that reported forelectric 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 whensuch plant is removed from service. If the respondent has a significant amount of plant retired at year end which has not been recordedand/or classified to the various reserve functional classifications, make preliminary closing entries to tentatively functionalize the bookcost of the plant retired. In addition, include all costs included in retirement work in progress at year end in the appropriate functionalclassifications.4. Show separately interest credits under a sinking fund or similar method of depreciation accounting.
Balance Beginning of Year 1 1,750,735,947 1,750,735,947
TOTAL (Enter Total of lines 20 thru 28) 29 1,818,635,521 1,818,635,521
Page 219FERC FORM NO. 1 (REV. 12-05)
Schedule Page: 219 Line No.: 14 Column: bRelocation 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
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87) Page 450.1
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of
INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1)
Idaho Power Company X04/13/2012 2011/Q4
Line No.
Description of Investment Date Acquired(c)(b)(a)
Amount of Investment atBeginning of Year
Date Of Maturity
(d)
1. Report below investments in Accounts 123.1, investments in Subsidiary Companies.2. Provide a subheading for each company and List there under the information called for below. Sub - TOTAL by company and give a TOTAL incolumns (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 tocurrent settlement. With respect to each advance show whether the advance is a note or open account. List each note giving date of issuance, maturitydate, 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 forAccount 418.1.
Idaho Energy Resources Company 1
50002/01/74Common Stock 2
2,462,594Capital contributions 3
70,098,680Equity in earnings 4
5
72,561,774Subtotal Idaho Energy Resources Company 6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
FERC FORM NO. 1 (ED. 12-89) Page 224
42 Total Cost of Account 123.1 $ TOTAL 72,561,774 2,463,094
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of
INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1) (Continued)
Idaho Power Company X04/13/2012 2011/Q4
Line No.
Equity in Subsidiary Earnings of Year
Revenues for Year Amount of Investment atEnd of Year
Gain or Loss from InvestmentDisposed of
(e) (f) (g) (h)
4. For any securities, notes, or accounts that were pledged designate such securities, notes, or accounts in a footnote, and state the name of pledgeeand purpose of the pledge.5. If Commission approval was required for any advance made or security acquired, designate such fact in a footnote and give name of Commission,date of authorization, and case or docket number.6. Report column (f) interest and dividend revenues form investments, including such revenues form securities disposed of during the year.7. In column (h) report for each investment disposed of during the year, the gain or loss represented by the difference between cost of the investment (orthe other amount at which carried in the books of account if difference from cost) and the selling price thereof, not including interest adjustment includiblein column (f).8. Report on Line 42, column (a) the TOTAL cost of Account 123.1
1
500 2
2,462,594 3
76,066,425 5,967,745 4
5
78,529,519 5,967,745 6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
FERC FORM NO. 1 (ED. 12-89) Page 225
42 5,967,745 78,529,519
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of
MATERIALS AND SUPPLIES
Idaho Power Company X04/13/2012 2011/Q4
Line No.
Account Balance Balance
(c)(b)(a)
Department orDepartments which
(d)
Beginning of Year End of YearUse Material
1. For Account 154, report the amount of plant materials and operating supplies under the primary functional classifications as indicated in column (a);estimates of amounts by function are acceptable. In column (d), designate the department or departments which use the class of material.2. Give an explanation of important inventory adjustments during the year (in a footnote) showing general classes of material and supplies and thevarious accounts (operating expenses, clearing accounts, plant, etc.) affected debited or credited. Show separately debit or credits to stores expenseclearing, if applicable.
27,546,983 Electric 47,865,097 1 Fuel Stock (Account 151)
2 Fuel Stock Expenses Undistributed (Account 152)
3 Residuals and Extracted Products (Account 153)
4 Plant Materials and Operating Supplies (Account 154)
5 Assigned to - Construction (Estimated)
6 Assigned to - Operations and Maintenance
14,416,312 14,808,824 7 Production Plant (Estimated)
13,541,576 13,087,873 9 Distribution Plant (Estimated)
10 Regional Transmission and Market Operation Plant(Estimated)
897,634 1,201,188 11 Assigned to - Other (provide details in footnote)
42,221,176 Electric 42,015,731 12 TOTAL Account 154 (Enter Total of lines 5 thru 11)
13 Merchandise (Account 155)
14 Other Materials and Supplies (Account 156)
15 Nuclear Materials Held for Sale (Account 157) (Notapplic to Gas Util)
3,379,745 Electric 4,474,719 16 Stores Expense Undistributed (Account 163)
17
18
19
73,147,904 94,355,547 20 TOTAL Materials and Supplies (Per Balance Sheet)
Page 227FERC FORM NO. 1 (REV. 12-05)
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
Transmission Service and Generation Interconnection Study Costs
Idaho Power Company X04/13/2012
2011/Q4
Line No. Description
Costs Incurred During
(b)(a)Period Account Charged
(c)
ReimbursementsReceived During
(d)
Account CreditedWith Reimbursement
(e)
1. Report the particulars (details) called for concerning the costs incurred and the reimbursements received for performing transmission service andgenerator 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.
the Period
Transmission Studies 1
1,480RLE TRANS SIS 74668832 186623 17,936 186623 2
4,610ROGERSON FLATS GI 322 186623 ( 786) 186623 37
JACK RANCH WIND GI 323 186623 5,000 186623 38
JACK RANCH WIND GI 324 186623 10,000 186623 39
16,644SALMON CREEK GI 325 186623 ( 30,000) 186623 40
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
Transmission Service and Generation Interconnection Study Costs
Idaho Power Company X04/13/2012
2011/Q4
Line No. Description
Costs Incurred During
(b)(a)Period Account Charged
(c)
ReimbursementsReceived During
(d)
Account CreditedWith Reimbursement
(e)the Period
(continued)
Transmission Studies 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Generation Studies 21
15,832JACK RANCH WIND GI 327 186623 ( 20,584) 186623 22
17,256TUMBLE WEED 34.5 GI 332 186623 186623 23
BENNETT CREEK SOLAR GI 333 186623 231 186623 24
23,839HIGH MESA WIND GI 334 186623 ( 68,201) 186623 25
SLATERS FLAT GI 335 186623 530 186623 26
6,621TWO PONDS GI 336 186623 82,373 186623 27
RYEGRASS WINDFARM GI 337 186623 ( 1,077) 186623 28
MAINLINE WINDFARM GI 338 186623 ( 1,078) 186623 29
HAMMETT HILL WINDFARM GI 339 186623 ( 1,078) 186623 30
DESERT MEADOW WINDFARM GI 340 186623 ( 1,078) 186623 31
COLD SPRINGS WINDFARM GI 341 186623 ( 1,078) 186623 32
2,763BEAR CREEK WIND GI 343 186623 2,496 186623 33
13,346DYNAMIS LANDFILL GI 344 186623 ( 21,667) 186623 34
7,182MURPHY FLATS GI 345 186623 16,310 186623 35
9,714MURPHY FLAT WIND GI 346 186623 ( 99,714) 186623 36
5,533AG POWER GI 348 186623 10,023 186623 37
22,237NOTCH BUTTE GI 349 186623 186623 38
DEEP CREEK GI 350 186623 663 186623 39
28,929RAINBOW WEST GI 352 186623 ( 59,212) 186623 40
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.1
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
Transmission Service and Generation Interconnection Study Costs
Idaho Power Company X04/13/2012
2011/Q4
Line No. Description
Costs Incurred During
(b)(a)Period Account Charged
(c)
ReimbursementsReceived During
(d)
Account CreditedWith Reimbursement
(e)the Period
(continued)
Transmission Studies 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Generation Studies 21
RAINBOW RANCH GI 353 186623 573 186623 22
9,716MALAD STATION GI 354 186623 ( 9,930) 186623 23
TRADE DOLLAR MINE GI 355 186623 80 186623 24
2,303SALMON FALLS WIND GI 357 186623 ( 101,177) 186623 25
1,656MURPHY FLATS GI 358 186623 ( 6,457) 186623 26
14,342NOTCHBUTTE GI 359 186623 ( 31,000) 186623 27
FARGO DROP GI 360 186623 ( 88) 186623 28
553AG ENERGY GI 361 186623 ( 553) 186623 29
5,048COLEMAN HYDRO GI 362 186623 ( 18,975) 186623 30
352EIGHTMILE HYDRO GI 366 186623 ( 352) 186623 31
7,151CLARK CANYON HYDRO GI 367 186623 ( 7,151) 186623 32
2,661U3 HYDRO GI 368 186623 ( 2,661) 186623 33
2,228GRAND VIEW SOLAR TWO GI 369 186623 ( 32,147) 186623 34
14,350MEADOW CREEK WIND GI 370 186623 ( 153,446) 186623 35
6,565WONDEROUS WIND GI 371 186623 ( 6,565) 186623 36
214WEST BOISE WASTE WATER GI 372 186623 ( 214) 186623 37
21,101MTNAIR EXPANSION GI 373-378 186623 ( 50,000) 186623 38
2,078BANNOCK COUNTY LANDFILL GI 380 186623 ( 10,849) 186623 39
939DOUBLE EAGLE DAIRY GI 381 186623 ( 939) 186623 40
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.2
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
Transmission Service and Generation Interconnection Study Costs
Idaho Power Company X04/13/2012
2011/Q4
Line No. Description
Costs Incurred During
(b)(a)Period Account Charged
(c)
ReimbursementsReceived During
(d)
Account CreditedWith Reimbursement
(e)the Period
(continued)
Transmission Studies 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Generation Studies 21
9,575FARGO DROP GI 382 186623 ( 12,250) 186623 22
2,913BETASEED BIOGAS GI 383 186623 ( 1,000) 186623 23
JETTCREEK WINDFARM GI 384 186623 ( 1,000) 186623 24
PROSPECTOR WINDFARM GI 385 186623 ( 1,000) 186623 25
BENSON CREEK WINDFARM GI 386 186623 ( 1,000) 186623 26
DURBIN CREEK WINDFARM GI 387 186623 ( 1,000) 186623 27
28
29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.3
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
OTHER REGULATORY ASSETS (Account 182.3)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
Description and Purpose of Debits CREDITSWritten off Duringthe Quarter/YearAccount Charged
(d)(c)(a)
Balance at end ofCurrent Quarter/Year
(e)
Other Regulatory Assets Written off Duringthe PeriodAmount
(f)
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 groupedby classes.3. For Regulatory Assets being amortized, show period of amortization.
44 TOTAL 761,425,884 392,854,761 989,194,015 620,622,892
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
OTHER REGULATORY ASSETS (Account 182.3)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
Description and Purpose of Debits CREDITSWritten off Duringthe Quarter/YearAccount Charged
(d)(c)(a)
Balance at end ofCurrent Quarter/Year
(e)
Other Regulatory Assets Written off Duringthe PeriodAmount
(f)
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 groupedby classes.3. For Regulatory Assets being amortized, show period of amortization.
Balance atBeginning of
CurrentQuarter/Year
(b) 1
( 278,674) -429,062 286,1861823/4210 135,798PCAM Interest Res 2008 OPUC Order #08-238 (182329) 2
3 6,964,691 4,762,316 17,054,3861823/401 14,852,011Excess Power Cost Deferral 2007 4
IPUC Order #09-189 (182358) 5
6( 452,759) -308,869 590182/4210 144,4802007 EPC Interest Res IPUC Order #09-189 (182351) 7
44 TOTAL 761,425,884 392,854,761 989,194,015 620,622,892
Schedule Page: 232.1 Line No.: 38 Column: aAccounts included in minor items:182305182316182331182334182335182340182344182345182347182349182350182353182355182357182369182374182375182376
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87) Page 450.1
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
MISCELLANEOUS DEFFERED DEBITS (Account 186)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
Description of Miscellaneous Debits CREDITSAccount
(c)(b)(a)
Balance atEnd of Year
(d)
Deferred Debits Amount(e)
Balance at Beginning of Year
(f)Charged
1. Report below the particulars (details) called for concerning miscellaneous deferred debits.2. For any deferred debit being amortized, show period of amortization in column (a)3. Minor item (1% of the Balance at End of Year for Account 186 or amounts less than $100,000, whichever is less) may be grouped byclasses.
773,585 715,957 87,111 29,483 VariousRents - Rights of way (186160) 1 2
48 Deferred Regulatory Comm.Expenses (See pages 350 - 351)
55,131,472 50,880,202
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
MISCELLANEOUS DEFFERED DEBITS (Account 186)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
Description of Miscellaneous Debits CREDITSAccount
(c)(b)(a)
Balance atEnd of Year
(d)
Deferred Debits Amount(e)
Balance at Beginning of Year
(f)Charged
1. Report below the particulars (details) called for concerning miscellaneous deferred debits.2. For any deferred debit being amortized, show period of amortization in column (a)3. Minor item (1% of the Balance at End of Year for Account 186 or amounts less than $100,000, whichever is less) may be grouped byclasses.
48 Deferred Regulatory Comm.Expenses (See pages 350 - 351)
55,131,472 50,880,202
Schedule Page: 233.1 Line No.: 5 Column: aAccounts included in minor items:186100186255186623186703186946
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87) Page 450.1
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
ACCUMULATED DEFERRED INCOME TAXES (Account 190)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
Description and Location Balance of Begining
(c)(b)(a)
Balance at Endof Year of Year
1. Report the information called for below concerning the respondent’s accounting for deferred income taxes.2. At Other (Specify), include deferrals relating to other income and deductions.
Electric 1
2
-509,154Emission Allowances 3
5,117,985 7,061,283Advances for Construction 4
46,276,158 6,072,776Other Electric (See footnote) 5
6
157,500,863 126,631,210Other (See footnote) 7
208,895,006 139,256,115TOTAL Electric (Enter Total of lines 2 thru 7) 8
Gas 9
10
11
12
13
14
Other 15
TOTAL Gas (Enter Total of lines 10 thru 15 16
19,082,040 18,090,657Other Non Electric See footnote 17
227,977,046 157,346,772TOTAL (Acct 190) (Total of lines 8, 16 and 17) 18
Notes
FERC FORM NO. 1 (ED. 12-88) Page 234
Schedule Page: 234 Line No.: 5 Column: a (Note 1): Ending Balance Ending BalanceRevenue Sharing 0.00 10,594,313.78 Post Retiree Benefits-VEBA 5,658,260.39 7,474,519.09 AFUDC Hells Canyon Relicensing 8,292,259.43 12,958,192.16 Rate Case Disallowance 2,765,193.22 2,621,255.57 Stock Based Compensation 2,496,071.09 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 46,276,157.96
Schedule Page: 234 Line No.: 7 Column: a (Note 2): Ending Balance Ending BalancePension 64,358,799.67 96,551,656.75 Regulatory Liability for Income Taxes 46,199,137.04 45,472,547.23 Postretirement Plan 8,025,874.06 6,367,217.42 Minimum Pension Liability 8,047,399.21 9,109,441.86 Total Other 126,631,209.98 157,500,863.26
Schedule Page: 234 Line No.: 17 Column: a (Note 3): Ending Balance Ending BalanceSenior 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
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87) Page 450.1
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
CAPITAL STOCKS (Account 201 and 204)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
Class and Series of Stock and Number of shares
(c)(b)(a)
Call Price at End of Year
Par or StatedValue per share
(d)
Name of Stock Series Authorized by Charter
1. Report below the particulars (details) called for concerning common and preferred stock at end of year, distinguishing separate seriesof any general class. Show separate totals for common and preferred stock. If information to meet the stock exchange reportingrequirement outlined in column (a) is available from the SEC 10-K Report Form filing, a specific reference to report form (i.e., year andcompany title) may be reported in column (a) provided the fiscal years for both the 10-K report and this report are compatible.2. Entries in column (b) should represent the number of shares authorized by the articles of incorporation as amended to end of year.
Account 201 1 2.50 50,000,000 Common Stock registered on New York 2
and Pacific Stock Exchange 3 2.50 50,000,000Total Common Stock 4
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
CAPITAL STOCKS (Account 201 and 204) (Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
OUTSTANDING PER BALANCE SHEET HELD BY RESPONDENTIN SINKING AND OTHER FUNDS
Shares(g)
Cost(h)
Shares SharesAmount
(Total amount outstanding without reductionfor amounts held by respondent)
Amount(e) (f) (i) (j)
3. Give particulars (details) concerning shares of any class and series of stock authorized to be issued by a regulatory commissionwhich 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 ornon-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 whichis pledged, stating name of pledgee and purposes of pledge.
1
97,877,030 39,150,812 2
3
97,877,030 39,150,812 4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
FERC FORM NO. 1 (ED. 12-88) Page 251
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd ofIdaho Power Company X
04/13/20122011/Q4
Line Item Amount(b)(a)
OTHER PAID-IN CAPITAL (Accounts 208-211, inc.)
No.
Report below the balance at the end of the year and the information specified below for the respective other paid-in capital accounts. Provide asubheading 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 morecolumns for any account if deemed necessary. Explain changes made in any account during the year and give the accounting entries effecting suchchange.(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 toamounts 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 ofyear with a designation of the nature of each credit and debit identified by the class and series of stock to which related.(d) Miscellaneous Paid-in Capital (Account 211)-Classify amounts included in this account according to captions which, together with brief explanations,disclose the general nature of the transactions which gave rise to the reported amounts.
Account 208 - Donations received from stockholders - None 1
2
Account 209 - Reduction in par or stated value of Capital Stock - None 3
4
Account 210 - Gain on reacquired Capital Stock - None 5
6
7
Account 211 - Miscellaneous paid-in Capital - None 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
FERC FORM NO. 1 (ED. 12-87) Page 253
40 TOTAL
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
CAPITAL STOCK EXPENSE (Account 214)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
Class and Series of Stock Balance at End of Year(b)(a)
1. Report the balance at end of the year of discount on capital stock for each class and series of capital stock.2. If any change occurred during the year in the balance in respect to any class or series of stock, attach a statement giving particulars(details) of the change. State the reason for any charge-off of capital stock expense and specify the account charged.
2,096,925Common Stock 1
2
3
4
5
6
7
8
9
Explanation of Changes during the year: 10
11
12
13
14
15
16
17
18
19
20
21
FERC FORM NO. 1 (ED. 12-87) Page 254b
22 TOTAL 2,096,925
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
LONG-TERM DEBT (Account 221, 222, 223 and 224)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
Class and Series of Obligation, Coupon Rate
(c)(b)(a)
Total expense, Premium or Discount
Principal AmountOf Debt issued(For new issue, give commission Authorization numbers and dates)
1. Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221, Bonds, 222,Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt.2. In column (a), for new issues, give Commission authorization numbers and dates.3. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds.4. For advances from Associated Companies, report separately advances on notes and advances on open accounts. Designatedemand 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 wereissued.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 withissues redeemed during the year. Also, give in a footnote the date of the Commission’s authorization of treatment other than asspecified by the Uniform System of Accounts.
Account 221: 1First Mortgage Bonds: 2
1,190,698 130,000,0004.50% Series due 2020 3 234,601 4 D
5 728,701 70,000,0005.50% Series due 2033 6 36,400 7 D
8 1,034,909 100,000,0006.15% Series Due 2019 9 184,949 10 D
11 1,159,871 100,000,0003.40% Series due 2020 12 498,864 13 D
14 408,411 60,000,0005.30% Series Due 2035 15 D
3,802,019 16 17
641,201 70,000,0004.25%Series due 2013 18 372,696 19 D
20 944,356 100,000,0004.75% Series due 2012 21
1,047,617 22 D 23
1,191,216 100,000,0006.00% Series due 2032 24 543,244 25 D
26 -585,759 55,000,0005.875% Series due 2034 27 746,961 28 D
29 524,419 50,000,0005.50% Series due 2034 30 383,322 31 D
32
FERC FORM NO. 1 (ED. 12-96) Page 256
33 TOTAL 1,617,045,000 27,130,028
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
LONG-TERM DEBT (Account 221, 222, 223 and 224)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
Class and Series of Obligation, Coupon Rate
(c)(b)(a)
Total expense, Premium or Discount
Principal AmountOf Debt issued(For new issue, give commission Authorization numbers and dates)
1. Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221, Bonds, 222,Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt.2. In column (a), for new issues, give Commission authorization numbers and dates.3. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds.4. For advances from Associated Companies, report separately advances on notes and advances on open accounts. Designatedemand 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 wereissued.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 withissues redeemed during the year. Also, give in a footnote the date of the Commission’s authorization of treatment other than asspecified by the Uniform System of Accounts.
1,284,871 100,000,0004.85% Series Due 2040 1 169,984 2 D
3 1,495,799 140,000,0006.30% Series due 2037 4 278,367 5 D
6 1,141,489 100,000,0006.25% Series due 2037 7 267,677 8 D
9 188,545 4,360,000Port of Morrow Variable due 2027 10
11 1,697,856 49,800,000Humboldt Variable due 2024 12
13 3,026,122 116,300,000Sweetwater Variable due 2026 14
15 16
1,630,120 120,000,0006.025 % Series Due 2018 17 18
Account 223: Advances for Associated Companies 25 26
Account 224: 27 19,885,000Bond Guarantee - American Falls 28 11,700,000Note Guarantee - Milner Dam 29 31,585,000Subtotal Account 224 30
31 32
FERC FORM NO. 1 (ED. 12-96) Page 256.1
33 TOTAL 1,617,045,000 27,130,028
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
LONG-TERM DEBT (Account 221, 222, 223 and 224) (Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.Nominal Date
of IssueDate ofMaturity
AMORTIZATION PERIOD
Date From Date To
Outstanding(Total amount outstanding without
reduction for amounts held byrespondent)
Interest for YearAmount
(d) (e) (f) (g) (h) (i)
10. Identify separate undisposed amounts applicable to issues which were redeemed in prior years.11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, Premiumon Debt - Credit.12. In a footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to long-termadvances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaidduring 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 pledgeeand 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 interestexpense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427, interest onLong-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.
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
LONG-TERM DEBT (Account 221, 222, 223 and 224) (Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.Nominal Date
of IssueDate ofMaturity
AMORTIZATION PERIOD
Date From Date To
Outstanding(Total amount outstanding without
reduction for amounts held byrespondent)
Interest for YearAmount
(d) (e) (f) (g) (h) (i)
10. Identify separate undisposed amounts applicable to issues which were redeemed in prior years.11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, Premiumon Debt - Credit.12. In a footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to long-termadvances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaidduring 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 pledgeeand 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 interestexpense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427, interest onLong-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.
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
RECONCILIATION OF REPORTED NET INCOME WITH TAXABLE INCOME FOR FEDERAL INCOME TAXES
Idaho Power Company X04/13/2012
2011/Q4
Particulars (Details)(b)(a)
Amount LineNo.
1. Report the reconciliation of reported net income for the year with taxable income used in computing Federal income tax accruals and showcomputation 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 forthe year. Submit a reconciliation even though there is no taxable income for the year. Indicate clearly the nature of each reconciling amount.2. If the utility is a member of a group which files a consolidated Federal tax return, reconcile reported net income with taxable net income as if a separatereturn were to be field, indicating, however, intercompany amounts to be eliminated in such a consolidated return. State names of group member, taxassigned 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 theabove instructions. For electronic reporting purposes complete Line 27 and provide the substitute Page in the context of a footnote.
164,749,627Net Income for the Year (Page 117) 1 2 3
Taxable Income Not Reported on Books 4 22,801,060 5
6 7 8
Deductions Recorded on Books Not Deducted for Return 9 -22,327,229 10
11 12 13
Income Recorded on Books Not Included in Return 14 6,698,653 15
16 17 18
Deductions on Return Not Charged Against Book Income 19 130,977,371 20
21 22 23 24 25 26
27,547,434Federal Tax Net Income 27Show Computation of Tax: 28
Schedule Page: 261 Line No.: 5 Column: b 4003-CONSTRUCTION ADV-252 $ (5,552,281)4005-AVOIDED COST INT CAP 18,471,438 4006-RETIREMENTS-RECORD TAX GAIN/LOSS 4,000,000 4010-EMISSION ALLOWANCE-254.409-411 1,141,995 4013-CIAC AS TAXABLE INC IN ACCT 107 3,748,724 4018-LINDEN FEEDER DEPOSITS-253.206 0 4021-ENGINEERING FEES-IN ACCT 107-FED ONLY 115,387 4022-FERC CREDIT OFA-254.307 (465,593)4024-GREEN TAG SALES 2,006,420 4501-ROYALTY INCOME BTL 0 4506-CIAC-MERIDIAN GOLD (56,560)4507-CIAC-MICRON-DRAM (608,470)Total $ 22,801,060
Schedule Page: 261 Line No.: 10 Column: b Total Federal and State taxes deducted on books $ (44,418,448)5001-BAD DEBT EXPENSE (205,868)5010-SFAS 112-POST-EMPLY BEN 182/253 (849,962)5014-OVERACCRUED VACATION-ACCT 242 176,500 5017-INJURIES & DAMAGES 42,684 5019-DIRECTORS FEES DEF 26,758 5022-CAPITALIZED OVERHEADS (17,000,000)5024-MEALS (50% NON-DEDUCTIBLE) CHRGD TO R.E. 600,000 5025-MILNER FALLING WATER - REV ACCRL (334,136)5027-AMORTIZATION OF ACCOUNT 114 (22,723)5028-OREGON OPER PROPERTY TAX ADJ (5,072)5023-PENSION EXPENSE-Acct 228 5,487,134 5033-NONVEBA PEN&BEN-Acct 228 (380,803)5035-PCA EXPENSE DEFERRAL 30,679,760 5043-AMERICAN FALLS - FALLING WATER CONTRACT-FT 219,181 5047-OTHER EMPLOYEE'S LT DEFERRED COMP-228 (1,306,905)5052-AMORTIZATION OF ACCOUNT 181 313,103 5053-STOCK BASED COMPENSATION 645,487 5054-IPUC GRID WEST LOANS-ACCT 182 186,435 5055-OPUC GRID WEST LOANS-ACCT 182 14,191 5056-FERC GRID WEST EXP-ACCT 182 83,796 5057-INTERVENER FUNDING ORDERS-ACCT 182 (54,903)5058-FIXED COST ADJUSTMENT (FCA)-ACCT 182 (2,115,823)5059-PS & I COSTS-COAL & CHP PLANTS-WRITE OFF (36,407)5060-OREGON-PCAM (POWER COST ADJ MECHANISM) 1,220,784 5061-PENSION EXPENSE-OREGON 1,758,706 5062-LIDAR SURVEYS DEFFERAL-ACCT 182 (436,047)5063-BENNETT MTN MAINT DEFERRAL (299,546)5501-SEC PLAN-NET INS COSTS (76,501)5503-128-EDC-UNRLZD GN/LS FRM RABBI TRUST (430,015)5504-NONDEDUCTIBLE POLITICAL EXP-426.4 875,858 5505-SEC PLAN-BENEFIT ACCR 3,200,861 5510-FINES & PENALTIES-OPERATING 430,042 5531-RATE CASE DISALLOWANCES-REVERSE AMORT (296,299)5532-DELIVERY ACCRUALS-253.550 (19,051)
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87) Page 450.1
5537-BRIDGER SIERRA RESERVE-LEGAL FEES-Acct 228.4 0 5540-UNREALIZED LOSS ON INVESTMENTS-Acct 124 0 Total $ (22,327,229)
Schedule Page: 261 Line No.: 15 Column: b7010-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 13,332,724 7504-RECLASS TAX EXEMPT INTEREST-FED ONLY 1,882 7509-SECURITY PLAN-INSURANCE PROCEEDS 945,984 7514-COLI-INSURANCE PROCEEDS 0 7518-IRS INTEREST INCOME 0 Total $ 6,698,653 Schedule Page: 261 Line No.: 20 Column: b8001-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 (2,229,258)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 40,000,000 8077-PP INS & OTR EXP (1 YR OR LESS)-165 1,659,465 8079-CUSTOM EFFICIENCY INCENTIVE PAY 7,096,442 8501-COLI-TAX ADJ FROM BOOKS 158,095 8504-OREGON NONOP PROPERTY TAX ADJUST (6)8703-IPCO - 162 (M) $1m THRESHOLD 0 IRS INTEREST EXPENSE 238,097 STATE INCOME TAX DEDUCTED ON FEDERAL RETURN 7,195,334 Total $ 130,977,371
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87) Page 450.2
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
Idaho Power Company X04/13/2012
2011/Q4
Line No.
Kind of Tax(See instruction 5)
BALANCE AT BEGINNING OF YEARTaxes Accrued(Account 236)
Prepaid Taxes(Include in Account 165)
TaxesChargedDuringYear
TaxesPaid
DuringAdjust-mentsYear
(a) (b) (c) (d) (e) (f)
1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts duringthe 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 thanaccrued 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.
5. If any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year, identifyingthe 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 adjustmentsby parentheses.7. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pendingtransmittal of such taxes to the taxing authority.8. Report in columns (i) through (l) how the taxes were distributed. Report in column (I) only the amounts charged to Accounts 408.1 and 409.1pertaining to electric operations. Report in column (l) the amounts charged to Accounts 408.1 and 109.1 pertaining to other utility departments andamounts charged to Accounts 408.2 and 409.2. Also shown in column (l) the taxes charged to utility plant or other balance sheet accounts.9. For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax.
Schedule Page: 262 Line No.: 1 Column: iThis footnote is for the total of Column I on Page 263. The total of column I and theamounts associated with accounts 408.1 & 409.1 in column I should total back to the sum oflines 14, 15 & 16 on Page 114. For the year 2011 this cross-check will not work as thetotal of lines 14-16 on Page 114 is $ 74,436,114 additional expense than line 41 on page263. This difference represents an amount booked for the accounting of FIN 48. When FIN 48was booked it does use account 409.1, however the other side of the entry is not asociatedwith FERC account 236 or 165. Therefore FIN 48 will show up in the amount on Page 114 butwill not show up on Pages 262 & 263.Schedule Page: 262 Line No.: 2 Column: lAccount 409.2 $ (638,707) 234.2 (717,831) -------------Total $ (1,356,538) =============Schedule Page: 262 Line No.: 8 Column: lAccount 107 $ 780,067 Schedule Page: 262 Line No.: 9 Column: lAccount 409.2 $ 21,567 Schedule Page: 262 Line No.: 10 Column: lAccount 409.2 $ (104,386) 234 (143,241) ------------Total $ (247,627) ============Schedule Page: 262 Line No.: 18 Column: lAccount 107 $ 73,425 Schedule Page: 262 Line No.: 19 Column: lAccount 409.2 $ 1,672Schedule Page: 262 Line No.: 20 Column: lAccount 409.2 $ (5,634) 234 (7,284) ----------Total $ (12,918) ==========Schedule Page: 262 Line No.: 38 Column: lAccount 409.2 $ (2,440) 234 (2,428) -----------Total $ (4,868) ===========
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87) Page 450.1
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
(c)(b)(a)of YearSubdivisions AdjustmentsDeferred for Year Allocations to
Current Year's IncomeAccount No. Amount Account No. Amount
(d) (e) (f) (g)
Report below information applicable to Account 255. Where appropriate, segregate the balances and transactions by utility and nonutilityoperations. Explain by footnote any correction adjustments to the account balance shown in column (g).Include in column (i) the averageperiod over which the tax credits are amortized.
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
OTHER DEFFERED CREDITS (Account 253)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
Description and Other DEBITS Credits
Account(c)(b)(a)
Balance atEnd of Year
(d)
Deferred Credits Amount
(e)
Balance at Beginning of Year Contra
(f)
1. Report below the particulars (details) called for concerning other deferred credits.2. For any deferred credit being amortized, show the period of amortization.3. Minor items (5% of the Balance End of Year for Account 253 or amounts less than $100,000, whichever is greater) may be grouped by classes.
47 TOTAL 174,562,639 173,700,336 27,530,572 26,668,269
Schedule Page: 269 Line No.: 24 Column: aAccounts included in minor items:253042253550
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87) Page 450.1
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
ACCUMULATED DEFFERED INCOME TAXES - OTHER PROPERTY (Account 282)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
Account
(a) (b) (c) (d)
Balance atBeginning of Year
CHANGES DURING YEAR
Amounts Debited Amounts Credited to Account 410.1 to Account 411.1
1. Report the information called for below concerning the respondent’s accounting for deferred income taxes rating to property notsubject to accelerated amortization2. For other (Specify),include deferrals relating to other income and deductions.
Account 282 1
Electric 284,793,872 50,711,765 2,171,003 2
Gas 3
Other 4
TOTAL (Enter Total of lines 2 thru 4) 284,793,872 50,711,765 2,171,003 5
Non-Operating Property 6
Other - Regulatory Asset for I 422,215,476 7
8
TOTAL Account 282 (Enter Total of lines 5 thru 8) 707,009,348 50,711,765 2,171,003 9
Classification of TOTAL 10
Federal Income Tax 601,940,143 50,211,165 2,171,003 11
State Income Tax 105,069,205 500,601 12
Local Income Tax 13
FERC FORM NO. 1 (ED. 12-96) Page 274
NOTES
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
ACCUMULATED DEFERRED INCOME TAXES - OTHER PROPERTY (Account 282) (Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
CHANGES DURING YEAR ADJUSTMENTSBalance at
End of YearDebits CreditsAmounts Debited
to Account 410.2Amounts Credited to Account 411.2 Account
CreditedAmount
DebitedAccount Amount
(e) (f) (h) (j) (k)(g) (i)
3. Use footnotes as required.
1
333,334,634 2
3
4
333,334,634 5
6
182 599,991,590 -159,138,028182 18,638,086 7
8
933,326,224 -159,138,028 18,638,086 9
10
795,963,656 -133,493,583 12,489,768 11
137,362,570 -25,644,445 6,148,319 12
13
FERC FORM NO. 1 (ED. 12-96) Page 275
NOTES (Continued)
Schedule Page: 274 Line No.: 2 Column: b2011 Changes during Year Adj Dr Adj
Credits2011
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
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87) Page 450.1
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
ACCUMULATED DEFFERED INCOME TAXES - OTHER (Account 283)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
Account
(a) (b) (c) (d)
Balance atBeginning of Year
CHANGES DURING YEARAmounts Debited Amounts Credited to Account 410.1 to Account 411.1
1. Report the information called for below concerning the respondent’s accounting for deferred income taxes relating to amountsrecorded in Account 283.2. For other (Specify),include deferrals relating to other income and deductions.
Account 283 1
Electric 2
46,760,251 53,826,297 25,656,008Other Electric -- See Note 3
4
5
6
7
73,705,667 Other -- See Note 8
46,760,251 53,826,297 99,361,675TOTAL Electric (Total of lines 3 thru 8) 9
Gas 10
11
12
13
14
15
16
TOTAL Gas (Total of lines 11 thru 16) 17
265,485 Other -- See Note 18
46,760,251 53,826,297 99,627,160TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18) 19
Classification of TOTAL 20
39,225,027 45,152,408 83,572,690Federal Income Tax 21
7,535,224 8,673,888 16,054,470State Income Tax 22
Local Income Tax 23
FERC FORM NO. 1 (ED. 12-96) Page 276
NOTES
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
ACCUMULATED DEFERRED INCOME TAXES - OTHER (Account 283) (Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
CHANGES DURING YEAR ADJUSTMENTSBalance at
End of YearDebits CreditsAmounts Debited
to Account 410.2Amounts Credited to Account 411.2 Account
CreditedAmount
DebitedAccount Amount
(e) (f) (h) (j) (k)(g) (i)
3. Provide in the space below explanations for Page 276 and 277. Include amounts relating to insignificant items listed under Other.4. Use footnotes as required.
1
2
32,722,054 3
4
5
6
7
104,275,112 30,569,445 8
136,997,166 30,569,445 9
10
11
12
13
14
15
16
17
441,529 36,749 212,793 18
137,438,695 30,569,445 36,749 212,793 19
20
115,291,044 25,643,297 30,827 178,503 21
22,147,650 4,926,147 5,922 34,291 22
23
FERC FORM NO. 1 (ED. 12-96) Page 277
NOTES (Continued)
Schedule Page: 276 Line No.: 3 Column: b2011 Changes during Year Adj Debits Adj
Credits2011
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
TOTAL 25,656,008.09 53,826,296.68 46,760,250.71 0 0 0 0 32,722,054.06
Schedule Page: 276 Line No.: 8 Column: b
Beginning DR to CR to DRto
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 kPension 64,358,799.67 190 32,192,857.08 96,551,656.75 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 73,705,666.98 0 0 0 0 0 30,569,444.55 104,275,111.53 Schedule Page: 276 Line No.: 18 Column: b
2011 Changes during Year AdjDebits
AdjCredits
2011
Beginning DR to CRto
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 kAdvance 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) 204,533.72 36,419.34 139,717.75 TOTAL 265,484.81 0 0 212,793.32 36,748.93 0 0 441,529.20
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87) Page 450.1
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
OTHER REGULATORY LIABILITIES (Account 254)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
Description and Purpose of DEBITS CreditsAccount
(d)(c)(a)
Balance at Endof Current
Quarter/Year
(e)
Other Regulatory Liabilities Amount
(f)Credited
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 groupedby classes.3. For Regulatory Liabilities being amortized, show period of amortization.
Balance at Beginingof Current
Quarter/Year
(b)
573,226 5,235,834 3,394,965 8,057,573Market to Market Short Term - (254001) 175 1
27,098,897 27,098,897Revenue Sharing (254101) Various 27
IPUC Order #30978 28
29
13,880 111 411,557 397,788BPA Credit Residential Idaho (254401) Various 30
Advice # 11-03 31
32
1,323 159,309 160,632WAQC Carryover (254901) Various 33
IPUC Order #29505 34
35
22,818 118,237,871 65,249 118,280,302Minor Items (10) Various 36
37
38
39
40
FERC FORM NO. 1/3-Q (REV 02-04) Page 278
41 TOTAL 234,039,200 192,835,857 96,483,245 55,279,902
Schedule Page: 278 Line No.: 36 Column: aAccounts included in minor items:254004254006254201254202254402254403254404254409254410254411254413254416
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87) Page 450.1
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
ELECTRIC OPERATING REVENUES (Account 400)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
Title of Account
(c)(b)(a)
Operating Revenues Yearto Date Quarterly/Annual
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 MWHrelated 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 areadded 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 theclose 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.
Operating RevenuesPrevious year (no Quarterly)
Sales of Electricity 1
400,606,630(440) Residential Sales 405,981,556 2
(442) Commercial and Industrial Sales 3
338,716,361Small (or Comm.) (See Instr. 4) 322,307,065 4
138,394,166Large (or Ind.) (See Instr. 4) 140,701,371 5
3,278,628(444) Public Street and Highway Lighting 3,289,385 6
(445) Other Sales to Public Authorities 7
(446) Sales to Railroads and Railways 8
(448) Interdepartmental Sales 9
880,995,785TOTAL Sales to Ultimate Consumers 872,279,377 10
78,133,502(447) Sales for Resale 101,602,140 11
959,129,287TOTAL Sales of Electricity 973,881,517 12
10,667,522(Less) (449.1) Provision for Rate Refunds 37,734,709 13
948,461,765TOTAL Revenues Net of Prov. for Refunds 936,146,808 14
Other Operating Revenues 15
(450) Forfeited Discounts 16
3,532,831(451) Miscellaneous Service Revenues 3,564,200 17
(453) Sales of Water and Water Power 18
21,141,127(454) Rent from Electric Property 24,256,300 19
(455) Interdepartmental Rents 20
44,517,995(456) Other Electric Revenues 38,244,930 21
15,398,402(456.1) Revenues from Transmission of Electricity of Others 19,372,904 22
(457.1) Regional Control Service Revenues 23
(457.2) Miscellaneous Revenues 24
25
84,590,355TOTAL Other Operating Revenues 85,438,334 26
1,033,052,120TOTAL Electric Operating Revenues 1,021,585,142 27
Page 300FERC FORM NO. 1/3-Q (REV. 12-05)
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
ELECTRIC OPERATING REVENUES (Account 400)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
MEGAWATT HOURS SOLDPrevious Year (no Quarterly)Current Year (no Quarterly)
AVG.NO. CUSTOMERS PER MONTHYear to Date Quarterly/Annual Amount Previous year (no Quarterly)
(d) (e) (f) (g)
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 bythe 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 ofclassification 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,and 6, see Page 304 for amounts relating to unbilled revenue by accounts.9. Include unmetered sales. Provide details of such Sales in a footnote.
1
4,967,379 407,551 409,786 5,146,013 2
3
5,439,730 81,571 82,045 5,458,954 4
3,075,379 124 123 3,099,743 5
30,016 1,459 1,578 29,720 6
7
8
9
13,512,504 490,705 493,532 13,734,430 10
1,981,936 3,634,924 11
15,494,440 490,705 493,532 17,369,354 12
13
15,494,440 490,705 493,532 17,369,354 14
Page 301
Line 12, column (b) includes $ of unbilled revenues.
Line 12, column (d) includes MWH relating to unbilled revenues
640,470
38,351
FERC FORM NO. 1/3-Q (REV. 12-05)
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
SALES OF ELECTRICITY BY RATE SCHEDULES
Idaho Power Company X04/13/2012
2011/Q4
Line No.
Number and Title of Rate schedule MWh Sold(b)(a)
Revenue(c)
Average Numberof Customers
(d)
KWh of SalesPer Customer
(e)Revenue Per
KWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh percustomer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under eachapplicable 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 residentialschedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reportedcustomers.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 ifall 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.
2,859 0.1881 537,868 6 15 - Dusk to dawn lighting 22,994 0.0360 827,035 7 Unbilled Revenues
1,862,085 8 Other Revenues 5,146,003 409,786 12,558 0.0789 405,985,970 9 Total 440
10 11 442-Commercial & Industrial Sales
162,322 30,972 5,241 0.0989 16,053,391 12 07 - General service 431,095 187 2,305,321 0.0477 20,549,318 13 09 - General service
3,156,665 31,007 101,805 0.0567 178,829,445 14 09 - General service 5,506 3 1,835,333 0.0534 294,295 15 09 - General service 4,103 0.1702 698,315 16 15 - Dusk to Dawn Light
41 TOTAL Billed42 Total Unbilled Rev.(See Instr. 6)43 TOTAL
Schedule Page: 304 Line No.: 9 Column: bThis amount is different from page 301 column D line 2 in the amount of 10 MWh due to anerror during the year where a rate 09S was recorded to the residential account. Page 301is broken down by FERC account and page 304 is by rate schedule. Schedule Page: 304 Line No.: 9 Column: cThis amount is different from page 301 column B line 2 in the amount of 4,414 due to anerror during the year where a rate 09S was recorded to the residential account. Page 301is broken down by FERC account and page 304 is by rate schedule. Schedule Page: 304 Line No.: 24 Column: bThis amount is different from page 301 column D total of lines 4 and 5 in the amount of 10MWh due to an error during the year where a rate 09S was recorded to the residentialaccount. Page 301 is broken down by FERC account and page 304 is by rate schedule. Schedule Page: 304 Line No.: 24 Column: cThis amount is different from page 301 column B total of lines 4 and 5 in the amount of4,414 due to an error during the year where a rate 09S was recorded to the residentialaccount. Page 301 is broken down by FERC account and page 304 is by rate schedule.
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87) Page 450.1
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
SALES FOR RESALE (Account 447)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
Name of Company or Public Authority
(c)(b)(a)
FERC RateMonthly Billing
Average
(d)
Statistical
cationClassifi- Schedule or
Tariff Number Demand (MW)(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average Average
Monthly NCP Demand Monthly CP Demand
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than powerexchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits forenergy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on thePurchased 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 anyownership 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 supplierincludes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be thesame 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 economicreasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy fromthird parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definitionof RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest datethat 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 Lessthan 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 oneyear or less.LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability ofservice, 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" meansLonger than one year but Less than five years.
Raft River Rural Electric 7.1768.4368.436V6-44RQ 1
Raft River Rural Electric n/an/an/aV6-44RQ 2
3
Arizona Public Service Co. n/an/an/aWSPPSF 4
Arizona Public Service Co. n/an/an/aWSPPOS 5
Avista Corp. n/an/an/aWSPPSF 6
Avista Corp. n/an/an/aWSPPOS 7
Barclays Bank PLC n/an/an/aWSPPSF 8
Barclays Bank PLC n/an/an/a-OS 9
Black Hills Power Inc. n/an/an/aWSPPOS 10
Black Hills Power Inc. n/an/an/aWSPPOS 11
Black Hills Power Inc. n/an/an/aWSPPSF 12
Bonneville Power Administration n/an/an/aWSPPSF 13
BP Energy Company n/an/an/aWSPPSF 14
FERC FORM NO. 1 (ED. 12-90) Page 310
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
SALES FOR RESALE (Account 447)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
Name of Company or Public Authority
(c)(b)(a)
FERC RateMonthly Billing
Average
(d)
Statistical
cationClassifi- Schedule or
Tariff Number Demand (MW)(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average Average
Monthly NCP Demand Monthly CP Demand
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than powerexchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits forenergy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on thePurchased 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 anyownership 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 supplierincludes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be thesame 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 economicreasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy fromthird parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definitionof RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest datethat 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 Lessthan 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 oneyear or less.LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability ofservice, 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" meansLonger than one year but Less than five years.
Calpine Energy Services, L.P. n/an/an/aWSPPSF 1
Cargill Power Markets LLC n/an/an/a-OS 2
Cargill Power Markets LLC n/an/an/aWSPPOS 3
Cargill Power Markets LLC n/an/an/aWSPPOS 4
Cargill Power Markets LLC n/an/an/aWSPPSF 5
Citigroup Energy Inc. n/an/an/aWSPPSF 6
Citigroup Energy Inc. n/an/an/aWSPPOS 7
Citigroup Energy Inc. n/an/an/a-OS 8
Clatskanie PUD n/an/an/aWSPPSF 9
Constellation Energy Commodities Group, n/an/an/aWSPPSF 10
DB Energy Trading LLC n/an/an/aWSPPSF 11
EDF Trading North America, LLC n/an/an/aWSPPSF 12
Eugene Electric Board n/an/an/aWSPPSF 13
Exelon Generation Company, LLC n/an/an/aWSPPSF 14
FERC FORM NO. 1 (ED. 12-90) Page 310.1
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
SALES FOR RESALE (Account 447)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
Name of Company or Public Authority
(c)(b)(a)
FERC RateMonthly Billing
Average
(d)
Statistical
cationClassifi- Schedule or
Tariff Number Demand (MW)(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average Average
Monthly NCP Demand Monthly CP Demand
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than powerexchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits forenergy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on thePurchased 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 anyownership 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 supplierincludes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be thesame 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 economicreasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy fromthird parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definitionof RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest datethat 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 Lessthan 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 oneyear or less.LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability ofservice, 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" meansLonger than one year but Less than five years.
Grant CO Public Utility District #2 -- n/an/an/aWSPPSF 1
IBERDROLA RENEWABLES, Inc. n/an/an/aWSPPOS 2
IBERDROLA RENEWABLES, Inc. n/an/an/aWSPPSF 3
IBERDROLA RENEWABLES, Inc. n/an/an/aWSPPOS 4
IBERDROLA RENEWABLES, Inc. n/an/an/a-OS 5
J.P. Morgan Ventures Energy Corporation n/an/an/a-OS 6
J.P. Morgan Ventures Energy Corporation n/an/an/aWSPPSF 7
Jeffries Bache n/an/an/a-OS 8
Macquarie Energy LLC n/an/an/aWSPPOS 9
Macquarie Energy LLC n/an/an/aWSPPSF 10
Morgan Stanley Capital Group Inc. n/an/an/a-OS 11
Morgan Stanley Capital Group Inc. n/an/an/a-OS 12
Morgan Stanley Capital Group Inc. n/an/an/aV6-62SF 13
Morgan Stanley Capital Group Inc. n/an/an/aWSPPOS 14
FERC FORM NO. 1 (ED. 12-90) Page 310.2
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
SALES FOR RESALE (Account 447)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
Name of Company or Public Authority
(c)(b)(a)
FERC RateMonthly Billing
Average
(d)
Statistical
cationClassifi- Schedule or
Tariff Number Demand (MW)(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average Average
Monthly NCP Demand Monthly CP Demand
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than powerexchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits forenergy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on thePurchased 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 anyownership 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 supplierincludes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be thesame 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 economicreasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy fromthird parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definitionof RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest datethat 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 Lessthan 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 oneyear or less.LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability ofservice, 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" meansLonger than one year but Less than five years.
NorthWestern Energy n/an/an/aWSPPOS 1
PacifiCorp Inc. n/an/an/aWSPP S 2
PacifiCorp Inc. n/an/an/aWSPPOS 3
PacifiCorp Inc. n/an/an/aT-7SF 4
Portland General Electric Company n/an/an/aWSPPOS 5
Portland General Electric Company n/an/an/aWSPPOS 6
Portland General Electric Company n/an/an/aWSPPSF 7
Powerex Corp. n/an/an/aWSPPOS 8
Powerex Corp. n/an/an/aWSPPOS 9
Powerex Corp. n/an/an/aWSPPSF 10
PPL EnergyPlus, LLC n/an/an/aWSPPOS 11
PPL EnergyPlus, LLC n/an/an/aWSPPOS 12
PPL EnergyPlus, LLC n/an/an/aWSPPSF 13
Puget Sound Energy, Inc. n/an/an/aWSPPSF 14
FERC FORM NO. 1 (ED. 12-90) Page 310.3
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
SALES FOR RESALE (Account 447)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
Name of Company or Public Authority
(c)(b)(a)
FERC RateMonthly Billing
Average
(d)
Statistical
cationClassifi- Schedule or
Tariff Number Demand (MW)(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average Average
Monthly NCP Demand Monthly CP Demand
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than powerexchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits forenergy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on thePurchased 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 anyownership 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 supplierincludes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be thesame 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 economicreasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy fromthird parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definitionof RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest datethat 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 Lessthan 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 oneyear or less.LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability ofservice, 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" meansLonger than one year but Less than five years.
Puget Sound Energy, Inc. n/an/an/aT-7SF 1
Puget Sound Energy, Inc. n/an/an/aWSPPOS 2
Rainbow Energy Marketing Corporation n/an/an/aWSPPOS 3
Rainbow Energy Marketing Corporation n/an/an/aWSPPSF 4
Royal Bank of Canada n/an/an/a-OS 5
Seattle City Light n/an/an/aWSPPOS 6
Seattle City Light n/an/an/aWSPPSF 7
Sempra Energy Trading LLC n/an/an/a-OS 8
Sempra Energy Trading LLC n/an/an/aWSPPOS 9
Shell Energy North America (US), L.P. n/an/an/aWSPPOS 10
Shell Energy North America (US), L.P. n/an/an/aWSPPOS 11
Shell Energy North America (US), L.P. n/an/an/aWSPPOS 12
Shell Energy North America (US), L.P. n/an/an/aWSPPOS 13
Shell Energy North America (US), L.P. n/an/an/aWSPPSF 14
FERC FORM NO. 1 (ED. 12-90) Page 310.4
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
SALES FOR RESALE (Account 447)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
Name of Company or Public Authority
(c)(b)(a)
FERC RateMonthly Billing
Average
(d)
Statistical
cationClassifi- Schedule or
Tariff Number Demand (MW)(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average Average
Monthly NCP Demand Monthly CP Demand
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than powerexchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits forenergy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on thePurchased 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 anyownership 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 supplierincludes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be thesame 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 economicreasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy fromthird parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definitionof RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest datethat 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 Lessthan 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 oneyear or less.LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability ofservice, 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" meansLonger than one year but Less than five years.
Sierra Pacific Power Co., dba NV Energy n/an/an/aT-7SF 1
Sierra Pacific Power Co., dba NV Energy n/an/an/aWSPPOS 2
Sierra Pacific Power Co., dba NV Energy n/an/an/aWSPPSF 3
Sierra Pacific Power Co., dba NV Energy n/an/an/aWSPPOS 4
Southern California Edison n/an/an/aWSPPOS 5
Snohomish County PUD n/an/an/aWSPPSF 6
Tenaska Power Services Co. n/an/an/aWSPPOS 7
Tenaska Power Services Co. n/an/an/aWSPPSF 8
Tenaska Power Services Co. n/an/an/aWSPPOS 9
The Energy Authority, Inc. n/an/an/aWSPPSF 10
TransAlta Energy Marketing (U.S.) Inc. n/an/an/aWSPPOS 11
TransAlta Energy Marketing (U.S.) Inc. n/an/an/aWSPPOS 12
TransAlta Energy Marketing (U.S.) Inc. n/an/an/aWSPPSF 13
Turlock Irrigation District n/an/an/aWSPPSF 14
FERC FORM NO. 1 (ED. 12-90) Page 310.5
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
SALES FOR RESALE (Account 447)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
Name of Company or Public Authority
(c)(b)(a)
FERC RateMonthly Billing
Average
(d)
Statistical
cationClassifi- Schedule or
Tariff Number Demand (MW)(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average Average
Monthly NCP Demand Monthly CP Demand
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than powerexchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits forenergy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on thePurchased 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 anyownership 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 supplierincludes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be thesame 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 economicreasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy fromthird parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definitionof RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest datethat 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 Lessthan 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 oneyear or less.LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability ofservice, 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" meansLonger than one year but Less than five years.
United Materials of Great Falls n/an/an/a61LF 1
Wells Fargo Bank, N.A. n/an/an/a-OS 2
Marcquarie Energy LLC n/an/an/aWSPPAD 3
4
5
6
7
8
9
10
11
12
13
14
FERC FORM NO. 1 (ED. 12-90) Page 310.6
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
SALES FOR RESALE (Account 447) (Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)Total ($)
REVENUE
($) ($) ($)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as allnon-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature ofthe 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 reportingyears. 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" incolumn (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 underwhich 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 theaverage monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the averagemonthly 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 maximummetered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minuteintegration) 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, includingout-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 theLast -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401,line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401,iine 24.10. Footnote entries as required and provide explanations following all required data.
1,085,425 540,239 4,500 1,630,164 38,222 1
254,060 254,060 2
3
13,314,698 13,314,698 533,806 4
93,600 93,600 3,600 5
84,748 84,748 4,050 6
3,140 3,140 290 7
1,502,700 1,502,700 30,000 8
94,553 94,553 9
2,295 2,295 10
702,444 702,444 34,301 11
779,325 779,325 44,873 12
1,528,500 1,528,500 55,635 13
717,310 717,310 63,160 14
FERC FORM NO. 1 (ED. 12-90) Page 311
1,085,425
98,041,629
99,127,054
38,222
3,596,702
3,634,924
258,560 1,884,224
1,676,287
1,934,847
99,717,916
101,602,140
540,239
0
540,239
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
SALES FOR RESALE (Account 447) (Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)Total ($)
REVENUE
($) ($) ($)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as allnon-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature ofthe 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 reportingyears. 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" incolumn (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 underwhich 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 theaverage monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the averagemonthly 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 maximummetered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minuteintegration) 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, includingout-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 theLast -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.
378 378 10 1
14,492 14,492 2
695,944 695,944 3
23,623 23,623 951 4
11,442,864 11,442,864 386,461 5
13,799,257 13,799,257 560,092 6
167,095 167,095 6,244 7
341,599 341,599 8
463,000 463,000 16,800 9
1,155,785 1,155,785 44,800 10
1,091,669 1,091,669 42,750 11
2,461,720 2,461,720 85,400 12
248,556 248,556 13,710 13
26,400 26,400 800 14
FERC FORM NO. 1 (ED. 12-90) Page 311.1
1,085,425
98,041,629
99,127,054
38,222
3,596,702
3,634,924
258,560 1,884,224
1,676,287
1,934,847
99,717,916
101,602,140
540,239
0
540,239
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
SALES FOR RESALE (Account 447) (Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)Total ($)
REVENUE
($) ($) ($)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as allnon-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature ofthe 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 reportingyears. 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" incolumn (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 underwhich 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 theaverage monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the averagemonthly 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 maximummetered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minuteintegration) 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, includingout-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 theLast -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.
151,320 151,320 5,600 1
9,407 9,407 2
3,325,760 3,325,760 127,040 3
7,408 7,408 341 4
68,748 68,748 5
765,968 765,968 6
325,674 325,674 10,422 7
6,807,639 6,807,639 8
524,508 524,508 9
5,696,223 5,696,223 169,183 10
138,330 138,330 11
10,732 10,732 12
4,786,783 4,786,783 225,125 13
111,981 111,981 14
FERC FORM NO. 1 (ED. 12-90) Page 311.2
1,085,425
98,041,629
99,127,054
38,222
3,596,702
3,634,924
258,560 1,884,224
1,676,287
1,934,847
99,717,916
101,602,140
540,239
0
540,239
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
SALES FOR RESALE (Account 447) (Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)Total ($)
REVENUE
($) ($) ($)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as allnon-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature ofthe 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 reportingyears. 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" incolumn (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 underwhich 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 theaverage monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the averagemonthly 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 maximummetered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minuteintegration) 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, includingout-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 theLast -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.
27,573 27,573 4,258 1
894,457 894,457 68,075 2
158 158 3
4,970 4,970 190 4
584 584 5
34,350 34,350 2,925 6
412,810 412,810 16,671 7
490,861 490,861 8
2,540,384 2,540,384 196,235 9
856,711 856,711 34,508 10
14,900 14,900 11
2,459 2,459 335 12
1,609,656 1,609,656 56,880 13
1,451,355 1,451,355 57,402 14
FERC FORM NO. 1 (ED. 12-90) Page 311.3
1,085,425
98,041,629
99,127,054
38,222
3,596,702
3,634,924
258,560 1,884,224
1,676,287
1,934,847
99,717,916
101,602,140
540,239
0
540,239
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
SALES FOR RESALE (Account 447) (Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)Total ($)
REVENUE
($) ($) ($)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as allnon-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature ofthe 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 reportingyears. 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" incolumn (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 underwhich 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 theaverage monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the averagemonthly 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 maximummetered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minuteintegration) 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, includingout-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 theLast -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.
88 88 3 1
228,295 228,295 15,915 2
126,369 126,369 3
3,796,180 3,796,180 132,200 4
142,696 142,696 5
13,675 13,675 1,100 6
109,050 109,050 4,140 7
672,024 672,024 8
29 29 9
37,302 37,302 10
15,451 15,451 11
99,168 99,168 3,584 12
864,566 864,566 41,696 13
7,531,637 7,531,637 286,405 14
FERC FORM NO. 1 (ED. 12-90) Page 311.4
1,085,425
98,041,629
99,127,054
38,222
3,596,702
3,634,924
258,560 1,884,224
1,676,287
1,934,847
99,717,916
101,602,140
540,239
0
540,239
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
SALES FOR RESALE (Account 447) (Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)Total ($)
REVENUE
($) ($) ($)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as allnon-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature ofthe 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 reportingyears. 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" incolumn (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 underwhich 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 theaverage monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the averagemonthly 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 maximummetered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minuteintegration) 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, includingout-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 theLast -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401,line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401,iine 24.10. Footnote entries as required and provide explanations following all required data.
2,066 2,066 69 1
194,888 194,888 2
6,000 6,000 200 3
52 52 2 4
109 109 5
1,100 1,100 50 6
2,547 2,547 7
2,500 2,500 100 8
115,296 115,296 14,393 9
6,200 6,200 250 10
10,764 10,764 11
2,419,207 2,419,207 141,558 12
1,377,652 1,377,652 51,664 13
10,028 10,028 400 14
FERC FORM NO. 1 (ED. 12-90) Page 311.5
1,085,425
98,041,629
99,127,054
38,222
3,596,702
3,634,924
258,560 1,884,224
1,676,287
1,934,847
99,717,916
101,602,140
540,239
0
540,239
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
SALES FOR RESALE (Account 447) (Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)Total ($)
REVENUE
($) ($) ($)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as allnon-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature ofthe 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 reportingyears. 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" incolumn (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 underwhich 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 theaverage monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the averagemonthly 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 maximummetered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minuteintegration) 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, includingout-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 theLast -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.
26,446 26,446 1
77,127 77,127 2
2,000 2,000 50 3
4
5
6
7
8
9
10
11
12
13
14
FERC FORM NO. 1 (ED. 12-90) Page 311.6
1,085,425
98,041,629
99,127,054
38,222
3,596,702
3,634,924
258,560 1,884,224
1,676,287
1,934,847
99,717,916
101,602,140
540,239
0
540,239
Schedule Page: 310 Line No.: 1 Column: b Customer ChargeSchedule Page: 310 Line No.: 2 Column: b Network Transmission ChargesSchedule Page: 310 Line No.: 5 Column: bNon-firm Sales Schedule Page: 310 Line No.: 7 Column: bNon-firm Sales Schedule Page: 310 Line No.: 9 Column: bISDA Master Agreement with Barclays Bank dated May 2, 2011 Schedule Page: 310 Line No.: 10 Column: bFinancial Transmission Losses Schedule Page: 310 Line No.: 11 Column: bNon-firm Sales Schedule Page: 310.1 Line No.: 2 Column: bISDA Master Agreement with Cargil Powr Markets LLC, dated June 13, 2011 Schedule Page: 310.1 Line No.: 3 Column: bFinancial Transmission Losses Schedule Page: 310.1 Line No.: 4 Column: bNon-firm Sales Schedule Page: 310.1 Line No.: 7 Column: bUnit Contingent Schedule Page: 310.1 Line No.: 8 Column: bISDA Master Agreement with Citigroup Energy, Inc., dated March 7, 2011 Schedule Page: 310.2 Line No.: 2 Column: bFinancial Transmission Losses Schedule Page: 310.2 Line No.: 4 Column: bNon-firm Sales Schedule Page: 310.2 Line No.: 5 Column: bISDA Master Agreement with Iberdrola Renewables, Inc., dated July 19, 2011 Schedule Page: 310.2 Line No.: 6 Column: bISDA Master Agreement with JP Morgan Ventures Energy Corporation dated November 4, 2005. Schedule Page: 310.2 Line No.: 8 Column: bPrudential Bache Commodities (Jeffries Bache), LLC Futures Account Document, datedSeptember 4, 2008. Schedule Page: 310.2 Line No.: 9 Column: bISDA Master Agreement with Macquarie Energy, LLC dated April 12, 2011 Schedule Page: 310.2 Line No.: 11 Column: bISDA Master Agreement with Morgan Stanley dated March 1, 2000 Schedule Page: 310.2 Line No.: 12 Column: bISDA Master Agreement with Morgan Stanley dated March 1, 2000 Schedule Page: 310.2 Line No.: 14 Column: bFinancial Transmission Losses Schedule Page: 310.3 Line No.: 1 Column: bNon-firm Sales Schedule Page: 310.3 Line No.: 3 Column: bFinancial Transmission Losses Schedule Page: 310.3 Line No.: 4 Column: bSpinning or Operating Reserves Schedule Page: 310.3 Line No.: 5 Column: bFinancial Transmission Losses Schedule Page: 310.3 Line No.: 6 Column: bNon-firm Sales
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87) Page 450.1
Schedule Page: 310.3 Line No.: 8 Column: bFinancial Transmission Losses Schedule Page: 310.3 Line No.: 9 Column: bNon-firm Sales Schedule Page: 310.3 Line No.: 11 Column: bFinancial Transmission Losses Schedule Page: 310.3 Line No.: 12 Column: bNon-firm Sales Schedule Page: 310.4 Line No.: 1 Column: bSpinning or Operating Reserves Schedule Page: 310.4 Line No.: 2 Column: bNon-firm Sales Schedule Page: 310.4 Line No.: 3 Column: bFinancial Transmission Losses Schedule Page: 310.4 Line No.: 5 Column: bISDA Master Agreement with Royal Bank of Canada dated August 26, 2005 Schedule Page: 310.4 Line No.: 6 Column: bNon-firm Sales Schedule Page: 310.4 Line No.: 8 Column: bISDA Master Agreement with Sempra Energy Trading dated February 21, 2008. Schedule Page: 310.4 Line No.: 9 Column: bFinancial Transmission Losses Schedule Page: 310.4 Line No.: 10 Column: bISDA Master Agreement with Shell Energy North America dated November 1, 2009 Schedule Page: 310.4 Line No.: 11 Column: bFinancial Transmission Losses Schedule Page: 310.4 Line No.: 12 Column: bUnit Contingent Schedule Page: 310.4 Line No.: 13 Column: bNon-firm Sales Schedule Page: 310.5 Line No.: 1 Column: bSpinning or Operating Reserves Schedule Page: 310.5 Line No.: 2 Column: bFinancial Transmission Losses Schedule Page: 310.5 Line No.: 4 Column: bNon-firm Sales Schedule Page: 310.5 Line No.: 5 Column: bFinancial Transmission Losses Schedule Page: 310.5 Line No.: 7 Column: bFinancial Transmission Losses Schedule Page: 310.5 Line No.: 9 Column: bNon-firm Sales Schedule Page: 310.5 Line No.: 11 Column: bFinancial Transmission Losses Schedule Page: 310.5 Line No.: 12 Column: bNon-firm Sales Schedule Page: 310.6 Line No.: 2 Column: bISDA Master Agreement with Wells Fargo Bank, N.A. dated March 1, 2006 Schedule Page: 310.6 Line No.: 3 Column: bDecember 2010 Adjustment
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87) Page 450.2
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd ofIdaho Power Company X
04/13/20122011/Q4
Line No.
Account Amount for
(c)(b)(a)Current Year Previous Year
Amount forIf the amount for previous year is not derived from previously reported figures, explain in footnote.
1. POWER PRODUCTION EXPENSES 1A. Steam Power Generation 2Operation 3(500) Operation Supervision and Engineering 4 1,888,571 1,690,161(501) Fuel 5 146,926,801 119,844,954(502) Steam Expenses 6 7,337,561 6,950,410(503) Steam from Other Sources 7(Less) (504) Steam Transferred-Cr. 8(505) Electric Expenses 9 2,140,193 2,231,309(506) Miscellaneous Steam Power Expenses 10 9,797,755 9,734,263(507) Rents 11 229,315 498,085(509) Allowances 12TOTAL Operation (Enter Total of Lines 4 thru 12) 13 168,320,196 140,949,182Maintenance 14(510) Maintenance Supervision and Engineering 15 2,292,767 2,075,559(511) Maintenance of Structures 16 309,374 920,609(512) Maintenance of Boiler Plant 17 16,067,832 15,351,039(513) Maintenance of Electric Plant 18 3,915,291 6,827,635(514) Maintenance of Miscellaneous Steam Plant 19 3,753,015 6,486,063TOTAL Maintenance (Enter Total of Lines 15 thru 19) 20 26,338,279 31,660,905TOTAL Power Production Expenses-Steam Power (Entr Tot lines 13 & 20) 21 194,658,475 172,610,087B. Nuclear Power Generation 22Operation 23(517) Operation Supervision and Engineering 24(518) Fuel 25(519) Coolants and Water 26(520) Steam Expenses 27(521) Steam from Other Sources 28(Less) (522) Steam Transferred-Cr. 29(523) Electric Expenses 30(524) Miscellaneous Nuclear Power Expenses 31(525) Rents 32TOTAL Operation (Enter Total of lines 24 thru 32) 33Maintenance 34(528) Maintenance Supervision and Engineering 35(529) Maintenance of Structures 36(530) Maintenance of Reactor Plant Equipment 37(531) Maintenance of Electric Plant 38(532) Maintenance of Miscellaneous Nuclear Plant 39TOTAL Maintenance (Enter Total of lines 35 thru 39) 40TOTAL Power Production Expenses-Nuc. Power (Entr tot lines 33 & 40) 41C. Hydraulic Power Generation 42Operation 43(535) Operation Supervision and Engineering 44 5,362,099 5,380,371(536) Water for Power 45 7,322,751 8,772,110(537) Hydraulic Expenses 46 10,671,807 12,513,192(538) Electric Expenses 47 1,565,842 1,611,582(539) Miscellaneous Hydraulic Power Generation Expenses 48 2,895,723 3,081,121(540) Rents 49 406,432 209,213TOTAL Operation (Enter Total of Lines 44 thru 49) 50 28,224,654 31,567,589C. Hydraulic Power Generation (Continued) 51Maintenance 52(541) Mainentance Supervision and Engineering 53 1,967,876 1,763,673(542) Maintenance of Structures 54 1,155,653 1,722,862(543) Maintenance of Reservoirs, Dams, and Waterways 55 1,368,190 1,563,284(544) Maintenance of Electric Plant 56 3,177,811 1,789,947(545) Maintenance of Miscellaneous Hydraulic Plant 57 3,029,473 2,719,281TOTAL Maintenance (Enter Total of lines 53 thru 57) 58 10,699,003 9,559,047TOTAL Power Production Expenses-Hydraulic Power (tot of lines 50 & 58) 59 38,923,657 41,126,636
FERC FORM NO. 1 (ED. 12-93) Page 320
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd ofIdaho Power Company X
04/13/20122011/Q4
Line No.
Account Amount for
(c)(b)(a)Current Year Previous Year
Amount forIf the amount for previous year is not derived from previously reported figures, explain in footnote.
D. Other Power Generation 60Operation 61(546) Operation Supervision and Engineering 62 328,417 820,192(547) Fuel 63 12,745,952 11,696,917(548) Generation Expenses 64 448,744 749,804(549) Miscellaneous Other Power Generation Expenses 65 450,180 779,335(550) Rents 66TOTAL Operation (Enter Total of lines 62 thru 66) 67 13,973,293 14,046,248Maintenance 68(551) Maintenance Supervision and Engineering 69 43(552) Maintenance of Structures 70 182,043 179,520(553) Maintenance of Generating and Electric Plant 71 118,533 115,128(554) Maintenance of Miscellaneous Other Power Generation Plant 72 1,077,264 1,861,365TOTAL Maintenance (Enter Total of lines 69 thru 72) 73 1,377,883 2,156,013TOTAL Power Production Expenses-Other Power (Enter Tot of 67 & 73) 74 15,351,176 16,202,261E. Other Power Supply Expenses 75(555) Purchased Power 76 137,850,336 156,873,749(556) System Control and Load Dispatching 77 160 1,219(557) Other Expenses 78 53,795,016 41,459,600TOTAL Other Power Supply Exp (Enter Total of lines 76 thru 78) 79 191,645,512 198,334,568TOTAL Power Production Expenses (Total of lines 21, 41, 59, 74 & 79) 80 440,578,820 428,273,5522. TRANSMISSION EXPENSES 81Operation 82(560) Operation Supervision and Engineering 83 2,992,955 3,326,891(561) Load Dispatching 84 273,869 192,086(561.1) Load Dispatch-Reliability 85(561.2) Load Dispatch-Monitor and Operate Transmission System 86 1,254,735 1,188,357(561.3) Load Dispatch-Transmission Service and Scheduling 87 1,316,482 1,423,636(561.4) Scheduling, System Control and Dispatch Services 88(561.5) Reliability, Planning and Standards Development 89(561.6) Transmission Service Studies 90(561.7) Generation Interconnection Studies 91 108,008 102,697(561.8) Reliability, Planning and Standards Development Services 92(562) Station Expenses 93 1,987,214 2,252,352(563) Overhead Lines Expenses 94 660,035 746,070(564) Underground Lines Expenses 95(565) Transmission of Electricity by Others 96 5,918,507 6,462,104(566) Miscellaneous Transmission Expenses 97 336,835 307,899(567) Rents 98 1,569,168 3,283,621TOTAL Operation (Enter Total of lines 83 thru 98) 99 16,417,808 19,285,713Maintenance 100(568) Maintenance Supervision and Engineering 101 540,340 220,612(569) Maintenance of Structures 102 195(569.1) Maintenance of Computer Hardware 103 66,482 54,018(569.2) Maintenance of Computer Software 104 324,033 347,776(569.3) Maintenance of Communication Equipment 105 28,510 26,183(569.4) Maintenance of Miscellaneous Regional Transmission Plant 106(570) Maintenance of Station Equipment 107 3,447,662 2,975,539(571) Maintenance of Overhead Lines 108 2,781,256 3,675,361(572) Maintenance of Underground Lines 109(573) Maintenance of Miscellaneous Transmission Plant 110 -40 5,474TOTAL Maintenance (Total of lines 101 thru 110) 111 7,188,438 7,304,963TOTAL Transmission Expenses (Total of lines 99 and 111) 112 23,606,246 26,590,676
FERC FORM NO. 1 (ED. 12-93) Page 321
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd ofIdaho Power Company X
04/13/20122011/Q4
Line No.
Account Amount for
(c)(b)(a)Current Year Previous Year
Amount forIf the amount for previous year is not derived from previously reported figures, explain in footnote.
3. REGIONAL MARKET EXPENSES 113Operation 114(575.1) Operation Supervision 115(575.2) Day-Ahead and Real-Time Market Facilitation 116(575.3) Transmission Rights Market Facilitation 117(575.4) Capacity Market Facilitation 118(575.5) Ancillary Services Market Facilitation 119(575.6) Market Monitoring and Compliance 120(575.7) Market Facilitation, Monitoring and Compliance Services 121(575.8) Rents 122Total Operation (Lines 115 thru 122) 123Maintenance 124(576.1) Maintenance of Structures and Improvements 125(576.2) Maintenance of Computer Hardware 126(576.3) Maintenance of Computer Software 127(576.4) Maintenance of Communication Equipment 128(576.5) Maintenance of Miscellaneous Market Operation Plant 129Total Maintenance (Lines 125 thru 129) 130TOTAL Regional Transmission and Market Op Expns (Total 123 and 130) 1314. DISTRIBUTION EXPENSES 132Operation 133(580) Operation Supervision and Engineering 134 3,713,391 3,746,431(581) Load Dispatching 135 3,419,960 3,482,055(582) Station Expenses 136 1,277,818 1,192,869(583) Overhead Line Expenses 137 3,029,340 3,039,224(584) Underground Line Expenses 138 1,792,342 1,825,857(585) Street Lighting and Signal System Expenses 139 79,537 122,065(586) Meter Expenses 140 4,219,270 4,130,937(587) Customer Installations Expenses 141 1,521,427 1,092,077(588) Miscellaneous Expenses 142 5,004,179 5,494,553(589) Rents 143 440,788 830,940TOTAL Operation (Enter Total of lines 134 thru 143) 144 24,498,052 24,957,008Maintenance 145(590) Maintenance Supervision and Engineering 146 371,979 402,381(591) Maintenance of Structures 147 -11,385 5,711(592) Maintenance of Station Equipment 148 3,774,723 3,230,860(593) Maintenance of Overhead Lines 149 14,297,636 14,495,482(594) Maintenance of Underground Lines 150 1,003,405 1,054,033(595) Maintenance of Line Transformers 151 448,157 433,841(596) Maintenance of Street Lighting and Signal Systems 152 587,953 554,042(597) Maintenance of Meters 153 700,080 472,599(598) Maintenance of Miscellaneous Distribution Plant 154 137,583 252,535TOTAL Maintenance (Total of lines 146 thru 154) 155 21,310,131 20,901,484TOTAL Distribution Expenses (Total of lines 144 and 155) 156 45,808,183 45,858,4925. CUSTOMER ACCOUNTS EXPENSES 157Operation 158(901) Supervision 159 410,702 427,283(902) Meter Reading Expenses 160 4,026,937 2,453,647(903) Customer Records and Collection Expenses 161 12,988,731 12,944,062(904) Uncollectible Accounts 162 4,638,855 4,269,718(905) Miscellaneous Customer Accounts Expenses 163 342 252TOTAL Customer Accounts Expenses (Total of lines 159 thru 163) 164 22,065,567 20,094,962
FERC FORM NO. 1 (ED. 12-93) Page 322
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd ofIdaho Power Company X
04/13/20122011/Q4
Line No.
Account Amount for
(c)(b)(a)Current Year Previous Year
Amount forIf the amount for previous year is not derived from previously reported figures, explain in footnote.
6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES 165Operation 166(907) Supervision 167 352,779 528,250(908) Customer Assistance Expenses 168 51,959,849 44,034,548(909) Informational and Instructional Expenses 169 31,517 82,775(910) Miscellaneous Customer Service and Informational Expenses 170 864,003 531,823TOTAL Customer Service and Information Expenses (Total 167 thru 170) 171 53,208,148 45,177,3967. SALES EXPENSES 172Operation 173(911) Supervision 174(912) Demonstrating and Selling Expenses 175(913) Advertising Expenses 176(916) Miscellaneous Sales Expenses 177TOTAL Sales Expenses (Enter Total of lines 174 thru 177) 1788. ADMINISTRATIVE AND GENERAL EXPENSES 179Operation 180(920) Administrative and General Salaries 181 63,660,597 67,143,039(921) Office Supplies and Expenses 182 13,613,991 15,742,902(Less) (922) Administrative Expenses Transferred-Credit 183 27,799,634 26,009,805(923) Outside Services Employed 184 7,210,630 4,925,844(924) Property Insurance 185 3,329,577 3,207,120(925) Injuries and Damages 186 5,668,380 5,806,100(926) Employee Pensions and Benefits 187 30,031,098 60,010,908(927) Franchise Requirements 188 2,549(928) Regulatory Commission Expenses 189 3,797,836 3,449,337(929) (Less) Duplicate Charges-Cr. 190(930.1) General Advertising Expenses 191 417,950 552,129(930.2) Miscellaneous General Expenses 192 3,826,102 3,750,121(931) Rents 193 12,600 7,103TOTAL Operation (Enter Total of lines 181 thru 193) 194 103,771,676 138,584,798Maintenance 195(935) Maintenance of General Plant 196 4,182,610 4,522,111TOTAL Administrative & General Expenses (Total of lines 194 and 196) 197 107,954,286 143,106,909TOTAL Elec Op and Maint Expns (Total 80,112,131,156,164,171,178,197) 198 693,221,250 709,101,987
FERC FORM NO. 1 (ED. 12-93) Page 323
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
PURCHASED POWER (Account 555)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
Name of Company or Public Authority
(c)(b)(a)
FERC RateMonthly Billing
Average
(d)
Statistical
cationClassifi- Schedule or
Tariff Number Demand (MW)(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average Average
Monthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing ofdebits 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 useacronyms. 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 supplierincludes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be thesame 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 economicreasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy fromthird parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meetsthe definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as theearliest 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 lessthan 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 oneyear or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability ofservice, 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" meanslonger 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 allnon-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature ofthe service in a footnote for each adjustment.
Cogeneration and Small Power Producers 1
N/AN/AN/AAgPower Jerome/Double A Digester -LU 2
.488Allan Ravenscroft/Malad River -LU 3
N/AN/AN/ABennett Creek Wind Farm -LU 4
N/AN/AN/ABettencourt DryCreek Biofactory -LU 5
N/AN/AN/ABig Sky West Dairy Digester -LU 6
Big Wood Canal Company 7
N/AN/AN/A Black Canyon #3 -LU 8
N/AN/AN/A Jim Knight -LU 9
N/AN/AN/A Sagebrush -LU 10
N/AN/AN/ABlind Canyon Hydro -LU 11
N/AN/AN/ABranchflower/Trout Company -LU 12
N/AN/AN/ABurley Butte Wind Park -LU 13
N/AN/AN/ABypass Limited -LU 14
FERC FORM NO. 1 (ED. 12-90) Page 326
Total
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
PURCHASED POWER (Account 555)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
Name of Company or Public Authority
(c)(b)(a)
FERC RateMonthly Billing
Average
(d)
Statistical
cationClassifi- Schedule or
Tariff Number Demand (MW)(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average Average
Monthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing ofdebits 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 useacronyms. 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 supplierincludes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be thesame 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 economicreasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy fromthird parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meetsthe definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as theearliest 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 lessthan 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 oneyear or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability ofservice, 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" meanslonger 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 allnon-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature ofthe service in a footnote for each adjustment.
N/AN/AN/ACamp Reed Wind Park -LU 1
N/AN/AN/ACargill Inc./B6 Anaerobic Digester -LU 2
N/AN/AN/ACassia Gulch Wind Park -LU 3
N/AN/AN/ACassia Wind Farm -LU 4
N/AN/AN/ACity of Cove, Oregon/Mill Creek -LU 5
N/AN/AN/ACity of Hailey -LU 6
N/AN/AN/ACity of Pocatello -LU 7
N/AN/AN/AClear Springs Food Inc. -LU 8
.05Clifton E. Jenson/Birchcreek -LU 9
Consolidated Hydro Inc./Enel 10
N/AN/AN/A Barber Dam -LU 11
N/AN/AN/A GeoBon #2 -LU 12
N/AN/AN/A Rock Creek #2 -LU 13
N/AN/AN/A Dietrich Drop -LU 14
FERC FORM NO. 1 (ED. 12-90) Page 326.1
Total
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
PURCHASED POWER (Account 555)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
Name of Company or Public Authority
(c)(b)(a)
FERC RateMonthly Billing
Average
(d)
Statistical
cationClassifi- Schedule or
Tariff Number Demand (MW)(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average Average
Monthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing ofdebits 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 useacronyms. 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 supplierincludes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be thesame 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 economicreasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy fromthird parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meetsthe definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as theearliest 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 lessthan 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 oneyear or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability ofservice, 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" meanslonger 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 allnon-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature ofthe service in a footnote for each adjustment.
N/AN/AN/A Lowline #2 -LU 1
N/AN/AN/AContractors Power Group Inc./Mile 28 -LU 2
N/AN/AN/ACrystal Springs Hydro -LU 3
.084Curry Cattle Company -LU 4
N/AN/AN/ADavid McCollum/Canyon Springs -LU 5
N/AN/AN/ADavid R Snedigar -LU 6
N/AN/AN/AD.R. Johnson Lumber/Co Gen Co -SF 7
N/AN/AN/AFaulkner Brothers Hydro Inc. -LU 8
N/AN/AN/AFisheries Development -OS 9
N/AN/AN/AFossil Gulch Wind -LU 10
N/AN/AN/AG2 Energy Hidden Hollow -LU 11
N/AN/AN/AGlenns Ferry Cogen Partners/Magic -LU 12
N/AN/AN/AGolden Valley Wind Park -LU 13
N/AN/AN/AHazelton B Power Company -LU 14
FERC FORM NO. 1 (ED. 12-90) Page 326.2
Total
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
PURCHASED POWER (Account 555)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
Name of Company or Public Authority
(c)(b)(a)
FERC RateMonthly Billing
Average
(d)
Statistical
cationClassifi- Schedule or
Tariff Number Demand (MW)(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average Average
Monthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing ofdebits 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 useacronyms. 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 supplierincludes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be thesame 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 economicreasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy fromthird parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meetsthe definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as theearliest 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 lessthan 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 oneyear or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability ofservice, 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" meanslonger 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 allnon-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature ofthe service in a footnote for each adjustment.
N/AN/AN/AH.K. Hydro Mud Creek S & S -LU 1
N/AN/AN/AHoreshoe Bend Hydro -LU 2
N/AN/AN/AHorseshoe Bend Wind/United Materials -LU 3
N/AN/AN/AHot Springs Wind Farm -LU 4
N/AN/AN/AIdaho Winds/Sawtooth Wind Project -LU 5
N/AN/AN/AJR Simplot Co. -LU 6
N/AN/AN/AJ.M. Miller/Sahko Hydro -LU 7
N/AN/AN/AJames B. Howell/CHI Elk Creek -LU 8
N/AN/AN/AJohn R LeMoyne -LU 9
N/AN/AN/AKasel & Witherspoon -LU 10
N/AN/AN/AKoyle Hydro Inc. -LU 11
N/AN/AN/ALateral 10 Ventures -LU 12
N/AN/AN/ALemhi Hydro Power Co./Schaffner -LU 13
N/AN/AN/ALime Wind -LU 14
FERC FORM NO. 1 (ED. 12-90) Page 326.3
Total
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
PURCHASED POWER (Account 555)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
Name of Company or Public Authority
(c)(b)(a)
FERC RateMonthly Billing
Average
(d)
Statistical
cationClassifi- Schedule or
Tariff Number Demand (MW)(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average Average
Monthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing ofdebits 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 useacronyms. 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 supplierincludes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be thesame 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 economicreasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy fromthird parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meetsthe definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as theearliest 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 lessthan 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 oneyear or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability ofservice, 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" meanslonger 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 allnon-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature ofthe service in a footnote for each adjustment.
N/AN/AN/ALittle Mac Power Co./Cedar Draw -LU 1
N/AN/AN/ALittle Wood River Irrigation District -LU 2
N/AN/AN/AMagic Reservoir Hydro -LU 3
N/AN/AN/AMarco Rancher's Irrigation Inc. -LU 4
N/AN/AN/AMarysville Hydro Partners/Falls River -LU 5
N/AN/AN/AMilner Dam Wind Park -LU 6
N/AN/AN/AMud Creek White Hydro, Inc -LU 7
N/AN/AN/AOregon Trail Wind Park -LU 8
Owyhee Irrigation District 9
N/AN/AN/A Mitchell Butte -LU 10
N/AN/AN/A Owyhee Dam -LU 11
N/AN/AN/A Tunnel #1 -LU 12
N/AN/AN/APaynes Ferry Wind Park -LU 13
1.389Pigeon Cove Power -LU 14
FERC FORM NO. 1 (ED. 12-90) Page 326.4
Total
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
PURCHASED POWER (Account 555)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
Name of Company or Public Authority
(c)(b)(a)
FERC RateMonthly Billing
Average
(d)
Statistical
cationClassifi- Schedule or
Tariff Number Demand (MW)(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average Average
Monthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing ofdebits 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 useacronyms. 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 supplierincludes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be thesame 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 economicreasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy fromthird parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meetsthe definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as theearliest 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 lessthan 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 oneyear or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability ofservice, 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" meanslonger 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 allnon-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature ofthe service in a footnote for each adjustment.
N/AN/AN/APilgrim Stage Station Wind Park -LU 1
N/AN/AN/APristine Springs Inc #3 -LU 2
N/AN/AN/APristine Springs Inc #1 -LU 3
N/AN/AN/AReynolds Irrigation District -LU 4
Richard Kaster 5
N/AN/AN/A Box Canyon -LU 6
N/AN/AN/A Briggs Creek -LU 7
N/AN/AN/ARim View Trout Company -OS 8
N/AN/AN/ARiverside Hydro/Mora Drop -LU 9
N/AN/AN/ARiverside Investments/Arena Drop -LU 10
1.732Rock Creek #1 Joint Venture -LU 11
N/AN/AN/ARockland Wind Project -LU 12
N/AN/AN/ARupert Cogen Partners/Magic Valley -LU 13
N/AN/AN/ASalmon Falls Wind Park -LU 14
FERC FORM NO. 1 (ED. 12-90) Page 326.5
Total
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
PURCHASED POWER (Account 555)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
Name of Company or Public Authority
(c)(b)(a)
FERC RateMonthly Billing
Average
(d)
Statistical
cationClassifi- Schedule or
Tariff Number Demand (MW)(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average Average
Monthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing ofdebits 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 useacronyms. 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 supplierincludes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be thesame 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 economicreasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy fromthird parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meetsthe definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as theearliest 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 lessthan 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 oneyear or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability ofservice, 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" meanslonger 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 allnon-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature ofthe service in a footnote for each adjustment.
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
PURCHASED POWER (Account 555)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
Name of Company or Public Authority
(c)(b)(a)
FERC RateMonthly Billing
Average
(d)
Statistical
cationClassifi- Schedule or
Tariff Number Demand (MW)(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average Average
Monthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing ofdebits 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 useacronyms. 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 supplierincludes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be thesame 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 economicreasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy fromthird parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meetsthe definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as theearliest 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 lessthan 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 oneyear or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability ofservice, 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" meanslonger 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 allnon-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature ofthe service in a footnote for each adjustment.
N/AN/AN/AWilliam Arkoosh/Littlewood -LU 1
N/AN/AN/AWillis and Betty Deveny/Shingle Creek -LU 2
N/AN/AN/AWilson Power Company -LU 3
N/AN/AN/AYahoo Creek Wind Park -LU 4
N/AN/AN/ANew Wind Projects Scheduled Energy -LU 5
Other Purchased Power 6
N/AN/AN/AArizona Public Service Co. WSPPSF 7
N/AN/AN/AAvista Corp. T-12SF 8
N/AN/AN/AAvista Corp. WSPPSF 9
N/AN/AN/AAvista Corp. WSPPOS 10
N/AN/AN/ABarclays Bank PLC WSPPSF 11
N/AN/AN/ABarclays Bank PLC -OS 12
N/AN/AN/ABlack Hills Power Inc. WSPPSF 13
N/AN/AN/ABonneville Power Administration WSPPOS 14
FERC FORM NO. 1 (ED. 12-90) Page 326.7
Total
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
PURCHASED POWER (Account 555)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
Name of Company or Public Authority
(c)(b)(a)
FERC RateMonthly Billing
Average
(d)
Statistical
cationClassifi- Schedule or
Tariff Number Demand (MW)(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average Average
Monthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing ofdebits 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 useacronyms. 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 supplierincludes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be thesame 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 economicreasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy fromthird parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meetsthe definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as theearliest 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 lessthan 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 oneyear or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability ofservice, 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" meanslonger 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 allnon-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature ofthe service in a footnote for each adjustment.
N/AN/AN/ABonneville Power Administration WSPPSF 1
N/AN/AN/ABonneville Power Administration WSPPSF 2
N/AN/AN/ABP Energy Company WSPPSF 3
N/AN/AN/ACalpine Energy Services, L.P. WSPPSF 4
N/AN/AN/ACargill Power Markets LLC WSPPSF 5
N/AN/AN/AChelan Co PUD WSPPSF 6
N/AN/AN/ACitigroup Energy Inc. WSPPSF 7
N/AN/AN/ACitigroup Energy Inc. -OS 8
N/AN/AN/AClatskanie PUD WSPPSF 9
N/AN/AN/AConstellation Energy Commodities Group WSPPSF 10
N/AN/AN/ADB Energy Trading LLC WSPPSF 11
N/AN/AN/ADouglas County PUD WSPPSF 12
N/AN/AN/AEDF Trading North America, LLC WSPPSF 13
N/AN/AN/AEl Paso Electric Company WSPPSF 14
FERC FORM NO. 1 (ED. 12-90) Page 326.8
Total
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
PURCHASED POWER (Account 555)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
Name of Company or Public Authority
(c)(b)(a)
FERC RateMonthly Billing
Average
(d)
Statistical
cationClassifi- Schedule or
Tariff Number Demand (MW)(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average Average
Monthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing ofdebits 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 useacronyms. 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 supplierincludes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be thesame 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 economicreasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy fromthird parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meetsthe definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as theearliest 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 lessthan 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 oneyear or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability ofservice, 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" meanslonger 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 allnon-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature ofthe service in a footnote for each adjustment.
N/AN/AN/AEugene Water & Electric Board WSPPSF 1
N/AN/AN/AGlendale Power Marketing WSPPSF 2
N/AN/AN/AGrant CO Public Utility District #2 -- WSPPSF 3
N/AN/AN/AIBERDROLA RENEWABLES, Inc. WSPPSF 4
N/AN/AN/AJ.P. Morgan Ventures Energy Corporatio WSPPSF 5
N/AN/AN/AJPMorgan Chase Bank, N.A. -OS 6
N/AN/AN/AJefferies Bache -OS 7
N/AN/AN/ALos Alamos County Utilities WSPPSF 8
N/AN/AN/AMacquarie Cook Power Inc. WSPPSF 9
N/AN/AN/AMacquarie Cook Power Inc. -OS 10
N/AN/AN/AMorgan Stanley Capital Group Inc. V6-62SF 11
N/AN/AN/AMorgan Stanley Capital Group Inc. V6-62SF 12
N/AN/AN/ANaturEner USA, LLC WSPPSF 13
N/AN/AN/ANevada Power Co, DBA NV Energy WSPPSF 14
FERC FORM NO. 1 (ED. 12-90) Page 326.9
Total
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
PURCHASED POWER (Account 555)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
Name of Company or Public Authority
(c)(b)(a)
FERC RateMonthly Billing
Average
(d)
Statistical
cationClassifi- Schedule or
Tariff Number Demand (MW)(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average Average
Monthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing ofdebits 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 useacronyms. 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 supplierincludes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be thesame 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 economicreasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy fromthird parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meetsthe definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as theearliest 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 lessthan 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 oneyear or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability ofservice, 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" meanslonger 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 allnon-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature ofthe service in a footnote for each adjustment.
N/AN/AN/ANextEra Energy Power Marketing, LLC WSPPSF 1
N/AN/AN/ANorthWestern Energy T-7SF 2
N/AN/AN/ANorthWestern Energy WSPPSF 3
N/AN/AN/APacifiCorp Inc. T-13SF 4
N/AN/AN/APacifiCorp Inc. WSPPSF 5
N/AN/AN/APacifiCorp Inc. WSPPSF 6
N/AN/AN/APacifiCorp Inc. WSPPOS 7
N/AN/AN/APortland General Electric Company T-14SF 8
N/AN/AN/APortland General Electric Company WSPPSF 9
N/AN/AN/APortland General Electric Company WSPPSF 10
N/AN/AN/APowerex Corp. WSPPSF 11
N/AN/AN/APowerex Corp. WSPPSF 12
N/AN/AN/APPL EnergyPlus, LLC WSPPIF 13
N/AN/AN/APPL EnergyPlus, LLC WSPPSF 14
FERC FORM NO. 1 (ED. 12-90) Page 326.10
Total
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
PURCHASED POWER (Account 555)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
Name of Company or Public Authority
(c)(b)(a)
FERC RateMonthly Billing
Average
(d)
Statistical
cationClassifi- Schedule or
Tariff Number Demand (MW)(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average Average
Monthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing ofdebits 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 useacronyms. 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 supplierincludes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be thesame 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 economicreasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy fromthird parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meetsthe definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as theearliest 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 lessthan 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 oneyear or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability ofservice, 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" meanslonger 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 allnon-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature ofthe service in a footnote for each adjustment.
N/AN/AN/APublic Service Company of New Mexico WSPPSF 1
N/AN/AN/APuget Sound Energy, Inc. T-9SF 2
N/AN/AN/APuget Sound Energy, Inc. WSPPSF 3
N/AN/AN/APuget Sound Energy, Inc. WSPPSF 4
N/AN/AN/ARainbow Energy Marketing Corporation WSPPSF 5
N/AN/AN/ASan Diego Gas and Electric WSPPSF 6
N/AN/AN/ASeattle City Light WSPPSF 7
N/AN/AN/ASeattle City Light WSPPSF 8
N/AN/AN/AShell Energy North America (US), L.P. WSPPSF 9
N/AN/AN/AShell Energy North America (US), L.P. -OS 10
N/AN/AN/ASierra Pacific Power Co., dba NV Energ T-55SF 11
N/AN/AN/ASierra Pacific Power Co., dba NV Energ WSPPSF 12
N/AN/AN/ASierra Pacific Power Co., dba NV Energ WSPPSF 13
N/AN/AN/ASierra Pacific Power Co., dba NV Energ WSPPOS 14
FERC FORM NO. 1 (ED. 12-90) Page 326.11
Total
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
PURCHASED POWER (Account 555)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
Name of Company or Public Authority
(c)(b)(a)
FERC RateMonthly Billing
Average
(d)
Statistical
cationClassifi- Schedule or
Tariff Number Demand (MW)(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average Average
Monthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing ofdebits 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 useacronyms. 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 supplierincludes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be thesame 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 economicreasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy fromthird parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meetsthe definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as theearliest 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 lessthan 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 oneyear or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability ofservice, 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" meanslonger 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 allnon-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature ofthe service in a footnote for each adjustment.
N/AN/AN/ASnohomish County PUD WSPPSF 1
N/AN/AN/ASouthern California Edison WSPPSF 2
N/AN/AN/ASouthwestern Public Service Company WSPPSF 3
N/AN/AN/ATacoma Power WSPPSF 4
N/AN/AN/AThe Energy Authority, Inc. WSPPSF 5
N/AN/AN/ATransAlta Energy Marketing (U.S.) Inc. WSPPSF 6
N/AN/AN/ATransAlta Energy Marketing (U.S.) Inc. WSPPSF 7
N/AN/AN/ATri-State Generation and Transmission WSPPSF 8
N/AN/AN/ATucson Electric Power Company WSPPSF 9
N/AN/AN/AWells Fargo Authority, N.A. -OS 10
N/AN/AN/AWestern Area Power Administration WSPPSF 11
N/AN/AN/ARaft River Energy I LLC -LU 12
N/AN/AN/ATelocaset Wind Power Partners LLC APP-ALU 13
N/AN/AN/ANet Metering Customers -OS 14
FERC FORM NO. 1 (ED. 12-90) Page 326.12
Total
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
PURCHASED POWER (Account 555)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
Name of Company or Public Authority
(c)(b)(a)
FERC RateMonthly Billing
Average
(d)
Statistical
cationClassifi- Schedule or
Tariff Number Demand (MW)(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average Average
Monthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing ofdebits 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 useacronyms. 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 supplierincludes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be thesame 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 economicreasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy fromthird parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meetsthe definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as theearliest 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 lessthan 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 oneyear or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability ofservice, 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" meanslonger 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 allnon-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature ofthe service in a footnote for each adjustment.
N/AN/AN/AOregon Solar Customers -OS 1
N/AN/AN/AMacquarie Energy LLC WSPPAD 2
Power Exchanges 3
---Benton Co Public Utility District #1 -EX 4
---Bonneville Power Administration -EX 5
---NorthWestern Energy -EX 6
---PacifiCorp Inc. -EX 7
---Puget Sound Energy, Inc. -EX 8
---Sierra Pacific Power Co., dba NV Energ -EX 9
---Utah Associated Municipal Power System -EX 10
---Clatskanie PUD 153EX 11
---Sierra Pacific Power Co., dba NV Energ WSPPEX 12
---PacifiCorp Inc WSPPEX 13
Other Transactions 14
FERC FORM NO. 1 (ED. 12-90) Page 326.13
Total
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
PURCHASED POWER (Account 555)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
Name of Company or Public Authority
(c)(b)(a)
FERC RateMonthly Billing
Average
(d)
Statistical
cationClassifi- Schedule or
Tariff Number Demand (MW)(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average Average
Monthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing ofdebits 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 useacronyms. 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 supplierincludes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be thesame 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 economicreasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy fromthird parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meetsthe definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as theearliest 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 lessthan 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 oneyear or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability ofservice, 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" meanslonger 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 allnon-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature ofthe service in a footnote for each adjustment.
---Acct Valuation-Clatskanie PUD Exchange - 1
---Write-Off (Lehman Brothers) - 2
3
4
5
6
7
8
9
10
11
12
13
14
FERC FORM NO. 1 (ED. 12-90) Page 326.14
Total
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
PURCHASED POWER(Account 555) (Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGESMegaWatt Hours
ReceivedMegaWatt Hours
Delivered(l) (m)
of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reportingyears. 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 appropriatedesignation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, asidentified 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 themonthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the averagemonthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCPdemand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand duringthe hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) mustbe 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 megawatthoursof 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, includingout-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlementamount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by theagreement, 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 reportedas Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. Thetotal 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.
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
PURCHASED POWER(Account 555) (Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGESMegaWatt Hours
ReceivedMegaWatt Hours
Delivered(l) (m)
of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reportingyears. 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 appropriatedesignation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, asidentified 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 themonthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the averagemonthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCPdemand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand duringthe hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) mustbe 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 megawatthoursof 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, includingout-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlementamount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by theagreement, 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 reportedas Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. Thetotal 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.
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
PURCHASED POWER(Account 555) (Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGESMegaWatt Hours
ReceivedMegaWatt Hours
Delivered(l) (m)
of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reportingyears. 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 appropriatedesignation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, asidentified 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 themonthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the averagemonthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCPdemand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand duringthe hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) mustbe 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 megawatthoursof 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, includingout-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlementamount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by theagreement, 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 reportedas Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. Thetotal 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.
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
PURCHASED POWER(Account 555) (Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGESMegaWatt Hours
ReceivedMegaWatt Hours
Delivered(l) (m)
of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reportingyears. 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 appropriatedesignation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, asidentified 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 themonthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the averagemonthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCPdemand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand duringthe hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) mustbe 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 megawatthoursof 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, includingout-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlementamount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by theagreement, 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 reportedas Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. Thetotal 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.
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
PURCHASED POWER(Account 555) (Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGESMegaWatt Hours
ReceivedMegaWatt Hours
Delivered(l) (m)
of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reportingyears. 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 appropriatedesignation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, asidentified 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 themonthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the averagemonthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCPdemand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand duringthe hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) mustbe 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 megawatthoursof 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, includingout-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlementamount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by theagreement, 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 reportedas Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. Thetotal 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.
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
PURCHASED POWER(Account 555) (Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGESMegaWatt Hours
ReceivedMegaWatt Hours
Delivered(l) (m)
of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reportingyears. 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 appropriatedesignation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, asidentified 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 themonthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the averagemonthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCPdemand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand duringthe hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) mustbe 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 megawatthoursof 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, includingout-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlementamount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by theagreement, 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 reportedas Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. Thetotal 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.
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
PURCHASED POWER(Account 555) (Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGESMegaWatt Hours
ReceivedMegaWatt Hours
Delivered(l) (m)
of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reportingyears. 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 appropriatedesignation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, asidentified 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 themonthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the averagemonthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCPdemand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand duringthe hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) mustbe 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 megawatthoursof 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, includingout-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlementamount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by theagreement, 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 reportedas Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. Thetotal 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.
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
PURCHASED POWER(Account 555) (Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGESMegaWatt Hours
ReceivedMegaWatt Hours
Delivered(l) (m)
of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reportingyears. 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 appropriatedesignation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, asidentified 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 themonthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the averagemonthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCPdemand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand duringthe hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) mustbe 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 megawatthoursof 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, includingout-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlementamount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by theagreement, 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 reportedas Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. Thetotal 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.
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
PURCHASED POWER(Account 555) (Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGESMegaWatt Hours
ReceivedMegaWatt Hours
Delivered(l) (m)
of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reportingyears. 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 appropriatedesignation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, asidentified 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 themonthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the averagemonthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCPdemand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand duringthe hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) mustbe 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 megawatthoursof 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, includingout-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlementamount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by theagreement, 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 reportedas Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. Thetotal 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.
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
PURCHASED POWER(Account 555) (Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGESMegaWatt Hours
ReceivedMegaWatt Hours
Delivered(l) (m)
of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reportingyears. 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 appropriatedesignation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, asidentified 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 themonthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the averagemonthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCPdemand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand duringthe hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) mustbe 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 megawatthoursof 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, includingout-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlementamount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by theagreement, 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 reportedas Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. Thetotal 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.
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
PURCHASED POWER(Account 555) (Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGESMegaWatt Hours
ReceivedMegaWatt Hours
Delivered(l) (m)
of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reportingyears. 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 appropriatedesignation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, asidentified 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 themonthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the averagemonthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCPdemand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand duringthe hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) mustbe 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 megawatthoursof 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, includingout-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlementamount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by theagreement, 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 reportedas Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. Thetotal 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.
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
PURCHASED POWER(Account 555) (Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGESMegaWatt Hours
ReceivedMegaWatt Hours
Delivered(l) (m)
of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reportingyears. 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 appropriatedesignation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, asidentified 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 themonthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the averagemonthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCPdemand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand duringthe hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) mustbe 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 megawatthoursof 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, includingout-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlementamount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by theagreement, 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 reportedas Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. Thetotal 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.
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
PURCHASED POWER(Account 555) (Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGESMegaWatt Hours
ReceivedMegaWatt Hours
Delivered(l) (m)
of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reportingyears. 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 appropriatedesignation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, asidentified 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 themonthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the averagemonthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCPdemand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand duringthe hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) mustbe 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 megawatthoursof 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, includingout-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlementamount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by theagreement, 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 reportedas Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. Thetotal 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.
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
PURCHASED POWER(Account 555) (Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGESMegaWatt Hours
ReceivedMegaWatt Hours
Delivered(l) (m)
of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reportingyears. 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 appropriatedesignation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, asidentified 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 themonthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the averagemonthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCPdemand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand duringthe hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) mustbe 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 megawatthoursof 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, includingout-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlementamount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by theagreement, 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 reportedas Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. Thetotal 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.
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
PURCHASED POWER(Account 555) (Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGESMegaWatt Hours
ReceivedMegaWatt Hours
Delivered(l) (m)
of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reportingyears. 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 appropriatedesignation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, asidentified 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 themonthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the averagemonthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCPdemand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand duringthe hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) mustbe 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 megawatthoursof 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, includingout-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlementamount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by theagreement, 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 reportedas Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. Thetotal 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.
Schedule Page: 326 Line No.: 3 Column: eUnavailable Schedule Page: 326 Line No.: 3 Column: fUnavailable Schedule Page: 326.1 Line No.: 9 Column: eUnavailable Schedule Page: 326.1 Line No.: 9 Column: fUnavailable Schedule Page: 326.2 Line No.: 4 Column: eUnavailable Schedule Page: 326.2 Line No.: 4 Column: fUnavailable Schedule Page: 326.2 Line No.: 9 Column: bNon Firm Purchases Schedule Page: 326.2 Line No.: 12 Column: aISDA Master Agreement with Shell Energy North America dated November 1, 2009 Schedule Page: 326.2 Line No.: 14 Column: aIda West, a subsidiary of Idaho Power Company, has partial ownership of these projects. Schedule Page: 326.4 Line No.: 5 Column: aIda West, a subsidiary of Idaho Power Company, has partial ownership of these projects. Schedule Page: 326.4 Line No.: 14 Column: eUnavailable Schedule Page: 326.4 Line No.: 14 Column: fUnavailable Schedule Page: 326.5 Line No.: 8 Column: bNon Firm Purchases Schedule Page: 326.5 Line No.: 11 Column: eUnavailable Schedule Page: 326.5 Line No.: 11 Column: fUnavailable Schedule Page: 326.6 Line No.: 6 Column: aIda West, a subsidiary of Idaho Power Company, has partial ownership of these projects. Schedule Page: 326.6 Line No.: 7 Column: aThe Tamarack Energy Partnership demand readings are taken from an electronic demandrecorder provided by Idaho Power Co. The actual demand is not used in determining the costof energy.Schedule Page: 326.6 Line No.: 7 Column: eUnavailable Schedule Page: 326.6 Line No.: 7 Column: fUnavailable Schedule Page: 326.6 Line No.: 8 Column: bNon Firm Purchases Schedule Page: 326.7 Line No.: 3 Column: aIda West, a subsidiary of Idaho Power Company, has partial ownership of these projects. Schedule Page: 326.7 Line No.: 5 Column: bEnergy scheduled in December 2010, booked in January 2011 Schedule Page: 326.7 Line No.: 10 Column: bFinancial Transmission Losses Schedule Page: 326.7 Line No.: 12 Column: bISDA Master Agreement with Barclays Bank PLC dated March 2, 2011 Schedule Page: 326.7 Line No.: 14 Column: bFinancial Transmission Losses Schedule Page: 326.8 Line No.: 2 Column: b
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87) Page 450.1
Non Firm Purchases Schedule Page: 326.8 Line No.: 8 Column: bISDA Master Agreement with Citigroup Energy PLC dated March 7, 2011 Schedule Page: 326.9 Line No.: 6 Column: bISDA Master Agreement with JP Morgan Chase Bank dated November 4, 2005 Schedule Page: 326.9 Line No.: 7 Column: bPrudential Bache Commodities, LLC (Jefferies Bache) Futures Account Document, datedSeptember 4, 2008 Schedule Page: 326.9 Line No.: 10 Column: bISDA Master Agreement with Macquarie Energy PLC dated April 12, 2011 Schedule Page: 326.9 Line No.: 12 Column: bNon Firm Purchases Schedule Page: 326.10 Line No.: 5 Column: bNon Firm Purchases Schedule Page: 326.10 Line No.: 7 Column: bFinancial Transmission Losses Schedule Page: 326.11 Line No.: 4 Column: bNon Firm Purchases Schedule Page: 326.11 Line No.: 10 Column: bISDA Master Agreement with Shell Energy North America dated November 1, 2009 Schedule Page: 326.11 Line No.: 13 Column: bNon Firm Purchases Schedule Page: 326.11 Line No.: 14 Column: bFinancial Transmission Losses Schedule Page: 326.12 Line No.: 10 Column: bISDA Master Agreement with Wells Fargo Bank, N.A., dated March 1, 2006 Schedule Page: 326.12 Line No.: 12 Column: bUnavailable Schedule Page: 326.12 Line No.: 14 Column: bSchedule 84 Net Metering Schedule Page: 326.13 Line No.: 1 Column: bSchedule 88 Oregon Solar Schedule Page: 326.13 Line No.: 2 Column: b December 2010 adjustmentSchedule Page: 326.13 Line No.: 4 Column: bScheduled losses not removed with loss transactions Schedule Page: 326.13 Line No.: 5 Column: bScheduled losses not removed with loss transactions Schedule Page: 326.13 Line No.: 6 Column: bScheduled losses not removed with loss transactions Schedule Page: 326.13 Line No.: 7 Column: bScheduled losses not removed with loss transactions Schedule Page: 326.13 Line No.: 8 Column: bScheduled losses not removed with loss transactions Schedule Page: 326.13 Line No.: 9 Column: bScheduled losses not removed with loss transactions Schedule Page: 326.13 Line No.: 10 Column: bScheduled losses not removed with loss transactions
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87) Page 450.2
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1)
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd ofIdaho Power Company X
04/13/20122011/Q4
Line No.
Payment By
(c)(b)(a) (d)
Statistical
cationClassifi-
(Footnote Affiliation)
(Including transactions referred to as 'wheeling')
(Company of Public Authority)(Footnote Affiliation)
(Company of Public Authority)(Footnote Affiliation)
(Company of Public Authority)Energy Received From Energy Delivered To
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities, qualifyingfacilities, 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 orpublic 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 footnoteany 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 PointTransmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point TransmissionReservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this codefor any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for eachadjustment. See General Instruction for definitions of codes.
Bonneville Power Administration - OTEC Bonneville Power Administration Oregon Trails Electric Co-op FNO 1
Bonneville Power Administration - USBR Bonneville Power Administration United States Bureau of Reclamati FNO 2
Bonneville Power Administration - Raft Bonneville Power Administration Raft River Electric Co-op FNO 3
Bonneville Power Administration - PF Bonneville Power Administration Priority Firm Customers FNO 4
Milner Irrigation District United States Bureau of Reclamati Milner Irrigation District OLF 5
Cargill Seattle City Light Bonneville Power Administration OS 6
PacifiCorp PacifiCorp West PacifiCorp West FNO 7
United States Bureau of Indian Affairs Bonneville Power Administration United States Bureau of Indian Af OS 8
PacifiCorp PacifiCorp West PacifiCorp West OS 9
BC Hydro Powerex NorthWestern/PacifiCorp East PacifiCorp East NF 10
BC Hydro Powerex NorthWestern/PacifiCorp East Sierra Pacific Power NF 11
BC Hydro Powerex PacifiCorp East NorthWestern/PacifiCorp East NF 12
BC Hydro Powerex PacifiCorp East PacifiCorp East NF 13
BC Hydro Powerex PacifiCorp East PacifiCorp West NF 14
BC Hydro Powerex PacifiCorp East Bonneville Power Administration NF 15
BC Hydro Powerex PacifiCorp East Avista NF 16
BC Hydro Powerex PacifiCorp East Sierra Pacific Power NF 17
BC Hydro Powerex PacifiCorp East PacifiCorp West NF 18
BC Hydro Powerex NorthWestern/PacifiCorp East PacifiCorp East NF 19
BC Hydro Powerex NorthWestern/PacifiCorp East PacifiCorp East SFP 20
BC Hydro Powerex NorthWestern/PacifiCorp East PacifiCorp East NF 21
BC Hydro Powerex NorthWestern/PacifiCorp East PacifiCorp East SFP 22
BC Hydro Powerex NorthWestern/PacifiCorp East PacifiCorp West NF 23
BC Hydro Powerex NorthWestern/PacifiCorp East Bonneville Power Administration NF 24
BC Hydro Powerex NorthWestern/PacifiCorp East Sierra Pacific Power NF 25
BC Hydro Powerex NorthWestern/PacifiCorp East Sierra Pacific Power SFP 26
BC Hydro Powerex PacifiCorp East NorthWestern/PacifiCorp East NF 27
BC Hydro Powerex PacifiCorp East PacifiCorp East NF 28
BC Hydro Powerex PacifiCorp East NorthWestern/PacifiCorp East NF 29
BC Hydro Powerex PacifiCorp East PacifiCorp West NF 30
BC Hydro Powerex PacifiCorp East PacifiCorp West NF 31
BC Hydro Powerex PacifiCorp East Bonneville Power Administration NF 32
BC Hydro Powerex PacifiCorp East Avista NF 33
BC Hydro Powerex PacifiCorp East Sierra Pacific Power NF 34
FERC FORM NO. 1 (ED. 12-90) Page 328
TOTAL
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1)
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd ofIdaho Power Company X
04/13/20122011/Q4
Line No.
Payment By
(c)(b)(a) (d)
Statistical
cationClassifi-
(Footnote Affiliation)
(Including transactions referred to as 'wheeling')
(Company of Public Authority)(Footnote Affiliation)
(Company of Public Authority)(Footnote Affiliation)
(Company of Public Authority)Energy Received From Energy Delivered To
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities, qualifyingfacilities, 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 orpublic 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 footnoteany 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 PointTransmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point TransmissionReservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this codefor any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for eachadjustment. See General Instruction for definitions of codes.
BC Hydro Powerex PacifiCorp East Sierra Pacific Power SFP 1
BC Hydro Powerex PacifiCorp East PacifiCorp West NF 2
BC Hydro Powerex PacifiCorp West PacifiCorp East NF 3
BC Hydro Powerex PacifiCorp West PacifiCorp East SFP 4
BC Hydro Powerex PacifiCorp West PacifiCorp East NF 5
BC Hydro Powerex PacifiCorp West PacifiCorp East SFP 6
BC Hydro Powerex PacifiCorp West PacifiCorp West NF 7
BC Hydro Powerex PacifiCorp West Sierra Pacific Power NF 8
BC Hydro Powerex PacifiCorp West Sierra Pacific Power SFP 9
BC Hydro Powerex NorthWestern/PacifiCorp East NorthWestern/PacifiCorp East NF 10
BC Hydro Powerex NorthWestern/PacifiCorp East NorthWestern/PacifiCorp East NF 11
BC Hydro Powerex NorthWestern/PacifiCorp East PacifiCorp East NF 12
BC Hydro Powerex NorthWestern/PacifiCorp East PacifiCorp West NF 13
BC Hydro Powerex NorthWestern/PacifiCorp East PacifiCorp West NF 14
BC Hydro Powerex NorthWestern/PacifiCorp East NorthWestern/PacifiCorp East NF 15
BC Hydro Powerex NorthWestern/PacifiCorp East Bonneville Power Administration NF 16
BC Hydro Powerex NorthWestern/PacifiCorp East Sierra Pacific Power NF 17
BC Hydro Powerex NorthWestern/PacifiCorp East PacifiCorp West NF 18
BC Hydro Powerex Idaho Power Company NorthWestern/PacifiCorp East NF 19
BC Hydro Powerex Idaho Power Company Bonneville Power Administration NF 20
BC Hydro Powerex PacifiCorp West PacifiCorp East NF 21
BC Hydro Powerex PacifiCorp West NorthWestern/PacifiCorp East NF 22
BC Hydro Powerex PacifiCorp West Bonneville Power Administration NF 23
BC Hydro Powerex PacifiCorp West Sierra Pacific Power NF 24
BC Hydro Powerex Idaho Power Company PacifiCorp East NF 25
BC Hydro Powerex Idaho Power Company Bonneville Power Administration NF 26
BC Hydro Powerex Idaho Power Company PacifiCorp West NF 27
BC Hydro Powerex NorthWestern/PacifiCorp East PacifiCorp East NF 28
BC Hydro Powerex NorthWestern/PacifiCorp East PacifiCorp East NF 29
BC Hydro Powerex NorthWestern/PacifiCorp East PacifiCorp West NF 30
BC Hydro Powerex NorthWestern/PacifiCorp East PacifiCorp West NF 31
BC Hydro Powerex NorthWestern/PacifiCorp East Bonneville Power Administration NF 32
BC Hydro Powerex NorthWestern/PacifiCorp East Sierra Pacific Power NF 33
BC Hydro Powerex Bonneville Power Administration PacifiCorp East NF 34
FERC FORM NO. 1 (ED. 12-90) Page 328.1
TOTAL
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1)
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd ofIdaho Power Company X
04/13/20122011/Q4
Line No.
Payment By
(c)(b)(a) (d)
Statistical
cationClassifi-
(Footnote Affiliation)
(Including transactions referred to as 'wheeling')
(Company of Public Authority)(Footnote Affiliation)
(Company of Public Authority)(Footnote Affiliation)
(Company of Public Authority)Energy Received From Energy Delivered To
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities, qualifyingfacilities, 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 orpublic 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 footnoteany 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 PointTransmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point TransmissionReservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this codefor any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for eachadjustment. See General Instruction for definitions of codes.
BC Hydro Powerex Bonneville Power Administration PacifiCorp East SFP 1
BC Hydro Powerex Bonneville Power Administration PacifiCorp East NF 2
BC Hydro Powerex Bonneville Power Administration PacifiCorp East SFP 3
BC Hydro Powerex Bonneville Power Administration PacifiCorp West NF 4
BC Hydro Powerex Bonneville Power Administration Sierra Pacific Power NF 5
BC Hydro Powerex Bonneville Power Administration Sierra Pacific Power SFP 6
BC Hydro Powerex Avista PacifiCorp East NF 7
BC Hydro Powerex Avista PacifiCorp East NF 8
BC Hydro Powerex Avista PacifiCorp West NF 9
BC Hydro Powerex Avista Sierra Pacific Power NF 10
BC Hydro Powerex Sierra Pacific Power NorthWestern/PacifiCorp East NF 11
BC Hydro Powerex Sierra Pacific Power PacifiCorp East NF 12
BC Hydro Powerex Sierra Pacific Power Bonneville Power Administration NF 13
BC Hydro Powerex Idaho Power Company NorthWestern/PacifiCorp East NF 14
BC Hydro Powerex Idaho Power Company Bonneville Power Administration NF 15
BC Hydro Powerex Idaho Power Company NorthWestern/PacifiCorp East NF 16
BC Hydro Powerex Idaho Power Company Bonneville Power Administration NF 17
Black Hills Power PacifiCorp East Sierra Pacific Power NF 18
Black Hills Power PacifiCorp West Bonneville Power Administration NF 19
Black Hills Power Bonneville Power Administration PacifiCorp East NF 20
Black Hills Power Bonneville Power Administration PacifiCorp West NF 21
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration NF 22
Bonneville Power Administration Bonneville Power Administration Sierra Pacific Power NF 23
Bonneville Power Administration Avista Bonneville Power Administration NF 24
Bonneville Power Administration Avista Bonneville Power Administration SFP 25
Bonneville Power Administration Avista Sierra Pacific Power NF 26
Cargill-Alliant PacifiCorp East NorthWestern/PacifiCorp East NF 27
Cargill-Alliant PacifiCorp East NorthWestern/PacifiCorp East NF 28
Cargill-Alliant PacifiCorp East PacifiCorp West NF 29
Cargill-Alliant PacifiCorp East PacifiCorp West NF 30
Cargill-Alliant PacifiCorp East Bonneville Power Administration NF 31
Cargill-Alliant PacifiCorp East Avista NF 32
Cargill-Alliant PacifiCorp East Sierra Pacific Power NF 33
Cargill-Alliant PacifiCorp East Sierra Pacific Power SFP 34
FERC FORM NO. 1 (ED. 12-90) Page 328.2
TOTAL
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1)
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd ofIdaho Power Company X
04/13/20122011/Q4
Line No.
Payment By
(c)(b)(a) (d)
Statistical
cationClassifi-
(Footnote Affiliation)
(Including transactions referred to as 'wheeling')
(Company of Public Authority)(Footnote Affiliation)
(Company of Public Authority)(Footnote Affiliation)
(Company of Public Authority)Energy Received From Energy Delivered To
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities, qualifyingfacilities, 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 orpublic 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 footnoteany 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 PointTransmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point TransmissionReservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this codefor any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for eachadjustment. See General Instruction for definitions of codes.
Cargill-Alliant NorthWestern/PacifiCorp East PacifiCorp East NF 1
Cargill-Alliant NorthWestern/PacifiCorp East PacifiCorp East SFP 2
Cargill-Alliant NorthWestern/PacifiCorp East PacifiCorp East NF 3
Cargill-Alliant NorthWestern/PacifiCorp East PacifiCorp West NF 4
Cargill-Alliant NorthWestern/PacifiCorp East PacifiCorp West SFP 5
Cargill-Alliant NorthWestern/PacifiCorp East Bonneville Power Administration NF 6
Cargill-Alliant NorthWestern/PacifiCorp East Sierra Pacific Power NF 7
Cargill-Alliant NorthWestern/PacifiCorp East Sierra Pacific Power SFP 8
Cargill-Alliant PacifiCorp East PacifiCorp East NF 9
Cargill-Alliant PacifiCorp East PacifiCorp East SFP 10
Cargill-Alliant PacifiCorp East PacifiCorp West NF 11
Cargill-Alliant PacifiCorp East Bonneville Power Administration NF 12
Cargill-Alliant PacifiCorp East Bonneville Power Administration SFP 13
Cargill-Alliant PacifiCorp East Sierra Pacific Power NF 14
Cargill-Alliant PacifiCorp East Sierra Pacific Power SFP 15
Cargill-Alliant PacifiCorp West PacifiCorp East NF 16
Cargill-Alliant PacifiCorp West PacifiCorp East SFP 17
Cargill-Alliant PacifiCorp West Sierra Pacific Power NF 18
Cargill-Alliant PacifiCorp West Sierra Pacific Power SFP 19
Cargill-Alliant Idaho Power Company PacifiCorp East SFP 20
Cargill-Alliant Idaho Power Company Sierra Pacific Power NF 21
Cargill-Alliant Idaho Power Company Sierra Pacific Power SFP 22
Cargill-Alliant PacifiCorp West NorthWestern/PacifiCorp East NF 23
Cargill-Alliant PacifiCorp West Bonneville Power Administration NF 24
Cargill-Alliant PacifiCorp West Sierra Pacific Power NF 25
Cargill-Alliant PacifiCorp West Sierra Pacific Power SFP 26
Cargill-Alliant NorthWestern/PacifiCorp East PacifiCorp East SFP 27
Cargill-Alliant NorthWestern/PacifiCorp East Sierra Pacific Power NF 28
Cargill-Alliant Bonneville Power Administration PacifiCorp East NF 29
Cargill-Alliant Bonneville Power Administration PacifiCorp East SFP 30
Cargill-Alliant Bonneville Power Administration PacifiCorp West NF 31
Cargill-Alliant Bonneville Power Administration Avista NF 32
Cargill-Alliant Bonneville Power Administration Sierra Pacific Power NF 33
Cargill-Alliant Bonneville Power Administration Sierra Pacific Power SFP 34
FERC FORM NO. 1 (ED. 12-90) Page 328.3
TOTAL
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1)
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd ofIdaho Power Company X
04/13/20122011/Q4
Line No.
Payment By
(c)(b)(a) (d)
Statistical
cationClassifi-
(Footnote Affiliation)
(Including transactions referred to as 'wheeling')
(Company of Public Authority)(Footnote Affiliation)
(Company of Public Authority)(Footnote Affiliation)
(Company of Public Authority)Energy Received From Energy Delivered To
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities, qualifyingfacilities, 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 orpublic 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 footnoteany 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 PointTransmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point TransmissionReservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this codefor any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for eachadjustment. See General Instruction for definitions of codes.
Cargill-Alliant Avista PacifiCorp East NF 1
Cargill-Alliant Avista Sierra Pacific Power NF 2
Cargill-Alliant Sierra Pacific Power PacifiCorp East NF 3
Cargill-Alliant Sierra Pacific Power PacifiCorp East SFP 4
Cargill-Alliant Sierra Pacific Power NorthWestern/PacifiCorp East NF 5
Cargill-Alliant Sierra Pacific Power PacifiCorp East NF 6
Cargill-Alliant Sierra Pacific Power NorthWestern/PacifiCorp East NF 7
Cargill-Alliant Sierra Pacific Power Bonneville Power Administration NF 8
Cargill-Alliant Sierra Pacific Power Bonneville Power Administration SFP 9
Cargill-Alliant Sierra Pacific Power Avista NF 10
Cargill-Alliant Sierra Pacific Power Avista SFP 11
Cargill-Alliant Sierra Pacific Power Sierra Pacific Power NF 12
Cargill-Alliant Sierra Pacific Power Sierra Pacific Power SFP 13
Cargill-Alliant Sierra Pacific Power Bonneville Power Administration NF 14
Cargill-Alliant Idaho Power Company Avista NF 15
Cargill-Alliant Idaho Power Company PacifiCorp East NF 16
Cargill-Alliant Idaho Power Company PacifiCorp East SFP 17
Cargill-Alliant Idaho Power Company Bonneville Power Administration NF 18
Cargill-Alliant Idaho Power Company Bonneville Power Administration SFP 19
Cargill-Alliant Idaho Power Company Sierra Pacific Power NF 20
Cargill-Alliant Idaho Power Company Sierra Pacific Power SFP 21
Citigroup Energy NF 22
Iberdrola Energy PacifiCorp East Bonneville Power Administration NF 23
Iberdrola Energy PacifiCorp East Bonneville Power Administration NF 24
Iberdrola Energy PacifiCorp East Sierra Pacific Power NF 25
Iberdrola Energy Bonneville Power Administration PacifiCorp East NF 26
Iberdrola Energy Bonneville Power Administration Sierra Pacific Power NF 27
Iberdrola Energy Avista Sierra Pacific Power NF 28
Iberdrola Energy Sierra Pacific Power Bonneville Power Administration NF 29
Morgan Stanley Capital Group NorthWestern/PacifiCorp East PacifiCorp East NF 30
Morgan Stanley Capital Group NorthWestern/PacifiCorp East PacifiCorp East NF 31
Morgan Stanley Capital Group NorthWestern/PacifiCorp East Bonneville Power Administration NF 32
Morgan Stanley Capital Group NorthWestern/PacifiCorp East Sierra Pacific Power NF 33
Morgan Stanley Capital Group PacifiCorp East Bonneville Power Administration NF 34
FERC FORM NO. 1 (ED. 12-90) Page 328.4
TOTAL
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1)
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd ofIdaho Power Company X
04/13/20122011/Q4
Line No.
Payment By
(c)(b)(a) (d)
Statistical
cationClassifi-
(Footnote Affiliation)
(Including transactions referred to as 'wheeling')
(Company of Public Authority)(Footnote Affiliation)
(Company of Public Authority)(Footnote Affiliation)
(Company of Public Authority)Energy Received From Energy Delivered To
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities, qualifyingfacilities, 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 orpublic 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 footnoteany 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 PointTransmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point TransmissionReservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this codefor any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for eachadjustment. See General Instruction for definitions of codes.
Morgan Stanley Capital Group PacifiCorp East Sierra Pacific Power NF 1
Morgan Stanley Capital Group NorthWestern/PacifiCorp East PacifiCorp East NF 2
Morgan Stanley Capital Group NorthWestern/PacifiCorp East PacifiCorp East NF 3
Morgan Stanley Capital Group NorthWestern/PacifiCorp East Bonneville Power Administration NF 4
Morgan Stanley Capital Group NorthWestern/PacifiCorp East Sierra Pacific Power NF 5
Morgan Stanley Capital Group PacifiCorp East NorthWestern/PacifiCorp East NF 6
Morgan Stanley Capital Group PacifiCorp East PacifiCorp East NF 7
Morgan Stanley Capital Group PacifiCorp East NorthWestern/PacifiCorp East NF 8
Morgan Stanley Capital Group PacifiCorp East PacifiCorp West NF 9
Morgan Stanley Capital Group PacifiCorp East Bonneville Power Administration NF 10
Morgan Stanley Capital Group PacifiCorp East Avista NF 11
Morgan Stanley Capital Group PacifiCorp East Sierra Pacific Power NF 12
Morgan Stanley Capital Group PacifiCorp East Sierra Pacific Power SFP 13
Morgan Stanley Capital Group PacifiCorp West PacifiCorp East NF 14
Morgan Stanley Capital Group PacifiCorp West Sierra Pacific Power NF 15
Morgan Stanley Capital Group PacifiCorp West Bonneville Power Administration NF 16
Morgan Stanley Capital Group PacifiCorp West Sierra Pacific Power NF 17
Morgan Stanley Capital Group NorthWestern/PacifiCorp East PacifiCorp East NF 18
Morgan Stanley Capital Group NorthWestern/PacifiCorp East PacifiCorp East NF 19
Morgan Stanley Capital Group NorthWestern/PacifiCorp East PacifiCorp West NF 20
Morgan Stanley Capital Group NorthWestern/PacifiCorp East Bonneville Power Administration NF 21
Morgan Stanley Capital Group NorthWestern/PacifiCorp East Avista NF 22
Morgan Stanley Capital Group NorthWestern/PacifiCorp East Sierra Pacific Power NF 23
Morgan Stanley Capital Group Bonneville Power Administration PacifiCorp East NF 24
Morgan Stanley Capital Group Bonneville Power Administration PacifiCorp East NF 25
Morgan Stanley Capital Group Bonneville Power Administration PacifiCorp West NF 26
Morgan Stanley Capital Group Bonneville Power Administration PacifiCorp West NF 27
Morgan Stanley Capital Group Bonneville Power Administration Sierra Pacific Power NF 28
Morgan Stanley Capital Group Avista PacifiCorp East NF 29
Morgan Stanley Capital Group Avista PacifiCorp East NF 30
Morgan Stanley Capital Group Avista Bonneville Power Administration NF 31
Morgan Stanley Capital Group Avista Sierra Pacific Power NF 32
Morgan Stanley Capital Group Sierra Pacific Power NorthWestern/PacifiCorp East NF 33
Morgan Stanley Capital Group Sierra Pacific Power Bonneville Power Administration NF 34
FERC FORM NO. 1 (ED. 12-90) Page 328.5
TOTAL
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1)
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd ofIdaho Power Company X
04/13/20122011/Q4
Line No.
Payment By
(c)(b)(a) (d)
Statistical
cationClassifi-
(Footnote Affiliation)
(Including transactions referred to as 'wheeling')
(Company of Public Authority)(Footnote Affiliation)
(Company of Public Authority)(Footnote Affiliation)
(Company of Public Authority)Energy Received From Energy Delivered To
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities, qualifyingfacilities, 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 orpublic 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 footnoteany 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 PointTransmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point TransmissionReservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this codefor any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for eachadjustment. See General Instruction for definitions of codes.
Noble Americas NF 1
Pacificorp Power Marketing PacifiCorp East PacifiCorp West NF 2
Pacificorp Power Marketing PacifiCorp East NorthWestern/PacifiCorp East SFP 3
Pacificorp Power Marketing PacifiCorp East Idaho Power Company NF 4
Pacificorp Power Marketing PacifiCorp East Idaho Power Company LFP 5
Pacificorp Power Marketing PacifiCorp East Bonneville Power Administration NF 6
Pacificorp Power Marketing PacifiCorp East Sierra Pacific Power NF 7
Pacificorp Power Marketing PacifiCorp East Sierra Pacific Power SFP 8
Pacificorp Power Marketing PacifiCorp East PacifiCorp East NF 9
Pacificorp Power Marketing PacifiCorp West PacifiCorp East NF 10
Pacificorp Power Marketing PacifiCorp West Bonneville Power Administration NF 11
Pacificorp Power Marketing PacifiCorp West PacifiCorp East NF 12
Pacificorp Power Marketing Idaho Power Company PacifiCorp East LFP 13
Pacificorp Power Marketing Idaho Power Company PacifiCorp East NF 14
Pacificorp Power Marketing Idaho Power Company PacifiCorp East LFP 15
Pacificorp Power Marketing Idaho Power Company PacifiCorp West NF 16
Pacificorp Power Marketing Idaho Power Company Bonneville Power Administration NF 17
Pacificorp Power Marketing Idaho Power Company PacifiCorp West LFP 18
Pacificorp Power Marketing Bonneville Power Administration PacifiCorp East NF 19
Pacificorp Power Marketing Avista PacifiCorp East NF 20
Pacificorp Power Marketing Avista PacifiCorp West NF 21
Portland General Electric NorthWestern/PacifiCorp East Bonneville Power Administration NF 22
PPL Energy Plus PacifiCorp East PacifiCorp East NF 23
PPL Energy Plus PacifiCorp East PacifiCorp West NF 24
PPL Energy Plus PacifiCorp East Bonneville Power Administration NF 25
PPL Energy Plus PacifiCorp East Avista NF 26
PPL Energy Plus NorthWestern/PacifiCorp East PacifiCorp East NF 27
PPL Energy Plus NorthWestern/PacifiCorp East PacifiCorp East NF 28
PPL Energy Plus NorthWestern/PacifiCorp East PacifiCorp West NF 29
PPL Energy Plus NorthWestern/PacifiCorp East Bonneville Power Administration NF 30
PPL Energy Plus Bonneville Power Administration PacifiCorp East NF 31
PPL Energy Plus Bonneville Power Administration PacifiCorp East NF 32
PPL Energy Plus Bonneville Power Administration PacifiCorp West NF 33
PPL Energy Plus Avista PacifiCorp East NF 34
FERC FORM NO. 1 (ED. 12-90) Page 328.6
TOTAL
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1)
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd ofIdaho Power Company X
04/13/20122011/Q4
Line No.
Payment By
(c)(b)(a) (d)
Statistical
cationClassifi-
(Footnote Affiliation)
(Including transactions referred to as 'wheeling')
(Company of Public Authority)(Footnote Affiliation)
(Company of Public Authority)(Footnote Affiliation)
(Company of Public Authority)Energy Received From Energy Delivered To
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities, qualifyingfacilities, 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 orpublic 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 footnoteany 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 PointTransmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point TransmissionReservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this codefor any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for eachadjustment. See General Instruction for definitions of codes.
PPL Energy Plus Avista PacifiCorp East NF 1
PPL Energy Plus Avista Bonneville Power Administration NF 2
Puget Sound Energy PacifiCorp East Bonneville Power Administration NF 3
Puget Sound Energy NorthWestern/PacifiCorp East Bonneville Power Administration NF 4
Puget Sound Energy NorthWestern/PacifiCorp East Bonneville Power Administration NF 5
Puget Sound Energy Bonneville Power Administration Sierra Pacific Power NF 6
Puget Sound Energy Avista Idaho Power Company NF 7
Rainbow Energy Marketing PacifiCorp East NorthWestern/PacifiCorp East NF 8
Rainbow Energy Marketing PacifiCorp East NorthWestern/PacifiCorp East NF 9
Rainbow Energy Marketing NorthWestern/PacifiCorp East PacifiCorp East SFP 10
Rainbow Energy Marketing NorthWestern/PacifiCorp East PacifiCorp East SFP 11
Rainbow Energy Marketing PacifiCorp East Sierra Pacific Power NF 12
Rainbow Energy Marketing PacifiCorp East Sierra Pacific Power SFP 13
Rainbow Energy Marketing PacifiCorp West PacifiCorp East NF 14
Rainbow Energy Marketing PacifiCorp West PacifiCorp East SFP 15
Rainbow Energy Marketing PacifiCorp West PacifiCorp East SFP 16
Rainbow Energy Marketing NorthWestern/PacifiCorp East PacifiCorp East NF 17
Rainbow Energy Marketing NorthWestern/PacifiCorp East PacifiCorp East SFP 18
Rainbow Energy Marketing NorthWestern/PacifiCorp East PacifiCorp East NF 19
Rainbow Energy Marketing NorthWestern/PacifiCorp East PacifiCorp East SFP 20
Rainbow Energy Marketing NorthWestern/PacifiCorp East Sierra Pacific Power NF 21
Rainbow Energy Marketing NorthWestern/PacifiCorp East Sierra Pacific Power SFP 22
Rainbow Energy Marketing Avista PacifiCorp East NF 23
Rainbow Energy Marketing Avista PacifiCorp East SFP 24
Rainbow Energy Marketing Avista PacifiCorp East NF 25
Rainbow Energy Marketing Avista PacifiCorp East SFP 26
Rainbow Energy Marketing Avista Sierra Pacific Power NF 27
Rainbow Energy Marketing Avista Sierra Pacific Power SFP 28
Rainbow Energy Marketing Idaho Power Company PacifiCorp East NF 29
Seattle City Light LFP 30
Shell Energy PacifiCorp East Bonneville Power Administration NF 31
Shell Energy PacifiCorp East PacifiCorp East NF 32
Shell Energy PacifiCorp East Bonneville Power Administration NF 33
Shell Energy PacifiCorp East Sierra Pacific Power NF 34
FERC FORM NO. 1 (ED. 12-90) Page 328.7
TOTAL
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1)
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd ofIdaho Power Company X
04/13/20122011/Q4
Line No.
Payment By
(c)(b)(a) (d)
Statistical
cationClassifi-
(Footnote Affiliation)
(Including transactions referred to as 'wheeling')
(Company of Public Authority)(Footnote Affiliation)
(Company of Public Authority)(Footnote Affiliation)
(Company of Public Authority)Energy Received From Energy Delivered To
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities, qualifyingfacilities, 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 orpublic 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 footnoteany 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 PointTransmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point TransmissionReservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this codefor any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for eachadjustment. See General Instruction for definitions of codes.
Shell Energy NorthWestern/PacifiCorp East PacifiCorp East NF 1
Shell Energy NorthWestern/PacifiCorp East Bonneville Power Administration NF 2
Shell Energy Bonneville Power Administration PacifiCorp East NF 3
Shell Energy Bonneville Power Administration Sierra Pacific Power NF 4
Shell Energy Avista PacifiCorp East NF 5
Shell Energy Sierra Pacific Power PacifiCorp East NF 6
Shell Energy Sierra Pacific Power PacifiCorp East NF 7
Shell Energy Sierra Pacific Power Bonneville Power Administration NF 8
Shell Energy Sierra Pacific Power PacifiCorp East NF 9
Shell Energy Sierra Pacific Power PacifiCorp East NF 10
Shell Energy Sierra Pacific Power Bonneville Power Administration NF 11
Shell Energy Sierra Pacific Power Avista NF 12
Shell Energy Idaho Power Company PacifiCorp East NF 13
Shell Energy Idaho Power Company Bonneville Power Administration NF 14
Shell Energy Idaho Power Company Avista NF 15
Shell Energy Idaho Power Company PacifiCorp East NF 16
Shell Energy Idaho Power Company Bonneville Power Administration NF 17
Sierra Pacific Power Marketing PacifiCorp East Sierra Pacific Power NF 18
Sierra Pacific Power Marketing PacifiCorp East Sierra Pacific Power SFP 19
Sierra Pacific Power Marketing PacifiCorp East Sierra Pacific Power NF 20
Sierra Pacific Power Marketing PacifiCorp East Sierra Pacific Power SFP 21
Sierra Pacific Power Marketing NorthWestern/PacifiCorp East Sierra Pacific Power NF 22
Sierra Pacific Power Marketing NorthWestern/PacifiCorp East Sierra Pacific Power SFP 23
Sierra Pacific Power Marketing Bonneville Power Administration Sierra Pacific Power NF 24
Sierra Pacific Power Marketing Bonneville Power Administration Sierra Pacific Power SFP 25
Sierra Pacific Power Marketing Avista PacifiCorp East NF 26
Sierra Pacific Power Marketing Avista Sierra Pacific Power NF 27
Sierra Pacific Power Marketing Avista Sierra Pacific Power SFP 28
Sierra Pacific Power Marketing Sierra Pacific Power PacifiCorp East NF 29
Sierra Pacific Power Marketing Sierra Pacific Power NorthWestern/PacifiCorp East NF 30
Sierra Pacific Power Marketing Sierra Pacific Power Bonneville Power Administration NF 31
Sierra Pacific Power Marketing Sierra Pacific Power Avista NF 32
Southern California Edison NorthWestern/PacifiCorp East Bonneville Power Administration NF 33
Tenaska NorthWestern/PacifiCorp East PacifiCorp East NF 34
FERC FORM NO. 1 (ED. 12-90) Page 328.8
TOTAL
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1)
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd ofIdaho Power Company X
04/13/20122011/Q4
Line No.
Payment By
(c)(b)(a) (d)
Statistical
cationClassifi-
(Footnote Affiliation)
(Including transactions referred to as 'wheeling')
(Company of Public Authority)(Footnote Affiliation)
(Company of Public Authority)(Footnote Affiliation)
(Company of Public Authority)Energy Received From Energy Delivered To
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities, qualifyingfacilities, 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 orpublic 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 footnoteany 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 PointTransmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point TransmissionReservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this codefor any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for eachadjustment. See General Instruction for definitions of codes.
Tenaska NorthWestern/PacifiCorp East PacifiCorp East NF 1
Tenaska Bonneville Power Administration PacifiCorp East NF 2
Tenaska Bonneville Power Administration PacifiCorp East NF 3
Tenaska Bonneville Power Administration PacifiCorp West NF 4
The Energy Authority PacifiCorp East Bonneville Power Administration NF 5
Transalta Energy Marketing PacifiCorp East Bonneville Power Administration NF 6
Transalta Energy Marketing NorthWestern/PacifiCorp East PacifiCorp East NF 7
Transalta Energy Marketing NorthWestern/PacifiCorp East PacifiCorp East NF 8
Transalta Energy Marketing PacifiCorp East Bonneville Power Administration NF 9
Transalta Energy Marketing NorthWestern/PacifiCorp East PacifiCorp East NF 10
Transalta Energy Marketing Bonneville Power Administration PacifiCorp East NF 11
Transalta Energy Marketing Bonneville Power Administration PacifiCorp East NF 12
Transalta Energy Marketing Bonneville Power Administration Sierra Pacific Power NF 13
Transalta Energy Marketing Avista PacifiCorp East NF 14
Transalta Energy Marketing Avista PacifiCorp East NF 15
Transalta Energy Marketing Sierra Pacific Power Bonneville Power Administration NF 16
Transalta Energy Marketing Idaho Power Company PacifiCorp East NF 17
Transalta Energy Marketing Idaho Power Company Bonneville Power Administration NF 18
Utah Associated Municipal Power PacifiCorp East Sierra Pacific Power NF 19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
FERC FORM NO. 1 (ED. 12-90) Page 328.9
TOTAL
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
(Including transactions reffered to as 'wheeling')
FERC RateSchedule of
Tariff Number(e)
Point of Receipt(Subsatation or Other
Designation)(f)
Point of Delivery(Substation or Other
(g)
BillingDemand
(MW)(h)
TRANSFER OF ENERGYMegaWatt Hours
Received(i)
Delivered(j)
MegaWatt HoursDesignation)
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contractdesignations under which service, as identified in column (d), is provided.6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report thedesignation 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 thecontract.7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demandreported 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.
5 368,297 368,297 1
5 189,508 189,508 2
5 205,046 205,046 3
5 907,088 907,088 4
Minidoka, IdahoLegacy Various in Idaho 8,322 8,322 5
10 388,704 388,704 6
5 2,094 2,094 7
LaGrande, OregonLegacy Various in Idaho 14,238 14,238 8
JBSNLegacy ENPR 9
AVAT.NWMT5 BORA 92 92 10
AVAT.NWMT5 M345 30 30 11
BORA5 BPAT.NWMT 855 855 12
BORA5 BRDY 179 179 13
BORA5 JBSN 490 490 14
BORA5 LAGRANDE 9,866 9,866 15
BORA5 LOLO 99 99 16
BORA5 M345 3,546 3,546 17
BORA5 M500 2,314 2,314 18
BPAT.NWMT5 BORA 3,310 3,310 19
BPAT.NWMT5 BORA 3,688 3,688 20
BPAT.NWMT5 BRDY 2,380 2,380 21
BPAT.NWMT5 BRDY 8,830 8,830 22
BPAT.NWMT5 JBSN 95 95 23
BPAT.NWMT5 LAGRANDE 397 397 24
BPAT.NWMT5 M345 664 664 25
BPAT.NWMT5 M345 18,792 18,792 26
BRDY5 AVAT.NWMT 102 102 27
BRDY5 BORA 260 260 28
BRDY5 BPAT.NWMT 154 154 29
BRDY5 ENPR 80 80 30
BRDY5 JBSN 90 90 31
BRDY5 LAGRANDE 14,347 14,347 32
BRDY5 LOLO 10 10 33
BRDY5 M345 2,386 2,386 34
FERC FORM NO. 1 (ED. 12-90) Page 329
0 6,092,216 6,092,216
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
(Including transactions reffered to as 'wheeling')
FERC RateSchedule of
Tariff Number(e)
Point of Receipt(Subsatation or Other
Designation)(f)
Point of Delivery(Substation or Other
(g)
BillingDemand
(MW)(h)
TRANSFER OF ENERGYMegaWatt Hours
Received(i)
Delivered(j)
MegaWatt HoursDesignation)
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contractdesignations under which service, as identified in column (d), is provided.6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report thedesignation 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 thecontract.7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demandreported 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.
BRDY5 M345 1,848 1,848 1
BRDY5 M500 1,281 1,281 2
ENPR5 BORA 219,615 219,615 3
ENPR5 BORA 1,433 1,433 4
ENPR5 BRDY 19,008 19,008 5
ENPR5 BRDY 3,642 3,642 6
ENPR5 JBSN 211 211 7
ENPR5 M345 1,127 1,127 8
ENPR5 M345 32 32 9
GSHN5 AVAT.NWMT 10 10 10
GSHN5 BPAT.NWMT 523 523 11
GSHN5 BRDY 667 667 12
GSHN5 ENPR 83 83 13
GSHN5 JBSN 544 544 14
GSHN5 JEFF 35 35 15
GSHN5 LAGRANDE 10,167 10,167 16
GSHN5 M345 579 579 17
GSHN5 M500 796 796 18
HCPR5 BPAT.NWMT 149 149 19
HCPR5 LAGRANDE 3,056 3,056 20
JBSN5 BORA 20 20 21
JBSN5 BPAT.NWMT 36 36 22
JBSN5 LAGRANDE 2,947 2,947 23
JBSN5 M345 138 138 24
JBWT5 BORA 35 35 25
JBWT5 LAGRANDE 1,448 1,448 26
JBWT5 M500 127 127 27
JEFF5 BORA 6,317 6,317 28
JEFF5 BRDY 746 746 29
JEFF5 ENPR 53 53 30
JEFF5 JBSN 88 88 31
JEFF5 LAGRANDE 400 400 32
JEFF5 M345 103 103 33
LAGRANDE5 BORA 54,378 54,378 34
FERC FORM NO. 1 (ED. 12-90) Page 329.1
0 6,092,216 6,092,216
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
(Including transactions reffered to as 'wheeling')
FERC RateSchedule of
Tariff Number(e)
Point of Receipt(Subsatation or Other
Designation)(f)
Point of Delivery(Substation or Other
(g)
BillingDemand
(MW)(h)
TRANSFER OF ENERGYMegaWatt Hours
Received(i)
Delivered(j)
MegaWatt HoursDesignation)
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contractdesignations under which service, as identified in column (d), is provided.6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report thedesignation 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 thecontract.7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demandreported 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.
LAGRANDE5 BORA 799 799 1
LAGRANDE5 BRDY 12,461 12,461 2
LAGRANDE5 BRDY 2,482 2,482 3
LAGRANDE5 JBSN 1,847 1,847 4
LAGRANDE5 M345 11,056 11,056 5
LAGRANDE5 M345 373 373 6
LOLO5 BORA 11,424 11,424 7
LOLO5 BRDY 1,165 1,165 8
LOLO5 JBSN 168 168 9
LOLO5 M345 3,569 3,569 10
M3455 BPAT.NWMT 132 132 11
M3455 BRDY 80 80 12
M3455 LAGRANDE 2,001 2,001 13
MDSK5 BPAT.NWMT 175 175 14
MDSK5 LAGRANDE 1,272 1,272 15
OBBLPR5 BPAT.NWMT 204 204 16
OBBLPR5 LAGRANDE 1,738 1,738 17
BORA5 M345 2,250 2,250 18
JBSN5 LAGRANDE 10 10 19
LAGRANDE5 BORA 25 25 20
LAGRANDE5 JBSN 60 60 21
LAGRANDE5 LAGRANDE 3,005 3,005 22
LAGRANDE5 M345 1,542 1,542 23
LOLO5 LAGRANDE 7,115 7,115 24
LOLO5 LAGRANDE 768 768 25
LOLO5 M345 324 324 26
BORA5 AVAT.NWMT 525 525 27
BORA5 BPAT.NWMT 1,420 1,420 28
BORA5 ENPR 820 820 29
BORA5 JBSN 996 996 30
BORA5 LAGRANDE 10,089 10,089 31
BORA5 LOLO 249 249 32
BORA5 M345 8,416 8,416 33
BORA5 M345 4,153 4,153 34
FERC FORM NO. 1 (ED. 12-90) Page 329.2
0 6,092,216 6,092,216
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
(Including transactions reffered to as 'wheeling')
FERC RateSchedule of
Tariff Number(e)
Point of Receipt(Subsatation or Other
Designation)(f)
Point of Delivery(Substation or Other
(g)
BillingDemand
(MW)(h)
TRANSFER OF ENERGYMegaWatt Hours
Received(i)
Delivered(j)
MegaWatt HoursDesignation)
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contractdesignations under which service, as identified in column (d), is provided.6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report thedesignation 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 thecontract.7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demandreported 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.
BPAT.NWMT5 BORA 2,651 2,651 1
BPAT.NWMT5 BORA 33,899 33,899 2
BPAT.NWMT5 BRDY 25 25 3
BPAT.NWMT5 JBSN 440 440 4
BPAT.NWMT5 JBSN 1,200 1,200 5
BPAT.NWMT5 LAGRANDE 5 5 6
BPAT.NWMT5 M345 2,791 2,791 7
BPAT.NWMT5 M345 43,719 43,719 8
BRDY5 BORA 322 322 9
BRDY5 BORA 504 504 10
BRDY5 ENPR 63 63 11
BRDY5 LAGRANDE 112 112 12
BRDY5 LAGRANDE 600 600 13
BRDY5 M345 932 932 14
BRDY5 M345 64 64 15
ENPR5 BORA 69,699 69,699 16
ENPR5 BORA 60,810 60,810 17
ENPR5 M345 8,765 8,765 18
ENPR5 M345 1,392 1,392 19
HCPR5 BORA 400 400 20
HCPR5 M345 800 800 21
HCPR5 M345 1,600 1,600 22
JBSN5 BPAT.NWMT 3,200 3,200 23
JBSN5 LAGRANDE 148 148 24
JBSN5 M345 592 592 25
JBSN5 M345 408 408 26
JEFF5 BORA 320 320 27
JEFF5 M345 928 928 28
LAGRANDE5 BORA 2,346 2,346 29
LAGRANDE5 BORA 1,454 1,454 30
LAGRANDE5 JBSN 306 306 31
LAGRANDE5 LOLO 238 238 32
LAGRANDE5 M345 11,482 11,482 33
LAGRANDE5 M345 17,606 17,606 34
FERC FORM NO. 1 (ED. 12-90) Page 329.3
0 6,092,216 6,092,216
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
(Including transactions reffered to as 'wheeling')
FERC RateSchedule of
Tariff Number(e)
Point of Receipt(Subsatation or Other
Designation)(f)
Point of Delivery(Substation or Other
(g)
BillingDemand
(MW)(h)
TRANSFER OF ENERGYMegaWatt Hours
Received(i)
Delivered(j)
MegaWatt HoursDesignation)
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contractdesignations under which service, as identified in column (d), is provided.6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report thedesignation 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 thecontract.7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demandreported 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.
LOLO5 BORA 1,142 1,142 1
LOLO5 M345 5,988 5,988 2
LYPK5 BORA 10,724 10,724 3
LYPK5 BORA 37,726 37,726 4
LYPK5 BPAT.NWMT 1,563 1,563 5
LYPK5 BRDY 667 667 6
LYPK5 JEFF 173 173 7
LYPK5 LAGRANDE 14,243 14,243 8
LYPK5 LAGRANDE 1,664 1,664 9
LYPK5 LOLO 100 100 10
LYPK5 LOLO 200 200 11
LYPK5 M345 64,772 64,772 12
LYPK5 M345 243,254 243,254 13
M3455 LAGRANDE 275 275 14
MDSK5 LOLO 200 200 15
OBBLPR5 BORA 1,000 1,000 16
OBBLPR5 BORA 1,000 1,000 17
OBBLPR5 LAGRANDE 410 410 18
OBBLPR5 LAGRANDE 1,808 1,808 19
OBBLPR5 M345 320 320 20
OBBLPR5 M345 480 480 21
5 22
BORA5 LAGRANDE 361 361 23
BRDY5 LAGRANDE 57 57 24
BRDY5 M345 24 24 25
LAGRANDE5 BORA 5,027 5,027 26
LAGRANDE5 M345 4,104 4,104 27
LOLO5 M345 380 380 28
M3455 LAGRANDE 381 381 29
AVAT.NWMT5 BORA 544 544 30
AVAT.NWMT5 BRDY 140 140 31
AVAT.NWMT5 LAGRANDE 132 132 32
AVAT.NWMT5 M345 3,663 3,663 33
BORA5 LAGRANDE 66 66 34
FERC FORM NO. 1 (ED. 12-90) Page 329.4
0 6,092,216 6,092,216
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
(Including transactions reffered to as 'wheeling')
FERC RateSchedule of
Tariff Number(e)
Point of Receipt(Subsatation or Other
Designation)(f)
Point of Delivery(Substation or Other
(g)
BillingDemand
(MW)(h)
TRANSFER OF ENERGYMegaWatt Hours
Received(i)
Delivered(j)
MegaWatt HoursDesignation)
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contractdesignations under which service, as identified in column (d), is provided.6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report thedesignation 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 thecontract.7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demandreported 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.
BORA5 M345 8,522 8,522 1
BPAT.NWMT5 BORA 371 371 2
BPAT.NWMT5 BRDY 1,237 1,237 3
BPAT.NWMT5 LAGRANDE 210 210 4
BPAT.NWMT5 M345 756 756 5
BRDY5 AVAT.NWMT 46 46 6
BRDY5 BORA 62 62 7
BRDY5 BPAT.NWMT 119 119 8
BRDY5 JBSN 99 99 9
BRDY5 LAGRANDE 19,275 19,275 10
BRDY5 LOLO 100 100 11
BRDY5 M345 8,148 8,148 12
BRDY5 M345 1,981 1,981 13
ENPR5 BRDY 1,128 1,128 14
ENPR5 M345 180 180 15
JBSN5 LAGRANDE 20 20 16
JBSN5 M345 29 29 17
JEFF5 BORA 5,996 5,996 18
JEFF5 BRDY 6,680 6,680 19
JEFF5 JBSN 250 250 20
JEFF5 LAGRANDE 5,698 5,698 21
JEFF5 LOLO 60 60 22
JEFF5 M345 21,705 21,705 23
LAGRANDE5 BORA 3,085 3,085 24
LAGRANDE5 BRDY 8,183 8,183 25
LAGRANDE5 ENPR 5 5 26
LAGRANDE5 JBSN 65 65 27
LAGRANDE5 M345 2,075 2,075 28
LOLO5 BORA 2,335 2,335 29
LOLO5 BRDY 2,292 2,292 30
LOLO5 LAGRANDE 411 411 31
LOLO5 M345 1,983 1,983 32
M3455 JEFF 114 114 33
M3455 LAGRANDE 1,597 1,597 34
FERC FORM NO. 1 (ED. 12-90) Page 329.5
0 6,092,216 6,092,216
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
(Including transactions reffered to as 'wheeling')
FERC RateSchedule of
Tariff Number(e)
Point of Receipt(Subsatation or Other
Designation)(f)
Point of Delivery(Substation or Other
(g)
BillingDemand
(MW)(h)
TRANSFER OF ENERGYMegaWatt Hours
Received(i)
Delivered(j)
MegaWatt HoursDesignation)
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contractdesignations under which service, as identified in column (d), is provided.6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report thedesignation 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 thecontract.7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demandreported 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.
05 0 1
BORA5 ENPR 8,014 8,014 2
BORA5 GSHN 3,740 3,740 3
BORA5 KPRT 390,968 390,968 4
BORA5 KPRT 403,551 403,551 5
BORA5 LAGRANDE 1,621 1,621 6
BORA5 M345 2,285 2,285 7
BORA5 M345 4,032 4,032 8
BRDY5 BRDY 1,616 1,616 9
ENPR5 BORA 29,752 29,752 10
ENPR5 LAGRANDE 682 682 11
JBSN5 BORA 2,675 2,675 12
JBWT5 BORA 61,027 61,027 13
JBWT5 BRDY 54,685 54,685 14
JBWT5 BRDY 381,175 381,175 15
JBWT5 ENPR 1,153 1,153 16
JBWT5 LAGRANDE 4,211 4,211 17
JBWT5 M500 906,776 906,776 18
LAGRANDE5 BORA 37,083 37,083 19
LOLO5 BORA 95,641 95,641 20
LOLO5 ENPR 921 921 21
JEFF5 LAGRANDE 580 580 22
BRDY5 BORA 724 724 23
BRDY5 JBSN 150 150 24
BRDY5 LAGRANDE 5,514 5,514 25
BRDY5 LOLO 964 964 26
JEFF5 BORA 79 79 27
JEFF5 BRDY 2,086 2,086 28
JEFF5 JBSN 420 420 29
JEFF5 LAGRANDE 1,259 1,259 30
LAGRANDE5 BORA 526 526 31
LAGRANDE5 BRDY 216 216 32
LAGRANDE5 JBSN 60 60 33
LOLO5 BORA 495 495 34
FERC FORM NO. 1 (ED. 12-90) Page 329.6
0 6,092,216 6,092,216
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
(Including transactions reffered to as 'wheeling')
FERC RateSchedule of
Tariff Number(e)
Point of Receipt(Subsatation or Other
Designation)(f)
Point of Delivery(Substation or Other
(g)
BillingDemand
(MW)(h)
TRANSFER OF ENERGYMegaWatt Hours
Received(i)
Delivered(j)
MegaWatt HoursDesignation)
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contractdesignations under which service, as identified in column (d), is provided.6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report thedesignation 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 thecontract.7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demandreported 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.
LOLO5 BRDY 150 150 1
LOLO5 LAGRANDE 937 937 2
BRDY5 LAGRANDE 180 180 3
GSHN5 LAGRANDE 155 155 4
JEFF5 LAGRANDE 15 15 5
LAGRANDE5 M345 134 134 6
LOLO5 IPCOLOSS 1 1 7
BORA5 AVAT.NWMT 200 200 8
BORA5 JEFF 800 800 9
BPAT.NWMT5 BORA 13,760 13,760 10
BPAT.NWMT5 BRDY 16,074 16,074 11
BRDY5 M345 172 172 12
BRDY5 M345 2,081 2,081 13
ENPR5 BRDY 1,623 1,623 14
ENPR5 BRDY 348 348 15
JBSN5 BRDY 1,568 1,568 16
JEFF5 BORA 7,980 7,980 17
JEFF5 BORA 8,109 8,109 18
JEFF5 BRDY 40 40 19
JEFF5 BRDY 4,093 4,093 20
JEFF5 M345 505 505 21
JEFF5 M345 23,673 23,673 22
LOLO5 BORA 9,934 9,934 23
LOLO5 BORA 2,501 2,501 24
LOLO5 BRDY 3,017 3,017 25
LOLO5 BRDY 1,050 1,050 26
LOLO5 M345 400 400 27
LOLO5 M345 2,250 2,250 28
OBBLPR5 BRDY 400 400 29
05 0 30
BORA5 LAGRANDE 25 25 31
BRDY5 BORA 192 192 32
BRDY5 LAGRANDE 5,375 5,375 33
BRDY5 M345 468 468 34
FERC FORM NO. 1 (ED. 12-90) Page 329.7
0 6,092,216 6,092,216
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
(Including transactions reffered to as 'wheeling')
FERC RateSchedule of
Tariff Number(e)
Point of Receipt(Subsatation or Other
Designation)(f)
Point of Delivery(Substation or Other
(g)
BillingDemand
(MW)(h)
TRANSFER OF ENERGYMegaWatt Hours
Received(i)
Delivered(j)
MegaWatt HoursDesignation)
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contractdesignations under which service, as identified in column (d), is provided.6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report thedesignation 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 thecontract.7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demandreported 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.
JEFF5 BORA 200 200 1
JEFF5 LAGRANDE 77 77 2
LAGRANDE5 BORA 13 13 3
LAGRANDE5 M345 2,231 2,231 4
LOLO5 BORA 25 25 5
LYPK5 BORA 12 12 6
LYPK5 BRDY 50 50 7
LYPK5 LAGRANDE 174 174 8
M3455 BORA 180 180 9
M3455 BRDY 100 100 10
M3455 LAGRANDE 3,533 3,533 11
M3455 LOLO 68 68 12
MDSK5 BORA 400 400 13
MDSK5 LAGRANDE 541 541 14
MDSK5 LOLO 17 17 15
OBBLPR5 BORA 300 300 16
OBBLPR5 LAGRANDE 67 67 17
BORA5 M345 6,360 6,360 18
BORA5 M345 9,140 9,140 19
BRDY5 M345 11,800 11,800 20
BRDY5 M345 31,608 31,608 21
JEFF5 M345 42,409 42,409 22
JEFF5 M345 11,141 11,141 23
LAGRANDE5 M345 34,496 34,496 24
LAGRANDE5 M345 4,325 4,325 25
LOLO5 BORA 48 48 26
LOLO5 M345 35,267 35,267 27
LOLO5 M345 7,424 7,424 28
M3455 BORA 1,082 1,082 29
M3455 JEFF 185 185 30
M3455 LAGRANDE 3,458 3,458 31
M3455 LOLO 225 225 32
GSHN5 LAGRANDE 125 125 33
AVAT.NWMT5 BRDY 95 95 34
FERC FORM NO. 1 (ED. 12-90) Page 329.8
0 6,092,216 6,092,216
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
(Including transactions reffered to as 'wheeling')
FERC RateSchedule of
Tariff Number(e)
Point of Receipt(Subsatation or Other
Designation)(f)
Point of Delivery(Substation or Other
(g)
BillingDemand
(MW)(h)
TRANSFER OF ENERGYMegaWatt Hours
Received(i)
Delivered(j)
MegaWatt HoursDesignation)
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contractdesignations under which service, as identified in column (d), is provided.6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report thedesignation 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 thecontract.7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demandreported 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.
BPAT.NWMT5 BRDY 398 398 1
LAGRANDE5 BORA 1,274 1,274 2
LAGRANDE5 BRDY 1,290 1,290 3
LAGRANDE5 JBSN 265 265 4
BRDY5 LAGRANDE 30 30 5
BORA5 LAGRANDE 706 706 6
BPAT.NWMT5 BORA 25 25 7
BPAT.NWMT5 BRDY 75 75 8
BRDY5 LAGRANDE 300 300 9
JEFF5 BORA 25 25 10
LAGRANDE5 BORA 6,588 6,588 11
LAGRANDE5 BRDY 1,066 1,066 12
LAGRANDE5 M345 488 488 13
LOLO5 BORA 513 513 14
LOLO5 BRDY 28 28 15
M3455 LAGRANDE 398 398 16
OBBLPR5 BORA 50 50 17
OBBLPR5 LAGRANDE 48 48 18
BORA5 M345 648 648 19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
FERC FORM NO. 1 (ED. 12-90) Page 329.9
0 6,092,216 6,092,216
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
(m)(l)(k) (n)(k+l+m)
Total Revenues ($)
(Including transactions reffered to as 'wheeling')
($)Energy Charges
($)(Other Charges)Demand Charges
($)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demandcharges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the amountof energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including out ofperiod adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total chargeshown 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 reportpurposes only on Page 401, Lines 16 and 17, respectively.11. Footnote entries and provide explanations following all required data.
1,414,450 1,454,250 39,800 1
1,163,226 1,365,019 201,793 2
535,470 553,630 18,160 3
3,193,659 2,987,818 -205,841 4
13,482 13,482 5
208,649 208,649 6
7,475 8,837 1,362 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 60,423 32
42 42 33
10,049 10,049 34
FERC FORM NO. 1 (ED. 12-90) Page 330
6,368,919 19,372,904 0 13,003,985
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
(m)(l)(k) (n)(k+l+m)
Total Revenues ($)
(Including transactions reffered to as 'wheeling')
($)Energy Charges
($)(Other Charges)Demand Charges
($)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demandcharges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the amountof energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including out ofperiod adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total chargeshown 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 reportpurposes only on Page 401, Lines 16 and 17, respectively.11. Footnote entries and provide explanations following all required data.
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 42 10
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 84 21
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 3,142 29
223 223 30
371 371 31
1,685 1,685 32
434 434 33
229,014 229,014 34
FERC FORM NO. 1 (ED. 12-90) Page 330.1
6,368,919 19,372,904 0 13,003,985
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
(m)(l)(k) (n)(k+l+m)
Total Revenues ($)
(Including transactions reffered to as 'wheeling')
($)Energy Charges
($)(Other Charges)Demand Charges
($)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demandcharges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the amountof energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including out ofperiod adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total chargeshown 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 reportpurposes only on Page 401, Lines 16 and 17, respectively.11. Footnote entries and provide explanations following all required data.
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
556 556 11
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 25 19
61 61 20
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
844 844 28
487 487 29
592 592 30
5,998 5,998 31
148 148 32
5,003 5,003 33
2,469 2,469 34
FERC FORM NO. 1 (ED. 12-90) Page 330.2
6,368,919 19,372,904 0 13,003,985
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
(m)(l)(k) (n)(k+l+m)
Total Revenues ($)
(Including transactions reffered to as 'wheeling')
($)Energy Charges
($)(Other Charges)Demand Charges
($)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demandcharges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the amountof energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including out ofperiod adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total chargeshown 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 reportpurposes only on Page 401, Lines 16 and 17, respectively.11. Footnote entries and provide explanations following all required data.
1,576 1,576 1
20,153 20,153 2
15 15 3
262 262 4
713 713 5
3 3 6
1,659 1,659 7
25,991 25,991 8
191 191 9
300 300 10
37 37 11
67 67 12
357 357 13
554 554 14
38 38 15
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 88 24
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
FERC FORM NO. 1 (ED. 12-90) Page 330.3
6,368,919 19,372,904 0 13,003,985
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
(m)(l)(k) (n)(k+l+m)
Total Revenues ($)
(Including transactions reffered to as 'wheeling')
($)Energy Charges
($)(Other Charges)Demand Charges
($)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demandcharges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the amountof energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including out ofperiod adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total chargeshown 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 reportpurposes only on Page 401, Lines 16 and 17, respectively.11. Footnote entries and provide explanations following all required data.
679 679 1
3,560 3,560 2
6,375 6,375 3
22,428 22,428 4
929 929 5
397 397 6
103 103 7
8,467 8,467 8
989 989 9
59 59 10
119 119 11
38,507 38,507 12
144,613 144,613 13
163 163 14
119 119 15
594 594 16
594 594 17
244 244 18
1,075 1,075 19
190 190 20
285 285 21
4 4 22
1,246 1,246 23
197 197 24
83 83 25
17,356 17,356 26
14,169 14,169 27
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
FERC FORM NO. 1 (ED. 12-90) Page 330.4
6,368,919 19,372,904 0 13,003,985
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
(m)(l)(k) (n)(k+l+m)
Total Revenues ($)
(Including transactions reffered to as 'wheeling')
($)Energy Charges
($)(Other Charges)Demand Charges
($)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demandcharges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the amountof energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including out ofperiod adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total chargeshown 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 reportpurposes only on Page 401, Lines 16 and 17, respectively.11. Footnote entries and provide explanations following all required data.
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 71 16
103 103 17
21,348 21,348 18
23,784 23,784 19
890 890 20
20,287 20,287 21
214 214 22
77,280 77,280 23
10,984 10,984 24
29,135 29,135 25
18 18 26
231 231 27
7,388 7,388 28
8,314 8,314 29
8,161 8,161 30
1,463 1,463 31
7,060 7,060 32
406 406 33
5,686 5,686 34
FERC FORM NO. 1 (ED. 12-90) Page 330.5
6,368,919 19,372,904 0 13,003,985
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
(m)(l)(k) (n)(k+l+m)
Total Revenues ($)
(Including transactions reffered to as 'wheeling')
($)Energy Charges
($)(Other Charges)Demand Charges
($)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demandcharges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the amountof energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including out ofperiod adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total chargeshown 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 reportpurposes only on Page 401, Lines 16 and 17, respectively.11. Footnote entries and provide explanations following all required data.
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 2,275 23
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 1,653 31
679 679 32
189 189 33
1,556 1,556 34
FERC FORM NO. 1 (ED. 12-90) Page 330.6
6,368,919 19,372,904 0 13,003,985
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
(m)(l)(k) (n)(k+l+m)
Total Revenues ($)
(Including transactions reffered to as 'wheeling')
($)Energy Charges
($)(Other Charges)Demand Charges
($)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demandcharges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the amountof energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including out ofperiod adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total chargeshown 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 reportpurposes only on Page 401, Lines 16 and 17, respectively.11. Footnote entries and provide explanations following all required data.
471 471 1
2,945 2,945 2
2,137 2,137 3
1,841 1,841 4
178 178 5
1,591 1,591 6
12 12 7
513 513 8
2,052 2,052 9
35,296 35,296 10
41,232 41,232 11
441 441 12
5,338 5,338 13
4,163 4,163 14
893 893 15
4,022 4,022 16
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
691 691 32
19,347 19,347 33
1,685 1,685 34
FERC FORM NO. 1 (ED. 12-90) Page 330.7
6,368,919 19,372,904 0 13,003,985
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
(m)(l)(k) (n)(k+l+m)
Total Revenues ($)
(Including transactions reffered to as 'wheeling')
($)Energy Charges
($)(Other Charges)Demand Charges
($)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demandcharges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the amountof energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including out ofperiod adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total chargeshown 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 reportpurposes only on Page 401, Lines 16 and 17, respectively.11. Footnote entries and provide explanations following all required data.
720 720 1
277 277 2
47 47 3
8,031 8,031 4
90 90 5
43 43 6
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 61 15
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
144 144 26
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 34
FERC FORM NO. 1 (ED. 12-90) Page 330.8
6,368,919 19,372,904 0 13,003,985
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
(m)(l)(k) (n)(k+l+m)
Total Revenues ($)
(Including transactions reffered to as 'wheeling')
($)Energy Charges
($)(Other Charges)Demand Charges
($)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demandcharges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the amountof energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including out ofperiod adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total chargeshown 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 reportpurposes only on Page 401, Lines 16 and 17, respectively.11. Footnote entries and provide explanations following all required data.
1,444 1,444 1
4,621 4,621 2
4,679 4,679 3
961 961 4
68 68 5
3,444 3,444 6
122 122 7
366 366 8
1,464 1,464 9
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
244 244 17
234 234 18
3,188 3,188 19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
FERC FORM NO. 1 (ED. 12-90) Page 330.9
6,368,919 19,372,904 0 13,003,985
Schedule Page: 328 Line No.: 1 Column: e5, Open Access Transmission Tariff, Volume 5, first revision Schedule Page: 328 Line No.: 1 Column: h The network service agreement between Idaho Power and the Bonneville Power Administrationfor the Oregon Trail Electric Cooperative expires September 30, 2028. The billing demandfor network service is the customer's demand at the time of Idaho Power Companytransmission system peak and varies by month. Schedule Page: 328 Line No.: 2 Column: hThe network service agreement between Idaho Power and the Bonneville Power Administrationfor the USBR expires December 31, 2014. The billing demand for network service is thecustomer's demand at the time of Idaho Power Company transmission system peak and variesby month. Schedule Page: 328 Line No.: 3 Column: hThe network service agreement between Idaho Power and the Bonneville Power Administrationfor Raft River expired September 30, 2011. The billing demand for network service is thecustomer's demand at the time of Idaho Power Company transmission system peak and variesby month. Schedule Page: 328 Line No.: 4 Column: hThe network service agreement between Idaho Power and the Bonneville Power Administrationfor the Priority Firm Customers expires September 20, 2028. The billing demand for networkservice is the customer's demand at the time of Idaho Power Company transmission systempeak and varies by month. Schedule Page: 328 Line No.: 5 Column: eLegacy, contract prior to the Open Access Transmission Tariff Schedule Page: 328 Line No.: 5 Column: hThe contract between Idaho Power and the Milner Irrigation District expires December 31,2012. Schedule Page: 328 Line No.: 6 Column: hThe agreement between Idaho Power and the City of Seattle expires December 31, 2017. Cityof Seattle has sold this transmission service request to Cargill and Cargill is nowresponsible for payment. Schedule Page: 328 Line No.: 7 Column: hThe contract between Idaho Power and PacifiCorp - Imnaha expires on March 31, 2016. Thebilling demand for network service is the customer's demand at the time of Idaho PowerCompany transmission system peak and varies by month. Schedule Page: 328 Line No.: 8 Column: eLegacy, contract prior to the Open Access Transmission Tariff Schedule Page: 328 Line No.: 8 Column: hThe agreement between Idaho Power and the United States Department of the Interior, Bureauof Indian Affairs is subject to termination upon 90 days written notice by the Bureau. Schedule Page: 328 Line No.: 9 Column: eLegacy, contract prior to the Open Access Transmission Tariff Schedule Page: 328.6 Line No.: 5 Column: h Legacy agreement providing OATT-like service, but billed under 454 Facilities revenue
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87) Page 450.1
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
Idaho Power Company X04/13/2012
2011/Q4
Line No. Name of Company or Public
(d)(c)(a)Authority (Footnote Affiliations)
TRANSFER OF ENERGYMagawatt-
hoursReceived
Magawatt-
Deliveredhours
EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERSDemandCharges
($)(e)
EnergyCharges
(f)($)
OtherCharges
($)(g)
($)
Total Cost ofTransmission
(h)
(Including transactions referred to as "wheeling")
1. Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other publicauthorities, 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 thetransmission service provider. Use additional columns as necessary to report all companies or public authorities that providedtransmission 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 - OtherLong-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm TransmissionService, 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 demandcharges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all other chargeson bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of theamount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no monetary settlementwas made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement, including the amount andtype 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.
StatisticalClassification
(b)
NF 138,336 138,336 21,503 21,503Avista Corp-WWP Div 1
SFP 1,473,302 1,473,302 274,437 274,437Avista Corp-WWP Div 2
OS -36,582 -36,582Avista Corp-WWP Div 3
OS 447 447Bonneville Power Admin 4
NF 8,011 8,011 1,700 1,700Bonneville Power Admin 5
LFP 1,195,392 1,195,392 286,453 286,453Bonneville Power Admin 6
LFP 30,404 30,404Bonneville Power Admin 7
SFP 330 330Bonneville Power Admin 8
SFP 144 144 4 4Cargill Power Markets 9
LFP 199,600 199,600 20,710 20,710Northwestern Energy 10
SFP 818,047 818,047 45,995 45,995NorthWesern Energy 11
OS -205,566 -205,566NorthWestern Energy 12
LFP 759,375 759,375 8,720 8,720PacifiCorp Inc. 13
NF 194,002 194,002 34,690 34,690PacifiCorp Inc. 14
OS -21,949 -21,949PacifiCorp Inc. 15
SFP 649,815 649,815 46,666 46,666PacifiCorp Inc. 16
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
Idaho Power Company X04/13/2012
2011/Q4
Line No. Name of Company or Public
(d)(c)(a)Authority (Footnote Affiliations)
TRANSFER OF ENERGYMagawatt-
hoursReceived
Magawatt-
Deliveredhours
EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERSDemandCharges
($)(e)
EnergyCharges
(f)($)
OtherCharges
($)(g)
($)
Total Cost ofTransmission
(h)
(Including transactions referred to as "wheeling")
1. Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other publicauthorities, 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 thetransmission service provider. Use additional columns as necessary to report all companies or public authorities that providedtransmission 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 - OtherLong-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm TransmissionService, 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 demandcharges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all other chargeson bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of theamount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no monetary settlementwas made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement, including the amount andtype 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.
StatisticalClassification
(b)
OS -75,143 -75,143PacifiCorp Inc. 1
SFP 911,685 911,685 361,028 361,028Portland General Ele Co 2
OS -124,160 -124,160Powerex Corp. 3
SFP 750 750 600 600Puget Sound Energy, Inc 4
SFP 527,869 527,869 182,876 182,876Seattle City Light 5
NF 17,995 17,995 2,269 2,269Sierra Pacific Power Co 6
Schedule Page: 332 Line No.: 3 Column: a Resale TransmissionSchedule Page: 332 Line No.: 4 Column: aReserves Provided Schedule Page: 332 Line No.: 6 Column: bContract Expiration Date 09/30/2016 Schedule Page: 332 Line No.: 7 Column: bContract Expiration Date 07/16/2011 Schedule Page: 332 Line No.: 10 Column: bContract can be terminated at anytime, with 30 days prior notice. Schedule Page: 332 Line No.: 12 Column: aResale Transmission Schedule Page: 332 Line No.: 13 Column: bContract Expiration Date 05/31/2014 Schedule Page: 332 Line No.: 15 Column: aUnreserved Usage Distribution Schedule Page: 332.1 Line No.: 1 Column: aResale Transmission Schedule Page: 332.1 Line No.: 2 Column: aResale Transmission
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87) Page 450.1
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Idaho Power Company X04/13/2012
2011/Q4
Line Description Amount(b)(a)No. 405,549Industry Association Dues 1
Nuclear Power Research Expenses 2Other Experimental and General Research Expenses 3
268,796Pub & Dist Info to Stkhldrs...expn servicing outstanding Securities 4 1,071,130Oth Expn >=5,000 show purpose, recipient, amount. Group if < $5,000 5
16 104,397Chamber of Commerce & Other Civic Organizations 17
18 22,000Associated Taxpayers of Idaho 19 46,750Corporate Executive Board 20 14,000Idaho Association of Commerce & Industry 21 1,000Idaho Association of Counties 22 6,000Idaho Mining Association 23
10,000Idaho Technology Council 24 4,950National Association of Directors 25
91,722Northwest Power Pool 26 2,000Pacific Northwest Utilities 27
828,246Western Electricity Coordinating Council 28 26,095Western Energy Institute 29 1,590Wyoming Taxpayers Association 30 900Misc Memberships under $1,000 (3) 31
32Misc General Management 33
28,832Moody's Analytics Inc 34 52,067New York Stock Exchange 35 5,475Port Of Morrow 36
14,063Pr Newswire 37
38
39
40
41
42
43
44
45
3,750,121
FERC FORM NO. 1 (ED. 12-94) Page 335
46 TOTAL
Schedule Page: 335 Line No.: 5 Column: b Recipient Purpose AmountAmerican Stock Transfer & Trust Transfer & Fees $ 57,412 Bank Of New York Port of Morrow 6,593Broadbridge Financial Solutions Proxy & Bulletin 49,858Deutsche Bank Broker Fees 34,952E Source Mgmt Services 23,340Stock Based Compensation Stock Expense 432,000 Thomson Financial Analyst Service 104,855Wells Fargo Transfer & fees 125,464Rate Related Amortization Misc Expense 230,655Business Plus Misc Expense 6,000 ----------Total $1,071,130 ==========
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87) Page 450.1
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Account 403, 404, 405)
Idaho Power Company X04/13/2012
2011/Q4
Line No. Functional Classification
Depreciation
(d)(b)(a)
Amortization of
Total
(Except amortization of aquisition adjustments)
A. Summary of Depreciation and Amortization Charges
Expense(Account 403)
Limited TermElectric Plant
Amortization ofOther Electric
Plant (Acc 405)(e) (f)
1. Report in section A for the year the amounts for : (b) Depreciation Expense (Account 403; (c) Depreciation Expense for AssetRetirement Costs (Account 403.1; (d) Amortization of Limited-Term Electric Plant (Account 404); and (e) Amortization of Other ElectricPlant (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 tocompute 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 changesto 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 includedin any sub-account used.In column (b) report all depreciable plant balances to which rates are applied showing subtotals by functional Classifications and showingcomposite total. Indicate at the bottom of section C the manner in which column balances are obtained. If average balances, state themethod of averaging used.For columns (c), (d), and (e) report available information for each plant subaccount, account or functional classification Listed in column(a). If plant mortality studies are prepared to assist in estimating average service Lives, show in column (f) the type mortality curveselected as most appropriate for the account and in column (g), if available, the weighted average remaining life of surviving plant. Ifcomposite depreciation accounting is used, report available information called for in columns (b) through (g) on this basis.4. If provisions for depreciation were made during the year in addition to depreciation provided by application of reported rates, state at thebottom of section C the amounts and nature of the provisions and the plant items to which related.
(Account 404)(c)
DepreciationExpense for AssetRetirement Costs(Account 403.1)
6,764,513 6,764,513 1 Intangible Plant
18,914,566 18,914,566 2 Steam Production Plant
3 Nuclear Production Plant
15,504,618 15,504,618 4 Hydraulic Production Plant-Conventional
5 Hydraulic Production Plant-Pumped Storage
4,926,750 4,926,750 6 Other Production Plant
17,667,549 17,667,549 7 Transmission Plant
43,735,020 43,735,020 8 Distribution Plant
9 Regional Transmission and Market Operation
12,549,538 12,549,538 10 General Plant
-296,299 -296,299 11 Common Plant-Electric
119,766,255 113,001,742 6,764,513 12 TOTAL
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) 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
B. Basis for Amortization Charges
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No. Account No.
(c)(b)(a) (d) (e)
C. Factors Used in Estimating Depreciation ChargesDepreciablePlant Base
(In Thousands)
EstimatedAvg. Service
Life
NetSalvage
(Percent)
AppliedDepr. rates
MortalityCurveType
AverageRemaining
Life(f) (g)
(Percent)
75.00 4.16 21.80R4.0310.20 633 12
100.00 -10.00 1.54 23.30S1.0311.00 143,759 13
60.00 -7.00 1.68 22.60R3.0312.10 81,207 14
70.00 -5.00 2.17 22.30R1.5312.20 484,069 15
25.00 20.00 2.57 12.20R3.0312.30 4,208 16
50.00 -5.00 2.50 20.30S0.5314.00 150,651 17
65.00 -7.00 6.24 22.20S1.5315.00 60,126 18
50.00 -5.00 5.93 20.80R0.5316.00 13,265 19
10.00 25.00 8.13 7.60L2.5316.10 92 20
10.00 25.00 9.52 L2.5316.40 241 21
10.00 25.00 5.94 8.20L2.5316.50 83 22
19.00 25.00 3.69 12.00S2.0316.60 106 23
19.00 25.00 3.88 16.70S2.0316.70 80 24
16.00 30.00 14.29 9.30S0.0316.80 1,300 25
30.00 25.00 1.99 21.10S1.5316.90 14 26
317.00 8,005 27
Subtotal Steam 947,839 28
100.00 -25.00 2.71 32.10R2.5331.00 156,227 29
90.00 -20.00 2.27 27.20S4.0332.10 19,461 30
90.00 -20.00 2.22 29.80S4.0332.20 227,957 31
2.87 28.60SQUARE332.30 5,472 32
80.00 -5.00 1.91 33.00R3.0333.00 197,921 33
50.00 -5.00 3.00 25.30R1.5334.00 45,854 34
90.00 2.11 30.50R2.0335.00 18,534 35
15.00 1.70 12.30SQUARE335.10 60 36
20.00 3.53 10.70SQUARE335.20 364 37
5.00 13.89 2.00SQUARE335.30 124 38
75.00 1.94 30.40R3.0336.00 8,112 39
Subtotal Hydro 680,086 40
35.00 3.02 30.40SQUARE341.00 7,169 41
35.00 2.75 32.40SQUARE342.00 4,446 42
35.00 2.98 29.70SQUARE343.00 98,952 43
35.00 2.54 33.80SQUARE344.00 31,682 44
35.00 2.89 28.30SQUARE345.00 25,078 45
35.00 2.71 29.50SQUARE346.00 3,138 46
Subtotal Other 170,465 47
65.00 1.51 54.20R3.0350.20 30,980 48
60.00 -30.00 1.68 47.30R3.0352.00 57,995 49
45.00 -5.00 2.06 35.40R1.0353.00 351,925 50
FERC FORM NO. 1 (REV. 12-03) Page 337
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No. Account No.
(c)(b)(a) (d) (e)
C. Factors Used in Estimating Depreciation ChargesDepreciablePlant Base
(In Thousands)
EstimatedAvg. Service
Life
NetSalvage
(Percent)
AppliedDepr. rates
MortalityCurveType
AverageRemaining
Life(f) (g)
(Percent)
65.00 -25.00 1.96 48.60S3.0354.00 147,491 12
55.00 -60.00 2.81 36.70R2.0355.00 107,027 13
65.00 -30.00 1.92 48.30R1.5356.00 171,802 14
65.00 0.98 23.80R3.0359.00 413 15
Subtotal Transmission 867,633 16
30.00 3.33 30.00SQUARE360.22 683 17
65.00 -30.00 1.85 52.60R2.5361.00 32,336 18
50.00 -5.00 1.89 42.10R0.5362.00 194,190 19
44.00 -50.00 3.29 31.50R1.5364.00 228,880 20
47.00 -40.00 2.95 35.10R0.5365.00 122,537 21
60.00 -20.00 1.95 51.20R2.0366.00 47,989 22
50.00 -15.00 1.97 41.10S0.5367.00 196,701 23
37.00 5.00 1.67 30.80R1.0368.00 429,420 24
35.00 -40.00 3.09 25.60R2.5369.00 57,225 25
20.00 6.95 11.90O1.0370.00 13,834 26
15.00 6.76 14.40S3.0370.10 57,488 27
3.00 25.67 1.50SQUARE370.30 41,109 28
10.00 -5.00 3.68 1.40S4.0371.10 27 29
15.00 -5.00 0.63 13.90R2.0371.20 2,728 30
25.00 -25.00 4.09 13.90R1.5373.20 4,395 31
374.00 643 32
Subtotal Distribution 1,430,185 33
100.00 -5.00 2.38 33.60S1.5390.11 26,794 34
50.00 -5.00 2.24 36.30L2.0390.12 57,632 35
30.00 2.58 20.80S3.0390.20 559 36
20.00 4.97 10.30SQUARE391.11 14,611 37
5.00 24.37 2.10SQUARE391.20 20,992 38
7.00 13.96 3.90L4.0391.21 4,956 39
10.00 25.00 6.23 5.90L2.5392.10 611 40
8.00 50.00 8.62 4.30S2.5392.30 2,590 41
10.00 25.00 3.58 7.30L2.5392.40 18,957 42
10.00 25.00 1.49 8.60L2.5392.50 766 43
19.00 25.00 3.69 12.00S2.0392.60 28,766 44
19.00 25.00 2.39 11.90S2.0392.70 4,923 45
30.00 25.00 1.99 21.10S1.5392.90 4,365 46
25.00 5.40 9.70SQUARE393.00 1,600 47
20.00 4.84 11.70SQUARE394.00 6,055 48
20.00 5.39 10.20SQUARE395.00 11,866 49
16.00 30.00 6.95 7.00S0.0396.00 10,696 50
FERC FORM NO. 1 (REV. 12-03) Page 337.1
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No. Account No.
(c)(b)(a) (d) (e)
C. Factors Used in Estimating Depreciation ChargesDepreciablePlant Base
(In Thousands)
EstimatedAvg. Service
Life
NetSalvage
(Percent)
AppliedDepr. rates
MortalityCurveType
AverageRemaining
Life(f) (g)
(Percent)
15.00 6.16 7.70SQUARE397.10 6,052 12
15.00 6.99 9.60SQUARE397.20 20,618 13
15.00 8.36 6.60SQUARE397.30 3,514 14
10.00 8.20 5.60SQUARE397.40 2,530 15
15.00 9.57 6.90SQUARE398.00 5,255 16
Subtotal General 254,708 17
Total Plant 4,350,916 18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
FERC FORM NO. 1 (REV. 12-03) Page 337.2
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
REGULATORY COMMISSION EXPENSES
Idaho Power Company X04/13/2012
2011/Q4
Line No.
Description Assessed by
(c)(b)(a)
Total Expense for
Expenses of
(d)
(Furnish name of regulatory commission or body the Regulatorydocket or case number and a description of the case) Commission Utility Current Year
(b) + (c)
Deferredin Account182.3 at
Beginning of Year(e)
1. Report particulars (details) of regulatory commission expenses incurred during the current year (or incurred in previous years, if beingamortized) 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 amountsdeferred in previous years.
Federal Energy Regulatory Commission: 1 Annual admin charges assessed by FERC 3,420,728 3,420,728 2
3Regulatory FERC fees credit -465,593 -465,593 4
5 General Regulatory Expenses and 6 Various other Dockets 44,334 44,334 7
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
REGULATORY COMMISSION EXPENSES (Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
(j)(i)(f) (k) (l)
EXPENSES INCURRED DURING YEAR AMORTIZED DURING YEARCURRENTLY CHARGED TO
Department AccountNo.(g)
Amount(h)
Deferred toAccount 182.3
ContraAccount
Amount Deferred in Account 182.3
End of Year
3. Show in column (k) any expenses incurred in prior years which are being amortized. List in column (a) the period of amortization.4. List in column (f), (g), and (h) expenses incurred during year which were charged currently to income, plant, or other accounts.5. Minor items (less than $25,000) may be grouped.
1 Electric 2 3,420,728 928
3 Electric 4 -465,593 928
5 6
Electric 7 44,334 928 8
Electric 9 158,501 928 10 11
Electric 12 29,224 928 13 14
Electric 15 10,534 928 16 17
Electric 18 51,581 928 Electric 19 16,345 928 Electric 20 20,721 928 Electric 21 16,225 928 Electric 22 18,671 928 Electric 23 36,618 928 Electric 24 91,448 928
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES
Idaho Power Company X04/13/2012
2011/Q4
Line No.
Description(b)(a)
Classification
1. Describe and show below costs incurred and accounts charged during the year for technological research, development, and demonstration (R, D & D)project initiated, continued or concluded during the year. Report also support given to others during the year for jointly-sponsored projects.(Identifyrecipient regardless of affiliation.) For any R, D & D work carried with others, show separately the respondent's cost for the year and cost chargeable toothers (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.) c. Internal combustion or gas turbine (7) Total Cost Incurred d. Nuclear B. Electric, R, D & D Performed Externally: e. Unconventional generation (1) Research Support to the electrical Research Council or the Electric f. Siting and heat rejection Power Research Institute (2) Transmission
Approximately $4 million of Idaho Power's 2011 1energy efficiency spending was related to 2research and analysis, education, technology 3evaluation and market transformation. Most of 4this activity was done in conjuction with the 5Northwest Energy Efficiency Alliance (NEEA). 6
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
DISTRIBUTION OF SALARIES AND WAGES
Idaho Power Company X04/13/2012
2011/Q4
Line No.
Classification
(c)(b)(a)
Direct Payroll Allocation of Total
(d)Distribution Payroll charged for
Clearing Accounts
Report below the distribution of total salaries and wages for the year. Segregate amounts originally charged to clearing accounts toUtility Departments, Construction, Plant Removals, and Other Accounts, and enter such amounts in the appropriate lines and columnsprovided. In determining this segregation of salaries and wages originally charged to clearing accounts, a method of approximationgiving substantially correct results may be used.
Electric 1Operation 2
16,828,328Production 3 6,540,757Transmission 4
Regional Market 5 16,919,375Distribution 6 8,747,995Customer Accounts 7 4,518,214Customer Service and Informational 8
Sales 9 42,450,346Administrative and General 10 96,005,015TOTAL Operation (Enter Total of lines 3 thru 10) 11
Regional Market 15 8,693,630Distribution 16 1,150,256Administrative and General 17
19,735,471TOTAL Maintenance (Total of lines 13 thru 17) 18Total Operation and Maintenance 19
23,496,171Production (Enter Total of lines 3 and 13) 20 9,764,499Transmission (Enter Total of lines 4 and 14) 21
Regional Market (Enter Total of Lines 5 and 15) 22 25,613,005Distribution (Enter Total of lines 6 and 16) 23 8,747,995Customer Accounts (Transcribe from line 7) 24 4,518,214Customer Service and Informational (Transcribe from line 8) 25
Sales (Transcribe from line 9) 26 43,600,602Administrative and General (Enter Total of lines 10 and 17) 27
115,740,486 115,740,486TOTAL Oper. and Maint. (Total of lines 20 thru 27) 28Gas 29Operation 30Production-Manufactured Gas 31Production-Nat. Gas (Including Expl. and Dev.) 32Other Gas Supply 33Storage, LNG Terminaling and Processing 34Transmission 35Distribution 36Customer Accounts 37Customer Service and Informational 38Sales 39Administrative and General 40TOTAL Operation (Enter Total of lines 31 thru 40) 41Maintenance 42Production-Manufactured Gas 43Production-Natural Gas (Including Exploration and Development) 44Other Gas Supply 45Storage, LNG Terminaling and Processing 46Transmission 47
FERC FORM NO. 1 (ED. 12-88) Page 354
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd ofIdaho Power Company X
04/13/20122011/Q4
Line No.
Classification
(c)(b)(a)
Direct Payroll Allocation of Total
(d)Distribution Payroll charged for
Clearing Accounts
DISTRIBUTION OF SALARIES AND WAGES (Continued)
Distribution 48Administrative and General 49TOTAL Maint. (Enter Total of lines 43 thru 49) 50Total Operation and Maintenance 51Production-Manufactured Gas (Enter Total of lines 31 and 43) 52Production-Natural Gas (Including Expl. and Dev.) (Total lines 32, 53Other Gas Supply (Enter Total of lines 33 and 45) 54Storage, LNG Terminaling and Processing (Total of lines 31 thru 47) 55Transmission (Lines 35 and 47) 56Distribution (Lines 36 and 48) 57Customer Accounts (Line 37) 58Customer Service and Informational (Line 38) 59Sales (Line 39) 60Administrative and General (Lines 40 and 49) 61TOTAL Operation and Maint. (Total of lines 52 thru 61) 62Other Utility Departments 63Operation and Maintenance 64
115,740,486 115,740,486TOTAL All Utility Dept. (Total of lines 28, 62, and 64) 65Utility Plant 66Construction (By Utility Departments) 67
34,917,073 34,917,073TOTAL Other Accounts 95 200,486,394 200,486,394TOTAL SALARIES AND WAGES 96
FERC FORM NO. 1 (ED. 12-88) Page 355
Idaho Power Company
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
MONTHLY TRANSMISSION SYSTEM PEAK LOAD
Idaho Power Company X04/13/2012
2011/Q4
Line No.
Monthly PeakMW - Total
(c)(b)(a)
Month
NAME OF SYSTEM:
Day ofMonthly
Peak
(1) Report the monthly peak load on the respondent's transmission system. If the respondent has two or more power systems which are not physicallyintegrated, furnish the required information for each non-integrated system.(2) Report on Column (b) by month the transmission system's peak load.(3) Report on Columns (c ) and (d) the specified information for each monthly transmission - system peak load reported on Column (b).(4) Report on Columns (e) through (j) by month the system' monthly maximum megawatt load by statistical classifications. See General Instruction for thedefinition of each statistical classification.
1,259 1,701 613 9,837 13,410Total for Quarter 4 16
5,062 7,287 2,791 41,914 57,054Total Year toDate/Year
17
FERC FORM NO. 1/3-Q (NEW. 07-04) Page 400
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
ELECTRIC ENERGY ACCOUNT
Idaho Power Company X04/13/2012
2011/Q4
Line No.
Item
(a)(b)(a) (b)
Line No.
MegaWatt Hours Item MegaWatt Hours
Report below the information called for concerning the disposition of electric energy generated, purchased, exchanged and wheeled during the year.
SOURCES OF ENERGY1
Generation (Excluding Station Use):2
4,820,344Steam3
Nuclear4
10,936,822Hydro-Conventional5
Hydro-Pumped Storage6
137,829Other7
Less Energy for Pumping8
15,894,995Net Generation (Enter Total of lines 3
through 8)
9
2,777,898Purchases10
Power Exchanges:11
602,391Received12
680,849Delivered13
-78,458Net Exchanges (Line 12 minus line 13)14
Transmission For Other (Wheeling)15
6,094,045Received16
6,092,216Delivered17
1,829Net Transmission for Other (Line 16 minus
line 17)
18
Transmission By Others Losses19
18,596,264TOTAL (Enter Total of lines 9, 10, 14, 18
and 19)
20
DISPOSITION OF ENERGY21
13,734,430Sales to Ultimate Consumers (Including
Interdepartmental Sales)
22
38,222Requirements Sales for Resale (See
instruction 4, page 311.)
23
3,596,702Non-Requirements Sales for Resale (See
instruction 4, page 311.)
24
Energy Furnished Without Charge25
Energy Used by the Company (Electric
Dept Only, Excluding Station Use)
26
1,226,910Total Energy Losses27
18,596,264TOTAL (Enter Total of Lines 22 Through
27) (MUST EQUAL LINE 20)
28
FERC FORM NO. 1 (ED. 12-90) Page 401a
(d)Day of Month
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
MONTHLY PEAKS AND OUTPUT
Idaho Power Company X04/13/2012
2011/Q4
Line No. Total Monthly Energy Megawatts
(c)(b)(a)Hour
(e)
MONTHLY PEAK
Month
NAME OF SYSTEM: Idaho Power CompanyMonthly Non-Requirments
Sales for Resale &Associated Losses (See Instr. 4)
1. Report the monthly peak load and energy output. If the respondent has two or more power which are not physically integrated, furnish the requiredinformation 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).
(f)January 29 4 2,231 299,156 8 AM 1,597,182
February 30 2 2,261 227,298 8 AM 1,335,990
March 31 8 1,907 307,278 8 AM 1,428,726
April 32 6 1,761 329,304 8 AM 1,345,151
May 33 16 1,746 389,411 11 AM 1,492,714
June 34 28 2,842 467,350 7 PM 1,776,088
July 35 6 2,973 162,831 8 PM 1,859,037
August 36 25 2,887 219,992 5 PM 1,812,353
September 37 7 2,564 352,808 6 PM 1,649,332
October 38 1 1,974 371,794 6 PM 1,415,974
November 39 16 1,933 237,956 8 AM 1,365,640
December 40 8 2,135 231,524 8 AM 1,518,077
FERC FORM NO. 1 (ED. 12-90) Page 401b
41 TOTAL 18,596,264 3,596,702
Schedule Page: 401 Line No.: 16 Column: bPage 329 column I differs from Page 401 by 1,829 MWH, reported for Lucky Peak variationand BPA Energy Imbalance schedules on page 401. The numbers that are shown on pages328-330 are for account 456 wheeling only. However the numbers on page 401 have to beadjusted for account 447 transmission.
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87) Page 450.1
BoardmanJim Bridger
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End ofIdaho Power Company X04/13/2012 2011/Q4
Line No.
Item
(b)(a) (c)
PlantName:
PlantName:
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 inthis 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 operatedas 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 attendmore 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 atherm 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 costper 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 onefuel is burned in a plant furnish only the composite heat rate for all fuels burned.
SteamSteam 1 Kind of Plant (Internal Comb, Gas Turb, NuclearConventionalSemi-Outdoor Boiler 2 Type of Constr (Conventional, Outdoor, Boiler, etc)
19801974 3 Year Originally Constructed19801979 4 Year Last Unit was Installed
64.20770.50 5 Total Installed Cap (Max Gen Name Plate Ratings-MW)60710 6 Net Peak Demand on Plant - MW (60 minutes)
69278760 7 Plant Hours Connected to Load00 8 Net Continuous Plant Capability (Megawatts)00 9 When Not Limited by Condenser Water00 10 When Limited by Condenser Water00 11 Average Number of Employees
2877660003865922000 12 Net Generation, Exclusive of Plant Use - KWh106610494358 13 Cost of Plant: Land and Land Rights
1383983266616189 14 Structures and Improvements60888268456703918 15 Equipment Costs
00 16 Asset Retirement Costs74834710523814465 17 Total Cost
1165.6497679.8371 18 Cost per KW of Installed Capacity (line 17/5) Including903348180745 19 Production Expenses: Oper, Supv, & Engr
568393992177415 20 Fuel00 21 Coolants and Water (Nuclear Plants Only)
832774331677 22 Steam Expenses00 23 Steam From Other Sources00 24 Steam Transferred (Cr)00 25 Electric Expenses
202872346835 29 Maintenance Supervision and Engineering438862251 30 Maintenance of Structures
10646570615 31 Maintenance of Boiler (or reactor) Plant2352243076437 32 Maintenance of Electric Plant4213925702564 33 Maintenance of Misc Steam (or Nuclear) Plant
9995198119654574 34 Total Production Expenses0.03470.0310 35 Expenses per Net KWh
Coal Oil Coal Oil 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)Tons Barrels Tons Barrels 37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)2161284 10732 0 171802 1170 0 38 Quantity (Units) of Fuel Burned9216 140000 0 8341 138800 0 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)40.722 150.926 0.000 28.907 132.823 0.000 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year42.137 82.085 0.000 32.042 121.791 0.000 41 Average Cost of Fuel per Unit Burned2.282 13.954 0.000 1.937 20.889 0.000 42 Average Cost of Fuel Burned per Million BTU0.024 0.000 0.000 0.020 0.000 0.000 43 Average Cost of Fuel Burned per KWh Net Gen10337.000 0.000 0.000 9897.000 0.000 0.000 44 Average BTU per KWh Net Generation
FERC FORM NO. 1 (REV. 12-03) Page 402
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and LoadDispatching, 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 plantsdesigned for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclearsteam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined cycleoperation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain byfootnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost unitsused for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for thereport period and other physical and operating characteristics of plant.
Bennett MountainDanskinValmy
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Schedule Page: 402 Line No.: 3 Column: bThis footnote applies to lines 3 and 4. The Jim Bridger PowerPlant consists of four equal units constructed jointly by IdahoPower Company and Pacific Power and Light Company, with Idahoowning 1/3 and PacifiCorp owning 2/3. Unit #1 was placed incommercial operation November 30, 1974, Unit #2 December 1, 1975,Unit #3 September 1, 1976, and Unit #4 November 29, 1979.Schedule Page: 402 Line No.: 3 Column: cThis footnote applies to lines 3 and 4. The Boardman plantconsists of one unit constructed jointly by Portland GeneralElectric Company, Idaho Power Company, and Pacific NorthwestGenerating Company, with Idaho Power Company owning 10%. Theunit was placed in commercial operation August 3, 1980.Schedule Page: 402 Line No.: 3 Column: dThis footnote applies to lines 3 and 4. The Valmy plant consistsof two units constructed jointly by Sierra Pacific Power Companyand Idaho Power Company, with Sierra owning 1/2 and Idaho owning1/2. Unit #1 was placed in commercial operation December 11, 1981and Unit #2 May 21, 1985.Schedule Page: 402 Line No.: 5 Column: bThis footnote applies to line 5 and lines 12 through 43.Information reflects Idaho Power Company's share as explainedin note for line 3 page 402 column B.Schedule Page: 402 Line No.: 5 Column: cThis footnote applies to line 5 and lines 12 through 43.Information reflects Idaho Power Company's share as explainedin note on line 3 page 402 column CSchedule Page: 402 Line No.: 5 Column: dThis footnote applies to line 5 and lines 12 through 43.Information reflects Idaho Power Company's share as explainedin note for line 3 page 403 column D.Schedule Page: 402 Line No.: 9 Column: bThis footnote applies to lines 9, 10, and 11. PacifiCorpas operator of the plant will report thisinformation.Schedule Page: 402 Line No.: 9 Column: cThis footnote applies to lines 9, 10, and 11. Portland GeneralElectric Company, as operator will report this information.Schedule Page: 402 Line No.: 9 Column: dThis footnote applies to lines 9, 10, and 11. Sierra PacificPower, as operator of the plant, will report this information.
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87) Page 450.1
1975Bliss
2736American Falls
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
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 afootnote. 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 eachplant.
Kind of Plant (Run-of-River or Storage) 1 Run-of-River Run-of-RiverPlant Construction type (Conventional or Outdoor) 2 Outdoor OutdoorYear Originally Constructed 3 1978 1949Year Last Unit was Installed 4 1978 1950Total installed cap (Gen name plate Rating in MW) 5 92.30 75.00Net Peak Demand on Plant-Megawatts (60 minutes) 6 108 77Plant Hours Connect to Load 7 8,694 8,760Net Plant Capability (in megawatts) 8 (a) Under Most Favorable Oper Conditions 9 110 76 (b) Under the Most Adverse Oper Conditions 10 0 1Average Number of Employees 11 4 4Net Generation, Exclusive of Plant Use - Kwh 12 586,802,000 513,605,000Cost of Plant 13 Land and Land Rights 14 875,318 768,358 Structures and Improvements 15 11,807,207 1,039,561 Reservoirs, Dams, and Waterways 16 4,293,075 8,413,888 Equipment Costs 17 31,659,620 8,393,112 Roads, Railroads, and Bridges 18 839,276 486,477 Asset Retirement Costs 19 0 0 TOTAL cost (Total of 14 thru 19) 20 49,474,496 19,101,396 Cost per KW of Installed Capacity (line 20 / 5) 21 536.0184 254.6853Production Expenses 22 Operation Supervision and Engineering 23 222,397 782,452 Water for Power 24 1,674,772 699,745 Hydraulic Expenses 25 116,486 780,235 Electric Expenses 26 50,572 45,043 Misc Hydraulic Power Generation Expenses 27 210,138 244,914 Rents 28 -568 -45,035 Maintenance Supervision and Engineering 29 89,270 151,939 Maintenance of Structures 30 211,483 274,177 Maintenance of Reservoirs, Dams, and Waterways 31 7,497 518,836 Maintenance of Electric Plant 32 292,363 86,802 Maintenance of Misc Hydraulic Plant 33 103,363 154,730 Total Production Expenses (total 23 thru 33) 34 2,977,773 3,693,838 Expenses per net KWh 35 0.0051 0.0072
FERC FORM NO. 1 (REV. 12-03) Page 406
2726Malad
1971Hells Canyon
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
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 afootnote. 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 eachplant.
Kind of Plant (Run-of-River or Storage) 1 Storage Run-of-RiverPlant Construction type (Conventional or Outdoor) 2 Outdoor OutdoorYear Originally Constructed 3 1967 1948Year Last Unit was Installed 4 1967 1948Total installed cap (Gen name plate Rating in MW) 5 391.50 21.77Net Peak Demand on Plant-Megawatts (60 minutes) 6 440 24Plant Hours Connect to Load 7 8,757 8,760Net Plant Capability (in megawatts) 8 (a) Under Most Favorable Oper Conditions 9 445 25 (b) Under the Most Adverse Oper Conditions 10 137 21Average Number of Employees 11 5 1Net Generation, Exclusive of Plant Use - Kwh 12 2,816,349,000 173,042,000Cost of Plant 13 Land and Land Rights 14 1,877,301 205,376 Structures and Improvements 15 2,811,400 2,777,503 Reservoirs, Dams, and Waterways 16 52,700,383 6,265,302 Equipment Costs 17 17,216,890 4,292,367 Roads, Railroads, and Bridges 18 819,192 304,683 Asset Retirement Costs 19 0 0 TOTAL cost (Total of 14 thru 19) 20 75,425,166 13,845,231 Cost per KW of Installed Capacity (line 20 / 5) 21 192.6569 635.9775Production Expenses 22 Operation Supervision and Engineering 23 377,827 214,911 Water for Power 24 327,519 702,291 Hydraulic Expenses 25 525,528 259,355 Electric Expenses 26 212,729 47,858 Misc Hydraulic Power Generation Expenses 27 249,786 115,885 Rents 28 82,999 0 Maintenance Supervision and Engineering 29 269,283 34,863 Maintenance of Structures 30 72,377 12,790 Maintenance of Reservoirs, Dams, and Waterways 31 211,408 8,405 Maintenance of Electric Plant 32 174,027 30,574 Maintenance of Misc Hydraulic Plant 33 374,531 52,676 Total Production Expenses (total 23 thru 33) 34 2,878,014 1,479,608 Expenses per net KWh 35 0.0010 0.0086
FERC FORM NO. 1 (REV. 12-03) Page 406.1
2778Shoshone Falls
2777Upper Salmon
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
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 afootnote. 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 eachplant.
Kind of Plant (Run-of-River or Storage) 1 Run-of-River Run-of-RiverPlant Construction type (Conventional or Outdoor) 2 Outdoor ConventionalYear Originally Constructed 3 1937 1907Year Last Unit was Installed 4 1947 1921Total installed cap (Gen name plate Rating in MW) 5 34.50 12.50Net Peak Demand on Plant-Megawatts (60 minutes) 6 37 14Plant Hours Connect to Load 7 8,760 8,640Net Plant Capability (in megawatts) 8 (a) Under Most Favorable Oper Conditions 9 39 14 (b) Under the Most Adverse Oper Conditions 10 32 11Average Number of Employees 11 3 2Net Generation, Exclusive of Plant Use - Kwh 12 293,884,000 110,438,000Cost of Plant 13 Land and Land Rights 14 202,399 313,328 Structures and Improvements 15 2,013,430 1,231,506 Reservoirs, Dams, and Waterways 16 5,569,171 512,402 Equipment Costs 17 7,763,706 4,523,995 Roads, Railroads, and Bridges 18 29,359 51,383 Asset Retirement Costs 19 0 0 TOTAL cost (Total of 14 thru 19) 20 15,578,065 6,632,614 Cost per KW of Installed Capacity (line 20 / 5) 21 451.5381 530.6091Production Expenses 22 Operation Supervision and Engineering 23 388,900 193,209 Water for Power 24 373,144 169,172 Hydraulic Expenses 25 551,980 127,220 Electric Expenses 26 86,416 38,400 Misc Hydraulic Power Generation Expenses 27 205,221 107,273 Rents 28 0 -315 Maintenance Supervision and Engineering 29 97,699 21,664 Maintenance of Structures 30 115,610 31,721 Maintenance of Reservoirs, Dams, and Waterways 31 254,149 6,789 Maintenance of Electric Plant 32 67,839 46,273 Maintenance of Misc Hydraulic Plant 33 239,825 67,634 Total Production Expenses (total 23 thru 33) 34 2,380,783 809,040 Expenses per net KWh 35 0.0081 0.0073
FERC FORM NO. 1 (REV. 12-03) Page 406.2
1971Brownlee Oxbow
1971Cascade
2848
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expensesdo not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
Run-of-River StorageStorage 1
Outdoor OutdoorOutdoor 2
1983 19611958 3
1984 19611980 4
12.42 190.00585.40 5
14 220680 6
8,711 8,7608,760 7 8
15 221747 9
1 202220 10
2 67 11
50,909,000 1,397,275,0002,924,285,000 12 13
82,142 1,210,18717,382,696 14
7,364,154 9,963,20131,438,553 15
3,145,630 30,466,78467,073,285 16
12,696,273 15,820,68355,992,367 17
122,668 565,844518,444 18
0 00 19
23,410,867 58,026,699172,405,345 20
1,884.9329 305.4037294.5086 21 22
204,900 350,884632,600 23
202,919 298,949576,341 24
320,137 471,375901,670 25
131,909 186,903303,160 26
179,822 273,829408,009 27
-17 49,901304,316 28
73,556 236,376455,958 29
63,144 261,452197,794 30
483 5,32165,107 31
63,839 162,548358,259 32
104,754 247,620682,115 33
1,345,446 2,545,1584,885,329 34
0.0264 0.00180.0017 35
FERC FORM NO. 1 (REV. 12-03) Page 407
2055C J Strike Twin Falls
18Swan Falls
503
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expensesdo not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
Run-of-River Run-of-RiverRun-of-River 1
Conventional ConventionalOutdoor 2
1910 19351952 3
1994 19951952 4
25.00 52.7482.80 5
25 5192 6
8,760 8,6278,760 7 8
24 5391 9
14 5084 10
4 46 11
157,917,000 394,475,000657,632,000 12 13
51,675 255,4995,473,876 14
25,453,938 10,808,0479,203,458 15
13,856,887 7,908,87010,438,597 16
30,331,287 20,759,50311,937,740 17
835,946 1,917,603248,183 18
0 00 19
70,529,733 41,649,52237,301,854 20
2,821.1893 789.7141450.5055 21 22
212,122 232,982870,472 23
174,581 216,977843,278 24
148,772 178,3931,171,858 25
34,517 53,46242,777 26
113,831 148,674355,585 27
-31,048 -11,887-113,298 28
61,292 30,04796,665 29
79,419 38,832128,592 30
183,048 37,877115,796 31
22,414 38,864134,533 32
125,136 79,005144,740 33
1,124,084 1,043,2263,790,998 34
0.0071 0.00260.0058 35
FERC FORM NO. 1 (REV. 12-03) Page 407.1
1971Common Facilities Milner
2899Lower Salmon
2061
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expensesdo not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
Run-of-River Run-of-River 1
Outdoor Conventional 2
1949 1992 3
1949 1992 4
60.00 59.450.00 5
65 590 6
8,760 8,6530 7 8
64 610 9
60 10 10
7 20 11
391,028,000 435,475,0000 12 13
424,428 138,100114,367 14
2,805,900 10,340,10526,615,283 15
6,916,532 17,114,93413,556,785 16
8,069,424 27,665,1971,288,563 17
88,693 501,87799,051 18
0 00 19
18,304,977 55,760,21341,674,049 20
305.0830 937.93460.0000 21 22
379,189 233,9580 23
352,498 2,115,8190 24
379,465 119,0646,376,408 25
232,553 49,5000 26
203,217 236,9620 27
-13,894 -11,9410 28
73,977 44,1600 29
156,154 43,7010 30
8,085 80,6120 31
119,879 79,5940 32
160,281 74,10654,282 33
2,051,404 3,065,5356,430,690 34
0.0052 0.00700.0000 35
FERC FORM NO. 1 (REV. 12-03) Page 407.2
Schedule Page: 406 Line No.: 1 Column: bAmerican Falls generating capacity is dependent upon water releases controlled by theUSBR. Schedule Page: 406 Line No.: 1 Column: e Cascade generating capacity is dependent upon water releases controlled by the USBR.Schedule Page: 406 Line No.: 1 Column: fUpstream storage in Brownlee Reservoir Schedule Page: 406.1 Line No.: 1 Column: bUpstream storage in Brownlee Reservoir Schedule Page: 406.1 Line No.: 1 Column: cLower Malad maximum demand 15,000 Kw, Upper Malad maximum demand 9,000 Kw non-coincident.
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87) Page 450.1
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
GENERATING PLANT STATISTICS (Small Plants)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
Name of PlantInstalled Capacity
(c)(b)(a)
Cost of PlantNet PeakDemand
(d)
YearOrig.
Const.Name Plate Rating
(In MW) MW(60 min.)
Net GenerationExcludingPlant Use
(e) (f)
1. Small generating plants are steam plants of, less than 25,000 Kw; internal combustion and gas turbine-plants, conventional hydro plants and pumpedstorage plants of less than 10,000 Kw installed capacity (name plate rating). 2. Designate any plant leased from others, operated under a license fromthe Federal Energy Regulatory Commission, or operated as a joint facility, and give a concise statement of the facts in a footnote. If licensed project, giveproject number in footnote.
Hydro: 1
2.50 2.3 16,495 1,759,9231937 Clear Lakes 2
8.80 7.4 17,211 9,322,8331912 Thousand Springs 3
4
5
Internal Combustion: 6
5.00 4.2 26 909,2591967 Salmon Diesel (1) 7
8
9
10
(1) Salmon units are classified as standby. 11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO. 1 (REV. 12-03) Page 410
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
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 withcombinations of steam, hydro internal combustion or gas turbine equipment, report each as a separate plant. However, if the exhaust heat from the gasturbine 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 AssetRetire. Costs) Per MW
1
36,555 703,969 2 123,037
252,473 1,059,413 3 213,644
4
5
6
181,852 7Diesel
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO. 1 (REV. 12-03) Page 411
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
TRANSMISSION LINE STATISTICS
Idaho Power Company X04/13/2012
2011/Q4
Line No.
(c)(b)(a) (d) (e)
DESIGNATION
From To
(f) (g)
VOLTAGE (KV)(Indicate whereother than60 cycle, 3 phase)
Operating Designed
Type of
Supporting
Structure
LENGTH (Pole miles)(In the case of underground lines
report circuit miles)On Structure
of LineDesignated
On Structuresof Another
Line
NumberOf
Circuits
(h)
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132kilovolts 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 reportsubstation 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 bythe use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainderof 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 isreported 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. Reportpole 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 withrespect to such structures are included in the expenses reported for the line designated.
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
TRANSMISSION LINE STATISTICS
Idaho Power Company X04/13/2012
2011/Q4
Line No.
(c)(b)(a) (d) (e)
DESIGNATION
From To
(f) (g)
VOLTAGE (KV)(Indicate whereother than60 cycle, 3 phase)
Operating Designed
Type of
Supporting
Structure
LENGTH (Pole miles)(In the case of underground lines
report circuit miles)On Structure
of LineDesignated
On Structuresof Another
Line
NumberOf
Circuits
(h)
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132kilovolts 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 reportsubstation 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 bythe use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainderof 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 isreported 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. Reportpole 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 withrespect to such structures are included in the expenses reported for the line designated.
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
TRANSMISSION LINE STATISTICS
Idaho Power Company X04/13/2012
2011/Q4
Line No.
(c)(b)(a) (d) (e)
DESIGNATION
From To
(f) (g)
VOLTAGE (KV)(Indicate whereother than60 cycle, 3 phase)
Operating Designed
Type of
Supporting
Structure
LENGTH (Pole miles)(In the case of underground lines
report circuit miles)On Structure
of LineDesignated
On Structuresof Another
Line
NumberOf
Circuits
(h)
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132kilovolts 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 reportsubstation 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 bythe use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainderof 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 isreported 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. Reportpole 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 withrespect to such structures are included in the expenses reported for the line designated.
H Wood 138.00 138.00 84.51 2 1 King Lower MaladH Wood 138.00 138.00 66.46 2 2 Emmett Jct PayetteH Wood 138.00 138.00 6.20 1 3 Mountain Home AFB TapH Wood 138.00 138.00 73.33 1 4 Ontario QuartzS Tower 138.00 138.00 1.03 2 5 King American Falls PPH Wood 138.00 138.00 141.74 1 6 King American Falls PPS P Wood 138.00 138.00 3.71 1 7 King American Falls PPH Wood 138.00 138.00 6.22 1 8 Duffin ClawsonH Wood 138.00 138.00 0.33 1 9 American Falls Brady TieH Wood 138.00 138.00 5.66 1 10 Upper Salmon A-B KingH Wood 138.00 138.00 125.59 1 11 Upper Salmon B WellsH Wood 138.00 138.00 73.71 1 12 King Wood RiverS P Wood 138.00 138.00 10.38 2 13 Boise Bench GroveH Wood 138.00 138.00 67.32 1 14 Quartz John DayH Wood 138.00 138.00 2.80 1 15 Sinker Creek TapH Wood 138.00 138.00 2.57 1 16 Mora CloverdaleS P Wood 138.00 138.00 22.28 1 17 Mora CloverdaleS P Steel 138.00 138.00 0.96 2 18 Mora CloverdaleS P Steel 138.00 138.00 3.80 1 19 Stoddard Jct Stoddard SubH Wood 138.00 138.00 1.95 1 20 Fossil Gulch TapH Wood 138.00 138.00 53.04 2 21 Wood River MidpointS P Wood 138.00 138.00 16.69 2 22 Wood River MidpointH Wood 138.00 138.00 37.16 1 23 Oxbow McCallS P Wood 138.00 138.00 2.32 1 24 Oxbow McCallS P Wood 138.00 138.00 7.50 2 25 Lowell Jct NampaS P Wood 138.00 138.00 19.40 1 26 Hunt MilnerH Wood 138.00 138.00 13.49 1 27 Strike Bruneau BridgeS P Wood 138.00 138.00 18.40 2 28 American Falls Kramer SubS P Wood 138.00 138.00 11.72 1 29 Pingree HavenS P Wood 138.00 138.00 25.13 2 30 Midpoint Twin FallsS P Wood 138.00 138.00 1.71 1 31 Twin Falls RussettS P Wood 138.00 46.00 6.18 2 32 Blackfoot AikenH Wood 138.00 69.00 57.21 1 33 Peterson TendoyS P Wood 138.00 138.00 6.36 1 34 Eastgate Tap EastgateS P Steel 138.00 138.00 1.83 2 35 Kimberly Tap Kimberly
FERC FORM NO. 1 (ED. 12-87) Page 422.2
36 TOTAL 4,759.01 11.02 186
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
TRANSMISSION LINE STATISTICS
Idaho Power Company X04/13/2012
2011/Q4
Line No.
(c)(b)(a) (d) (e)
DESIGNATION
From To
(f) (g)
VOLTAGE (KV)(Indicate whereother than60 cycle, 3 phase)
Operating Designed
Type of
Supporting
Structure
LENGTH (Pole miles)(In the case of underground lines
report circuit miles)On Structure
of LineDesignated
On Structuresof Another
Line
NumberOf
Circuits
(h)
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132kilovolts 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 reportsubstation 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 bythe use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainderof 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 isreported 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. Reportpole 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 withrespect to such structures are included in the expenses reported for the line designated.
H Wood 138.00 138.00 13.18 2 1 Boise Bench MoraS P Wood 138.00 138.00 0.51 1 2 Bowmont-Caldwell Simplot SubS P Wood 138.00 138.00 6.53 1 3 Gary Lane EagleS P Steel 138.00 138.00 2.98 10.06 1 4 Locust Grove Blackcat SubS P Wood 138.00 138.00 4.02 0.14 1 5 Boise Bench ButlerS P Wood 138.00 138.00 6.39 1 6 Eagle StarS P Steel 138.00 138.00 2.08 1 7 Karcher Sub Zilog TapS P Steel 138.00 138.00 4.02 0.40 1 8 Cloverdale - 712 712 - WyeS P Steel 138.00 138.00 1.90 1 9 Victory Jct VictoryS P Steel 138.00 138.00 2.94 1 10 Butler WyeH Wood 138.00 138.00 33.86 1 11 Horseflat StarkeyS P Steel 138.00 138.00 2.08 2 12 Starkey MccallH Wood 138.00 138.00 3.80 1 13 Starkey MccallS P Steel 138.00 138.00 1.50 1 14 Starkey MccallS P Wood 138.00 138.00 17.61 1 15 Starkey MccallS P Steel 138.00 138.00 2.80 1 16 Chestnut Happy Valley
138.00 17 Garnet WardS P Wood 138.00 138.00 8.80 1 18 McCall Lake ForkS Steel 138.00 138.00 2.90 19 McCall Lake ForkS P Steel 138.00 138.00 1.30 1 20 Caldwell WillisS P Steel 138.00 138.00 1.59 1 21 Caldwell WillisS P Wood 138.00 138.00 0.87 1 22 Caldwell WillisS P Steel 138.00 138.00 0.80 2 23 Valivue TapS Tower 138.00 138.00 1.24 2 24 Kinport Don #1S P Steel 138.00 138.00 2.74 1 25 Donn HOKUS P Steel 138.00 138.00 5.31 1 26 Rockland Jct Rockland Wind FarmS P Steel 138.00 138.00 0.22 2 27 HOKU AlamedS P Steel 138.00 138.00 0.23 2 28 HOKU AlamedS P Steel 138.00 138.00 2.85 1 29 HOKU AlamedH Wood 138.00 138.00 0.82 1 30 Twin Falls PP TapS P Steel 138.00 138.00 0.37 1 31 American Falls PP Amercian Falls Trans STH Wood 138.00 138.00 0.11 1 32 Lower Salmon King TieS Tower 138.00 138.00 4.32 2 33 C J Strike Strike JctH Wood 138.00 138.00 23.39 1 34 Strike Jct Mountain Home JctH Wood 138.00 0.05 1 35 Strike Jct Bowmont
FERC FORM NO. 1 (ED. 12-87) Page 422.3
36 TOTAL 4,759.01 11.02 186
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
TRANSMISSION LINE STATISTICS
Idaho Power Company X04/13/2012
2011/Q4
Line No.
(c)(b)(a) (d) (e)
DESIGNATION
From To
(f) (g)
VOLTAGE (KV)(Indicate whereother than60 cycle, 3 phase)
Operating Designed
Type of
Supporting
Structure
LENGTH (Pole miles)(In the case of underground lines
report circuit miles)On Structure
of LineDesignated
On Structuresof Another
Line
NumberOf
Circuits
(h)
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132kilovolts 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 reportsubstation 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 bythe use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainderof 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 isreported 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. Reportpole 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 withrespect to such structures are included in the expenses reported for the line designated.
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
TRANSMISSION LINE STATISTICS (Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
COST OF LINE (Include in Column (j) Land,
Size ofConductor
and Material
Land rights, and clearing right-of-way)EXPENSES, EXCEPT DEPRECIATION AND TAXES
OperationExpenses
Maintenance Rents TotalLand Construction andOther Costs
Total Cost
(i) (j) (k) (l) (m) (n) (o) (p)Expenses Expenses
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote ifyou do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report thepole 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 whichthe respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining thearrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expensesof the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or other party isan 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 howdetermined. Specify whether lessee is an associated company.10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
TRANSMISSION LINE STATISTICS (Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
COST OF LINE (Include in Column (j) Land,
Size ofConductor
and Material
Land rights, and clearing right-of-way)EXPENSES, EXCEPT DEPRECIATION AND TAXES
OperationExpenses
Maintenance Rents TotalLand Construction andOther Costs
Total Cost
(i) (j) (k) (l) (m) (n) (o) (p)Expenses Expenses
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote ifyou do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report thepole 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 whichthe respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining thearrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expensesof the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or other party isan 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 howdetermined. Specify whether lessee is an associated company.10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
TRANSMISSION LINE STATISTICS (Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
COST OF LINE (Include in Column (j) Land,
Size ofConductor
and Material
Land rights, and clearing right-of-way)EXPENSES, EXCEPT DEPRECIATION AND TAXES
OperationExpenses
Maintenance Rents TotalLand Construction andOther Costs
Total Cost
(i) (j) (k) (l) (m) (n) (o) (p)Expenses Expenses
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote ifyou do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report thepole 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 whichthe respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining thearrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expensesof the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or other party isan 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 howdetermined. Specify whether lessee is an associated company.10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
TRANSMISSION LINE STATISTICS (Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
COST OF LINE (Include in Column (j) Land,
Size ofConductor
and Material
Land rights, and clearing right-of-way)EXPENSES, EXCEPT DEPRECIATION AND TAXES
OperationExpenses
Maintenance Rents TotalLand Construction andOther Costs
Total Cost
(i) (j) (k) (l) (m) (n) (o) (p)Expenses Expenses
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote ifyou do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report thepole 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 whichthe respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining thearrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expensesof the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or other party isan 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 howdetermined. Specify whether lessee is an associated company.10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
TRANSMISSION LINE STATISTICS (Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
COST OF LINE (Include in Column (j) Land,
Size ofConductor
and Material
Land rights, and clearing right-of-way)EXPENSES, EXCEPT DEPRECIATION AND TAXES
OperationExpenses
Maintenance Rents TotalLand Construction andOther Costs
Total Cost
(i) (j) (k) (l) (m) (n) (o) (p)Expenses Expenses
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote ifyou do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report thepole 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 whichthe respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining thearrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expensesof the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or other party isan 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 howdetermined. Specify whether lessee is an associated company.10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
TRANSMISSION LINES ADDED DURING YEAR
Idaho Power Company X04/13/2012
2011/Q4
Line No.
(c)(b)(a) (d) (e)
LINE DESIGNATION
From To
LineLength
inMiles
SUPPORTING STRUCTURE
TypeAverage
Number perMiles
CIRCUITS PER STRUCTURE
Present Ultimate
(f) (g)
1. Report below the information called for concerning Transmission lines added or altered during the year. It is not necessary to reportminor revisions of lines.2. Provide separate subheadings for overhead and under- ground construction and show each transmission line separately. If actualcosts of competed construction are not readily available for reporting columns (l) to (o), it is permissible to report in these columns the
9.90W Pole 1 1 5 Neils Hot Springs Neils Hot Springs 10.44
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
19.48 58.30 5 5
FERC FORM NO. 1 (REV. 12-03) Page 424
44 TOTAL
Total
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
TRANSMISSION LINES ADDED DURING YEAR (Continued)
Idaho Power Company X04/13/2012
2011/Q4
Line No.
(k)(j)(h) (l) (m)
CONDUCTORSSize Configuration
VoltageKV
LINE COST
Land and Poles, Towersand Fixtures
Conductors
(n) (p)
Specificationand Spacing (Operating) Land Rights and Devices
(i)
costs. Designate, however, if estimated amounts are reported. Include costs of Clearing Land and Rights-of-Way, and Roads andTrails, in column (l) with appropriate footnote, and costs of Underground Conduit in column (m).3. If design voltage differs from operating voltage, indicate such fact by footnote; also where line is other than 60 cycle, 3 phase, indicatesuch other characteristic.
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
SUBSTATIONS
Idaho Power Company X04/13/2012
2011/Q4
Line No. Name and Location of Substation
Primary(c)(b)(a)
Tertiary(d)
Character of Substation
(e)Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.2. Substations which serve only one industrial or street railway customer should not be listed below.3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according tofunctional 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 whetherattended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations incolumn (f).
Adelaide 138.00 345.00 13.80transmission 1
Aiken 13.00 46.00distribution 2
Alameda 13.00 46.00distribution 3
Alameda 13.09 138.00distribution 4
American Falls PP - attended 13.80 138.00transmission 5
American Falls 46.00 138.00 12.47transmission 6
Artesian 13.00 46.00distribution 7
Bannock Creek 13.00 46.00distribution 8
Bennett Mountain Power Plant- attended 18.00 230.00transmission 9
Bennett Mountain Power Plant- attended 4.16 18.00distribution 10
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
SUBSTATIONS
Idaho Power Company X04/13/2012
2011/Q4
Line No. Name and Location of Substation
Primary(c)(b)(a)
Tertiary(d)
Character of Substation
(e)Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.2. Substations which serve only one industrial or street railway customer should not be listed below.3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according tofunctional 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 whetherattended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations incolumn (f).
Caldwell 13.09 138.00distribution 1
Caldwell 69.00 138.00 12.47transmission 2
Caldwell 138.00 230.00 12.47transmission 3
Caldwell 4.16 13.00distribution 4
Canyon Creek 35.00 138.00distribution 5
Canyon Creek 69.00 138.00 12.98transmission 6
Cascade Power Plant - attended 4.60 69.00transmission 7
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
SUBSTATIONS
Idaho Power Company X04/13/2012
2011/Q4
Line No. Name and Location of Substation
Primary(c)(b)(a)
Tertiary(d)
Character of Substation
(e)Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.2. Substations which serve only one industrial or street railway customer should not be listed below.3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according tofunctional 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 whetherattended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations incolumn (f).
Emmett 69.00 138.00 12.47Transmission 1
Falls 13.00 46.00distribution 2
Filer 13.00 46.00distribution 3
Flying H 2.40 69.00distribution 4
Fort Hall 13.00 46.00distribution 5
Fossil Gulch 35.00 138.00distribution 6
Fremont 46.00 138.00 12.50transmission 7
Gary 13.00 138.00distribution 8
Gem 13.00 69.00distribution 9
Gem 69.00distribution 10
Goodng Rural 13.00 46.00distribution 11
Golden Valley 13.00 69.00distribution 12
Gowen Substation 35.00 138.00distribution 13
Grindstone 35.00distribution 14
Grove 13.09 138.00distribution 15
Hagerman 13.00 46.00distribution 16
Hagerman 13.00 46.00 32.00distribution 17
Hailey 13.00 138.00distribution 18
Happy Valley 13.09 138.00distribution 19
Haven 35.00 138.00distribution 20
Haven 46.00 138.00transmission 21
Hemingway 230.00 500.00 34.50transmission 22
Hewlett Packard 13.00 138.00distribution 23
Hidden Springs 13.00 138.00distribution 24
Highland 13.00 138.00distribution 25
Hill 13.00 138.00distribution 26
Hillsdale 138.00distribution 27
Hoku 13.80 138.00distribution 28
Homedale 13.00 69.00distribution 29
Horse Flat 138.00 230.00 13.80transmission 30
Horseshoe Bend 35.00distribution 31
Horseshoe Bend 36.20 69.00distribution 32
Horseshoe Bend 25.00 69.00distribution 33
Huston 13.00 69.00distribution 34
Hulen 13.00 46.00distribution 35
Hunt 138.00 230.00 13.80transmission 36
Hydra 36.20 138.00distribution 37
Island 13.00 69.00distribution 38
Jerome 13.00 138.00distribution 39
Julion Clawson 35.00 138.00distribution 40
FERC FORM NO. 1 (ED. 12-96) Page 426.2
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
SUBSTATIONS
Idaho Power Company X04/13/2012
2011/Q4
Line No. Name and Location of Substation
Primary(c)(b)(a)
Tertiary(d)
Character of Substation
(e)Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.2. Substations which serve only one industrial or street railway customer should not be listed below.3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according tofunctional 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 whetherattended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations incolumn (f).
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
SUBSTATIONS
Idaho Power Company X04/13/2012
2011/Q4
Line No. Name and Location of Substation
Primary(c)(b)(a)
Tertiary(d)
Character of Substation
(e)Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.2. Substations which serve only one industrial or street railway customer should not be listed below.3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according tofunctional 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 whetherattended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations incolumn (f).
Moreland 13.00 35.00distribution 1
Moreland 13.00 46.00distribution 2
Moreland 35.00 46.00 12.47distribution 3
Mountain Home 13.00 69.00distribution 4
Mountain Home Air Force Base 13.00 69.00distribution 5
Mountain Home Air Force Base 13.00 138.00distribution 6
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
SUBSTATIONS
Idaho Power Company X04/13/2012
2011/Q4
Line No. Name and Location of Substation
Primary(c)(b)(a)
Tertiary(d)
Character of Substation
(e)Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.2. Substations which serve only one industrial or street railway customer should not be listed below.3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according tofunctional 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 whetherattended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations incolumn (f).
Siphon 35.00 138.00distribution 1
South Park 13.00 46.00distribution 2
Star 13.09 138.00distribution 3
Starkey 69.00 138.00 12.47Transmission 4
State 13.00 69.00distribution 5
Stoddard 13.00 138.00distribution 6
Strike Power Plant - attended 13.80 138.00transmission 7
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
SUBSTATIONS
Idaho Power Company X04/13/2012
2011/Q4
Line No. Name and Location of Substation
Primary(c)(b)(a)
Tertiary(d)
Character of Substation
(e)Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.2. Substations which serve only one industrial or street railway customer should not be listed below.3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according tofunctional 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 whetherattended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations incolumn (f).
Jim Bridger - attended 22.00 345.00transmission 30
Jim Bridger - attended 230.00 345.00 34.50transmission 31
32
33
34
35
36
Transformers-distribution substations under 10,000 37
KVA 84 unattended. 38
39
40
FERC FORM NO. 1 (ED. 12-96) Page 426.6
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
SUBSTATIONS
Idaho Power Company X04/13/2012
2011/Q4
Line No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation(In Service) (In MVa)
Number ofTransformers
In ServiceSpare
Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment forincreasing capacity.6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than byreason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date andperiod of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give nameof co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accountsaffected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
300 2 1
20 2 2
15 1 3
18 1 4
72 1 5
25 1 6
10 1 7
10 1 8
135 1 9
5 1 10
15 1 11
24 1 12
30 2 13
50 3 1 14
80 1 15
69 3 16
15 1 17
254 2 18
42 2 19
75 3 20
240 2 21
67 3 22
450 3 1 23
8 3 24
18 1 25
25 1 26
25 1 27
180 1 28
5 29
312 3 30
1 31
1 32
721 5 1 33
30 2 34
20 1 35
6 1 1 36
20 2 37
12 1 38
48 2 39
15 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
SUBSTATIONS
Idaho Power Company X04/13/2012
2011/Q4
Line No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation(In Service) (In MVa)
Number ofTransformers
In ServiceSpare
Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment forincreasing capacity.6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than byreason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date andperiod of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give nameof co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accountsaffected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
24 1 1
75 3 2
240 2 3
1 4
15 1 5
15 1 6
12 1 7
10 1 8
48 2 9
4 1 10
12 2 1 11
4 1 12
48 2 13
7 14
1 15
27 1 16
25 1 17
140 1 18
180 1 19
6 1 20
96 2 21
1 22
108 6 3 23
26 1 1 24
80 6 25
118 7 26
160 2 27
17 1 28
36 2 29
38 2 30
24 1 31
18 1 32
18 1 33
24 1 34
15 1 35
8 1 36
8 1 37
17 1 38
30 2 39
24 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.1
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
SUBSTATIONS
Idaho Power Company X04/13/2012
2011/Q4
Line No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation(In Service) (In MVa)
Number ofTransformers
In ServiceSpare
Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment forincreasing capacity.6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than byreason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date andperiod of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give nameof co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accountsaffected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
25 1 1
18 2 2
10 1 3
15 2 4
10 1 1 5
15 1 6
50 3 1 7
37 2 8
8 1 9
10 1 10
15 2 11
10 1 1 12
24 1 13
5 2 14
72 3 15
10 1 16
5 1 17
20 1 18
18 1 19
12 1 20
25 1 21
600 3 1 22
20 1 23
8 1 24
18 1 25
39 2 26
24 1 27
72 2 28
22 2 29
100 1 30
5 1 31
12 1 32
5 1 33
10 1 34
10 1 35
300 3 36
48 2 37
12 1 38
40 2 39
30 2 40
FERC FORM NO. 1 (ED. 12-96) Page 427.2
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
SUBSTATIONS
Idaho Power Company X04/13/2012
2011/Q4
Line No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation(In Service) (In MVa)
Number ofTransformers
In ServiceSpare
Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment forincreasing capacity.6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than byreason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date andperiod of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give nameof co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accountsaffected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
15 1 1
18 1 2
12 1 3
20 2 4
42 2 5
18 1 6
7 7
180 1 8
180 1 9
600 3 1 10
12 1 11
18 1 12
15 1 13
18 1 14
15 1 15
18 1 16
12 1 17
10 1 18
33 2 19
48 2 20
360 2 21
16 1 22
70 4 23
10 1 24
12 1 25
18 1 26
36 2 27
24 2 28
24 2 29
120 1 30
720 2 31
750 3 1 32
24 1 33
100 4 34
8 3 1 35
29 2 36
36 1 37
12 1 38
15 1 39
24 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.3
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
SUBSTATIONS
Idaho Power Company X04/13/2012
2011/Q4
Line No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation(In Service) (In MVa)
Number ofTransformers
In ServiceSpare
Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment forincreasing capacity.6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than byreason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date andperiod of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give nameof co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accountsaffected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
6 1 1
8 1 2
8 4 3
15 1 4
1 5
18 1 6
180 1 7
50 3 8
12 1 9
10 1 10
10 1 11
6 1 12
10 3 13
10 1 14
12 1 15
36 2 16
23 3 17
50 3 18
22 2 19
42 2 20
36 2 21
18 1 22
23
18 1 24
1 25
14 2 26
18 1 27
15 2 28
15 1 29
10 1 3 30
10 3 31
2 32
5 2 33
10 1 34
2 3 35
3 1 36
10 1 37
12 1 38
15 1 39
12 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.4
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
SUBSTATIONS
Idaho Power Company X04/13/2012
2011/Q4
Line No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation(In Service) (In MVa)
Number ofTransformers
In ServiceSpare
Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment forincreasing capacity.6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than byreason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date andperiod of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give nameof co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accountsaffected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
33 2 1
10 1 2
18 1 3
18 1 4
33 2 5
15 1 6
83 3 7
20 2 8
18 1 9
5 1 10
24 1 11
42 3 12
8 1 13
3 1 14
18 1 15
44 2 16
33 2 17
9 1 18
72 1 19
8 1 20
36 4 21
44 2 22
18 1 23
24 1 24
18 1 25
12 1 1 26
20 2 27
25 1 28
10 1 29
18 1 30
56 3 31
24 1 32
33
34
35
36
37
30 3 1 38
39
40
FERC FORM NO. 1 (ED. 12-96) Page 427.5
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
SUBSTATIONS
Idaho Power Company X04/13/2012
2011/Q4
Line No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation(In Service) (In MVa)
Number ofTransformers
In ServiceSpare
Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment forincreasing capacity.6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than byreason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date andperiod of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give nameof co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accountsaffected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
315 1 1
300 1 1 2
20 3 1 3
4
5
685 3 1 6
55 1 7
55 1 8
12 1 9
500 3 10
1 1 11
40 1 12
8 3 1 13
20 2 14
38 2 15
25 1 1 16
240 2 17
50 2 18
1 19
15 1 20
10 3 1 21
244 2 22
100 1 23
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FERC FORM NO. 1 (ED. 12-96) Page 427.6
Schedule Page: 426.2 Line No.: 22 Column: aPacifiCorp has a 59% interest in certain high-voltage transmission related andinterconnection equipment located at Idaho Power's Hemingway Station. Schedule Page: 426.4 Line No.: 23 Column: aIdaho Power has a 20.8% interest in certain high-voltage transmission related andinterconnection equipment located at PacifiCorp's Populus station. Schedule Page: 426.6 Line No.: 1 Column: aJointly 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: aJointly 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.: 6 Column: aJointly owned with Portland General Electric, Power Resources Cooperative and BA LeasingBCS, LLC. Idaho Power has a 10% share of the jointly owned capacity. 100% of the capacityis reported. Schedule Page: 426.6 Line No.: 7 Column: aJointly owned with Portland General Electric, Power Resources Cooperative and BA LeasingBCS, LLC. Idaho Power has a 10% share of the jointly owned capacity. 100% of the capacityis reported. Schedule Page: 426.6 Line No.: 8 Column: aJointly owned with Portland General Electric, Power Resources Cooperative and BA LeasingBCS, LLC. Idaho Power has a 10% share of the jointly owned capacity. 100% of the capacityis reported. Schedule Page: 426.6 Line No.: 30 Column: aJointly owned with PacificCorp. Idaho Power has a 33.3% share of ownership. Schedule Page: 426.6 Line No.: 31 Column: aJointly owned with PacificCorp. Idaho Power has a 33.3% share of ownership.
Name of Respondent
Idaho Power Company
This Report is:(1) X An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/13/2012
Year/Period of Report
2011/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87) Page 450.1
Name of Respondent This Report Is:(1) An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of ReportEnd of
TRANSACTIONS WITH ASSOCIATED (AFFILIATED) COMPANIES
Idaho Power Company X04/13/2012
2011/Q4
Line No. Description of the Non-Power Good or Service
Name of
(c)(b)(a) (d)
Associated/AffiliatedCompany
AccountCharged or
Credited
Amount
Credited
1. 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 notattempt 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.
Charged or
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20 Non-power Goods or Services Provided for Affiliate 21 Managerial Expense 457,141IDACORP, Inc. 417420
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FERC FORM NO. 1 (New) Page 429FERC FORM NO. 1-F (New)
Idaho Power Company STATE OF OREGON - ALLOCATED
An Original December 31, 2011
POLITICAL ADVERTISING
INSTRUCTIONS: List all payments for advertising, the purpose of which is to aid or defeat any measure before the people or to promote or prevent the enactment of any national, state, district or municipal legislation. Give the specific purpose of such advertising, when and where placed, and the account or accounts charged. Report whole dollars only. Provide a total for each account and a grand total.
Description Account AmountCharged
None
OREGON SUPPLEMENTPage 41
2011 Annual Report
At IDACORP, we have a legacy of
building today for tomorrow’s needs.
And 2011 was a year in which financial,
technological and infrastructure plans
at our primary subsidiary — Idaho
Power — came together to build for
the long view. Our three-part strategy
of responsible planning, responsible
development and protection of
resources, and responsible energy
use means we are looking to the
future while meeting today’s energy
needs. Much like in the 1950s when
Idaho Power built the three-dam
Hells Canyon hydroelectric complex,
our work has always set the stage
for today’s success, as well as future
growth. We are preparing for tomorrow
for our customers, for our employees,
and for you, our owners.
As part of our look forward, our
company was active on many
fronts during 2011. We continued
construction of the Langley Gulch
Power Plant and created our 2011
Integrated Resource Plan, our
biennial 20-year planning document.
We also pursued general rate cases
in Idaho and Oregon — both of
which concluded with collaborative
settlements. And we made progress
on our two large transmission
projects, Boardman to Hemingway
and Gateway West.
Specifically, we forged an agreement
with the Bonneville Power
Administration and PacifiCorp
to jointly fund the environmental
review and permitting of the 300-mile
Boardman to Hemingway project.
We continue to work jointly with
PacifiCorp on permitting the proposed
1,150-mile Gateway West project,
and reached a significant milestone
this summer when the Bureau of
Land Management issued the draft
Environmental Impact Statement for
the project. Both of these key projects
will provide additional access to
regional energy markets, increased
flexibility to site future generation
resources in southern Idaho, and
improve reliability.
2011 was a good year financially,
led by a strong third quarter, itself
supported by momentum built in the
first two quarters. The third quarter
brought a change that allowed us to
take advantage of benefits associated
with Idaho Power’s uniform
capitalization tax method, which
resulted in a welcomed outcome
during a continued weak economic
environment. The tax method change
not only contributed to our bottom
line, but resulted in $47 million in
benefits for our customers through
two regulatory sharing mechanisms.
It’s also important to acknowledge
other factors that contributed to our
excellent results, including effective
rate initiatives, strong hydroelectric
conditions, and increased sales
volumes among most customer
To ourfellowshareowners
1
2
Langley Gulch Power Plant
classes due to a cooler winter and
warmer summer.
Our vision to be regarded as an
exceptional utility continues to guide
us. We continued to look out for the
best interests of both our owners and
our customers. One example is our
request — and subsequent commission
approval — to continue an agreement
that has shown proven benefit to
customers and owners, providing
a revenue sharing opportunity for
customers and earnings support for
our company. This win-win will extend
through 2014.
Total shareowner return on IDACORP
stock in calendar year 2011 was
more than 18 percent. And, looking
forward, our Board of Directors
increased the 2012 regular quarterly
cash dividend to $0.33 per share
from $0.30 per share, representing a
10 percent increase. On the customer
side, our company was able to
provide Idaho customers a rate
reduction of more than $25 million
on June 1, 2011, due to the combined
effects of several regulatory
mechanisms. To provide this benefit
to customers in the current economy
was positive on many fronts.
With the nearly 500,000 customers
we serve, Idaho Power improved to
the fourth-highest ranking in the
West Midsize segment in the results
of the 2011 J.D. Power and Associates
Electric Utility Residential Customer
Satisfaction Study. In this study, Idaho
Power performed particularly well
in Power Quality & Reliability, Price,
Corporate Citizenship, Communication
and Customer Service. Our company
also tied for first place in the West
Midsize segment in the J.D. Power and
Associates 2012 Electric Utility Business
Customer Satisfaction Study.
Enhancing our ability to serve
customers was the successful
completion of a three-year process
to install approximately 500,000
“smart” electric meters for customers
throughout our service area in 2011.
The new meters are part of our
Gary Michael, Chairman of the Board
J. LaMont Keen, President & Chief Executive Officer
Advanced Metering Infrastructure
(AMI) initiative and the overall
Smart Grid program. These meters
are digital, secure and easier for
customers to read. Their functionality
enables customers to have more
information about their energy use,
empowering them to better manage
their consumption. The meters also
allow our company to save on fuel
and maintenance costs, as employees
are no longer driving 1.6 million
miles per year to read meters.
Additionally, Intelligent Utility
magazine ranked IDACORP the sixth
most intelligent utility in 2011, up from
10th place in 2010. With a score of 141.5,
we are considered “Near Genius.”
As we look at our accomplishments
in 2011, we also look forward to
2012 and beyond. To that end, in
November we announced leadership
changes that reinforce the successful
foundation we’ve already laid to build
for future years.
Beginning Jan. 1, 2012, Darrel
Anderson assumed the role of
President and Chief Financial Officer
of Idaho Power, and will continue as
Executive Vice President and Chief
Financial Officer for IDACORP. Dan
Minor was named Executive Vice
President and Chief Operating Officer
of Idaho Power. Steve Keen was
promoted to Senior Vice President of
Finance and Treasurer at Idaho Power.
These changes continue our legacy
of strong leadership. Our entire
leadership team continues to work
hard to position Idaho Power and
IDACORP for the future, while
maintaining a connection to our
history of success, and the people and
communities we serve.
Finally, we couldn’t have
accomplished any of the past year’s
successes without the more than
2,000 dedicated men and women
who make IDACORP run each and
every day. We would like to extend
a heartfelt “thank you” to them and
to our Board of Directors for making
2011 a positive and prosperous
year for our company. Here’s to a
successful 2012.
3
Total Return
2007 2009 2010 2011
-5.6%
-13.0%
13.6%
19.8% 20.0%
16.5%
-25.9%
10.7% 7.0%
18.3%
IDACORPEEI Electric Utilities Index
2008
Return on Year-End Equity
2007 2008 2009 2010 2011
6.8%7.6%
8.9%9.3%
10.1%
Earnings Per Share (Diluted) Current Annual Dividend $1.20
$1.86$2.17
$2.64$2.95
2007 2008 2009 2010 2011
$3.36
Total Operating Revenues $1,026,756 $1,036,029 <0.9>
Net Income $166,693 $142,798 16.7
Earnings Per Diluted Common Share $3.36 $2.95 13.9
Dividends Paid Per Common Share $1.20 $1.20 --
Total Assets $4,960,609 $4,676,055 6.1
Number of Employees 2,058 2,032 1.3 (full-time)
Thousands of Dollars, Except Per Share Amounts 2011 2010 % Change
Oxbow Power Plant
IDACORP and its core business Idaho Power have taken “the long view” ever since our company was founded. Rather than peering around the next corner, reacting to outside pressures or resting on past achievements, we’re looking down the road…and beyond. This has been a successful strategy ever since “back in the day,” when our Swan Falls project first delivered energy to the mountain mining communities that were the engines of the economy.
We also take time to look back and learn from the past. Idaho Power is a company steeped in history and tradition. We have been powering lives by providing electricity for nearly a century, and will continue this legacy a hundred years into the future.
One reason we have successfully maintained our tradition of service is our three-part business strategy. Responsible planning, responsible development and protection of resources, and responsible energy
use aren’t just words at Idaho Power — they define the way we deliver electric service to the people who count on us every day.
We’re planning for future growth and the eventual rebound of the economy. We’re diversifying our resource portfolio to include new baseload natural gas capacity, as well as renewables such as wind, solar and geothermal. We’re diligently pursuing regulatory strategies that help keep rates low while providing a good return to our owners. And these are just a few of our key initiatives. We’re constantly evolving and adapting on all fronts.
It’s worth noting that Idaho Power employees are Idaho Power customers. We don’t just work for our company — we live and play in and are part of the communities we serve. And we are committed to the prosperity of those communities and the characteristics that make them the unique places we are proud to call home. Today and tomorrow.
5
The Long View
We have been powering lives by providing electricity for nearly a century, and will continue this legacy a hundred years into the future.
Swan Falls Power Plant
Integrated Resource Plan (IRP) There’s nearly a century of trust built up between Idaho Power and the nearly 500,000 customers we serve, and it’s our duty to honor that trust. Across our entire business, we’re planning for the safe, secure energy future our customers are counting on us to provide.
One way we do this is our IRP, a biennial planning document which looks 20 years into the future. It encompasses many forward-looking elements, including development of a portfolio of energy resources, identification of future power generation and transmission needs, a continued focus on adding responsible renewable resources, and offering programs that encourage customers to use electricity efficiently.
Building our energy future requires collaboration and input. The IRP planning process doesn’t happen in a vacuum; we involve stakeholders from all aspects of our business and our service area. There are a multitude of voices engaged in the process, which makes our planning just that much stronger.
We’ve been putting together IRPs for 20 years, and it’s impressive to see how they have evolved. Each update builds on the foundation of earlier resource plans, and each includes incremental adjustments due to changing forecasts of future events. For instance, our first IRP, in 1991, included a portfolio heavy in coal resources. The 2011 version has taken a turn to natural gas, additional transmission, and renewable resources. These changes are an appropriate response given our look into the future.
Langley Gulch Power Plant Idaho Power’s ability to evolve with the times is literally expanding through the construction of our Langley Gulch natural gas-fired power plant. The clean, quiet, highly efficient power plant is being built on nearly 140 acres of undeveloped rangeland in a rural area about 50 miles west of our corporate headquarters in Boise.
The project is within budget and on schedule. We expect to bring this newest resource online by July 1, 2012 — in time to meet customer demand for summer power.
We built Langley Gulch in lieu of pursuing additional coal-burning generation. Langley’s combined-cycle
technology burns clean. That means a reduced carbon footprint — something our customers and our shareholders both appreciate and want.
As a baseload plant, the facility will be efficient and economical, and will run a great deal of the time. It also has the flexibility to vary output quickly to help integrate intermittent resources such as wind and solar.
7
A Long Look at Resources
Hydroelectric Generation What began as a challenging water year — in part mitigated by good carryover storage — has improved in recent weeks thanks to the better-late-than-never start to winter. January and February storms in the service area brought much needed precipitation and snow pack accumulations in the mountains. However, we are still below normal in the Snake River basin.
Due largely to favorable water conditions, hydroelectric generation comprised 69 percent of Idaho Power’s total system generation during 2011, compared to 51 percent during 2010. As of Feb. 22, 2012, Idaho Power expects hydroelectric generation during 2012 to be in the range of 7.5 to 9.5 million megawatt-
hours (MWh), compared to 10.9 million MWh in 2011 and 7.3 million MWh in 2010. Median annual hydroelectric generation is 8.6 million MWh.
Through our longstanding annual Power Cost Adjustment (PCA) mechanism, if power supply costs are above those anticipated, our Idaho customers pay 95 percent of the excess costs and the company absorbs the remaining 5 percent. This PCA “split,” implemented in 2009, helps protect us from the whims of Mother Nature, smoothing out power supply cost volatility.
Renewables and PURPA For nearly a century, Idaho Power has been committed to clean energy. Today about half of the energy in our portfolio is generated from hydro, wind, solar, biomass and geothermal. We are proud of our small carbon footprint and history of responsible energy that rivals that of any electric utility in the nation.
Over the past few years, renewable energy projects, especially wind projects, which qualify for higher rates under PURPA, or the Public Utility Regulatory Policies Act, have put an undue burden on the company and our customers. Over the next 10 years, customers may pay $850 million more than necessary for electricity that might not be needed. Because the cost is
borne by our customers, we are taking aggressive regulatory steps to address this imbalance.
Make no mistake — Idaho Power is a strong supporter of renewable energy. We always have been and will continue to be. We also believe that the addition of renewable resources needs to be accomplished responsibly, in a way that minimizes costs, and that does not impact our ability to provide reliable electric service to customers, every hour of every day. We know customers benefit from a diverse energy resource mix that can reliably provide electricity at a fair price. They always have, and always will.
7 8
Building our energy future requires collaboration and input.
Hydro63.0%
Natural Gas2.0%
Wind5.5%
Waste0.5%
Coal28.1%
Biomass0.4%
Other0.6%
2011 Resource Portfolio Fuel Mix*
* Because Idaho Power sells (or does not own) the renewable energy certificates or “green tags” associated with certain projects in its resource portfolio, using the proceeds to benefit customers, we are not permitted to say the electricity from those projects is delivered to customers.
We were pleased to be able to share earnings with customers in 2011, and potentially again in 2012 and in the following two years as well.
Idaho General Rate Case (GRC) settlement
By design, regulatory strategy requires a long look forward. The future must be analyzed, based on the present, in order to prepare for change that we know will come. We must also collaborate with stakeholders and take into account their needs and perspective to ensure the best outcome. The people who drive our regulatory strategy practice this day in and day out, with an excellent track record of success.
In late December, the Idaho Public Utilities Commission issued an order in Idaho Power’s 2011 GRC increasing base rates 4.19 percent, effective Jan. 1, 2012. This positive outcome was the result of a collaborative settlement reached with the company, the commission staff and customer groups. It provides our company a $34 million revenue increase, and a 7.86 percent authorized rate of return on rate base.
Idaho sharing settlement
The year 2011 also included realization of a $57 million income tax benefit for our company from a tax accounting method change. This contributed to the triggering of the sharing mechanism under our January 2010 Idaho settlement agreement, which provided that Idaho Power earnings over a 10.5 percent return on year-end equity in the Idaho jurisdiction are to be shared equally between Idaho customers and the company.
Also in the fourth quarter of 2011, we received a favorable commission decision regarding the continued availability of accumulated deferred investment tax credits. This gives the company return on equity/earnings-per-share support and helps position us for future success. It also allows us an opportunity to share earnings with customers now and in the future.
The sharing mechanism and settlement combined to provide $47 million in benefits to Idaho customers in 2011, while also reducing operating revenues for the period — a proven benefit to both customers and our company. And unlike previous settlement agreements, this one does not include a base rate moratorium. This gives us needed flexibility and allows us to continue positioning our company for success in 2012 and beyond.
We were pleased to be able to share earnings with customers in 2011, and potentially again in 2012 and in the following two years as well.
The Long Regulatory View
10
Economic development and new large loadsThe availability of competitively-priced electric service is essential to a healthy economy and necessary to attract, retain and expand business and industry. This proved true once again in November, as New York-based Agro Farma chose Twin Falls, Idaho as home to their newest, multi-million-dollar processing plant for their Greek yogurt brand, Chobani. This new large load will help contribute to the economy of our state, creating jobs and contributing to customer growth. The plant is anticipated to bring 400 new jobs to our service area, and is scheduled to start production in 2012.
Liquidity2011 was strong both financially and operationally. Financially, we recorded $3.36 in diluted annual earnings per share. This marks the fourth consecutive annual increase. IDACORP’s cash flow from operations for 2011 was $310.2 million, an increase of $4.8 million from 2010 and a $25.8 million increase from 2009.
New five-year credit facilities at IDACORP and Idaho Power On Oct. 26, 2011, we executed new five-year credit agreements which increased the size of the IDACORP facility from $100 million to $125 million, but maintained the Idaho Power facility at $300 million. Commercial paper outstanding at IDACORP as of Dec. 31, 2011 was $54.2 million compared to $66.9 million at Dec. 31, 2010. Idaho Power had no commercial paper outstanding at either date.
11
Long-Term Financial Stability
400New jobs
3.36diluted annual earnings per share
$
General BusinessCustomersThousands
2007 2008 2009 2010 2011
482 487 490 492 496
Additions to Property Plant and EquipmentMillions of dollars
2007 2008 2009 2010 2011
$287
$244 $252
$338 $338
$28$82
$228
$248$251
Total AdditionsInternal Generation
12
Dividend YieldAt year-end
3.4%
4.1%3.8%
3.2%
2007 2008 2009 2010 2011
2.8%
Hells Canyon Power Plant
We have installed nearly
500,000 “smart” electric meters
Transmission projects
Idaho Power works each day to ensure our system is strong so power is reliable now and in the future. Our efforts to permit and build high-capacity transmission projects will ensure we have capacity and options available for economic development as the economy rebounds.
We have forged an agreement with the Bonneville Power Administration and PacifiCorp to jointly fund the environmental review and permitting of the 300-mile Boardman to Hemingway (B2H)project. We continue to work jointly with PacifiCorp on permitting the proposed 1,150-mile Gateway West project and reached a significant milestone this summer when the
Bureau of Land Management issued the draft Environmental Impact Statement for the project. Both of these key projects will provide additional access to regional energy markets, increased flexibility to site future generation resources in southern Idaho, and improve reliability.
The B2H project will be essential to move electricity to and from the Pacific Northwest, and the Gateway West project will allow Idaho Power to site future generation resources in southern Idaho and deliver energy to customers. The partnerships help ensure the success of the projects and position us to move forward with construction once permits are secured.
Smart Grid
For Idaho Power, the Smart Grid represents energy innovation. Through our Smart Grid projects we’ll reduce the time and impact of outages; strengthen the grid by limiting the effects of power line disturbances; and support integration of renewable energy into our resource portfolio. We’re arming customers with the information they need to be wise energy consumers. We’re using proven new technology to retrieve energy usage data, and taking actions that will improve electrical grid performance.
Advanced Metering Infrastructure (AMI)
The year 2011 brought the successful completion of our three-year AMI project. We have installed nearly 500,000 “smart” electric meters for customers throughout our service area. These new meters are the foundation of our ongoing Smart Grid program.
Future Planning for the Long Term
14Idaho Power transmission lines
15
Sustainability at IDACORP
The IRP process, transmission projects, and our regulatory activities are just some of the ways IDACORP looks toward the future. But that’s not all. Sustainability is a business operating approach that focuses on enhancing financial, environmental and societal stewardship on a daily basis. Specifically, sustainability at IDACORP promotes three “E”s in business operations:
Enhanced operating efficiencies to reduce costs
Enhanced long-term value for shareholders
Enhanced relationships with stakeholders
Greenhouse gas emissions update
In service of our commitment to sustainability, Idaho Power is on track to meet its greenhouse gas (GHG) emissions reduction goal: reduce carbon dioxide (CO2) emission intensity for 2010 to 2013 to 10 to 15 percent below 2005 CO2 emission intensity. Idaho Power also remains committed to producing as much electricity as possible from hydropower for the benefit of customers and as a means of generating without producing GHG emissions.
The Future of Stewardship
Long Valley Operations Center
Sustainability is a business operating approach that focuses on enhancing financial, environmental and societal stewardship on a daily basis.
We are building a financially strong, stable company to meet the needs of our customers.
Taking the long view means being future-focused and adaptable. It’s the willingness and foresight to evolve and change as needed. To not just accept — but to embrace — the flexibility necessary to overcome the next challenge.
At IDACORP we are building a financially strong, stable company to meet the needs of our customers. We’ve done this for nearly 100 years. Our homes, communities, schools, farms and businesses have always needed our product, and we’re at the ready to provide an energy present and an energy future that enables economic development while maintaining the comfort and security that are paramount to quality of life.
So, in partnership with you, our owners, we will continue our efforts to maintain our heritage, focus on present-day goals, and sustain momentum for a bright future. We will stay nimble; we will evolve; and we are confident. Together we will take the long view and continue building a responsible, sustainable energy future for many generations to come.
Looking Back, Moving Forward
18
Boise
Payette
Twin FallsPocatello
Boardman
Bennett MountainLangley Gulch
Salmon
Evander Andrews
Jim Bridger
North Valmy
O R E G O N
N E VA D A U TA H
WA S H I N G T O N
12
34
5
6 7 89
1011
1213 14 15
1617
Snake River
W Y O M I N G
I D A H O
1 Idaho Power share 2 Danskin3 Est. on-line 2012
Jim Bridger 770,501 kW1
North Valmy 283,500 kW1
Boardman 64,200 kW1
Evander Andrews 270,900 kW2
Bennett Mountain 172,800 kW
Salmon Diesel 5,000 kW
Langley Gulch 300,000 kW3
Thermal Facilities
Shoshone Falls and power plant
20
IDACORP and Idaho Power
J. LaMont Keen (37) President and Chief Executive Officer, IDACORP, Inc. and Chief Executive Officer, Idaho Power
Darrel T. Anderson (16) Executive Vice President – Administrative Services and Chief Financial Officer, IDACORP, Inc. and President and Chief Financial Officer, Idaho Power
Rex Blackburn (4) Senior Vice President and General Counsel, IDACORP, Inc. and Idaho Power
Patrick A. Harrington (26) Corporate Secretary, IDACORP, Inc. and Idaho Power
Steven R. Keen (29) Vice President – Finance and Treasurer, IDACORP, Inc. and Senior Vice President – Finance and Treasurer, Idaho Power
Jeffrey L. Malmen (4) Vice President of Public Affairs, IDACORP, Inc. and Idaho Power
Daniel B. Minor (26) Executive Vice President, IDACORP, Inc. and Executive Vice President and Chief Operating Officer, Idaho Power
Ken W. Petersen (13) Corporate Controller and Chief Accounting Officer, IDACORP, Inc. and Idaho Power
Lori D. Smith (28) Vice President and Chief Risk Officer, IDACORP, Inc. and Idaho Power
Idaho Power
Dennis C. Gribble (33) Vice President and Chief Information Officer
Lisa A. Grow (24) Senior Vice President of Power Supply
Warren Kline (38) Vice President of Customer Operations
Luci K. McDonald (7) Vice President of Human Resources and Corporate Services
N. Vern Porter (22) Vice President of Delivery Engineering and Operations
Gregory W. Said (31) Vice President of Regulatory Affairs
Naomi C. Shankel (11) Vice President of Supply Chain
( ) years of service
1 Hells Canyon 391,500 kW
2 Oxbow 190,000 kW
3 Brownlee 585,400 kW
4 Cascade 12,420 kW
5 Swan Falls 27,170 kW
6 C.J. Strike 82,800 kW
7 Bliss 75,000 kW
8 Lower Malad 13,500 kW
9 Upper Malad 8,270 kW
10 Lower Salmon 60,000 kW
11 Upper Salmon 34,500 kW
12 Thousand Springs 8,800 kW
13 Clear Lake 2,500 kW
14 Shoshone Falls 12,500 kW
15 Twin Falls 52,897 kW
16 Milner 59,448 kW
17 American Falls 92,340 kW
Hydroelectric Facilities & Nameplate Capacities
IDACORP and Idaho Power Officers
Service Area
ReferencesDividend Payment Dates For IDACORP, Inc. Common Stock quarterly on or about the
28th of February, and the 30th of May, August and November.
Transfer Agents/Registrar For IDACORP, Inc. Common Stock
Street: 1221 W. Idaho St., Boise, Idaho 83702-5627
Phone: 208-388-2200
SEC Form 10-K
The IDACORP, Inc. and Idaho Power Company combined
Form 10-K has been filed with the Securities and Exchange
Commission. The Form 10-K and this Annual Report
to Shareholders also are available on our website at
www.idacorpinc.com. This report is prepared for the
information of shareholders of the company and is not to
be transmitted, nor is it to be used by others in connection
with any sale, offer for sale or solicitation of any offer to
buy any securities.
Forward-Looking Statement
Please refer to IDACORP’s and Idaho Power’s Form 10-K for
a description of the substantial risks and uncertainties
related to the forward-looking statements included in this
Annual Report.
21
IDACORP, Inc.—Boise, Idaho-based and formed in 1998—is a holding company comprised of Idaho Power Company, a regulated electric utility; IDACORP Financial, a holder of affordable housing projects and other real estate investments; and Ida-West Energy, an operator of small hydroelectric generation projects that satisfy the requirements of the Public Utility Regulatory Policies Act of 1978. IDACORP’s origins lie with Idaho Power and operations beginning in 1916. Today, Idaho Power employs approximately 2,000 people to serve a 24,000-square-mile service area in southern Idaho and eastern Oregon. With 17 low-cost hydroelectric projects as the core of its generation portfolio, Idaho Power’s nearly 500,000 residential, business and agricultural customers pay some of the nation’s lowest prices for electricity. To learn more about Idaho Power or IDACORP, Inc., visit www.idahopower.com or www.idacorpinc.com.
1
UNITED STATES SECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549
FORM 10-K
(Mark One)
X
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OFTHE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2011
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OFTHE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ................... to .................................................................
CommissionFile Number
1-144651-3198
State of incorporation: Idaho
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:IDACORP, Inc.: Common Stock, without par value
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:Idaho Power Company: Preferred Stock
Exact name of registrants as specified intheir charters, address of principal executive
offices, zip code and telephone numberIDACORP, Inc.
Idaho Power Company1221 W. Idaho StreetBoise, ID 83702-5627
(208) 388-2200
IRS Employer
Identification Number82-050580282-0130980
Name of exchange onwhich registered
New YorkStock Exchange
Indicate by check mark whether the registrants are well-known seasoned issuers, as defined in Rule 405 of the Securities Act.
IDACORP, Inc. Yes ( X ) No ( ) Idaho Power Company Yes ( ) No ( X ) Indicate by check mark if the registrants are not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
IDACORP, Inc. Yes ( ) No ( X ) Idaho Power Company Yes ( ) No ( X ) Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes ( X ) No ( ) Indicate by check mark whether the registrants have submitted electronically and posted on their corporate Web sites, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files).
IDACORP, Inc. Yes ( X ) No ( ) Idaho Power Company Yes ( X ) No ( ) Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants’ knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ( X )
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Indicate by check mark whether the registrants are large accelerated filers, accelerated filers, non-accelerated filers, or smaller reporting companies.
IDACORP, Inc.:
Idaho Power Company:
Large accelerated filer
Large accelerated filer
( X )
( )
Accelerated filer
Accelerated filer
( )
( )
Non-accelerated filer
Non-accelerated filer
( )
( X )
Smaller reporting company
Smaller reporting company
( )
( ) Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Act).
IDACORP, Inc. Yes ( ) No ( X ) Idaho Power Company Yes ( ) No ( X ) Aggregate market value of voting and non-voting common stock held by non-affiliates (June 30, 2011):
IDACORP, Inc.: $ 1,941,836,645 Idaho Power Company: None
Number of shares of common stock outstanding as of February 17, 2012:IDACORP, Inc.:Idaho Power Company:
49,947,09839,150,812, all held by IDACORP, Inc.
Documents Incorporated by Reference: Part III, Items 10 - 14 Portions of IDACORP, Inc.’s definitive proxy statement to be filed pursuant to Regulation 14A for
the 2012 annual meeting of shareholders.
This combined Form 10-K represents separate filings by IDACORP, Inc. and Idaho Power Company. Information contained herein relating to an individual registrant is filed by that registrant on its own behalf. Idaho Power Company makes no representation as to the information relating to IDACORP, Inc.’s other operations. Idaho Power Company meets the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K and is therefore filing this Form with the reduced disclosure format.
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COMMONLY USED TERMS
The following select abbreviations, terms, or acronyms are found in multiple locations within this report:
Accumulated Deferred Investment Tax CreditsAllowance for Funds Used During ConstructionAdvanced Metering InfrastructureAverage MegawattsAnnual Power Cost UpdateBridger Coal Company, a joint venture of IERCoU.S. Bureau of Land ManagementBonneville Power AdministrationClean Air ActComprehensive Aquifer Management PlanCarbon DioxideClean Water ActDraft Environmental Impact StatementDemand-Side ManagementDemand-Side ResourcesElectric Utility Steam Generating UnitsEnvironmental Impact StatementU.S. Environmental Protection AgencyEarnings Per ShareEndangered Species ActFinancial Accounting Standards BoardFixed Cost Adjustment MechanismFederal Energy Regulatory CommissionFederal Power ActGenerally Accepted Accounting PrinciplesGreenhouse GasHells Canyon ComplexIda-West Energy, a subsidiary of IDACORP, Inc.Idaho-jurisdiction return on year-end equityIDACORP Energy, a subsidiary of IDACORP, Inc.Idaho Energy Resources Co., a subsidiary of Idaho Power CompanyIDACORP Financial Services, a subsidiary of IDACORP, Inc.Idaho Public Utilities CommissionIntegrated Resource PlanU.S. Internal Revenue ServiceKilowattLoad Change Adjustment RateManagement’s Discussion and Analysis of Financial Condition and Results of OperationsMegawattMegawatt-hourNitrous OxideNew Source Performance StandardsOperations and MaintenanceOpen Access Transmission TariffOregon Public Utility CommissionPower Cost AdjustmentPower Cost Adjustment MechanismPublic Utility Regulatory Policies Act of 1978Renewable Energy CertificateRenewable Energy StandardRenewable Portfolio StandardU.S. Securities and Exchange CommissionSulfur DioxideU.S. Bureau of ReclamationNorth Valmy Steam Electric Generating PlantVariable Interest Entities
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TABLE OF CONTENTS
Part I
Item 1 Executive Officers of the Registrants
Item 1AItem 1BItem 2Item 3Item 4
Part II
Item 5
Item 6Item 7Item 7AItem 8Item 9Item 9AItem 9B
Part III
Item 10Item 11Item 12
Item 13Item 14
Part IV
Item 15
Signatures
*Except as indicated in Items 12 and 14, IDACORP, Inc. information is incorporated by reference toIDACORP, Inc.'s definitive proxy statement for the 2012 annual meeting of shareholders.
Market for Registrant's Common Equity, Related Stockholder Matters, and IssuerPurchases of Equity Securities
Selected Financial DataManagement's Discussion and Analysis of Financial Condition and Results of OperationsQuantitative and Qualitative Disclosures About Market RiskFinancial Statements and Supplementary DataChanges in and Disagreements with Accountants on Accounting and Financial DisclosureControls and ProceduresOther Information
Directors, Executive Officers and Corporate Governance*Executive Compensation*Security Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters*Certain Relationships and Related Transactions, and Director Independence*Principal Accountant Fees and Services*
Exhibits and Financial Statement Schedules
Page
SAFE HARBOR STATEMENT This Annual Report on Form 10-K contains "forward-looking statements" intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995. Forward-looking statements should be read with the cautionary statements and important factors included in this Form 10-K at Part I, Item 1A - "Risk Factors" and in Part II, Item 7 - "Management's Discussion and Analysis of Financial Condition and Results of Operations" (including under the heading "Forward-Looking Statements"). Forward-looking statements are all statements other than statements of historical fact, including, without limitation, those that are identified by the use of the words "anticipates," "believes," "estimates," "expects," "intends," "plans," "targets," "predicts," "projects," "may result," "may continue," or similar expressions.
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133133137
137137
137138138
139
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PART I ITEM 1. BUSINESS
OVERVIEW IDACORP, Inc. (IDACORP) is a holding company incorporated in 1998 under the laws of the state of Idaho, and its principal operating subsidiary is Idaho Power Company (Idaho Power). IDACORP is subject to the provisions of the Public Utility Holding Company Act of 2005, which provides access to books and records to the Federal Energy Regulatory Commission (FERC) and state utility regulatory commissions and imposes record retention and reporting requirements on IDACORP. Idaho Power was incorporated under the laws of the state of Idaho in 1989 as successor to a Maine corporation organized in 1915. Idaho Power is an electric utility engaged in the generation, transmission, distribution, sale, and purchase of electric energy and is regulated by the FERC and the state regulatory commissions of Idaho and Oregon. Idaho Power is the parent of Idaho Energy Resources Co. (IERCo), a joint venturer in Bridger Coal Company (BCC), which mines and supplies coal to the Jim Bridger generating plant owned in part by Idaho Power. IDACORP’s other subsidiaries include IDACORP Financial Services, Inc. (IFS), an investor in affordable housing and other real estate investments; Ida-West Energy Company (Ida-West), an operator of small hydroelectric generation projects that satisfy the requirements of the Public Utility Regulatory Policies Act of 1978 (PURPA); and IDACORP Energy (IE), a marketer of energy commodities that wound down operations in 2003. Idaho Power is IDACORP’s only reportable business segment, contributing 99 percent of IDACORP’s net income in 2011. Segment data is presented in Note 17 – "Segment Information" to the consolidated financial statements included in this report. As of December 31, 2011, IDACORP had 2,058 full-time employees, 2,046 of whom were employed by Idaho Power, and 23 part-time employees, 22 of whom were employed by Idaho Power. IDACORP and Idaho Power make available free of charge on their websites their Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and all amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the U.S. Securities Exchange Act of 1934 as soon as reasonably practicable after the reports are electronically filed with or furnished to the U.S. Securities and Exchange Commission (SEC). IDACORP's website is www.idacorpinc.com and can also be accessed through a link to the IDACORP website on the Idaho Power website at www.idahopower.com. The contents of the above-referenced website addresses are not part of this Annual Report on Form 10-K. Reports, proxy and information statements, and other information regarding IDACORP and Idaho Power may also be obtained directly from the SEC’s website, www.sec.gov, or from the SEC’s Public Reference Room at 100 F Street, NE, Washington, D.C. 20549. IDACORP’s and Idaho Power’s principal executive offices are located at 1221 W. Idaho Street, Boise, Idaho 83702, and the telephone number is (208) 388-2200.
UTILITY OPERATIONS Idaho Power’s service territory covers approximately 24,000 square miles in southern Idaho and eastern Oregon, with an estimated population of one million. Idaho Power holds franchises, typically in the form of right-of-way arrangements, in 71 cities in Idaho and nine cities in Oregon and holds certificates from the respective public utility regulatory authorities to serve all or a portion of 25 counties in Idaho and three counties in Oregon. As of December 31, 2011, Idaho Power supplied electric energy to approximately 496,000 general business customers. Idaho Power’s principal commercial and industrial customers are involved in food processing, electronics and general manufacturing, agriculture, forest products, beet sugar refining, and winter recreation. Idaho Power's service territory is illustrated on the following page.
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Weather, customer demand, and economic conditions impact electricity sales and costs and, therefore, utility revenues are not earned and associated expenses are not incurred evenly during the year. Extreme temperatures increase sales to customers who use electricity for cooling and heating, and moderate temperatures decrease sales. Increased precipitation levels during the agricultural growing season reduce electricity sales to customers who use electricity to operate irrigation pumps. Idaho Power’s retail energy sales typically peak during the summer irrigation and cooling season, with a lower peak in the winter that generally results from demand for electric power for heating purposes.
Electric utilities have historically been recognized as natural monopolies and have operated in a highly regulated environment in which they have an obligation to provide electric service to their customers in return for an exclusive franchise within their service territory with an opportunity to earn a regulated rate of return. Idaho Power is under the retail jurisdiction (as to rates, service, accounting, and other general matters of utility operation) of the Idaho Public Utilities Commission (IPUC) and the Oregon Public Utility Commission (OPUC), and as a regulated electric utility Idaho Power is generally not subject to retail competition. Idaho Power is also under the jurisdiction of the IPUC, the OPUC, and the Public Service Commission of Wyoming as to the issuance of debt and equity securities. Further, the FERC has jurisdiction over, among other items, Idaho Power's transmission and wholesale sales of electricity, hydroelectric relicensing, and system reliability.
General Business Strategy
IDACORP’s business strategy emphasizes Idaho Power as IDACORP’s core business. Idaho Power has a three-part strategy of responsible planning, responsible development and protection of resources, and responsible energy use to ensure adequate energy supplies. Idaho Power continuously evaluates and refines its business strategy to ensure coordination among and integration of all functional areas of the company. Idaho Power’s business strategy seeks to balance the interests of owners, customers, employees, and other stakeholders while maintaining the company’s financial stability and flexibility. The strategy includes:
• Responsible Planning: Idaho Power’s planning process is intended to ensure adequate generation and transmission
resources to meet anticipated population growth and increasing electricity demand. This planning process integrates Idaho Power’s regulatory strategy and financial planning, including the consideration of regional economic development in the communities Idaho Power serves.
• Responsible Development and Protection of Resources: Idaho Power’s business strategy includes the development and protection of generation, transmission, distribution, and associated infrastructure, and stewardship of the natural resources Idaho Power and the communities it serves depend upon. Additionally, the strategy considers workforce planning and employee development and retention related to these strategic elements.
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• Responsible Energy Use: Idaho Power's business strategy includes energy efficiency and demand response programs and preparation for potential carbon and renewable portfolio standards (RPS) legislation. The strategy also includes targeted reductions relating to carbon emission intensity and public reporting of these reductions.
Rates and Revenues Retail: Idaho Power periodically evaluates the need to seek changes to its retail electricity price structure to cover its operating costs and provide a reasonable rate of return. Idaho Power uses general rate cases, power cost adjustment (PCA) mechanisms, a fixed cost adjustment (FCA) mechanism, a pension balancing account, and subject-specific filings to recover its costs of providing service and to earn a return on investment. Retail prices are determined through formal ratemaking proceedings that generally include testimony by participating parties, data requests, public hearings, and the issuance of a final order. Participants in these proceedings, which are conducted under established procedural schedules, include Idaho Power, the IPUC or OPUC, and other interested parties. The IPUC and OPUC are required to ensure that the prices and terms of service are fair, non-discriminatory, and provide Idaho Power an opportunity to recover its costs and earn a fair return on investment. In addition to general rate case filings, ratemaking proceedings can involve charges or credits related to specific costs, programs, or activities, as well as the recovery or refund of deferred amounts recorded pursuant to specific authorization from the IPUC or OPUC. Deferred amounts are generally collected from, or refunded to, retail customers through the use of supplemental tariffs. For additional information on regulatory matters, including significant rate cases and proceedings, see the “Regulatory Matters” section of Part II, Item 7 – “Management’s Discussion and Analysis of Financial Condition and Results of Operations” (MD&A) and Note 3 – “Regulatory Matters” to the consolidated financial statements included in this report. Developments in 2011 with Special Customer Electric Service Agreements: Idaho Power is authorized to enter into special electric service arrangements with customers that have an aggregate power requirement that exceeds 20 megawatts (MW). Notable recent developments with respect to one of those arrangements are described below.
In March 2009, the IPUC approved a September 2008 electric service agreement between Idaho Power and Hoku Materials, Inc. (Hoku), to provide electric service to Hoku’s polysilicon production facility being constructed in Pocatello, Idaho. The initial term of the agreement is four years beginning December 1, 2009, with a maximum demand obligation during the initial term of 82 MW. Hoku was still not taking significant service as of December 31, 2011. In December 2011, Idaho Power sent to Hoku a notice of termination of service pursuant to IPUC rules to terminate service as a result of an overdue invoice for electric service. On January 9, 2012, Hoku filed a petition with the IPUC alleging that its contract with Idaho Power was contrary to the public interest and requested that the IPUC reform the contract and sought reparations for previously paid amounts under the electric service agreement. On January 13, 2012, the IPUC ordered Idaho Power and Hoku to enter into negotiations to seek settlement of Hoku's petition. On February 17, 2012, Idaho Power, Hoku, and the IPUC Staff filed with the IPUC a settlement stipulation that would amend the electric service agreement. The stipulation provides for a minimum monthly charge of $0.8 million (compared to the existing minimum monthly charge of approximately $2 million) from January 2012 to July 2013 and the establishment of a balancing mechanism that will track and accrue (up to a maximum balance of approximately $16.5 million) on a monthly basis the difference between (a) the first block minimum energy charges (excluding demand charges) under the existing agreement and (b) the modified minimum billed energy charge (excluding demand charges) under the settlement stipulation. In January 2014, Idaho Power will begin invoicing Hoku for, in addition to applicable demand and energy charges, recovery of the deferred amount over a 12 month period, one-twelfth per month. Further, the stipulation provides that Hoku will pay to Idaho Power $2.0 million upon IPUC approval of the stipulation out of existing funds on deposit with Idaho Power, and $0.1 million per month in cash for 18 months commencing with its January 2012 invoice. The stipulation also extends the term of the electric service agreement through December 1, 2014. During the final year of the agreement, Hoku will pay embedded-cost based rates for service. Hoku agrees in the stipulation to cap its monthly power demand during the January 2012 to July 2013 deferral period to 20 MW, with the option to increase usage to 82 MW following a notice period and payment of applicable deposits. In the event Hoku uses more than 20 MW of energy in any given month, Hoku will be required to pay the minimum billed energy charge amounts set forth in the existing electric service agreement. Wholesale: As a public utility under Part II of the Federal Power Act (FPA), Idaho Power has authority to charge market-based rates for wholesale energy sales under its FERC tariff and to provide transmission services under its Open Access Transmission Tariff (OATT). Idaho Power’s OATT is revised each year based on financial and operational data Idaho Power files annually with the FERC in its Form 1. The Energy Policy Act of 2005 granted the FERC increased statutory authority to implement mandatory transmission and network reliability standards, as well as enhanced oversight of power and transmission markets,
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including protection against market manipulation. These mandatory transmission and reliability standards, which are applicable to Idaho Power, were developed by the North American Electric Reliability Corporation (NERC) and the Western Electricity Coordinating Council (WECC), which has responsibility for compliance and enforcement of transmission and reliability standards. Idaho Power has one low-volume wholesale reserve sales contract, with United Materials of Great Falls, Inc. The agreement requires Idaho Power to carry energy reserves in association with an energy sales agreement between Idaho Power and United Materials from the Horseshoe Bend Wind Farm located in Montana. The term of the agreement runs seasonally through May 2013. Idaho Power had one firm wholesale power sales contract with Raft River Electric Cooperative for up to 15 MW, which expired in September 2011. Idaho Power participates in the wholesale energy market by buying power to help meet load demands and selling power that is in excess of load demands. Idaho Power's market activities are guided by a risk management policy and frequently updated operating plans, which are influenced by customer load, market prices, generating costs, and availability of generating resources. Some of Idaho Power's hydroelectric generation facilities are operated to optimize the water that is available by choosing when to run hydroelectric generation units and when to store water in reservoirs. These decisions affect the timing and volumes of market purchases and market sales. Even in below-normal water years, there are opportunities to vary water usage to maximize generation unit efficiency, capture marketplace economic benefits, and meet load demand. Wholesale energy market prices and compliance factors, such as allowable river stage elevation changes and flood control requirements, influence these dispatch decisions. Energy Sales: The table below presents Idaho Power’s revenues and energy use by customer type for the last three years. Approximately 95 percent of Idaho Power’s general business revenue comes from customers located in Idaho, with the remainder coming from customers located in Oregon. Idaho Power’s operations are discussed further in Part II, Item 7 - “MD&A – Results of Operations - Utility Operations.”
Revenues (thousands of dollars)ResidentialCommercialIndustrialIrrigationProvision for sharingDeferred revenue related to Hells Canyon Complex relicensing AFUDC
Power Supply Idaho Power primarily relies on company-owned hydroelectric, coal, and gas-fired generation facilities and long-term power purchase agreements to supply the energy needed to serve customers. Idaho Power’s annual hydroelectric generation varies depending on water conditions in the Snake River. Market purchases and sales are used to balance supply and demand throughout the year. Idaho Power’s generating plants and their capacities are listed in Part I, Item 2 - “Properties.”
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Weather, load demand, and economic conditions impact power supply costs. Drought conditions and increased peak load demand cause a greater reliance on potentially more expensive energy sources to meet load requirements. Conversely, favorable hydroelectric generation conditions increase production at Idaho Power’s hydroelectric generating facilities and reduce the need for thermal generation and purchased power. Economic conditions can affect the market price of natural gas and coal, which may impact fuel expense and market prices for purchased power. Idaho Power’s system is dual peaking, with the larger peak demand occurring in the summer. The all-time system peak demand is 3,214 MW, set on June 30, 2008, and the all-time winter peak demand is 2,527 MW, set on December 10, 2009. During these and other similarly heavy load periods Idaho Power’s system is fully committed to serve load and meet required operating reserves. During 2011, the largest peak demand was 2,973 MW, set on July 6, 2011. The following table presents Idaho Power’s total power supply for the last three years:
Hydroelectric plantsCoal-fired plantsNatural gas fired plants
Total system generationPurchased power - cogeneration and
small power productionPurchased power - other
Total purchased powerTotal power supply
MWh2011
(thousands of MWh)10,9374,820
13815,895
1,4951,2562,751
18,646
2010
7,3446,864
16014,368
910
1,4912,401
16,769
2009
8,0966,941
24215,279
970
1,9422,912
18,191
Percent of Total Generation2011
69%30%1%
100%
2010
51%48%1%
100%
2009
53%45%2%
100%
Hydroelectric Generation: Idaho Power operates 17 hydroelectric projects located on the Snake River and its tributaries. Together, these hydroelectric facilities provide a total nameplate capacity of 1,709 MW and annual generation equal to approximately 8.6 million megawatt-hours (MWh) under median water conditions. The availability of hydroelectric power depends on the amount of snow pack in the mountains upstream of Idaho Power’s hydroelectric facilities, reservoir storage, springtime snow pack run-off, river base flows, spring flows, rainfall, amount and timing of water leases, and other weather and stream flow management considerations. During low water years, when stream flows into Idaho Power’s hydroelectric projects are reduced, Idaho Power’s hydroelectric generation is reduced. The manner in which Idaho Power has optimized operation of its hydroelectric facilities in the past has been impacted by intermittent wind generation and may continue to be impacted in the future as the company is faced with integrating an increasing amount of intermittent wind generation. As additional intermittent wind generation resources are developed in the region and contracted to Idaho Power, the operational impacts will likely increase. For related information on intermittent wind generation see “Purchased Power Agreements” below. Significantly greater snow accumulation during the winter and the resulting effect on stream flow conditions resulted in above average stream flow in 2011, which resulted in a 3.6 million MWh increase in generation from Idaho Power’s hydroelectric facilities compared to 2010. The observed stream flow data released in August 2011 by the U.S. Army Corps of Engineers, Northwest Division indicated that Brownlee Reservoir inflow for April through July 2011 was 10.5 million acre-feet (maf), compared to 4.6 maf in April through July 2010 and 5.6 maf in April through July 2009. Annual Brownlee Reservoir inflow for 2011 was 19.3 maf compared to 10.7 maf in 2010 and 11.3 maf in 2009. Power generation at the Idaho Power hydroelectric power plants on the Snake River also depends on the state water rights held by Idaho Power and the long-term sustainability of the Snake River, tributary spring flows, and the Eastern Snake Plain Aquifer that is connected to the Snake River. Idaho Power continues to participate in water management issues in Idaho that may affect those water rights and resources with the goal to preserve, to the fullest extent possible, the long-term availability of water for use at Idaho Power’s hydroelectric projects on the Snake River. For more information on water management issues see Note 10 - "Contingencies" to the consolidated financial statements included in this report. Idaho Power is subject to the provisions of the FPA as a “public utility” and as a “licensee.” As a licensee under Part I of the FPA, Idaho Power and its licensed hydroelectric projects are subject to conditions described in the FPA and related FERC regulations. These conditions and regulations include provisions relating to condemnation of a project upon payment of just
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compensation, amortization of project investment from excess project earnings, possible takeover of a project after expiration of its license upon payment of net investment, severance damages, and other matters. Idaho Power obtains licenses for its hydroelectric projects from the FERC, similar to other utilities that operate nonfederal hydroelectric projects on qualified waterways. The licensing process includes an extensive public review process and involves numerous natural resource and environmental issues. The licenses last from 30 to 50 years depending on the size, complexity, and cost of the project. Idaho Power is actively pursuing the relicensing of the Hells Canyon Complex and Swan Falls projects. Idaho Power also has three Oregon licenses under the Oregon Hydroelectric Act, which applies to Idaho Power’s Brownlee, Oxbow, and Hells Canyon facilities. For further information on relicensing activities see Part II, Item 7 – “MD&A – Regulatory Matters – Relicensing of Hydroelectric Projects.” Coal and Natural Gas-Fired Generation: Idaho Power co-owns three coal-fired power plants and owns two natural gas-fired combustion turbine power plants. The coal-fired plants are:
• Jim Bridger located in Wyoming, in which Idaho Power has a one-third interest;• Boardman located in Oregon, in which Idaho Power has a 10 percent interest; and• Valmy located in Nevada, in which Idaho Power has a 50 percent interest.
The natural gas-fired plants, Danskin and Bennett Mountain, are located in Idaho. The Langley Gulch natural gas-fired combined cycle power plant located in Idaho is currently under construction and is contracted to achieve commercial operation no later than November 1, 2012. Based on the current project status, Idaho Power estimates that the plant will be in service by July 1, 2012. Fuel Supply - Coal: Idaho Power, through its subsidiary IERCo, owns a one-third interest in BCC, which owns the Jim Bridger mine that supplies coal to the Jim Bridger generating plant, which is operated by PacifiCorp. The mine, located near the Jim Bridger plant, operates under a long-term sales agreement that provides for delivery of coal over a 51-year period ending in 2024 from surface, high-wall, and underground sources. Idaho Power believes that the Jim Bridger mine has sufficient reserves to provide coal deliveries for the term of the sales agreement. Idaho Power also has a coal supply contract providing for annual deliveries of coal through 2014 from the Black Butte Coal Company’s Black Butte mine located near the Jim Bridger plant. This contract supplements the Bridger Coal deliveries and provides another coal supply to operate the Jim Bridger plant. The Jim Bridger plant’s rail load-in facility and unit coal train provide the opportunity to access other fuel supplies for tonnage requirements above established contract minimums. The Boardman generating plant receives coal through annual contracts with suppliers from the Powder River Basin in northeast Wyoming. Portland General Electric Company, as the operator of the Boardman plant, has two agreements to supply coal beginning in 2012. All of the Boardman plant’s coal requirements in 2012, approximately 50 percent in 2013, and 33 percent in 2014, are under contract. A portion of the 2013 and 2014 coal used will be low sulfur content as Boardman prepares for the 2015 transition to a lower sulfur fuel content. As a ten percent owner of the plant, Idaho Power is obligated to purchase ten percent of the coal purchased under these agreements. In December 2010, the Oregon Environmental Quality Commission approved a plan to cease coal-fired operations at the Boardman power plant not later than December 31, 2020. For additional information, see Part II, Item 7 – "MD&A – Environmental Matters – Environmental Regulation."
NV Energy, Inc., as the operator of the Valmy generating plant, has agreements with coal suppliers through 2015. Idaho Power's share of these agreements along with existing coal inventory at the plant cover Idaho Power's projected coal supply needs for 2012, 2013, and 2014 and approximately 50 percent in 2015. As a 50 percent owner of the plant, Idaho Power is obligated for one-half of the coal purchased under these contracts. Fuel Supply - Natural Gas: Idaho Power owns and operates the Danskin and Bennett Mountain combustion turbines, and is constructing its Langley Gulch natural gas-fired combined-cycle power plant. Natural gas for all facilities is purchased based on system requirements and dispatch efficiency. The natural gas is supplied through Williams-Northwest Pipeline under Idaho Power's 55,584 million British thermal units (MMBtu) per day long-term gas transportation service agreements. The agreements vary in contract length, with the latest termination date of May 2042, but with extensions at Idaho Power’s discretion. In addition to the long-term gas transportation service agreements, Idaho Power has entered into a long-term storage service agreement with Northwest Pipeline for 131,453 MMBtu of total storage capacity at the Jackson Prairie Storage Project. As the project is developed, storage capacity will be phased into service and allocated to Idaho Power on a monthly basis. Idaho Power's current storage allotment is approximately 89 percent of its eventual total, with its full allotment expected to be reached by July 2012. This firm storage contract expires in 2043. Natural gas will be purchased and stored with the intent of fulfilling needs as identified for seasonal peaks or to meet system requirements.
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Idaho Power estimates that its Langley Gulch plant will be in service by July 1, 2012, in time to contribute to meeting summer loads. Approximately 1.2 million MMBtu's of natural gas has been hedged using financial instruments for future purchases for start-up testing of the plant expected to take place between March 2012 and May 2012. Along with this, approximately 2.9 million MMBtu's of natural gas has been financially hedged for future purchases for the operational dispatch of Langley Gulch from July 2012 to January 2013. Idaho Power plans to manage the procurement of additional natural gas as necessary to meet system requirements and fueling strategies. Purchased Power Agreements: Idaho Power purchases power in the wholesale market and pursuant to long-term power purchase contracts, as described below:
Wholesale Market Purchases: Idaho Power purchases power in the wholesale market based on economics, operating reserve margins, risk limits, and unit availability, and from PURPA projects as mandated. Idaho Power seeks to manage its loads efficiently by utilizing its generation resources and long-term purchase power contracts in conjunction with buying and selling opportunities in the wholesale market. Idaho Power has the following notable firm wholesale power purchase contracts and energy exchange agreements:
• PPL Energy Plus, LLC - for 83 MW per hour during heavy load hours, to address increased demand during June, July and August. The contract term is through August 2012;
• Raft River Energy I, LLC - for up to 13 MW (nameplate generation) from its Raft River Geothermal Power Plant Unit #1 located in southern Idaho. The contract term is through April 2033;
• Telocaset Wind Power Partners, LLC - for 101 MW (nameplate generation) from its Elkhorn Valley wind project located in eastern Oregon. The contract term is through 2027;
• USG Oregon LLC - for 22 MW (estimated average annual output) from the to-be-constructed Neal Hot Springs #1 geothermal power plant located near Vale, Oregon. The contract term is 25 years with an option to extend. USG Oregon LLC has stated that it expects commercial operation by late 2012; and
• Clatskanie People’s Utility - for the exchange of up to 18 MW of energy from the Arrowrock Project in southern Idaho for energy from Idaho Power’s system or power purchased at the Mid-Columbia trading hub. The initial term of the agreement is January 1, 2010 through December 31, 2015. Idaho Power has the right to renew the agreement for two additional five-year terms.
CSPP and PURPA Power Purchase Contracts: Pursuant to the requirements of Section 210 of PURPA, the state regulatory commissions having jurisdiction over Idaho Power have each issued orders and rules regulating Idaho Power’s purchase of power from cogeneration and small power production (CSPP) facilities. A key component of the PURPA contracts is the energy price contained within the agreements. PURPA regulations specify that a utility must pay energy prices based on the utility’s avoided costs. The "published avoided cost" is a price established by the IPUC and OPUC to estimate Idaho Power’s cost of developing additional generation resources. The IPUC and OPUC have established specific rules and regulations to calculate the published avoided cost that Idaho Power is required to include in PURPA contracts. Idaho Power has contracts for the purchase of energy from a number of private developers. For these contracts:
• Idaho Power is required to purchase all of the output from the facilities located inside its service territory, subject to some exceptions such as adverse impacts on system reliability;
• Idaho Power is required to purchase the output of projects located outside its service territory if it has the ability to receive power at the facility’s requested point of delivery on the Idaho Power system;
• the IPUC jurisdictional portion of the costs associated with CSPP contracts is fully recovered through base rates and the PCA, and the OPUC jurisdictional portion is recovered through general rate case filings and the PCAM;
• IPUC jurisdictional regulations allow IPUC published avoided costs for up to a 20-year contract term. Effective December 14, 2010, wind and solar resource projects with a nameplate rating of 100 kW or less are eligible for the IPUC published avoided costs. For all other resource types, a project that generates up to ten average MW of energy monthly is eligible for the IPUC published avoided costs;
• OPUC jurisdictional regulations allow OPUC published avoided costs for up to a 20-year contract term for projects with a nameplate rating of up to ten MW of capacity; and
• if a PURPA project does not qualify for published avoided costs, Idaho Power is required to negotiate the terms, prices, and conditions with the developer. These negotiations reflect the characteristics of the individual projects (i.e., operational flexibility, location, and size) and the benefits to the Idaho Power system and must be consistent with other similar energy alternatives.
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Idaho Power believes that published avoided cost rates in effect as of the date of this report provide a favorable climate for PURPA project development. Mandated purchase of intermittent, non-dispatchable energy at published avoided cost rates may result in Idaho Power acquiring energy at above wholesale market prices when a surplus already exists (at times resulting in sale of the surplus energy in the wholesale markets at a loss) and result in additional integration costs, thus increasing costs to its customers. Following a dramatic increase in anticipated PURPA projects, in response to a November 5, 2010 application filed by Idaho Power and two other electric utilities with Idaho service territories, on February 7, 2011, the IPUC issued an order temporarily reducing the eligibility cap for projects obtaining published avoided cost rates, effective retroactively to December 14, 2010, to 100 kW for wind and solar PURPA projects only. On June 8, 2011, the IPUC disapproved 13 contracts for pending wind projects with a combined nameplate capacity of 294 MW. If these 13 contracts had all been approved, the amount of wind generation that Idaho Power had under contract would have exceeded 1,000 MW. The IPUC has opened a docket to further investigate PURPA contract terms and conditions and pricing models. This matter is scheduled for hearings in August 2012. For further information on those proceedings, refer to "MD&A - Regulatory Matters - PURPA Power Purchase Contracts."
As of December 31, 2011, Idaho Power had 40 MW of solar power generation under contract for purchase. In December 2011, Idaho Power entered into a PURPA purchase power agreement for a 20-MW waste biomass generation project. Idaho Power has also entered into a number of other PURPA agreements for smaller renewable energy projects.
As of December 31, 2011, Idaho Power had the following signed CSPP-related agreements with terms ranging from one to 35 years:
StatusOn-line at the end of 2011Contracted and projected to come on-line by year-end 2014Total
Number ofContracts
9623
119
NameplateCapacity (MW)
606383989
The majority of new facilities will be wind resources that will generate on an intermittent basis. During 2011, Idaho Power purchased 1.5 million MWh of power from CSPP facilities at a cost of $90 million, resulting in a blended price of $60.36 per MWh.
Transmission Services Electric transmission systems deliver energy from electric generation facilities to distribution systems for final delivery to customers. Transmission systems are designed to move electricity over long distances because generation facilities can be located anywhere from a few miles to hundreds of miles from customers. Idaho Power’s generating facilities are interconnected through its integrated transmission system and are operated on a coordinated basis to achieve maximum load-carrying capability and reliability. Idaho Power’s transmission system is directly interconnected with the transmission systems of the Bonneville Power Administration (BPA), Avista Corporation, PacifiCorp, NorthWestern Energy, and NV Energy, Inc. These interconnections, coupled with transmission line capacity made available under agreements with some of the above entities, permit the interchange, purchase, and sale of power among entities in the Western Power System. Idaho Power provides wholesale transmission service and provides firm and non-firm wheeling services for eligible transmission customers. Idaho Power is a member of the WECC, the Western Systems Power Pool, the Northwest Power Pool, the Northern Tier Transmission Group, and the North American Energy Standards Board. These groups have been formed to more efficiently coordinate transmission reliability and planning throughout the western grid. Resource Planning and Renewable Energy Projects Integrated Resource Plan: Idaho Power filed its 2011 Integrated Resource Plan (IRP) with the IPUC and OPUC in June 2011. The IRP forecasts Idaho Power’s load and resource situation for the next 20 years, analyzes potential supply-side and demand-side options, and identifies near-term and long-term actions. The 2011 IRP was accepted by the IPUC in December 2011. As of the date of this report the 2011 IRP has not been acknowledged by the OPUC. The four primary goals of the IRP are to:
• identify sufficient resources to reliably serve the growing demand for energy within Idaho Power’s service area throughout the 20-year planning period;
• ensure the selected resource portfolio balances cost, risk, and environmental concerns;• give equal and balanced treatment to both supply-side resources and demand-side measures; and• involve the public in the planning process in a meaningful way.
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Idaho Power updates the IRP every two years and work on the 2013 IRP will begin in the summer of 2012. Idaho Power expects that the updated plan will be completed and filed in June 2013. During the time between resource plan filings, the public and regulatory oversight of the activities identified in the 2011 IRP allows for discussion and adjustment of the IRP as warranted. Idaho Power makes periodic adjustments and corrections to the resource plan to reflect changes in technology, economic conditions, anticipated resource development, and regulatory requirements. The 2011 IRP included the 300-MW Langley Gulch project currently under construction and a 50-MW expansion of the Shoshone Falls hydroelectric facility. The 2011 IRP also identified the Boardman-to-Hemingway transmission line in the preferred resource portfolio. Idaho Power believes the Boardman-to-Hemingway transmission line and the Hemingway substation, together with the Gateway West transmission line, will improve reliability, relieve congestion, and provide system flexibility. Additional information about Idaho Power’s significant infrastructure development projects are discussed in Part II, Item 7 – “MD&A – Liquidity and Capital Resources – Capital Requirements – Major Infrastructure Projects.” The expected-case load forecast in the 2011 IRP projects peak-hour load will grow 69 MW annually and average-system load will increase annually 29 average MW (aMW) over the 20-year planning period, with an expected-case, median, average annual system load of 2,362 aMW by 2030. Idaho Power intends to meet the anticipated increase in demand through energy efficiency and demand response programs, the development of transmission capacity and additional generation resources, such as the Langley Gulch and Shoshone Falls projects, and from the purchase of power from third parties, including from renewable energy projects and market power purchases. Idaho Power stated in the 2011 IRP that it expects energy efficiency programs to result in 233 aMW of load reduction by 2030, and that demand response programs are targeted to reduce peak summer load by 351 MW by summer 2016.
The 2011 IRP also included discussion related to geothermal, combined heat and power (CHP), and solar resources, each of which is described below.
Geothermal Resources: Idaho Power has continued to work with geothermal project developers capable of delivering energy to the company’s service area. The 2009 IRP included two 20-MW increments of geothermal energy in the preferred portfolio—one in 2012 and one in 2016. The 20-MW increment in 2012 was addressed by a long-term power purchase agreement for the output from the Neal Hot Springs geothermal project located in eastern Oregon. This project is currently under construction and the developer expects it to be operational in late 2012. Idaho Power has contracted to receive the RECs from the project during the term of the agreement. The additional 2016 increment of geothermal energy was evaluated in the 2011 IRP and was found unnecessary with the addition of the Boardman-to-Hemingway transmission line project. The preferred portfolio in the 2011 IRP did include 52 MW of geothermal energy in 2021 and Idaho Power plans to follow the development of geothermal resources in and around Idaho Power's service area in the event a project materializes that could fill this need in 2021. CHP Resources: CHP, also commonly referred to as "cogeneration," facilities utilize by-product heat (often through steam) to generate electricity. CHP resources were not included in the 2011 IRP preferred portfolio because of the uncertainty in being able to successfully develop a CHP project. However, Idaho Power continues to work with large customers and other parties to explore CHP development opportunities. In 2009, Idaho Power signed an agreement to jointly investigate a CHP project with the Idaho Office of Energy Resources (IOER) and The Amalgamated Sugar Company (TASCO), one of Idaho Power’s large industrial customers. The agreement established the framework for a high-level feasibility study to investigate installing a CHP project at TASCO’s Nampa, Idaho facility that could generate as much as 100 MW of electricity. The IOER and Idaho Power jointly funded the study, which confirmed initial estimates of the project’s potential benefits. In September 2010, Idaho Power, IOER, and TASCO agreed to complete a more detailed feasibility study to refine performance and financial modeling of the proposed project. The second feasibility study indicated that the CHP project is technically feasible; however, given the increase in the amount of PURPA power generation Idaho Power now has under contract, current economic and electric power market conditions, the current treatment of CHP projects under federal incentive programs, and TASCO's and IPC's individual needs, proceeding with developing this CHP project does not appear to be the most economic choice for either party.
Solar Resources: On or before January 1, 2020, Idaho Power is required to own or contract to purchase the capacity and output from a qualifying solar photovoltaic (PV) system with a minimum capacity of 500 kW pursuant to the state of Oregon's solar PV capacity standard. The timing of development of this required project in Oregon and the solar demonstration project referenced in Idaho Power's 2011 IRP will depend in large part on Idaho Power's ability to resolve integration, reliability, and cost issues associated with the recent influx of PURPA resources from which Idaho Power is currently mandated to purchase power. However, with the cost of solar PV technology continuing to decrease, Idaho Power believes this technology will
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become more prevalent in its service area. Idaho Power continues to evaluate the timing for proceeding with solar resource projects.
Energy Efficiency and Demand Response Programs: Idaho Power has 16 energy efficiency and demand response programs targeting energy savings across the entire year and summer system demand reduction. These programs are offered to all customer segments and emphasize the wise use of energy, especially during periods of high demand. This energy and demand reduction can minimize or delay the need for new infrastructure. Idaho Power’s programs include:
• financial incentives for irrigation customers for either improving the energy efficiency of an irrigation system or installing new energy efficient systems;
• energy efficiency for new and existing homes, including efficient appliances and HVAC equipment, energy efficient building techniques, insulation improvement, air duct sealing, and energy efficient lighting;
• incentives to industrial and commercial customers for acquiring energy efficient equipment, and using energy efficiency techniques for operational and management processes; and
• demand response programs to reduce peak summer demand through the voluntary interruption of central air conditioners for residential customers, interruption of irrigation pumps, and reduction of commercial and industrial demand through a third-party demand response aggregator.
In 2011, Idaho Power’s energy efficiency programs reduced energy usage by approximately 160,000 MWh. Idaho Power's demand response programs had available capacity of approximately 410 MW; however, because of a relatively mild summer and the restructuring of Idaho Power's irrigation peak rewards program, Idaho Power realized approximately 83 MW in summer peak demand reduction through combined performance. In 2011, Idaho Power spent approximately $46.3 million on energy efficiency and targeted demand reduction response programs. Approximately $37.7 million of funding for these programs is provided by Idaho and Oregon energy efficiency tariff riders, while the balance of the funding comes from Idaho Power base rates. Beginning in 2011, as approved by the IPUC, Idaho Power capitalized approximately $7 million of custom efficiency program incentives as a regulatory asset.
Approximately $4 million of Idaho Power’s 2011 energy efficiency spending was related to research and analysis, education, technology evaluation, and market transformation. Most of this activity was done in conjunction with the Northwest Energy Efficiency Alliance.
Environmental Regulation and Costs Idaho Power's activities are subject to a broad range of federal, state, regional, and local laws and regulations designed to protect, restore, and enhance the quality of the environment. Environmental regulation continues to impact Idaho Power’s operations due to the cost of installation and operation of equipment and facilities required for compliance with environmental regulations, and the modification of system operations to accommodate environmental regulations. In addition to generally applicable regulations, the FERC licenses issued for Idaho Power’s hydroelectric generating plants have environmental requirements such as aeration of turbine water to meet dissolved gas and temperature standards in the tail waters downstream from the plants. Idaho Power monitors these issues and reports the results to the appropriate regulatory agencies. Idaho Power co-owns three coal-fired power plants and owns two natural gas combustion turbine power plants that are subject to a broad range of environmental requirements, including air quality regulation. For a more detailed discussion of these and other environmental issues, refer to Part II, Item 7 – “MD&A – Environmental Matters.”
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Idaho Power’s environmental compliance costs will continue to be significant for the foreseeable future, especially with potential additional regulation under discussion at the state and federal levels. Idaho Power estimates its environmental expenditures, based upon present environmental laws and regulations, will be as follows for the periods indicated, excluding allowance for funds used during construction (AFUDC) (in millions of dollars):
Environmental expenditures
Capital expenditures:Studies and measures at hydroelectric facilitiesInvestments in equipment and facilities at thermal plants
Total capital expenditures
Operating expenses:Operating costs for environmental facilities - hydroelectricOperating costs for environmental facilities - thermal
Total operations and maintenance
2012
$ 1215
$ 27
$ 2112
$ 33
2013 - 2014
$ 3199
$ 130
$ 4827
$ 75 Idaho Power anticipates that a number of new and impending EPA rulemakings and proceedings addressing, among other things, ozone and fine particulate matter pollution, emissions, and disposal of coal combustion residuals could result in substantially increased operating and compliance costs in addition to the amounts set forth above.
IFS IFS invests primarily in affordable housing developments, which provide a return principally by reducing federal and state income taxes through tax credits and accelerated tax depreciation benefits. IFS generated tax credits of $6 million, $7 million, and $8 million in 2011, 2010, and 2009, respectively. IFS’s portfolio also includes historic rehabilitation projects such as the Empire Building in Boise, Idaho. IFS made no new investments in 2011, but did have $7 million and $14 million in new investments during 2010 and 2009, respectively, and will continue to evaluate new opportunities for investment commensurate with the ongoing needs of IDACORP. IFS has focused on a diversified approach to its investment strategy in order to limit both geographic and operational risk. Over 90 percent of IFS’s investments have been made through syndicated funds. At December 31, 2011, the gross amount of IFS’s portfolio equaled $198 million in tax credit investments. These investments cover 49 states, Puerto Rico, and the U.S. Virgin Islands. The underlying investments include nearly 700 individual properties, of which all but five are administered through syndicated funds. IDA-WEST Ida-West operates and has a 50 percent interest in nine hydroelectric plants with a total generating capacity of 45 MW. Four of the projects are located in Idaho and five are in northern California. All nine projects are “qualifying facilities” under PURPA. Idaho Power purchased all of the power generated by Ida-West’s four Idaho hydroelectric projects at a cost of $9 million, $8 million, and $9 million in 2011, 2010, and 2009, respectively.
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EXECUTIVE OFFICERS OF THE REGISTRANTS The names, ages, and positions of the executive officers of IDACORP and Idaho Power are listed below, along with their business experience during at least the past five years. Mr. J. LaMont Keen and Mr. Steven R. Keen are brothers. There are no other family relationships among these officers, nor is there any arrangement or understanding between any officer and any other person pursuant to which the officer was elected. Senior Executive Officers (in alphabetical order)
DARREL T. ANDERSON, 53• President and Chief Financial Officer of Idaho Power Company, January 1, 2012 - present.• Executive Vice President, Administrative Services and Chief Financial Officer of IDACORP, Inc., October 1, 2009 -
present.• Executive Vice President, Administrative Services and Chief Financial Officer of Idaho Power Company, October 1,
2009 - December 31, 2011.• Senior Vice President - Administrative Services and Chief Financial Officer of IDACORP, Inc. and Idaho Power
Company, July 1, 2004 - October 1, 2009.
REX BLACKBURN, 56• Senior Vice President and General Counsel, IDACORP, Inc. and Idaho Power Company, April 1, 2009 - present.• Senior Attorney, Idaho Power Company, January 1, 2008 - March 31, 2009.• Partner at Blackburn and Jones, LLP, a law firm, January 2003 - December 31, 2007.
LISA A. GROW, 46
• Senior Vice President, Power Supply of Idaho Power Company, October 1, 2009 - present.• Vice President – Delivery Engineering and Operations of Idaho Power Company, July 20, 2005 - September 30, 2009.
J. LAMONT KEEN, 59
• President and Chief Executive Officer of IDACORP, Inc., July 1, 2006 - present.• Chief Executive Officer of Idaho Power Company, November 17, 2005 - present. • President of Idaho Power Company, March 1, 2002 - December 31, 2011.• Executive Vice President of IDACORP, Inc., March 1, 2002 - July 1, 2006.• Member of the Boards of Directors of both IDACORP, Inc. and Idaho Power Company.
STEVEN R. KEEN, 51• Senior Vice President, Finance and Treasurer of Idaho Power Company, January 1, 2012 - present.• Vice President, Finance and Treasurer of IDACORP, Inc., June 1, 2010 - present.• Vice President, Finance and Treasurer of Idaho Power Company, June 1, 2010 - December 31, 2011.• Vice President and Treasurer of IDACORP, Inc. and Idaho Power Company, June 1, 2006 - May 31, 2010.• President of IDACORP Financial Services, January 15, 1999 - May 31, 2007.
DANIEL B. MINOR, 54
• Executive Vice President and Chief Operating Officer of Idaho Power Company, January 1, 2012 - present.• Executive Vice President of IDACORP, Inc., May 20, 2010 - present.• Executive Vice President, Operations of Idaho Power Company, October 1, 2009 - December 31, 2011.• Senior Vice President – Delivery of Idaho Power Company, July 1, 2004 - October 1, 2009.
Other Executive Officers (in alphabetical order)
DENNIS C. GRIBBLE, 59• Vice President and Chief Information Officer of Idaho Power Company, June 1, 2006 - present.• Vice President and Chief Information Officer of IDACORP, Inc., June 1, 2006 - December 31, 2011. • Vice President and Treasurer of IDACORP, Inc. and Idaho Power Company, July 15, 2004 - June 1, 2006.
PATRICK A. HARRINGTON, 51
• Corporate Secretary of IDACORP, Inc. and Idaho Power Company, March 15, 2007 - present.• Senior Attorney, IDACORP, Inc. and Idaho Power Company, June 7, 2003 - March 15, 2007.
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WARREN KLINE, 56
• Vice President, Customer Operations of Idaho Power Company, May 20, 2010 - present.• Vice President – Customer Service and Regional Operations of Idaho Power Company, July 20, 2005 - May 20, 2010.
JEFFREY MALMEN, 44
• Vice President, Public Affairs of IDACORP, Inc. and Idaho Power Company, October 1, 2008 - present.• Senior Manager – Governmental Affairs of IDACORP, Inc. and Idaho Power Company, December 10, 2007 - October
1, 2008.• Chief of Staff of the Office of Idaho Governor C.L. “Butch” Otter, January 2007 - November 2007.• Chief of Staff of the Office of Idaho Congressman C.L. “Butch” Otter, January 2001 - December 2006.
LUCI K. MCDONALD, 54
• Vice President, Human Resources and Corporate Services of Idaho Power Company, May 20, 2010 - present• Vice President, Human Resources and Corporate Services of IDACORP, Inc., May 20, 2010 - December 31, 2011.• Vice President – Human Resources of IDACORP, Inc. and Idaho Power Company, December 6, 2004 - May 20, 2010.
KEN W. PETERSEN, 48
• Corporate Controller and Chief Accounting Officer of IDACORP, Inc. and Idaho Power Company, May 20, 2010 - present.
• Corporate Controller of IDACORP and Idaho Power Company, December 29, 2007 - May 20, 2010.• General Manager Delivery Services and Delivery Business Unit Controller of Idaho Power Company, January 3, 2004
- December 28, 2007. N. VERN PORTER, 52
• Vice President, Delivery Engineering and Operations, Idaho Power Company, October 1, 2009 - present.• General Manager of Power Production of Idaho Power Company, April 22, 2006 - October 1, 2009.• Senior Manager of Power Supply Operations of Idaho Power Company, August 30, 2003 - April 22, 2006.
GREGORY W. SAID, 57
• Vice President, Regulatory Affairs, Idaho Power Company, January 20, 2011 - present.• General Manager of Regulatory Affairs, Idaho Power Company, April 3, 2010 - January 20, 2011.• Director, State Regulation, Idaho Power Company, August 23, 2008 - April 3, 2010.• Manager, Revenue Requirement, Idaho Power Company, November 14, 1998 - August 23, 2008.
NAOMI SHANKEL, 40• Vice President, Supply Chain of Idaho Power Company, May 20, 2010 - present.• Vice President, Supply Chain of IDACORP, Inc., May 20, 2010 - December 31, 2011.• Vice President, Audit and Compliance of IDACORP, Inc. and Idaho Power Company, September 21, 2006 - May 20,
2010.• Director, Audit Services of IDACORP, Inc. and Idaho Power Company, July 19, 2003 - September 21, 2006.
LORI D. SMITH, 51
• Vice President, Chief Risk Officer of IDACORP, Inc. and Idaho Power Company, May 20, 2010 - present.• Vice President - Corporate Planning and Chief Risk Officer of IDACORP, Inc. and Idaho Power Company, January 1,
2008 - May 20, 2010.• Vice President - Finance and Chief Risk Officer of IDACORP, Inc. and Idaho Power Company, July 1, 2004 - January
1, 2008.
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ITEM 1A. RISK FACTORS In addition to the factors discussed elsewhere in this report, the risk factors set forth below may have a significant impact on the business, financial condition, or results of operations of IDACORP and Idaho Power and could cause actual results or outcomes to differ materially from those discussed in any forward-looking statements. If the Idaho Public Utilities Commission, the Oregon Public Utility Commission, or the Federal Energy Regulatory Commission grant less rate recovery in regulatory proceedings than Idaho Power needs to cover existing and future costs and earn a rate of return, earnings and cash flows may be reduced. The prices that the Idaho Public Utilities Commission and Oregon Public Utility Commission authorize Idaho Power to charge for its retail services, and the tariff rate that the Federal Energy Regulatory Commission permits Idaho Power to charge for transmission, are generally the most significant factors influencing IDACORP’s and Idaho Power’s financial position, results of operations, and liquidity. The Idaho Public Utilities Commission and Oregon Public Utility Commission have the authority to disallow recovery of any costs that they consider unreasonable or imprudently incurred. Also, the rates allowed by the Federal Energy Regulatory Commission for transmission service may be insufficient for recovery of costs incurred. While the Idaho Public Utilities Commission and Oregon Public Utility Commission have established an authorized rate of return for Idaho Power, the regulatory process does not provide assurance that Idaho Power will be able to achieve the authorized rate of return. Further, while the Idaho Public Utilities Commission and Oregon Public Utility Commission are required to establish rates that are fair, just, and reasonable, they have considerable discretion in applying this standard. The ratemaking process typically involves multiple parties, including governmental bodies, consumer advocacy groups, and customers. While each party has differing concerns, they often have the common objective of limiting rate increases or even reducing rates. Idaho Power cannot predict the outcome of ratemaking proceedings, including the extent to which costs, including the costs of significant capital projects, will be recovered or what rates of return will be authorized. The failure of Idaho Power to recover those costs, or recover them in a timely manner, may decrease IDACORP's and Idaho Power's earnings and adversely impact cash flows.
For additional information relating to Idaho Power's regulatory framework, see Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report and "Regulatory Matters" in Part II, Item 7 - "Management's Discussion and Analysis of Financial Condition and Results of Operations" in this report. Idaho Power's cost recovery deferral mechanisms may not function as intended, which may adversely affect cash flows and liquidity. Idaho Power has power cost adjustment mechanisms that provide for periodic adjustments to the rates charged to its Idaho and Oregon retail customers. The power cost adjustment tracks Idaho Power’s actual net power supply costs (primarily fuel and purchased power less off-system sales) and compares these amounts to net power supply costs currently being recovered in retail rates. A majority, but not all, of the variance between these two amounts is deferred for future recovery from, or refund to, customers. Accordingly, the power cost adjustment mechanisms only partially offset the potentially adverse financial impacts of forced generating plant outages, severe weather, reduced hydroelectric generation, and volatile wholesale energy prices. Because of the power cost adjustment mechanisms, the primary financial impact of power supply cost variations is on the timing of cash flows. When costs rise above the level recovered in retail base rates it adversely affects Idaho Power’s operating cash flow and liquidity until those costs are recovered from customers.
Idaho Power also has a fixed cost adjustment, which began as a pilot program for Idaho Power’s Idaho residential and small general service customers, running from 2007 through 2011. The fixed cost adjustment 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. In October 2011, Idaho Power filed an application with the Idaho Public Utilities Commission requesting that the fixed cost adjustment pilot program become permanent. As of the date of this report, the Idaho Public Utilities Commission has not issued a determination. If the fixed cost adjustment is not approved as permanent, or if the Idaho Public Utilities Commission modifies the fixed cost adjustment in some manner, Idaho Power may incur fixed costs that may not be recoverable in rates in times of declining usage per residential and small general service customer, or may recover more than the fixed costs incurred in times of increasing usage per residential and small general service customer. This over- or under-collection of fixed costs would likely continue until Idaho Power's next Idaho general rate case when the recovery of fixed costs through base rates can be realigned, which could adversely affect Idaho Power's cash flows and liquidity.
For additional information relating to Idaho Power's regulatory framework and cost recovery mechanisms, see Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report and "Regulatory Matters" in Part II, Item 7 - "Management's Discussion and Analysis of Financial Condition and Results of Operations" in this report.
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Reduced hydroelectric generation can reduce revenues and increase costs, and reduce earnings and cash flows. Idaho Power derives a significant portion of its power supply from its hydroelectric facilities. Because of Idaho Power’s heavy reliance on hydroelectric generation, the availability of water can significantly affect its operations. When hydroelectric generation is reduced, Idaho Power must increase its use of generally more expensive thermal generating resources and purchased power; therefore, opportunities for off-system sales are reduced, which reduces revenues. The further integration of wind and other intermittent power sources into Idaho Power's system may also displace lower cost hydroelectric resources. Integration of intermittent power sources may also increase costs at thermal plants due to wear and tear associated with frequent start-up and shut-down of those facilities to balance loads. While Idaho Power expects to recover, as a result of its power cost adjustment mechanisms, the majority of its net power supply costs above current rates (including the power cost adjustment forecast), recovery of the excess amounts may not occur until the subsequent power cost adjustment year, impacting cash flows and liquidity. Declines in stream flows and over-appropriation of water in Idaho may reduce hydroelectric generation and revenues and increase costs, and reduce earnings and cash flows. The combination of declining Snake River base flows, over-appropriation of water, and periods of drought have led to water rights disputes and proceedings among surface water and ground water irrigators and the State of Idaho. Recharging the Eastern Snake Plain aquifer by diverting surface water to porous locations and permitting it to sink into the aquifer is one proposed solution to the over-appropriation dispute. Diversions from the Snake River for aquifer recharge or the loss of water rights may further reduce Snake River flows available for hydroelectric generation. Idaho Power’s January 2010 settlement agreement with the State of Idaho resolves litigation regarding certain Idaho Power water rights on the Snake River and provides for ongoing Snake River water issues to be addressed in a comprehensive aquifer management plan process. However, there is no assurance that this process will lead to increased Snake River stream flows for Idaho Power’s hydroelectric projects. The comprehensive aquifer management plan process and the resolution of pending proceedings relating to the Snake River may affect Snake River flows available for hydroelectric generation and thereby reduce Idaho Power’s revenues and increase costs, and may reduce earnings and cash flows. Idaho Power’s reliance on coal and natural gas to fuel its power generation facilities exposes it to risk of increased costs and reduced earnings. In addition to hydroelectric generation, Idaho Power relies on coal and natural gas to fuel its generation facilities. As part of its normal business operations, Idaho Power purchases power and natural gas in the open market or under short-term, long-term, or variable-priced contracts. Market prices for coal and natural gas are influenced by factors impacting supply and demand, such as weather conditions, fuel transmission or transportation availability, economic conditions, and changes in technology. Increases in demand for coal or natural gas may result in market price increases, short-term price volatility, and supply availability issues. Any disruption in Idaho Power’s fuel supply may require the company to find alternative fuel sources at higher costs, to produce power from higher cost generation facilities, or to purchase power from other sources at higher costs. Idaho Power may not be able to fully recover these increased costs through ratemaking, which may reduce earnings. Further, Idaho Power's power cost adjustment mechanisms contain a cost-sharing feature that does not in all circumstances provide for full recovery of incurred costs in customer rates. Idaho Power’s power generating facilities are subject to numerous operational risks unique to it and its industry. Operating risks associated with Idaho Power's generation facilities include equipment failures, volatility in fuel and transportation pricing, interruptions in fuel supplies, increased regulatory compliance costs, labor disputes, workforce safety matters, the loss of cost-effective disposal options for solid waste, operator error, and the occurrence of catastrophic events at the facilities. Diminished availability or performance of Idaho Power's transmission and distribution facilities could result in reduced customer satisfaction and regulatory inquiries and fines. Operation of Idaho Power's owned and co-owned generating stations below expected capacity levels, or unplanned outages at these stations, could cause reduced energy output and lower efficiency levels and result in lost revenues and increased expenses. These operational risks may result in plant outages, as well as increased operation and maintenance expenses, power generation costs, and power purchase costs, which could have an adverse impact on earnings and cash flows.
Load changes in Idaho Power’s service territory expose Idaho Power to greater market and operational risk and could increase costs and reduce earnings and cash flows. While Idaho Power’s customer growth rate has slowed in recent years, increases in both the number of customers and the demand for energy have resulted and may continue to result in increased reliance on purchased power to meet peak system demand. While Idaho Power is exploring targeted opportunities for managed load growth, load growth can create planning and operating difficulties for Idaho Power that can negatively impact its ability to reliably serve customers. Through current regulatory mechanisms, Idaho Power can expect to recover the majority of the net power supply costs above the amounts included in its rates, though recovery of the excess amounts does not occur until the subsequent power cost adjustment year, and the remaining amount is absorbed by Idaho Power, which could increase costs and reduce earnings and cash flows. Load growth can also result in the need for additional investments in Idaho Power’s infrastructure to serve the new load. For instance, to meet customer demand Idaho Power is currently constructing its Langley
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Gulch natural gas-fired generating plant, and has in development a number of transmission projects. If Idaho Power is unable to secure timely rate relief from the Idaho Public Utilities Commission, the Oregon Public Utility Commission, or the Federal Energy Regulatory Commission to recover the costs of these additional investments, the resulting disconnect between the time investments are made and costs are recovered would have a negative effect on earnings and cash flows. Further, while Idaho Power has experienced a general trend of load growth in its service territory in recent years, increased emphasis on energy efficiency and weak economic conditions could result in a decline in loads, which may decrease Idaho Power's revenues from energy sales. Also, Idaho Power's regulatory mechanisms, including its load change adjustment rate included in its power cost adjustment, may not result in Idaho Power recovering all of its costs associated with load decreases, which would have a negative impact on earnings and cash flows.
Federally mandated purchases of power from PURPA power purchase projects, and integration of power generated from those projects into Idaho Power's system, may increase costs and decrease system reliability, and adversely affect cash flows, financial condition, and earnings. An abundance of intermittent, non-dispatchable wind power generation at times when Idaho Power has available lower-cost resources to meet load demands has an impact on the operation of Idaho Power's hydroelectric generation plants, system reliability, power supply costs, and the wholesale power markets in the Pacific Northwest. Wind power generated from PURPA projects, which Idaho Power is generally obligated to purchase regardless of the then-current load demand or wholesale energy market prices, increases the likelihood and frequency that Idaho Power will be required to reduce output from its lower-cost hydroelectric and fossil fuel-fired generation resources, even when weather conditions have resulted in favorable hydroelectric generation conditions or fuel prices are low. Wind generation in the Pacific Northwest during periods when abundant hydroelectric generation is also available reduces wholesale market prices. This may result in Idaho Power's sale of excess wind power at a significant discount to the price Idaho Power paid for the wind power under PURPA wind power purchase contracts. It may also result in the sale of excess lower-cost hydroelectric or fuel-based power at depressed wholesale market prices. When forecasted wind or other intermittent resources do not materialize, Idaho Power must obtain a substitute source of power to meet load demand, and often must purchase power in the wholesale power markets to balance loads. Further, balancing load and generation from Idaho Power's power generation portfolio is challenging, and Idaho Power expects that its costs will increase as a result of its efforts to integrate intermittent, non-dispatchable power from a large number of PURPA power projects. Idaho Power anticipates that those costs will escalate as the volume of wind and other intermittent power on Idaho Power's system increases, which may adversely affect IDACORP's and Idaho Power's cash flows, financial condition, and earnings. Weather and climate change could affect customer demand and hydroelectric generation and disrupt transmission and distribution systems, reducing earnings and cash flows. Warmer than normal winters, cooler than normal summers, and increased rainfall during the irrigation seasons reduce retail revenues from power sales and may impact the amount and timing of hydroelectric generation. Changes in the amount and timing of snowpack and stream flows may also adversely affect hydroelectric generation. Extreme weather events and their associated impacts, such as high winds and fires, can disrupt transmission and distribution systems and cause service interruptions and extended outages, increase supply chain costs, potentially interrupt use of generation resources, and limit Idaho Power's ability to meet customer energy demand. Rapid increases in load requirements resulting from unexpected adverse weather changes, particularly if coupled with transmission constraints or system damage, could adversely impact Idaho Power's costs and ability to meet customer energy demand. Conversely, rapid decreases in load requirements due to unexpected weather events could result in Idaho Power's sale of excess energy at depressed wholesale market prices. Disruption in generation, transmission, and distribution systems due to weather-related factors also increases operations and maintenance expenses and reduces earnings and cash flows.
Long-term climate change could increase the likelihood and frequency of these adverse weather events. Further, legislative and/or regulatory developments associated with climate change could affect construction plans and operations, including placing restrictions on the construction of new generation resources and the expansion of existing resources, result in closure of generation resources or installation of costly pollution control equipment, or require changes to the operation of generation resources and Idaho Power's power generation portfolio in general. Also, consumer preference for renewable or low greenhouse gas-emitting sources of energy could impact demand from existing sources and require significant investment in new generation and transmission resources. Any of these effects of weather and climate change could decrease revenues, increase operating costs, and reduce IDACORP’s and Idaho Power’s earnings and cash flows.
In Idaho Power's service territory, demand for power peaks during the hot summer months, often concurrent with a seasonal increase in wholesale power market prices. As a result, Idaho Power's operating results fluctuate substantially on a seasonal basis. In addition, Idaho Power will generally sell less power, and correspondingly have lower net income, when weather conditions in its service areas are milder. Unusually mild weather in the future could diminish IDACORP's and Idaho Power's results of operations and adversely affect its financial condition.
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Idaho Power’s risk management policy and programs relating to economically hedging power and gas exposures, financial and interest rate risk, and counterparty creditworthiness may not always perform as intended, and as a result Idaho Power may suffer economic losses. Idaho Power enters into transactions to hedge its positions in coal, natural gas, power, and other commodities. These hedging transactions are impacted by a range of factors, including variations in power demand, fluctuations in market prices, and market prices for alternative commodities. In connection with these hedging transactions, Idaho Power is exposed to the risk that counterparties that owe it money will default on their obligations. A similar risk of non-performance by third parties arises where those parties are obligated to purchase energy from, or sell energy to, Idaho Power, or are parties to commodity price risk management arrangements. Idaho Power actively manages the market risk inherent in its energy related activities and counterparty credit positions by establishing and enforcing risk limits and risk management policies. Idaho Power has procedures that monitor compliance with its risk management policies and programs, including verification of transactions, regular portfolio reporting of various risk management metrics, and daily counterparty credit risk analysis. However, actual hydroelectric and thermal generation, power purchase volumes from intermittent sources, transmission availability, and market prices may be significantly different than those originally planned for when Idaho Power enters into its positions in hedging transactions. This creates uncertainty in the appropriate amount of hedging activity to pursue. Forecasts of future loads and available resources to meet those loads are inherently uncertain and may cause Idaho Power to over- or under-hedge actual resource needs, exposing the company to market risk on the over- or under-hedged position. Changes in market prices are also unpredictable and can at times result in Idaho Power’s hedged positions performing less favorably than unhedged positions. In addition, Idaho Power’s counterparty credit policies may not prevent counterparties from failing to perform, forcing the company to replace forward contracts with transactions in the open market, where the price for the particular commodity may at that time be higher. As a result, risk management decisions may adversely affect IDACORP’s and Idaho Power’s financial condition, results of operations, or cash flows. Also, as part of IDACORP's and Idaho Power's risk management programs, they may use a variety of non-derivative and derivative financial instruments, such as swaps, futures, and forwards, to manage market risks. They may also use interest rate derivative instruments to hedge against interest rate fluctuations related to debt. In the absence of actively quoted market prices and pricing information from external sources, the valuation of some of the derivative instruments involves management’s judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of some of the contracts. IDACORP or Idaho Power could also recognize financial losses as a result of volatility in the market values of these contracts or if a counterparty fails to perform, which could adversely affect IDACORP's or Idaho Power's results of operations, financial condition, and cash flows.
Idaho Power’s ability to enter into swaps and derivatives and hedge commodity and interest rate risk may be adversely affected by recent federal legislation. The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) was signed into law in July 2010. The Dodd-Frank Act establishes regulatory jurisdiction by the Commodity Futures Trading Commission and the Securities and Exchange Commission for certain swaps and derivative instruments and the users of those instruments. A number of federal agencies, including the Commodity Futures Trading Commission and the Securities and Exchange Commission, must adopt rules to implement the Dodd-Frank Act. As Idaho Power enters into swap and derivative transactions from time to time in connection with its general business operations, these rules, when implemented, could have a significant impact on Idaho Power and will likely increase the costs Idaho Power incurs in connection with its swap and derivative transactions. Under the rules, Idaho Power may be required to post collateral to meet minimum capital and margin requirements. The Dodd-Frank Act also requires a broad category of swaps to be cleared and traded on registered exchanges or special derivatives exchanges. These clearing requirements would result in a significant change from Idaho Power's current practice of bilateral transactions and negotiated credit terms. The Dodd-Frank Act outlines an elective exemption to the clearing requirements for swaps entered into by end users that are not "major swap participants" or "swap dealers" and that enter into hedges to mitigate their own commercial risk. Although Idaho Power expects that its swaps will qualify under the end user exemption, there can be no assurance they will qualify. Further, even if Idaho Power's swaps were to qualify under the end user exemption, it will not be exempt from all swap-related requirements of the Dodd-Frank Act, and counterparties that are swap dealers or major swap participants may seek to pass along the increased cost and margin requirements through higher prices and reductions in unsecured credit limits. The occurrence of these events could have an adverse effect on IDACORP's and Idaho Power's results of operations, financial condition, and cash flows. Capital expenditures for power generation and delivery infrastructure and replacement of that infrastructure can significantly affect liquidity. Idaho Power’s business is capital intensive and requires significant investments in energy generation and other infrastructure projects. Long-term increases in both the number of customers and the demand for energy require expansion and reinforcement of transmission and distribution systems, generating facilities, and other infrastructure. For instance, Idaho Power is currently constructing the Langley Gulch power plant and is in the permitting process for two substantial 500-kV transmission line projects. The cost of maintaining existing, aging equipment and infrastructure and
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developing new infrastructure is substantial, and involves risks relating to, among other things, cost overruns, system outages, price increases in commodities (such as steel and copper), and denial by regulatory bodies of recovery through rates of costs incurred. Idaho Power may not be successful in limiting capital expenditures to planned amounts, particularly in the event of escalating costs for materials and labor. If Idaho Power does not receive timely regulatory recovery of costs associated with those expansion and reinforcement activities, Idaho Power will have to rely more heavily on external debt or equity financing for its future capital expenditures. These large capital expenditures may weaken the consolidated financial profile of IDACORP and Idaho Power. Additionally, a significant portion of Idaho Power’s facilities were constructed many years ago, which could affect reliability, increase repair and maintenance expenses, and increase reliance on market purchases of power. The performance of pension and postretirement benefit plan investments and other factors impacting plan costs could adversely affect cash flows and liquidity. Idaho Power provides a noncontributory defined benefit pension plan covering most employees, as well as a defined benefit postretirement benefit plan (consisting of health care and death benefits) that covers eligible retirees. Costs of providing these benefits are based in part on the value of the plans' assets and, therefore, adverse investment performance for these assets could increase Idaho Power’s funding requirements related to the plans. The key actuarial assumptions that affect funding obligations are the expected long-term return on plan assets and the discount rate used in determining future benefit obligations. Idaho Power evaluates the actuarial assumptions on an annual basis, taking into account changes in market conditions, trends, and future expectations. Estimates of future equity and debt market performance, changes in interest rates, and other factors Idaho Power and its actuary firms use to develop the actuarial assumptions are uncertain, and actual results could vary significantly from the estimates. Changes in demographics, including increased numbers of retirements or changes in life expectancy assumptions, may also increase Idaho Power's funding requirements for the pension and other postretirement benefit plans. Future pension funding requirements, and the timing of funding payments, may also be subject to changes in legislation. Depending on the timing of contributions to the plans and the availability of recovery of costs through rates, cash contributions to the plans could reduce the cash available for operating activities. For additional information regarding Idaho Power's funding obligations under its benefit plans, see Note 11 - "Benefit Plans" to the consolidated financial statements included in this report. Idaho Power’s business is subject to substantial governmental regulation, including environmental laws and mandatory reliability standards, which could increase costs. Idaho Power is subject to an extensive body of federal and state laws, policies, and regulations, as well as regulatory actions and regulatory audits, including those of the Federal Energy Regulatory Commission, the Environmental Protection Agency, the North American Electric Reliability Corporation, the Western Electricity Coordinating Council, and the public utility commissions in Idaho, Oregon, and Wyoming. Some of these regulations are changing or subject to interpretation, and failure to comply may result in penalties or other adverse consequences.
As an owner and operator of a bulk power transmission system, Idaho Power is subject to mandatory reliability standards issued by the North American Electric Reliability Corporation and enforced by the Federal Energy Regulatory Commission. The standards are based on the functions that need to be performed to ensure the bulk power system operates reliably and are guided by reliability and market interface principles. Compliance with reliability standards subjects Idaho Power to higher operating costs and increased capital expenditures. Further, Idaho Power has received notice of violations from, and self-reported reliability standard compliance issues to, the Federal Energy Regulatory Commission, the North American Electric Reliability Corporation, and the Western Electricity Coordinating Council, and has several matters pending. Potential monetary and non-monetary penalties for a violation of Federal Energy Regulatory Commission regulations may be substantial, and in some circumstances monetary penalties may be as high as $1 million per day per violation. The imposition of penalties on Idaho Power could have an adverse impact on its and IDACORP’s results of operations, financial condition, and cash flows.
Idaho Power is also subject to extensive federal, state, and local environmental statutes, rules, and regulations relating to air quality, water quality, natural resources, and health and safety. Compliance with these environmental statutes, rules, and regulations involves significant capital and operating expenditures and carries with it the risk of penalties and fines. These laws and regulations generally require Idaho Power to obtain and comply with a wide variety of environmental licenses, permits, inspections, and other approvals, and may be enforced by both public officials and private individuals. Idaho Power cannot predict the outcome or effect of any action or litigation that may arise from applicable environmental regulations. In addition, Idaho Power cannot predict with certainty the amount or timing of future expenditures related to environmental matters because of the difficulty of estimating clean up costs or mitigation measures. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on all potentially responsible parties. Environmental regulations may also require Idaho Power to install pollution control equipment at, or perform environmental remediation on, its or its co-owned facilities, often at a substantial cost.
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Emissions of nitrogen and sulfur oxides, mercury, and particulates from fossil fueled generating plants are potentially subject to increased regulations, controls, and mitigation expenses. Certain federal legislators, environmental advocacy groups, and regulatory agencies in the United States have also been focusing considerable attention on CO2 and other emissions from power generation facilities and their potential role in climate change and/or regional air quality compliance. Existing environmental regulations regarding air emissions (such as NOx, SO2, or mercury emissions), water quality, and other toxic pollutants may be revised or new climate change laws or regulations may be adopted or become applicable to Idaho Power. Moreover, there are many legislative and rulemaking initiatives pending at the federal and state level that are aimed at the reduction of fossil fuel plant emissions. Idaho Power cannot predict the outcome of pending or future legislative and rulemaking proposals. Future changes in environmental laws or regulations governing emissions reduction could make certain electric generating units (especially coal-fired units) uneconomical and subject to shut-down, could require the adoption of new methodologies or technologies that significantly increase costs or delay in-service dates, and may raise uncertainty about the future viability of fossil fuels as an energy source for new and existing electric generation facilities. Modification of existing environmental regulations or adoption of new environmental regulations may result in increased capital expenditures and could increase the cost of operating Idaho Power's generating plants or make them uneconomical to operate and result in reduced earnings and cash flows.
Furthermore, Idaho Power may not be able to obtain or maintain all environmental regulatory approvals necessary for operation of its facilities and execution of its long-term strategy, including construction of new transmission and distribution infrastructure. If there is a delay in obtaining any required environmental regulatory approval or if Idaho Power fails to obtain, maintain, or comply with any such approval, construction and/or operation of Idaho Power's owned or co-owned generation and/or transmission facilities could be delayed, halted, or subjected to additional costs. Complying with state or federal renewable portfolio standards could increase capital expenditures and operating costs and reduce earnings and cash flows. A number of states have adopted renewable portfolio standards, which require that electricity providers obtain a minimum percentage of their power from renewable energy sources by a specified date. Idaho Power’s operations in Oregon will be required to comply with a ten percent renewable portfolio standard beginning in 2025, and it is possible that other states, including Idaho, could adopt renewable portfolio standards that are applicable to Idaho Power in the future. The cost of purchasing or generating power from renewable energy sources is often greater than fossil fuel and hydroelectric generation sources, and construction of renewable energy facilities involves significant capital expenditures. As a result, new state or federal renewable portfolio standards could increase capital expenditures and operating costs and reduce earnings and cash flows. The listing as threatened or endangered under the Endangered Species Act of fish, wildlife, or plant species that are found in the areas of Idaho Power’s generation facilities or transmission lines may require mitigation, affect the location of a project or the ability to construct a project, and increase capital expenditures and operating costs. Relicensing of the Hells Canyon and Swan Falls hydroelectric projects and construction of the Gateway West and Boardman-to-Hemingway transmission lines requires consultation under the Endangered Species Act to determine the effects of these projects on any listed species within the project areas. The listing of species as threatened or endangered, including the relatively recent listing of slickspot peppergrass as a threatened species, will result in an Endangered Species Act consultation for the Gateway West and Boardman-to-Hemingway transmission lines and future transmission projects. Similarly, the presence of sage grouse in the vicinity of the Gateway West and Boardman-to-Hemingway transmission projects has required more extensive, costly, and time consuming evaluation and engineering. These and other requirements of the Endangered Species Act and similar laws may increase costs and reduce earnings and cash flows. Conditions imposed in connection with hydroelectric license renewals may require large capital expenditures, increase operating costs, reduce hydroelectric generation, and reduce earnings and cash flows. Idaho Power is currently involved in renewing federal licenses for some of its hydroelectric projects, including its largest hydroelectric generation source, the Hells Canyon Complex. Relicensing includes an extensive public review process that involves numerous natural resource issues and environmental conditions. The listing of various species of marine life, wildlife, and plants as threatened or endangered has resulted in significant changes to federally-authorized activities, including those of hydroelectric projects. In particular, fish and other marine life recovery plans may require major operational changes to the region’s hydroelectric projects. In addition, new interpretations of existing laws and regulations could be adopted or become applicable to hydroelectric facilities, which could further increase required expenditures for marine life recovery and endangered species protection and reduce the amount of hydroelectric generation available to meet Idaho Power’s energy requirements. In 2007, the Federal Energy Regulatory Commission Staff issued a final environmental impact statement for the Hells Canyon Complex, which the Federal Energy Regulatory Commission will use in part to determine whether, and under what conditions, to issue a new license for the Hells Canyon Complex. Certain portions of the final environmental impact statement involve
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issues that may be influenced by water quality certifications for the project under Section 401 of the Clean Water Act and formal consultations under the Endangered Species Act, which remain unresolved. One significant issue involves water temperature gradients, and certain parties in the Hells Canyon Complex relicensing proceedings have advocated for the installation of water temperature management apparatus which, if required to be installed, would require substantial capital expenditures to construct and maintain. There can be no assurance that recovery through rates would be authorized, particularly given the magnitude of any potential impact on customer rates, which at this time cannot be predicted with certainty. Idaho Power also cannot predict the requirements that might be imposed during the relicensing process, the economic impact of those requirements, or whether a new multi-year license will ultimately be issued. Imposition of onerous conditions in the relicensing process could result in Idaho Power incurring significant capital expenditures, increase operating costs, and reduce hydroelectric generation, which could reduce earnings and cash flows. IDACORP, Idaho Power, and their subsidiaries are subject to costs and other effects of legal and regulatory proceedings, settlements, investigations, and claims. From time to time in the normal course of business, IDACORP, Idaho Power, and their subsidiaries are subject to various regulatory proceedings, lawsuits, and claims that could result in adverse judgments, settlements, fines, penalties, injunctions, or other relief. These matters are subject to a number of uncertainties, and as a result management is often unable to predict the outcome of a matter. The final resolution of matters in which IDACORP, Idaho Power, or their subsidiaries are involved could require that they incur costs in a range of amounts that could have an adverse effect on their cash flows and results of operations. Similarly, the terms of resolution could require the companies to change their business practices and procedures, which could also have an adverse effect on their cash flows, financial positions, or results of operations.
IDACORP, IDACORP Energy, and Idaho Power are involved in a number of proceedings, including proceedings arising from the California energy crisis and the energy shortages, high prices, and blackouts in the western United States during 2000 and 2001, and a refund proceeding affecting sellers of wholesale power in the spot market in the Pacific Northwest. Idaho Power may also be subject to costs and other effects of additional legal claims, actions, and complaints, including those related to the Jim Bridger, Valmy, and Boardman coal-fired plants, in which Idaho Power holds an ownership interest. For instance, in September 2010 the Environmental Protection Agency issued a Notice of Violation to Portland General Electric Company, the majority owner of the Boardman plant, alleging violations of the New Source Performance Standards and operating permit requirements under the Clean Air Act as a result of prior modifications made to the plant. Private parties have also brought tort actions against companies relating to their alleged contribution to climate change, including claims relating to the Jim Bridger and Boardman power plants. If IDACORP, Idaho Power, or their subsidiaries are required to make payments in connection with any legal or regulatory proceeding, settlement, investigation, or claim, earnings and cash flows could be negatively affected. As a holding company, IDACORP does not have its own operating income and must rely on the upstream cash flows from its subsidiaries to pay dividends and make debt payments. IDACORP is a holding company with no significant operations of its own, and its primary assets are shares or other ownership interests of its subsidiaries, primarily Idaho Power. Consequently, IDACORP’s ability to pay dividends and to service its debt is dependent upon dividends and other payments received from its subsidiaries. IDACORP’s subsidiaries are separate and distinct legal entities and have no obligation to pay any amounts to IDACORP, whether through dividends, loans, or other payments. The ability of IDACORP’s subsidiaries to pay dividends or make distributions to IDACORP depends on several factors, including each subsidiaries’ actual and projected earnings and cash flow, capital requirements and general financial condition, regulatory restrictions, covenants contained in credit facilities to which they are parties, and the prior rights of holders of their existing and future first mortgage bonds and other debt or equity securities. Further, the amount and payment of dividends is at the discretion of the board of directors, which reviews the appropriateness of dividends in light of current and long-term financial position and results of operations, capital requirements, rating agency requirements, contractual and regulatory restrictions, legislative and regulatory developments affecting the electric utility industry in general and Idaho Power in particular, competitive conditions, and any other factors the board of directors deems relevant. Any of these factors may result in a reduction or cessation of dividends. See Part II, Item 5 - "Market for Registrant's Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities" of this report for a description of restrictions on IDACORP's and Idaho Power's payment of dividends. A downgrade in IDACORP’s and Idaho Power’s credit ratings could affect the companies’ ability to access capital, increase their cost of borrowing, and require the companies to post collateral with transaction counterparties. Access to capital markets is important to Idaho Power's ability to operate and to complete its capital projects, including its current and planned generation and transmission projects. Credit rating agencies periodically review the corporate credit ratings and long-term ratings of IDACORP and Idaho Power, and these ratings impact access to, and the cost of, borrowing. IDACORP and Idaho Power also have borrowing arrangements that rely on the ability of the banks to fund loans or support commercial paper, a principal source of short-term financing. Downgrades of IDACORP’s or Idaho Power’s credit ratings, or those affecting
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relationship banks, could limit the companies’ ability to access capital, including the commercial paper markets, require the companies to pay a higher interest rate on their debt, and require the companies to post additional performance assurance collateral with transaction counterparties. Volatility in the financial markets, or denial of regulatory authority to issue debt or equity securities, may negatively affect IDACORP’s and Idaho Power’s ability to access capital and/or increase their cost of borrowing, or result in losses on investments. IDACORP and Idaho Power require liquidity to pay operating expenses and principal of, and interest on, debt and to finance capital expenditures not satisfied by cash flows from operations. Financial markets have in recent years experienced extreme volatility and disruption, generally resulting in a decrease in the availability of liquidity and credit for borrowers. In a volatile credit environment, one or more of the participating banks in IDACORP’s and Idaho Power’s credit facilities may default on their obligations to make loans under, or withdraw from, the credit facilities, or IDACORP’s and Idaho Power’s access to capital may otherwise be inhibited. In addition, at times Idaho Power has a relatively large balance of short-term investments. Volatility in the financial markets may result in a lack of liquidity for short-term investments and declines in value of some investments. The occurrence of any of these events could affect Idaho Power's ability to execute its business plan and adversely affect IDACORP’s and Idaho Power’s earnings, liquidity, and financial condition. Further, Idaho Power is required to obtain regulatory approval in Idaho, Oregon, and Wyoming in order to borrow money or to issue securities and is therefore dependent on the public utility commissions of those states to issue favorable orders in a timely manner to permit them to finance their operations. Notably, without additional approval from those commissions, the aggregate amount of short-term borrowings by Idaho Power at any one time outstanding may not exceed $450 million. National and regional economic conditions, in conjunction with increased electric rates, may cause increased late payments and uncollectible customer accounts, or reduce energy consumption, which would reduce earnings and cash flows. Beginning in 2008, economic conditions in Idaho Power’s service area have been relatively weak. Unemployment rates are high relative to historic unemployment levels and customer growth has been slow relative to prior years. These factors may reduce the amount of energy Idaho Power’s customers consume; result in a loss of customers; increase the likelihood and prevalence of late payments and uncollectible accounts, and reduce the customer growth rate. A resulting decrease in overall customer usage or collections may reduce revenues and earnings. Changes in tax laws and regulations, or differing interpretation or enforcement of applicable laws by the Internal Revenue Service or other taxing jurisdictions, could have a material adverse impact on IDACORP’s or Idaho Power’s financial condition. IDACORP and Idaho Power must make judgments and interpretations about the application of the law when determining the provision for taxes. The companies’ tax obligations include income, real estate, public utility, municipal, sales and use, business and occupation, and employment-related taxes and ongoing issues related to these taxes. These judgments may include reserves for potential adverse outcomes regarding tax positions that may be subject to challenge by taxing authorities. For instance, recent income tax method changes had a significant impact on financial results in 2011. The outcome of ongoing and future income tax proceedings could differ materially from the amounts IDACORP and Idaho Power record prior to conclusion of those proceedings, and the difference could reduce IDACORP’s and Idaho Power’s earnings and cash flows. Further, in some instances the treatment from a ratemaking perspective of any tax benefits could be different than IDACORP or Idaho Power anticipate or request from applicable state regulatory commissions. The Idaho Public Utilities Commission or Oregon Public Utility Commission could, for instance, determine that all or a portion of any benefits resulting from tax-related projects be shared with customers in the form of reduced rates or otherwise, which may reduce revenue, earnings, and cash flows. Employee workforce factors could increase costs and reduce earnings. Idaho Power is subject to workforce factors, including loss or retirement of key personnel, availability of qualified personnel, an aging workforce, and impacts of efforts to organize workforce, including the possible unionization of one or more segments of the workforce. Idaho Power’s operations require a skilled workforce to perform specialized, complex utility functions. Idaho Power expects that a significant portion of its skilled workforce will be retiring, at a rate higher than Idaho Power's historical rate, within the next ten years, which places demand on Idaho Power to attract and retain skilled workers. Without a skilled workforce, Idaho Power’s ability to provide quality service to its customers and meet regulatory requirements will be challenged and could affect earnings. Also, the costs associated with attracting and retaining appropriately qualified employees to replace an aging and skilled workforce could reduce earnings and cash flows. Acts or threats of terrorism, cyber attacks, security breaches, and other acts of individuals or groups seeking to disrupt Idaho Power's operations, or the businesses of third parties, could result in reduced revenues and increased costs. Idaho Power's generation and transmission facilities are potential targets for terrorist acts and threats, as well as cyber attacks and other disruptive activities of individuals or groups. Some of Idaho Power's facilities are deemed critical infrastructure, in that incapacity or destruction of the facilities could have a debilitating impact on security, reliability or operability of the bulk
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electric power system, national economic security, national public health or safety, or any combination of those matters. The possibility that infrastructure facilities, such as generation facilities and electric transmission facilities, would be direct targets of, or indirect casualties of, an act of terror or cyber attack (whether originating internally or externally) may affect Idaho Power's operations by limiting the ability to generate, purchase, or transmit power and by delaying the development and construction of new generating and transmission facilities and capital improvements to existing facilities. These events, and governmental actions in response, could result in a material decrease in revenues and significant additional costs to repair and insure Idaho Power's assets, and could further adversely affect Idaho Power's operations by contributing to disruption of supplies and markets for natural gas or coal used to fuel gas-fired or coal-fired power plants. Because generation and transmission are part of an interconnected system, Idaho Power faces the risk of possible loss of business due to a disruption caused by the impact of an event on the interconnected system. The events could also impair IDACORP's and Idaho Power's ability to raise capital by contributing to financial instability and lower economic activity. Further, the implementation of security guidelines and measures has resulted in and is expected to continue to result in increased compliance costs.
In the normal course of business, Idaho Power collects, processes, and retains sensitive and confidential customer and proprietary information, and operates systems that directly impact the availability of electric power and the transmission of electric power in the electric grid. Idaho Power operates in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure. Despite the security measures in place, Idaho Power's facilities and systems, and those of third-party service providers, could be vulnerable to security breaches, data leakage, or other similar events that could interrupt operations, resulting in a shutdown of service and exposing Idaho Power to liability. Those breaches and events may result from acts of Idaho Power employees, contractors, or third parties. If Idaho Power's technology systems were to fail or be breached and Idaho Power were unable to recover the systems and/or data in a timely manner, Idaho Power may be unable to fulfill critical business functions. Also, confidential and proprietary business, employee, or customer information could be compromised, exposing Idaho Power to liability and causing business disruptions, which could have a material adverse effect on Idaho Power's operations and IDACORP's and Idaho Power's financial results. The implementation of security guidelines and measures and maintenance of insurance, to the extent available, addressing such activities could increase costs and impact financial results. In addition, these types of events could require significant management attention and resources, and could adversely affect IDACORP's and Idaho Power's reputation among customers and the public.
ITEM 1B. UNRESOLVED STAFF COMMENTS None.
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ITEM 2. PROPERTIES Idaho Power’s system is comprised of 17 hydroelectric generating plants located in southern Idaho and eastern Oregon, two natural gas-fired plants located in southern Idaho, and interests in three coal-fired steam electric generating plants located in Wyoming, Nevada, and Oregon. Idaho Power is also constructing a natural gas-fired combined cycle power plant in Idaho with a summer nameplate capacity of 300 MW, expected to be ready for commercial operation by July 1, 2012. As of December 31, 2011, the system also includes approximately 4,828 pole miles of high-voltage transmission lines, 23 step-up transmission substations located at power plants, 24 transmission substations, 10 switching stations, 228 energized distribution substations (excluding mobile substations and dispatch centers), and approximately 26,714 pole miles of distribution lines. Idaho Power holds FERC licenses for all of its hydroelectric projects that are subject to federal licensing. These projects and the other generating stations and their nameplate capacities are listed below.
(1) Licensed on an annual basis while the application for a new multi-year license is pending.(2) Idaho Power’s ownership interests are 33 percent for Jim Bridger, 50 percent for Valmy, and 10 percent for Boardman. Amounts shown represent Idaho Power’s share.(3) Pursuant to an Oregon Environmental Quality Commission plan and associated rules, the Boardman power plant is scheduled for cessation of coal-fired operations on December 31, 2020.
NameplateCapacity (kW)
60,00075,00034,50012,50082,80021,770
1,166,90027,17092,34012,42059,44852,897
11,300
1,709,045
770,501283,50064,200
270,9005,000
172,8001,566,9013,275,946
LicenseExpiration
203420342034203420342035200520102025203120382040
(1)
(1)
Relicensing of Idaho Power’s hydroelectric projects is discussed in Part II, Item 7 - “MD&A – Regulatory Matters – Relicensing of Hydroelectric Projects.” Idaho Power owns all of its interests in principal plants and other important units of real property, except for portions of certain projects licensed under the FPA and reservoirs and other easements. Idaho Power’s property is also subject to the lien of its Mortgage and Deed of Trust and the provisions of its project licenses. In addition, Idaho Power’s property is subject to minor
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defects common to properties of such size and character that do not materially impair the value to, or the use by, Idaho Power of such properties. Idaho Power considers its properties to be well-maintained and in good operating condition. IERCo owns a one-third interest in BCC and coal leases near the Jim Bridger generating plant in Wyoming from which coal is mined and supplied to the plant. Ida-West holds 50 percent interests in nine operating hydroelectric plants with a total generating capacity of 45 MW. These plants are located in Idaho and California.
ITEM 3. LEGAL PROCEEDINGS Refer to Note 10 – “Contingencies” to IDACORP’s and Idaho Power’s consolidated financial statements included in this report.
ITEM 4. MINE SAFETY DISCLOSURES
Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is included in Exhibit 95.1 of this report.
PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES
IDACORP’s common stock, without par value, is traded on the New York Stock Exchange (NYSE). On February 17, 2012, there were 12,508 holders of record of IDACORP common stock and the closing stock price was $41.85 per share. The outstanding shares of Idaho Power’s common stock, $2.50 par value, are held by IDACORP and are not traded. IDACORP became the holding company of Idaho Power on October 1, 1998. The amount and timing of dividends paid on IDACORP’s common stock are within the sole discretion of IDACORP’s board of directors. The board of directors reviews the dividend rate quarterly to determine its appropriateness in light of IDACORP’s current and long-term financial position and results of operations, capital requirements, rating agency requirements, contractual and regulatory restrictions, legislative and regulatory developments affecting the electric utility industry in general and Idaho Power in particular, competitive conditions, and any other factors the board of directors deems relevant. The ability of IDACORP to pay dividends on its common stock is dependent upon dividends paid to it by its subsidiaries, primarily Idaho Power. At its November 2011 meeting, the IDACORP board of directors adopted a dividend policy for IDACORP that provides for a target long-term dividend payout ratio of between 50 and 60 percent of sustainable IDACORP earnings, with the flexibility to achieve that payout ratio over time and to adjust the payout ratio or to deviate from the target payout ratio from time to time based on the various factors that drive the board of director's dividend decisions. Notwithstanding the dividend policy adopted by the IDACORP board of directors, the dividends IDACORP pays remain in the discretion of the board of directors who, when evaluating the dividend amount, will take into account the foregoing factors, among others. A covenant under IDACORP’s credit facility and Idaho Power’s credit facility described in Part II, Item 7 - “MD&A – Liquidity and Capital Resources - Financing Programs – Credit Facilities” requires IDACORP and Idaho Power to maintain leverage ratios of consolidated indebtedness to consolidated total capitalization, as defined in the respective credit facilities, of no more than 65 percent at the end of each fiscal quarter. 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 ability to pay dividends on its common stock held by IDACORP and IDACORP’s ability to pay dividends on its common stock are limited to the extent payment of such dividends would violate the covenants or Idaho Power’s Code of Conduct. At December 31, 2011, the leverage ratios for IDACORP and Idaho Power were 48 percent and 49 percent, respectively. Based on these restrictions, IDACORP’s and Idaho Power’s dividends were limited to $827 million and $723 million, respectively, at December 31, 2011. Idaho Power must obtain approval of the OPUC before it can directly or indirectly loan funds or issue notes or give credit on its books to IDACORP. Idaho Power’s articles of incorporation 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. IDACORP and Idaho Power paid dividends of $60 million, $58 million, and $57 million in 2011, 2010, and 2009, respectively.
On January 19, 2012, IDACORP's board of directors voted to increase the quarterly dividend payable February 29, 2012 to
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$0.33 per share of IDACORP common stock, from the prior dividend amount of $0.30 per share of IDACORP common stock. For additional information relating to IDACORP and Idaho Power dividends, including restrictions on IDACORP's and Idaho Power's payment of dividends, see Note 6 - “Common Stock” to the consolidated financial statements included in this report. The following table shows the reported high and low sales price of IDACORP’s common stock and dividends paid for 2011 and 2010 as reported by the NYSE.
Quarter1st2nd3rd4th
2011
High$ 38.72
40.3840.7142.66
Low$ 36.14
37.6533.8837.26
Dividends paidper share
$ 0.300.300.300.30
2010
High$ 35.69
36.9336.9837.76
Low$ 29.98
31.2232.4635.46
Dividends paidper share
$ 0.300.300.300.30
IDACORP, Inc. did not repurchase any shares of its common stock during the fourth quarter of 2011. Performance Graph The following performance graph shows a comparison of the five-year cumulative total shareholder return for IDACORP common stock, the S&P 500 Index, and the Edison Electric Institute (EEI) Electric Utilities Index. The data assumes that $100 was invested on December 31, 2006, with beginning-of-period weighting of the peer group indices (based on market capitalization) and monthly compounding of returns.
Source: Bloomberg and EEI
IDACORPS&P 500EEI Electric Utilities Index
2006$ 100.00
100.00100.00
2007$ 94.40
105.49116.56
2008$ 82.12
66.4786.37
2009$ 93.25
84.0695.62
2010$ 111.75
96.75102.34
2011$ 132.15
98.77122.80
The foregoing performance graph and data shall not be deemed “filed” as part of this Form 10-K for purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section and should not be deemed incorporated by reference into any other filing of IDACORP or Idaho Power under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent IDACORP or Idaho Power specifically incorporates it by reference into such filing.
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ITEM 6. SELECTED FINANCIAL DATA
IDACORP, Inc.SUMMARY OF OPERATIONS(thousands of dollars, except per share amounts) Operating revenuesOperating incomeNet income attributable to IDACORP, Inc.Diluted earnings per share from
continuing operationsDividends declared per share
Financial Condition:Total assetsLong-term debt (including current portion)
The financial statistics listed above are calculated in the following manner:(1) The sum of interest on long-term debt, other interest expense excluding AFUDC credits, and income before income taxes divided by the sum of interest on long-term debt and other interest expense excluding AFUDC credits.(2) The sum of interest on long-term debt, other interest expense excluding AFUDC credits, and income from continuing operations divided by the sum of interest on long-term debt and other interest expense excluding AFUDC credits.(3) Total equity, excluding non-controlling interests, at the end of the year divided by shares outstanding at the end of the year.(4) The closing price of IDACORP stock on the last day of the year divided by the book value per share, which is described in footnote (3) above.(5) Dividends paid per common share divided by diluted earnings per share.(6) Net income attributable to IDACORP, Inc. divided by total equity, excluding non-controlling interests, at the end of the year.
2011$1,026,756
164,248166,693
3.361.20
$4,960,6091,488,614
2.352.97
$ 33.18128%36%
10.1%
2010$1,036,029
198,670142,798
2.951.20
$4,676,055
1,610,859
2.652.66
$ 31.01119%41%9.3%
2009$1,049,800
203,583124,350
2.641.20
$4,238,727
1,419,070
2.882.59
$ 29.17110%45%8.9%
2008$ 960,414
190,66798,414
2.171.20
$4,022,845
1,269,979
2.472.23
$ 27.76106%55%7.6%
2007$ 879,394
152,07882,272
1.861.20
$3,653,308
1,168,336
2.352.16
$ 26.79131%65%6.8%
Beginning January 1, 2009, noncontrolling interests (previously known as minority interests) were required to be classified as equity. IDACORP’s consolidated financial statements reflect the reclassification of noncontrolling interests to equity for all periods presented.
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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FORWARD-LOOKING STATEMENTS In addition to the historical information contained in this report, this report contains (and oral communications made by IDACORP, Inc. and Idaho Power Company may contain) statements that relate to future events and expectations and, as such, constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Any statements that express, or involve discussions as to, expectations, beliefs, plans, objectives, assumptions, or future events or performance, often, but not always, through the use of words or phrases such as "anticipates," "believes," "estimates," "expects," "intends," "plans," "predicts," "projects," "may result," "may continue," or similar expressions, are not statements of historical facts and may be forward-looking. Forward-looking statements are not guarantees of future performance and involve estimates, assumptions, risks, and uncertainties. Actual results, performance, or outcomes may differ materially from the results discussed in the statements. In addition to any assumptions and other factors and matters referred to specifically in connection with such forward-looking statements, factors that could cause actual results or outcomes to differ materially from those contained in forward-looking statements include those factors set forth in Item 1A - "Risk Factors" of this report and the following important factors:
• the effect of regulatory decisions by the Idaho Public Utilities Commission, the Oregon Public Utility Commission, the Federal Energy Regulatory Commission, and other regulators affecting Idaho Power's ability to recover costs and/or earn a reasonable rate of return;
• variable hydrological conditions and over-appropriation of surface and groundwater in the Snake River basin, which can impact stream flows and the amount of generation from Idaho Power's hydroelectric facilities;
• the cost and availability of materials, fuel, and commodities, and their impact on Idaho Power's infrastructure costs, power costs, and ability to meet required loads, and their impact on the wholesale energy market in the western United States;
• costs and delays associated with construction and maintenance of power generation, transmission, and distribution facilities, including the inability to obtain required governmental permits and approvals, hydroelectric plant licenses under reasonable terms (and the costs resulting from conditions in such licenses), rights-of-way, and siting, and risks related to contracting, construction, and start-up;
• disruptions or outages of Idaho Power's generation or transmission systems or the western interconnected transmission system affecting Idaho Power's ability to deliver power to its customers and requiring the dispatch of more expensive generation resources or purchasing power, which may ultimately increase costs;
• increased costs associated with the legislatively mandated purchase of intermittent power, such as wind, at above-market rates, and the costs and other challenges of integrating intermittent power sources into Idaho Power's resource portfolio;
• population growth and changes in residential, commercial, and industrial growth and demographic patterns within Idaho Power's service area, the loss or change in the business of significant customers, and the associated impact on loads and load growth;
• the continuing effects of the weak economy in Idaho Power's service territory and elsewhere, including decreased demand for electricity, reducing revenue from sales of excess energy during periods of low wholesale market prices, impaired financial soundness of vendors and service providers, and elevated levels of uncollectible customer accounts;
• changes in and costs of compliance with laws, regulations, and policies relating to the environment, natural resources, and endangered species and the adoption of laws and regulations addressing greenhouse gas emissions, global climate change, and energy policies intended to mitigate carbon dioxide, mercury, and other emissions;
• global climate change and regional or national weather variations, which affect customer demand and hydroelectric generation and can impact the ability and cost to procure adequate supplies of natural gas, coal, or purchased power to serve customers;
• inclement weather and other natural phenomena such as earthquakes, floods, droughts, lightning, wind, and fire, which, in addition to affecting customer demand for power, could significantly affect the ability and cost to procure adequate supplies of fuel or power to serve customers, and could increase the costs to repair and maintain Idaho Power's generating facilities, transmission and distribution systems, and other infrastructure;
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• transaction risks, including increases in costs, associated with Idaho Power's energy commodity and other derivative instruments, the failure of Idaho Power's energy risk management policies to work as intended, exposure to counterparty credit risk, and potential higher costs of hedging activities due to new regulations pertaining to swaps and derivatives;
• wholesale market conditions, including availability of power on the spot market and the ability to enter into commodity financial hedges with creditworthy counterparties, and the cost of those hedges, which may affect the prices Idaho Power must pay for power as well as the prices at which Idaho Power can sell any excess power;
• deteriorating values in the equity markets, changes in interest rates and credit spreads, reductions in demand for investment-grade commercial paper, inflation, and other financial market conditions, as well as changes in government regulations, which affect, among other things, the cost of capital and the ability to access the capital markets, indebtedness obligations, and the amount and timing of required contributions to benefit plans;
• failure of Idaho Power to comply with state and federal laws, policies, and regulations, including new interpretations and enforcement initiatives by regulatory and oversight bodies, including, but not limited to, the Federal Energy Regulatory Commission, the North American Electric Reliability Corporation, the Western Electricity Coordinating Council, the U.S. Environmental Protection Agency, and Idaho and Oregon state regulatory commissions, which may result in penalties, increase the cost of compliance, the nature and extent of investigations and audits, and costs of remediation;
• the cost and outcome of litigation, dispute resolution, and regulatory proceedings, and penalties, settlements, or awards that influence the companies' business and operations;
• reductions in credit ratings, which could adversely impact access to capital markets and would require the posting of additional collateral to counterparties pursuant to existing power purchase and credit arrangements;
• the ability to obtain debt and equity financing or refinance existing debt when necessary or on favorable terms, which can be affected by factors such as credit ratings, volatility in the financial markets, the companies' financial performance, and other economic conditions;
• whether the companies will be able to continue to pay dividends under the terms of their respective financing and credit agreements and regulatory limitations, and whether the companies' boards of directors will continue to declare common stock dividends based on the boards of directors’ periodic consideration of factors ordinarily affecting dividend policy, such as current and prospective financial condition, earnings and liquidity, prospective business conditions, regulatory factors, and restrictions in applicable agreements;
• changes in tax laws or related regulations or new interpretations of applicable law by the Internal Revenue Service or state and local taxing jurisdictions, and the availability and use by IDACORP or Idaho Power of tax credits;
• employee workforce factors, including unionization or the attempt to unionize all or part of the companies' workforce, and the ability to adjust the labor cost structure to changes in growth within Idaho Power's service territory;
• the failure of information systems or the failure to secure information system data, security breaches, or the direct or indirect effect on the companies' business resulting from the occurrence of cyber attacks, terrorist incidents or the threat of terrorist incidents, and acts of war;
• adoption of or changes in accounting policies, principles, or estimates, including the potential adoption of all or a portion of International Financial Accounting Standards; and
• new accounting or Securities and Exchange Commission or New York Stock Exchange requirements, or new interpretations of existing requirements.
Any forward-looking statement speaks only as of the date on which such statement is made. New factors emerge from time to time and it is not possible for management to predict all such factors, nor can it assess the impact of any such factor on the business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement. IDACORP and Idaho Power disclaim any obligation to update publicly any forward-looking information, whether in response to new information, future events, or otherwise, except as required by applicable law.
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INTRODUCTION In Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A), the general financial condition and results of operations for IDACORP, Inc. and its subsidiaries (collectively, IDACORP) and Idaho Power Company and its subsidiary (collectively, Idaho Power) are discussed. While reading the MD&A, please refer to the accompanying consolidated financial statements of IDACORP and Idaho Power. IDACORP is a holding company formed in 1998 whose principal operating subsidiary is Idaho Power. IDACORP’s common stock is listed and trades on the New York Stock Exchange under the trading symbol “IDA.” Idaho Power is an electric utility with a service territory covering approximately 24,000 square miles in southern Idaho and eastern Oregon. Idaho Power provided electric service to approximately 496,000 general business customers as of December 31, 2011. As a regulated utility, many of Idaho Power's fundamental business decisions are subject to the approval of governmental agencies. Idaho Power is under the retail jurisdiction (as to rates, service, accounting, and other general matters of utility operation) of the Idaho Public Utilities Commission (IPUC) and the Oregon Public Utility Commission (OPUC), which determine the rates that Idaho Power charges to its general business customers. Also, as a public utility under the Federal Power Act, Idaho Power has authority to charge market-based rates for wholesale energy sales under its Federal Energy Regulatory Commission (FERC) tariff and to provide transmission services under its FERC open access transmission tariff (OATT). Idaho Power uses general rate cases, cost adjustment mechanisms, and subject-specific filings to recover its costs of providing service and the costs of its energy efficiency and demand-side resources programs, and to seek to earn a return on investment.
Idaho Power generates revenues and cash flows primarily from the sale and distribution of electricity to customers in its Idaho and Oregon service territories, as well as from the wholesale sale and transmission of electricity. Idaho Power’s revenues and income from operations are subject to fluctuations during the year due to the impacts of seasonal weather conditions on demand for electricity, availability of water for hydroelectric generation, price changes, customer usage patterns (which are affected in large part by the condition of the local economy), and the availability and price of purchased power and fuel. Idaho Power is a dual peaking utility that typically experiences its highest retail energy sales during the summer irrigation and cooling season, with a lower peak in the winter that generally results from heating demand. IDACORP’s and Idaho Power’s financial condition is also affected by regulatory decisions, through which Idaho Power seeks to recover its costs on a timely basis, and to earn an authorized return on investment, and by the ability to obtain financing through the issuance of debt and/or equity securities.
IDACORP’s other subsidiaries include IDACORP Financial Services, Inc. (IFS), an investor in affordable housing and other real estate investments; Ida-West Energy Company, an operator of small hydroelectric generation projects that satisfy the requirements of the Public Utility Regulatory Policies Act of 1978 (PURPA); and IDACORP Energy, a marketer of energy commodities, which wound down operations in 2003. Idaho Power is the parent of Idaho Energy Resources Co. (IERCo), 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. EXECUTIVE OVERVIEW Overview of 2011 Financial Results
IDACORP's earnings were $3.36 per diluted share for the year ended December 31, 2011 compared to $2.95 and $2.64 per diluted share in 2010 and 2009, respectively. IDACORP's earnings in 2011 were impacted by the approval of a tax method change that allowed Idaho Power to recognize during 2011 $56.9 million in tax benefits relating to tax years 2009 and prior. This tax benefit, combined with the results of ongoing operations, triggered sharing mechanisms in Idaho that reduced operating income by $47.4 million, reflecting earnings to be shared with Idaho customers to reduce rates. In addition, 2011 results include the full-year impact of base rate increases implemented in 2010, higher electricity sales volumes, and lower PCA rates. 2011 Accomplishments and 2012 Challenges and Areas of Emphasis
IDACORP’s business strategy emphasizes Idaho Power as IDACORP’s core business. Idaho Power has a three-part strategy of responsible planning, responsible development and protection of resources, and responsible energy use to ensure adequate energy supplies. This strategy is described in Part I, Item 1 - "Business" of this report. Examples of Idaho Power's achievements during 2011 under its three-part business strategy include:
• execution of Idaho Power's purposeful regulatory strategy, which resulted in settlement of Idaho Power's 2011 Idaho general rate case with the IPUC (including a base rate increase effective January 1, 2012), a June 1, 2011 base rate
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increase for recovery of the Idaho-allocated portion of Idaho Power's cash contributions to its defined benefit pension plan, and several other positive regulatory decisions;
• execution of a settlement agreement with the IPUC extending through 2014 Idaho Power's ability to amortize additional accumulated deferred investment tax credits (ADITC) to help achieve a minimum annual return on year-end equity in the Idaho jurisdiction (Idaho ROE) of 9.5 percent;
• significant progress toward cost-sharing agreements with other parties for the permitting of the Boardman-to-Hemingway and Gateway West 500-kV transmission projects, which were ultimately executed in January 2012;
• completion of deployment of smart meters to substantially all customers;• continued progress on the construction of the Langley Gulch power plant; • approval by the U.S. Congress Joint Committee on Taxation (Joint Committee) of a tax method change for uniform
capitalization, resulting in a significant increase in net income relative to 2010; and• ranking in the top quartile of the 120 largest utilities in the country for customer satisfaction in the J.D. Power and
Associates 2011 Electric Utility Residential Customer Satisfaction Study.
During 2012, IDACORP's and Idaho Power's management will continue to focus on and implement the companies' three-part strategy. Notable matters that the companies expect will require management's focus and attention in 2012 include:
• completion of construction and commencement of commercial operations of the Langley Gulch power plant, and timely and adequate rate recovery of costs for the plant;
• continued efforts toward permitting of the Boardman-to-Hemingway and Gateway West transmission projects;• seeking a positive outcome in proceedings at the IPUC relating to the pricing models and other terms of PURPA power
purchase agreements; • seeking methods for the integration of intermittent power sources and anticipated increases in intermittent wind
generation, which Idaho Power believes could have an adverse impact on system reliability and functionality and on customer rates;
• obtaining IPUC authorization to include Idaho Power's FCA as a permanent component of rates; • implementation of a new customer and billing system; and• continued work toward resolution of issues relating to relicensing of Idaho Power's hydroelectric projects, including
the Hells Canyon Complex.
Overview of General Factors and Trends Affecting Results of Operations and Financial Condition IDACORP's and Idaho Power's results of operations and financial condition are affected by regulatory, economic, and other factors, many of which are described below.
Emphasis on Regulatory Cost Recovery: The prices that Idaho Power is authorized to charge for its electric service is a major factor in determining IDACORP's and Idaho Power's results of operations and financial condition. Because of the significant impact of ratemaking decisions on Idaho Power's business and financial condition, the company continues to focus on timely recovery of its costs through filings with the company's regulators. Effective implementation of Idaho Power's purposeful regulatory strategy is particularly important in an economic climate that puts pressure on regulators to limit rate increases or otherwise take actions to limit the potential adverse impact of rates on customers. Regulatory developments that IDACORP and Idaho Power expect to have an impact on their future results, each of which is discussed in more detail under "Regulatory Matters" in this MD&A or in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report, include the following:
• Idaho 2011 General Rate Case and Settlement - On December 30, 2011, the IPUC approved a settlement stipulation resolving most of the issues in the general rate case. The settlement stipulation provides for a 7.86 percent authorized rate of return on an Idaho-jurisdictional rate base of approximately $2.36 billion. The settlement stipulation results in a $34 million, or 4.07 percent average, increase in Idaho Power's annual Idaho-jurisdictional base rate revenues, effective January 1, 2012.
• Extension of Certain Provisions of the January 2010 Settlement Agreement - On January 13, 2010, the IPUC approved a settlement agreement among Idaho Power, several of Idaho Power’s customers, the IPUC Staff, and others, in connection with a general rate case. The settlement agreement included, among other items: (a) a provision to share with Idaho customers 50 percent of any Idaho-jurisdiction earnings in excess of a 10.5 percent Idaho ROE in any calendar year from 2009 to 2011; and (b) a provision to allow the additional amortization of ADITC if Idaho Power's actual Idaho ROE was below 9.5 percent in any calendar year from 2009 to 2011. The sharing and amortization provisions of the January 2010 settlement agreement expired on December 31, 2011. On December 27, 2011, the
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IPUC issued an order approving a settlement stipulation providing for an extension through 2014, with modifications, of those two provisions of the January 2010 settlement agreement. The extension provides for up to $45 million of additional amortization of ADITC through 2014, with certain annual limits, and additional sharing of annual earnings in excess of specified Idaho ROEs. In consideration for the extension, the settlement stipulation provided that Idaho Power would allocate to customers (as a reduction to Idaho Power's pension regulatory asset) 75 percent of Idaho Power's share of 2011 Idaho-jurisdictional earnings over a 10.5 percent Idaho ROE. After the combined effect of the 50 percent sharing mechanism in the January 2010 settlement agreement and the December 2011 settlement order that provided for additional sharing, Idaho Power retained 12.5 percent of Idaho-jurisdiction earnings exceeding a 10.5 percent Idaho ROE.
• Idaho PCA Orders - In both its Idaho and Oregon jurisdictions, Idaho Power has power cost adjustment (PCA) mechanisms that address the volatility of power supply costs and provide for annual adjustments to the rates charged to retail customers. The Idaho PCA mechanism compares Idaho Power's actual net power supply costs to net power supply costs currently being recovered in retail rates, with most of the variance between these two amounts deferred for future recovery from, or refund to, customers. On May 31, 2011, the IPUC approved a $40.4 million PCA decrease, effective June 1, 2011. This followed a May 28, 2010 IPUC order approving a $146.9 million PCA decrease, effective June 1, 2010. These PCA rate decreases were offset by increases in power supply costs in base rates and deferrals and amortization under the PCA mechanism, resulting in a relatively small impact on earnings.
• Idaho FCA Mechanism - 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. The FCA began as a pilot program in 2007 and expired on December 31, 2011. On October 19, 2011, Idaho Power filed an application with the IPUC requesting that the FCA pilot program become permanent. As of the date of this report, a determination and order from the IPUC as to the future of the FCA is pending.
• Oregon 2011 General Rate Case - On July 29, 2011, Idaho Power filed a general rate case for its Oregon jurisdiction with the OPUC, requesting a $5.8 million increase in annual Oregon jurisdictional revenues. On February 1, 2012, Idaho Power, the OPUC Staff, and other interested parties executed and filed a partial settlement stipulation with the OPUC that provides for a return on equity of 9.9 percent and an overall rate of return of 7.757 percent. If the OPUC approves the stipulation, Idaho Power expects that new rates will become effective on March 1, 2012.
Economic Conditions and Customer Growth: Since 2008, economic conditions in Idaho Power's service territory have been relatively weak. Unemployment rates remain high compared to historical levels. After peaking at 10.0 percent in early 2011, the service area unemployment rate has fallen to 8.4 percent in December 2011, according to the Idaho Department of Labor. From 2001 through September 2008, the highest monthly unemployment rate in the service territory was 5.2 percent. The customer growth rate, while still positive, has been low relative to prior years. During 2011, the customer growth rate in Idaho Power's service territory was 0.7 percent. By comparison, for the 20-year period ending 2010 the average annual customer growth rate in Idaho Power's service territory was 2.7 percent. Economic conditions can impact consumer demand for electricity, collectability of accounts, the volume of off-system sales, and Idaho Power's need for purchased power. Management cannot predict the timing of, and pace at which, economic recovery may occur in Idaho Power's service territory. Idaho Power continues to manage costs while executing its three-part strategy of responsible planning, responsible development and protection of resources, and responsible energy use. Weather Conditions and Associated Impacts: Weather conditions normally have a significant impact on energy sales and the seasonality of those sales. Relatively low and high temperatures result in greater energy usage for heating and cooling, respectively. During the agricultural growing season, which in large part occurs during the second and third quarters of each calendar year, irrigation customers use electricity to operate irrigation pumps. A 1.6 percent increase in energy usage by Idaho Power customers during 2011 compared to 2010 is largely attributable to below average temperatures in the winter months offset by above average precipitation in the springtime, resulting in increased heating unit load and lower use of irrigation pumps. Idaho Power's hydroelectric facilities comprise approximately one-half of Idaho Power's nameplate generation capacity. The actual availability of hydroelectric power depends on the amount of snow pack in the mountains upstream of Idaho Power's hydroelectric facilities, reservoir storage, springtime snow pack run-off, base flows in the Snake River, spring flows, rainfall, water leases and other water rights, and other weather and stream flow considerations. At the date of this report, Idaho Power expects hydroelectric generation during 2012 in the range of 7.5 to 9.5 million MWh, based on reservoir storage levels and forecasted weather conditions as of February 12, 2012, compared to 10.9 million MWh in 2011 and 7.3 million MWh in 2010.
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Median annual hydroelectric generation is 8.6 million MWh. Due largely to favorable hydroelectric generation conditions, hydroelectric generation comprised 69 percent of Idaho Power's total system generation during 2011 and 51 percent during 2010. Where favorable hydroelectric generating conditions exist for Idaho Power, they also may be abundant for other Pacific Northwest hydroelectric facility operators, thus increasing the available supply of lower-cost power and depressing regional wholesale market prices, which impacts the revenue Idaho Power receives from off-system sales of its excess power. Average wholesale power prices per MWh for sales for resale were down 29 percent in 2011 relative to 2010.
Fuel and Purchased Power Expense: In addition to hydroelectric generation and power it purchases in the wholesale markets, Idaho Power relies significantly on coal and natural gas to fuel its generation facilities. Fuel costs are impacted by electricity sales volumes, the terms of contracts for fuel, Idaho Power's power generation capacity, the rate of expansion of alternative energy generation sources such as wind energy, the availability of hydroelectric generation resources, transmission capacity, energy market prices, and Idaho Power's hedging program for managing fuel costs.
For the year 2011, Idaho Power's weighted average fuel-related cost per MWh for its fossil fuel generation resources increased 17 percent relative to 2010, mainly due to the effect of lower generation output, which spreads fixed costs over lower output, and coal price increases. Notwithstanding the increase in fuel cost per MWh generated, total fuel expense decreased 18 percent relative to 2010, due to a decrease in output from fuel-fired power generating plants resulting from both the abundant hydroelectric generation and increased wind power obtained through mandated power purchases pursuant to PURPA. Looking ahead, operation of the Langley Gulch power plant that Idaho Power is currently constructing will increase Idaho Power's use of natural gas, and thus its exposure to volatility in natural gas prices.
Purchased power costs are impacted by the terms of contracts for purchased power, the rate of expansion of alternative energy generation sources such as wind energy, and wholesale energy market prices. Idaho Power is generally obligated to purchase power from PURPA generation projects at a specified price regardless of the then-current load demand or wholesale energy market prices. This increases the likelihood that Idaho Power will be required to reduce output from its lower-cost hydroelectric and fossil fuel-fired generation resources and may be required to sell in the wholesale power market the power it purchases from PURPA projects at a significant loss. Integration of intermittent, non-dispatchable resources into Idaho Power's portfolio also creates a number of operational risks, which Idaho Power is working to address. The Idaho and Oregon PCA mechanisms mitigate in large part the potential adverse impacts of fluctuations in Idaho Power's power supply costs. Idaho Power also uses physical and financial forward contracts for both electricity and fuel in order to manage the risks relating to fuel and power price exposures.
Regulatory and Environmental Compliance Costs and Expenditures: Idaho Power is subject to extensive federal and state laws, policies, and regulations, as well as regulatory actions and audits. Compliance with these requirements directly influences Idaho Power's operating environment and may significantly increase Idaho Power's operating costs. Further, potential monetary and non-monetary penalties for a violation of applicable laws or regulations may be substantial. Accordingly, Idaho Power has in place numerous compliance policies and initiatives, and frequently evaluates, updates, and supplements those policies and initiatives. In particular, environmental laws and regulations may, among other things, increase the cost of operating power generation plants and constructing new facilities, require that Idaho Power install additional pollution control devices at existing generating plants, or require that Idaho Power shut down certain power generation plants. For instance, the Boardman coal-fired power plant, in which Idaho Power owns a 10 percent interest, was recently the subject of proceedings with Oregon regulators relating to the installation of costly emission controls and a cessation of coal-fired operations in 2020, and in September 2010 the U.S. Environmental Protection Agency (EPA) issued a Notice of Violation relating to the Boardman plant, alleging Clean Air Act (CAA) violations. As legislation and regulations concerning greenhouse gas emissions develop, Idaho Power will assess the potential impact on the costs to operate its power generation facilities, as well as the willingness or ability of power plant participants to fund any required pollution control equipment upgrades. Other Notable Matters and Areas of Focus Pension Plans: In 2010, Idaho Power contributed $60 million to its defined benefit pension plan, and in 2011 Idaho Power contributed an additional $18.5 million to the plan. On May 19, 2011, the IPUC authorized Idaho Power to increase its annual recovery and amortization of deferred pension costs from $5.4 million to $17.1 million. Idaho Power expects to make additional significant cash contributions to its defined benefit pension plan through at least 2016. Water Management and Relicensing of Hydroelectric Projects: Because of Idaho Power's reliance on streamflow in the Snake River and its tributaries, Idaho Power participates in numerous proceedings and venues that may affect its water rights, seeking to preserve the long-term availability of its rights for use at its hydroelectric projects. Also, Idaho Power is involved in
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renewing federal licenses for the Hells Canyon Complex (HCC), its largest hydroelectric generation source, and the Swan Falls hydroelectric project. Relicensing involves numerous environmental issues and substantial costs. Idaho Power is working with the states of Idaho and Oregon, regulatory authorities, and interested parties to address concerns and take appropriate measures relating to the relicensing of Idaho Power's hydroelectric projects. Given the number of parties and issues involved, Idaho Power's relicensing costs have been and will continue to be substantial.
Transmission Projects: Idaho Power continues to focus on expansion of its transmission system in an effort to improve system reliability and resource adequacy through the proposed Boardman-to-Hemingway and Gateway West transmission projects. Construction of these projects cannot commence until all federal, state, and local regulatory requirements are met. In January 2012, Idaho Power entered into cost-sharing arrangements with third parties for the permitting phases of both projects. To further mitigate the risks associated with these projects, at least in part, Idaho Power plans to seek regulatory support for cost recovery from the IPUC and OPUC for the projects prior to construction.
2011 Tax-Related Projects: In September 2011, the U.S. Internal Revenue Service (IRS) notified Idaho Power that Idaho Power's uniform capitalization tax method agreement had been approved, resulting in the recognition of $56.9 million of its previously unrecognized tax benefits in 2011. Summary of 2011 Financial Results The following is a summary Idaho Power's net income, net income attributable to IDACORP, Inc., and IDACORP's earnings per diluted share for the years ended December 31, 2011, 2010, and 2009 (in thousands, except earnings per share amounts):
Idaho Power net incomeNet income attributable to IDACORP, Inc.Average outstanding shares – diluted (000’s)IDACORP, Inc. earnings per diluted share
Year Ended December 31,2011
$ 164,750$ 166,693
49,558$ 3.36
2010$ 140,634$ 142,798
48,340$ 2.95
2009$ 122,559$ 124,350
47,182$ 2.64
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The following table presents a reconciliation of net income attributable to IDACORP, Inc. for 2010 to 2011 (items are in millions and are before tax unless otherwise noted):
Net income attributable to IDACORP, Inc. - December 31, 2010Change in Idaho Power net income before taxes:
Rate and other regulatory changes, including power cost, pension expenserecovery, and fixed cost adjustment mechanisms
Changes in sales volumesIncreased transmission service revenuesIncreased other operating and maintenance expenses:
Pension and payroll related expenses (excluding pension impact ofsettlement stipulation below)
Thermal plant expensesOther
Increased depreciation expenseIncreased property taxesOther changes in operating income, netIncrease in Idaho Power operating income prior to sharing mechanisms
Additional pension expense as a result of settlement stipulationDecrease in revenues as a result of sharing mechanism
Decrease in operating income as a result of sharing mechanismsChange in Idaho Power operating income
Increase in AFUDCOther net decreases
Increases due to tax method changes and related examination settlementsChange in other income tax benefit
Total increase in Idaho Power net incomeOther net decreases (net of tax)
Net income attributable to IDACORP, Inc. - December 31, 2011
(20.3)(27.1)
$ 26.3
9.87.4
(17.2)(5.0)(2.2)(3.9)(4.8)1.1
11.5
(47.4)(35.9)11.6(3.7)27.824.3
$ 142.8
24.1(0.2)
$ 166.7 Idaho Power net income increased by $24.1 million in 2011 compared to 2010, largely as a result of approval by the U.S. Congress Joint Committee on Taxation of the uniform capitalization method agreement with the IRS, which allowed for recognition in 2011 of $56.9 million of previously unrecognized tax benefits for tax years 2009 and prior. This benefit was partially offset by $47.4 million due to Idaho-jurisdictional sharing mechanisms.
The uniform capitalization method approval contributed to triggering of the sharing mechanism under Idaho Power's January 2010 settlement agreement with the IPUC and other parties. Under this sharing mechanism, Idaho Power recorded a $27.1 million reduction in revenues to be refunded to or to otherwise benefit customers, reflecting the equal sharing of Idaho-jurisdiction earnings in excess of a 10.5 percent Idaho ROE.
Additionally, Idaho Power recorded $20.3 million of additional pension expense as a result of an IPUC order approving a 2011 settlement stipulation that had been executed by Idaho Power, the IPUC Staff, and one large industrial customer of Idaho Power. The settlement stipulation provided that Idaho Power would allocate to customers 75 percent of Idaho Power's share of 2011 Idaho-jurisdictional earnings over a 10.5 percent Idaho ROE. As agreed to with the IPUC, this allocation was used to reduce Idaho Power's pension regulatory asset (reducing a portion of Idaho customers' future obligation), resulting in the corresponding recognition of additional pension expense.
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Other items influencing the change in Idaho Power's operating income and annual earnings as compared to 2010 include:
• Several rate orders went into effect in 2010 and 2011 that impacted current year revenues and had a net positive impact on operating income. A June 1, 2010 base rate increase benefited 2011 with an additional five months of increased base rate revenue. A pension expense recovery rate increase occurred on June 1, 2010 and was further increased on June 1, 2011. Also included in the rate orders were PCA-related customer rate decreases on June 1 of both years. However, concurrent with each PCA rate decrease was a corresponding reduction in PCA expense. These rate changes, combined with lower power supply costs net of PCA mechanisms, improved operating income by approximately $26.3 million for the year.
• Increased sales volumes improved operating income by $9.8 million. Cooler temperatures early in the year contributed to an $8.0 million increase in electricity demand from residential customers, many of whom rely on electric power for heating systems during the winter months. This increase was partially offset by a $3.3 million decrease in irrigation revenues due to a wetter, cooler spring reducing the need to use irrigation pumps. A 17.7 percent increase in cooling degree days when compared with the prior year, particularly an increase in temperature in the late summer months, drove the remaining increase.
• Transmission system revenues, a component of other revenues, increased $7.4 million, principally resulting from increases in wheeling services attributable to increases in FERC transmission rates that took effect on October 1, 2010 and 2011, and from other facility rental increases.
• O&M expenses increased, primarily due to an $11.5 million increase in pension expense associated with the pension recovery rate orders, an increase in payroll-related costs of $5.7 million, and increased maintenance expense of $5.0 million at the thermal plants. These increases were partially offset by lower legal expenses of $2.3 million.
• Depreciation expense increased $3.9 million for the year due to increased plant in service.• Property tax increased $4.8 million in 2011, primarily due to lower residential and commercial values in other property
classes shifting tax costs to centrally assessed property.
Prior to the effects of the sharing mechanisms described above, Idaho Power operating income increased $11.5 million compared to 2010. After the effects of the sharing mechanism, operating income decreased $35.9 million compared to 2010. Also contributing to increased earnings at Idaho Power were increases of $11.6 million in AFUDC, which represents the cost of financing construction projects with borrowed funds and equity funds.
Key Operating and Financial Metrics IDACORP’s and Idaho Power’s outlook for 2012 full year metrics is as follows:
Idaho Power Operating & Maintenance Expense (millions)Idaho Power Capital Expenditures, excluding AFUDC (millions)Idaho Power Hydroelectric Generation (million MWh)Non-regulated subsidiary earnings and holding company expenses (millions)
2012 Estimate$325-$335$230-$240
7.5-9.5$0.0-$3.0
2011 Actual$339$33810.9$1.9
The 2012 range for capital expenditures includes the completion of the Langley Gulch power plant and expenditures for the siting and permitting of major transmission expansions for the Boardman-to-Hemingway and Gateway West transmission projects, net of ongoing payments from third parties participating as joint funders in the permitting project for future expenditures.
The estimated hydroelectric generation range is based on reservoir storage levels and forecasted weather conditions as of February 12, 2012.
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RESULTS OF OPERATIONS This section of the MD&A takes a closer look at the significant factors that affected IDACORP’s and Idaho Power’s earnings during the year ended December 31, 2011. In this analysis, the results for 2011 are compared to 2010 and the results for 2010 are compared to 2009.
(Megawatt-hours (MWh) and dollar amounts are in thousands unless otherwise indicated.) Utility Operations The table below presents Idaho Power’s energy sales, in MWh, and supply for the last three years.
General business salesOff-system salesTotal energy sales
Hydroelectric generationCoal generationNatural gas and other generationTotal system generation
Purchased powerLine lossesTotal energy supply
Year Ended December 31,2011
13,7343,635
17,369
10,9374,820
13815,895
2,751(1,277)17,369
2010
13,5131,982
15,495
7,3446,864
16014,368
2,401(1,274)15,495
2009
13,9482,836
16,784
8,0966,941
24215,279
2,912(1,407)16,784
For the year 2011, general business sales increased by 0.2 million MWh, mostly related to increased residential customer usage over the prior year. Off-system sales increased by 1.7 million MWh in 2011 as increases in output from hydroelectric and PURPA resources increased surplus power available for sale. Due largely to favorable hydroelectric generating conditions, hydroelectric generation comprised 69 percent of Idaho Power’s total system generation during 2011. Hydroelectric generation in 2011 was 127 percent of the annual median generation of 8.6 million MWh, which is based on hydrologic conditions for the period 1928 through 2010 and adjusted to reflect the current level of water resource development. The 0.8 million MWh reduction in hydroelectric generation in 2010 compared to 2009 was primarily due to reduced precipitation during the snow accumulation period.
The increase in hydroelectric generation during 2011 led to a decreased reliance on coal-fired generation, and also contributed to the availability of additional surplus power available for off-system sales. Most of the decrease in power supply costs that typically results from increased hydroelectric generation is returned to customers through the PCA mechanisms.
Idaho Power’s system is dual peaking, with the larger peak demand occurring in the summer. To reduce the magnitude of peak demands, Idaho Power has implemented a demand response program and a number of energy efficiency programs. The 2011 summer peak demand was 2,973 MW, set on July 6, 2011. The record summer peak demand of 3,214 MW was set on June 30, 2008, and the highest winter peak demand of 2,527 MW was set on December 10, 2009. During these and other similar heavy load periods, Idaho Power’s system is fully committed to serve loads and meet required operating reserves. When loads exceed Idaho Power's generation capacity, Idaho Power must rely on power obtained from purchase contracts (some power from which may not be available when required if the source is intermittent power such as wind) and may be required to purchase power in the wholesale energy spot market.
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General Business Revenues: The table below presents Idaho Power’s general business revenues, MWh sales, and number of customers for the past three years.
Revenue
ResidentialCommercialIndustrialIrrigation
TotalProvision for sharingDeferred revenues (1)
Total general business revenuesMWh
ResidentialCommercialIndustrialIrrigation
TotalCustomers (year end)
ResidentialCommercialIndustrialIrrigation
Total
Year Ended December 31,2011
$ 405,982
220,962140,701104,635872,280(27,099)(10,636)
$ 834,545
5,1463,8153,1001,673
13,734
411,48765,226
12118,736
495,570
2010
$ 400,607231,440138,394110,555880,996
—(10,625)
$ 870,371
4,9673,7633,0761,707
13,513
408,75464,647
12518,547
492,073
2009
$ 409,479232,816141,530109,655893,480
—(9,715)
$ 883,765
5,3003,8583,1401,650
13,948
406,63164,349
12918,818
489,927
(1) As part of its February 1, 2009 general rate case order, the IPUC allowed Idaho Power to recover AFUDC for the Hells Canyon Complex relicensing asset even though the relicensing process is not yet complete and the relicensing asset has not been placed in service. Idaho Power expects to collect approximately $10.7 million annually in the Idaho jurisdiction, but will defer revenue recognition of the amounts collected until the license is issued and the asset is placed in service.
Changes in customer demand and changes in rates are the primary causes of fluctuations in general business revenue. The table below presents the most significant rate increases and decreases, shown on an annualized basis, which impacted revenues over the last three years.
The Idaho general rate case settlement stipulation approved by the IPUC on December 30, 2011, resulted in a 4.2 percent overall, or $34 million annual, increase in Idaho-jurisdictional base rates, effective January 1, 2012. For more information related to the December 2011 settlement stipulation, see “Regulatory Matters” later in this MD&A.
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The primary influences on customer demand are weather and economic conditions. Extreme temperatures increase sales to customers who use electricity for cooling and heating, and moderate temperatures decrease sales. Precipitation levels during the agricultural growing season affect sales to customers who use electricity to operate irrigation pumps, with increased precipitation reducing electricity usage. Boise, Idaho weather impacts for the last three years are included in the table below.
Heating degree-days (1)
Cooling degree-days (1)
(1) Heating and cooling degree-days are common measures used in the utility industry to analyze the demand for electricity and indicate when a customer would use electricity for heating and air conditioning. A degree-day measures how much the average daily temperature varies from 65 degrees. Each degree of temperature above 65 degrees is counted as one cooling degree-day, and each degree of temperature below 65 degrees is counted as one heating degree-day.
Year Ended December 31,2011
5,5541,076
20105,078
914
20095,6121,188
Normal5,727
807
General Business Revenues - 2011 Compared to 2010: General business revenue decreased $35.8 million in 2011 compared to 2010. Most of the decrease is a result of recording a regulatory liability of $27.1 million to be refunded to, or otherwise be used to benefit, customers, reflecting the equal sharing of Idaho-jurisdiction earnings exceeding the authorized return on year-end equity of 10.5 percent, pursuant to a January 2010 Idaho settlement agreement. The offset to this liability was recorded as a reduction to general business revenue during the third and fourth quarters of 2011. The remaining changes in general business revenue, a decrease of $8.7 million for 2011, are primarily attributable to the effects of rate changes and usage. These factors are discussed in more detail below.
• Rates. Rate changes combined to reduce general business revenue by $38.8 million in 2011 compared to 2010. The revenue impact of several of these changes was directly offset by associated changes in operating expenses. For example, Idaho PCA amortization expense was reduced $56.3 million due to decreases in the corresponding Idaho PCA rates. The decrease in PCA rates were partially offset by an increase in base retail rates of $38.5 million for the year.
The $10.5 million decline in revenue from commercial customers in 2011 relative to 2010, notwithstanding an increase in usage, is largely due to the disproportionate impact of the PCA rate reductions that went into effect in 2010 and 2011. Commercial customer rates are typically subject to a greater adjustment when PCA rates increase or decrease.
• Customers. Changes related to a special industrial customer contract, along with small increments in customer count, increased general business revenues by $16.6 million. Customer growth from 2010 to 2011 was 0.7 percent.
• Usage. For 2011, higher usage increased general business revenue $13.5 million compared to 2010. The increase
was due primarily to colder first quarter temperatures, which increased power demand for residential heating purposes, as well as a 17.7 percent increase in cooling degree-days during the year, which increased power demand for air conditioning purposes. This increase was partially offset by a 2.3 percent decrease in irrigation usage resulting from the cooler spring weather and the timing and level of precipitation during the second quarter of 2011.
General Business Revenues - 2010 Compared to 2009:
• Rates. Rate increases positively impacted general business revenue by $16.9 million in 2010 as compared to 2009, due to increases in base rates of $73.5 million, partially offset by PCA rate decreases of $56.6 million.
• Customers. Growth in customer count contributed to a modest increase in general business revenues of $2.9 million. Customer growth from 2009 to 2010 was 0.5 percent.
• Usage. A decrease in usage reduced general business revenue by $33.4 million. Idaho Power believes the decline in total MWh sales was due primarily to mild temperatures, which decreased power demand for heating and cooling purposes, and partially due to the continued weakness of the economy and energy conservation practices in its service area.
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Off-System Sales: Off-system sales consist primarily of long-term sales contracts and opportunity sales of surplus system energy. The table below presents Idaho Power’s off-system sales for the last three years.
RevenueMWh soldRevenue per MWh
Year Ended December 31,2011
$ 101,6023,635
$ 27.95
2010$ 78,133
1,982$ 39.42
2009$ 94,373
2,836$ 33.28
Off-System Sales - 2011 Compared to 2010: Off-system sales revenue increased by $23.5 million, or 30 percent, in 2011 as compared to 2010. Sales volumes nearly doubled, as increases in output from hydroelectric and PURPA resources increased surplus power available for sale. This increase was partially offset by a 29 percent decrease in average prices due in part to abundant hydroelectric generation in the region.
Off-System Sales - 2010 Compared to 2009: Off-system sales revenue decreased $16.2 million in 2010 as compared to 2009. Hydroelectric generation decreased nine percent, which reduced surplus power available for sale. This decrease was partially offset by an 18 percent increase in revenue per MWh due to lower hydro generation in the region which drove wholesale power prices higher.
Other Revenues: The table below presents the components of other revenues for the last three years.
Transmission services, facility rental and otherEnergy efficiencyTotal
Year Ended December 31,2011
$ 48,91837,663
$ 86,581
2010$ 40,364
44,184$ 84,548
2009$ 36,037
31,821$ 67,858
Other Revenues - 2011 Compared to 2010: Other revenues increased $2.0 million in 2011 as compared to 2010, due mainly to:
• an increase of $7.4 million in transmission system revenues, resulting principally from increases in wheeling services attributable to increases in FERC transmission rates that took effect on October 1, 2010 and 2011, and from other facility rental increases; and
• a decrease in energy efficiency revenues of $6.5 million, due in part to an IPUC order that moved custom efficiency payments to a regulatory asset that will be amortized over time and recovered through general rate cases rather than through the energy efficiency rider. The remaining decrease relates to lower customer incentives paid versus the prior year. Energy efficiency activities are funded through a rider mechanism on customer bills. Energy efficiency program expenditures are reported as an operating expense with an equal amount of revenues recorded in other revenues, resulting in no net impact on earnings. The cumulative variance between expenditures and amounts collected through the rider is recorded as a regulatory asset or liability pending future collection from or obligation to customers. A liability balance indicates that Idaho Power has collected more than it has spent and an asset balance indicates that Idaho Power has spent more than it has collected. As of December 31, 2011, Idaho Power’s energy efficiency rider balance was a regulatory asset of $8.9 million.
Other Revenues - 2010 Compared to 2009: Other revenues increased $16.7 million in 2010 as compared to 2009, due mainly to:
• an increase of $4.3 million in transmission system revenues. Transmission system revenues increased $2.8 million primarily due to new transmission facilities, as well as rate changes. Wheeling revenue increased $2.1 million primarily due to increases in the FERC formula rate that took effect on October 1, 2009 and October 1, 2010; and
• an increase in energy efficiency revenues of $12.4 million, due to increased program activity. Energy efficiency activities are funded through rider mechanisms on customer bills.
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Purchased Power: The table below presents Idaho Power’s purchased power expenses and volumes for the last three years.
Expense
PURPA contractsOther purchased power (including wheeling)
Total purchased power expenseMWh purchased
PURPA contractsOther purchased power
Total MWh purchasedCost per MWh from PURPA contractsCost per MWh from other sourcesWeighted average - all sources
Year Ended December 31,2011
$ 90,25173,085
$ 163,336
1,4951,2562,751
$ 60.36$ 58.19$ 59.37
2010
$ 56,02287,747
$ 143,769
9101,4912,401
$ 61.56$ 58.85$ 59.88
2009
$ 59,606107,592
$ 167,198
9701,9422,912
$ 61.45$ 55.40$ 57.42
The purchased power cost per MWh often exceeds the off-system sales revenue per MWh because Idaho Power generally needs to purchase power during heavy load periods, which is higher priced energy, than during light load periods, which is lower priced energy, and conversely has less energy available for off-system sales during heavy load periods than light load periods. Also, in accordance with Idaho Power’s risk management policy, Idaho Power may purchase or sell energy several months in advance of anticipated delivery. The regional energy market price is dynamic and additional energy purchase or sale transactions that Idaho Power makes at current market prices may be noticeably different than the advance purchase or sale transactions prices. Purchased Power - 2011 Compared to 2010: Purchased power expense increased $19.6 million, or 14 percent, in 2011 as compared to 2010. This increase was driven by MWh purchased from PURPA contracts, which increased 64 percent due to new PURPA wind generation facilities coming on-line. The increase was partially offset by reduced wholesale market purchases resulted from Idaho Power's above average hydroelectric generation in 2011, and continued reliance on financial hedges to mitigate potential changes in forecasted hydrologic conditions. Wholesale market purchases were also down due to lower system loads resulting from relatively mild weather.
Purchased Power - 2010 Compared to 2009: Purchased power expense decreased $23.4 million in 2010 as compared to 2009, due to lower system loads that resulted from mild weather, relatively weak economic conditions, energy conservation practices, and a greater reliance on financial hedges to mitigate potential changes in forecasted hydrologic conditions.
Fuel Expense: Idaho Power’s fuel expenses and generation at its thermal generating plants for the last three years are included in the table below.
Expense
CoalNatural gas and other
Total fuel expenseMWh generated
CoalNatural gas and other
Total MWh generatedCost per MWh
CoalNatural gas and otherWeighted average, all sources
Year Ended December 31,2011
$ 119,845
11,697$ 131,542
4,820
1384,958
$ 24.86
84.7626.53
2010
$ 146,92712,746
$ 159,673
6,864160
7,024
$ 21.4179.6622.73
2009
$ 130,23419,332
$ 149,566
6,941242
7,183
$ 18.7679.8820.82
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Most fuel supply contracts are subject to changes in published indexes that are closely related to materials and supplies, labor, and diesel costs. In addition to commodity (variable) costs, both natural gas and coal expense include costs that are more fixed in nature for items such as capacity charges, transportation, and fuel handling. Period to period variances in fuel expense per MWh are noticeably impacted by these fixed charges when generation output is substantially different between the two periods.
Fuel Expense - 2011 Compared to 2010: In 2011, fuel expense decreased $28.1 million, or 18 percent, compared to 2010, due to lower generation at Idaho Power's thermal plants. The output at these plants was down 2.0 million MWh, or 30 percent in 2011 compared to 2010. The reduced dispatch was primarily caused by lower regional power prices due to higher regional hydroelectric and wind generation. The impact of lower thermal generation was partially offset by higher coal prices. During parts of 2010, the Bridger and Valmy generating plants received fuel from prior lower-cost contracts.
Fuel Expense - 2010 Compared to 2009: In 2010, fuel expense increased $10.1 million compared to 2009 due to new higher-priced contracts with Black Butte Coal Company for supplying the Valmy and Jim Bridger plants that took effect in early 2010. BCC, which also supplies coal to the Jim Bridger plant, experienced higher labor-related costs due to a tight labor market in the southwest Wyoming area and higher materials and supplies expense related to the underground mining operation. Fuel expense also increased due to a 31 percent increase in generation at the Boardman plant due to an extended outage in 2009 that did not recur in 2010, increasing fuel expense $1.8 million. These increases were partially offset by a $6.6 million decrease in fuel expense at the natural gas-fired peaking plants.
PCA Mechanisms: Idaho Power's power supply costs can vary significantly from year to year, primarily because of the impacts of weather, system loads, and commodity markets. To address the volatility of power supply costs, Idaho Power has PCA mechanisms for both the Idaho and Oregon jurisdictions. These mechanisms allow Idaho Power to recover from or refund to customers most of the fluctuations in power supply costs. Because of these mechanisms, the primary financial impacts of power supply cost variations is that cash is paid out but recovery from customers does not occur until a future period, or cash that is collected is refunded to customers, resulting in fluctuations in operating cash flows from year to year.
PCA expense represents the effects of the Idaho and Oregon PCA mechanisms. The table below presents the components of the Idaho and Oregon PCA mechanisms for the last three years.
Idaho power supply cost accrual (deferral)Oregon power supply cost accrualOregon excess power cost orderAmortization of prior year authorized balancesTotal power cost adjustment expense
Year Ended December 31,2011
$ 27,7681,523
—9,206
$ 38,497
2010$ (14,324)
——
65,550$ 51,226
2009$ (42,533)
184(6,358)
115,417$ 66,710
The power supply accruals or deferrals represent the portion of that periods' power supply cost fluctuations accrued or deferred under the PCA mechanisms. If actual power supply costs are greater than the amount forecasted in PCA rates, most of the excess is deferred. Accruals represent additional costs recorded because actual power supply costs were less than the amount forecasted in PCA rates, as was the case for both jurisdictions in 2011. The amortization of the prior year’s balances represents the amounts being collected (refunded) in the current PCA year that were deferred or accrued in the prior PCA year (the true-up component of the PCA).
PCA Mechanisms - 2011 Compared to 2010: Actual net power supply costs decreased in 2011 relative to 2010 while base net power supply costs increased, resulting in a change of $43.6 million—from a deferral of $14.3 million to an accrual of $29.3 million. For 2011, collections on deferred amounts have decreased due to lower PCA true-up rates, reducing the PCA amortization by $56.3 million.
PCA Mechanisms - 2010 Compared to 2009: A combination of changes in base power supply costs, elements of the PCA mechanism, and a decrease in PCA rates reduced PCA expenses $15.5 million in 2010 as compared to 2009. The $49.9 million decrease in the amortization of the prior year’s deferral balance resulted from lower PCA true-up rates in effect in 2010. The $28.2 million decrease in the Idaho deferral is due to changes in base and actual power supply costs and forecast rates. In addition, in 2009 Idaho Power recorded the effect of an order from the OPUC that allows Idaho Power to defer for future recovery $6.4 million of costs incurred in prior years.
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Other Operations and Maintenance Expenses: The $44.7 million increase in other O&M expense in 2011 as compared to 2010 was principally due to:
• $20.3 million of increased pension expenses relating to the settlement stipulation that reduced a portion of Idaho customers' future obligation through a reduction in the pension regulatory asset;
• increased pension and other benefit expenses of $11.5 million, primarily due to pension expense amortization that began in June 2010 and was increased in June 2011 in conjunction with recovery of deferred pension costs in rates;
• $5.0 million in higher thermal O&M due to maintenance outages at the Valmy plant, partially offset by an equipment impairment taken in 2010 at the Bridger plant that did not recur in 2011; and
• an increase in other payroll related costs of $5.7 million.
These increases were partially offset by a combination of lower meter reading expense and the completed amortization of certain DSM expenses of $3.5 million, and lower outside service fees of $2.3 million.
Other O&M expense increased $1.3 million from 2010 to 2009, an increase of less than one percent.
Income Taxes
Income Tax Expense: IDACORP's and Idaho Power's income tax expense for 2011 decreased significantly relative to 2010, primarily as a result of an IRS examination settlement in 2011 related to Idaho Power's uniform capitalization tax accounting method. Income tax expense in 2010 was down significantly from 2009, principally as a result of Idaho Power's tax accounting method change for repair-related expenditures and lower pre-tax earnings at IDACORP and Idaho Power. For additional information relating to IDACORP's and Idaho Power's income taxes, see Note 2 - “Income Taxes” to the consolidated financial statements included in this report.
Status of Audit Proceedings and Tax Method Changes: In September 2010, Idaho Power adopted a tax accounting method change for capitalized repair expenditures on utility assets concurrent with the filing of IDACORP's 2009 consolidated federal income tax return. Also in 2010, Idaho Power reached an agreement with the IRS, subject to subsequent review by the Joint Committee, regarding the allocation of mixed service costs in its method of uniform capitalization. Both methods were subject to audit under IDACORP's 2009 IRS examination.
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 examination and submitted its report on the 2009 tax year to the 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 the second quarter of 2011.
In September 2011, the IRS notified IDACORP that the Joint Committee had completed its review 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 the third quarter of 2011.
Completion of the Joint Committee review allowed the IRS to finalize its 2009 examination, process the income tax changes, and close the case in September 2011. In the fourth quarter, IDACORP and Idaho Power paid previously accrued income tax liabilities of $3.9 million and $8.1 million, respectively, related to the capitalized repairs examination agreement. The difference in liabilities is primarily due to IDACORP's utilization of deferred federal general business tax credits. 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 early 2011, IDACORP requested and received the return of $13 million of previously made estimated tax payments for the 2010 tax year.
In December 2011, the IRS completed its examination of IDACORP's 2010 tax year. There were no unresolved income tax issues as a result of the IRS examination. Accordingly, the examination had no impact on IDACORP or Idaho Power's 2011 financial position, results of operations, or cash flows. Bonus Depreciation Legislation: The Small Business Jobs Act (Jobs Act) and the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (Tax Relief Act) includes provisions for the extension and increase of bonus depreciation. Bonus depreciation provides for the accelerated deduction of current capital expenditures from certain asset
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classes. The Jobs Act extended 50 percent bonus depreciation to 2010 and the Tax Relief Act extended bonus depreciation to 2011-2012 and increased it to 100 percent for a portion of 2010 and 2011. Idaho Power has included an estimated bonus deprecation deduction in its current income tax provision. The estimated deduction would reduce Idaho Power's 2011 federal income tax liability by approximately $36 million. The State of Idaho did not conform to the federal bonus depreciation rules for 2010-2012.
LIQUIDITY AND CAPITAL RESOURCES Overview IDACORP's and Idaho Power's operating cash flows are driven principally by Idaho Power's sales of electricity and transmission capacity. General business revenues and the costs to supply power to general business customers, and the timing of income tax payments, are factors that have the greatest impact on Idaho Power's operating cash flows and are subject to risks and uncertainties relating to power generation conditions and Idaho Power's ability to obtain rate relief to cover its operating costs and provide a return on investment. Significant uses of cash flows from Idaho Power's utility operations include the purchase of electricity, the purchase of fuel for power generation, and payment of other operating expenses, taxes, and interest, with any excess amount being available for other uses such as capital expenditures and the payment of dividends. Idaho Power is in a period of significant infrastructure investment, adding capacity to its baseload generation, transmission system, and distribution facilities in an effort to ensure an adequate supply of electricity, to provide service to new customers, and to maintain system reliability. Idaho Power's aging hydroelectric and thermal generation facilities require continuing upgrades and component replacement, and the costs related to relicensing hydroelectric facilities and complying with the new licenses are substantial. Idaho Power expects that total capital expenditures will be between $720 million and $740 million over the period from 2012 through 2014.
Idaho Power's operating cash flows usually do not fully support the amount required for utility capital expenditures during periods of significant infrastructure development. Idaho Power uses operating and capital budgets to control operating costs and optimize capital expenditures, and funds its liquidity needs for capital expenditures through cash flows from operations, debt offerings, commercial paper markets, credit facilities, and capital contributions from IDACORP. Idaho Power seeks to recover its operating costs and earn a return on its capital expenditures through rates, periodically filing for rate adjustments for recovery of operating costs and capital investments to provide the opportunity to align Idaho Power's earned returns with those allowed by regulators. IDACORP and Idaho Power expect to continue financing capital requirements with a combination of internally generated funds and externally financed capital, and expect minimal need for external financing in 2012. However, IDACORP and Idaho Power monitor debt market conditions and may issue debt securities when they determine that, under the circumstances and in light of the timing and extent of financing needs, conditions are favorable for issuance of debt securities. Idaho Power has $100 million in principal amount of medium-term notes due in November 2012 and expects to fund retirement of those notes with cash from operations or some combination of cash from operations and the issuance of debt securities. IDACORP plans to continue to issue common stock under the pre-existing dividend reinvestment and employee-related stock purchase plans in 2012. While not expected in 2012, IDACORP may also determine to issue IDACORP common stock from time to time under its continuous equity program, depending on market conditions and capital needs. IDACORP and Idaho Power seek to maintain capital structures of approximately 50 percent debt and 50 percent equity, and maintaining this ratio influences IDACORP's and Idaho Power's debt and equity issuance decisions. As of December 31, 2011, IDACORP's capital structure consisted of approximately 52 percent equity and 48 percent debt, which decreases the likelihood that IDACORP will issue equity securities during 2012. A significant focus for 2012 will be to control costs and generate sufficient cash from operations to meet operating needs and contribute to capital expenditure requirements.
On October 26, 2011, IDACORP and Idaho Power entered into agreements that amended and restated their respective credit agreements. IDACORP's new credit facility consists of a revolving line of credit not to exceed the aggregate principal amount at any one time outstanding of $125 million, including swingline loans in an aggregate principal amount at any time outstanding not to exceed $15 million and letters of credit in an aggregate principal amount at any time outstanding not to exceed $50 million. Idaho Power's new credit facility consists of a revolving line of credit, through 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 amount at any time outstanding not to exceed $30 million. IDACORP and Idaho Power each have the right to request an increase in the aggregate principal amount of the new credit facilities to $150 million and $450 million, respectively, in each case subject to certain conditions.
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As of February 17, 2012, IDACORP's and Idaho Power's access to debt, equity, and credit arrangements included:
• their respective $125 million and $300 million revolving credit facilities;• IDACORP's shelf registration statement, which can be used for the issuance of debt securities and common stock,
including up to 3.0 million shares of IDACORP common stock available for issuance under its continuous equity program. Approximately $539 million of debt and equity securities issuances remained available under the shelf registration statement;
• Idaho Power's shelf registration statement, which can be used for the issuance of first mortgage bonds and debt securities. $300 million remained available under the shelf registration statement; and
• IDACORP's and Idaho Power's issuance of commercial paper, which can be used to meet short-term liquidity requirements.
The conditions of the capital markets and the weak economy have in recent years caused a general concern regarding access to sufficient capital at a reasonable cost. Notwithstanding these concerns, IDACORP and Idaho Power have not been significantly affected by this disruption in the credit environment, including in the commercial paper markets, and currently expect to continue to be able to access the capital markets to meet anticipated short- and long-term borrowing needs.
Idaho Power has PCA mechanisms in place that provide for the deferral of fluctuations in purchased power and fuel costs. However, if costs rise above the level currently recovered in retail rates, deferral balances will increase, which will negatively affect cash flow and liquidity until those costs are recovered from customers.
Operating Cash Flows IDACORP’s and Idaho Power’s operating cash inflows for the year ended December 31, 2011 were $310 million and $292 million, respectively. IDACORP's operating cash flows increased by $5 million and Idaho Power's decreased by $38 million compared to the year ended December 31, 2010. With the exception of cash flows related to income taxes, IDACORP’s operating cash flows are principally derived from the operating cash flows of Idaho Power. Significant items that affected the companies' operating cash flows in 2011 relative to 2010 included:
• income before income taxes decreased by $27 million for IDACORP and $28 million for Idaho Power;• in 2011, Idaho Power recorded a $27 million regulatory liability in addition to a $20 million reduction to pension-
related regulatory assets as a result of sharing mechanisms, which reduced income before income taxes but did not reduce operating cash flows. No sharing was recorded during 2010;
• cash outflows related to the pension and postretirement benefit plans decreased by $44 million. Idaho Power made an $18.5 million cash contribution to its defined benefit pension plan in 2011, compared with a $60 million cash contribution in 2010;
• cash inflows related to income taxes decreased by $15 million and $57 million for IDACORP and Idaho Power, respectively. IDACORP received income tax refunds of $12 million in 2011 compared with $27 million in 2010. Idaho Power’s net refunds from IDACORP for income tax were $1 million for the year, compared with $57 million for the same period in 2010;
• changes in regulatory assets associated with the Idaho and Oregon PCA mechanisms reduced cash flows by $13 million, as Idaho Power collected $56 million less of previously deferred costs due to decreases in PCA rates, partially offset by a $44 million increase in the current year PCA accrual, as compared with 2010;
• changes in fuel inventories reduced operating cash flows by $18 million, as fuel on hand increased by $20 million during 2011 due to decreased thermal plant operation, compared with $2 million during the same period in 2010; and
• differences in the timing of collections due to changes in retail accounts receivable and unbilled revenue balances decreased cash flows by $10 million, as Idaho Power collected more during 2010 than it recorded as revenues while collecting less during 2011 than it recorded as revenues.
IDACORP's and Idaho Power's operating cash inflows for the year ended December 31, 2010 were $305 million and $330 million, respectively. These amounts were an increase of $21 million and $58 million, respectively, compared to the year ended December 31, 2009. Significant items that affected operating cash flows in 2010 included:
• IDACORP's net refunds for income taxes were $27 million in 2010, as compared with $21 million in 2009. Idaho Power's net refunds from IDACORP for income tax were $57 million in 2010, as compared with $14 million in 2009;
• changes in accounts payable balances increased operating cash flows $32 million. Changes in amounts owed for
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purchased power and for coal contributed $14 million and $8 million, respectively, to the change;• differences in the timing of collections due to changes in retail accounts receivable and unbilled revenue balances
increased cash flows by $32 million as Idaho Power collected less during 2009 than it recorded as revenues while collecting more during 2010 than it recorded as revenues;
• in the first quarter of 2009, $13 million of refunds were made to Idaho Power's transmission customers upon a final order from the FERC on Idaho Power's OATT; and
• Idaho Power made a $60 million contribution to its defined benefit pension plan in 2010, decreasing operating cash flows. Idaho Power did not make a contribution to its defined benefit pension plan in 2009.
Investing Cash Flows Investing activities are predominantly related to capital expenditures for new construction and improvements to Idaho Power's generation, transmission, and distribution facilities. These capital expenditures address peak demand growth, aging plant and equipment, and customer growth. Idaho Power's construction expenditures were $338 million, $338 million, and $252 million in 2011, 2010 and 2009, respectively. In 2010, construction expenditures were partially offset by proceeds from the sale of $19 million of transmission-related assets to PacifiCorp. IDACORP cash flows relating to investments in affordable housing through IFS were $2 million, $13 million, and $6 million in 2011, 2010, and 2009, respectively. Financing Cash Flows Financing activities provide supplemental cash for both day-to-day operations and capital requirements as needed. Idaho Power funds liquidity needs for capital investment, working capital, energy and price hedging, and other financial commitments through cash flows from continuing operations, public debt offerings, commercial paper markets, credit facilities, and contributions from IDACORP. IDACORP funds its cash requirements, such as payment of taxes, capital contributions to Idaho Power, and non-utility expenses allocated to IDACORP, through cash flows from operations, commercial paper markets, sales of common stock, and credit facilities. Debt: On March 2, 2011, Idaho Power repaid at maturity $120 million of its 6.60% first mortgage bonds (secured notes) using a portion of the proceeds from the first mortgage bonds issued in August 2010 discussed in the next paragraph. Idaho Power's next upcoming material long-term debt principal repayment obligation is its $100 million of 4.75% first mortgage bonds that mature in November 2012.
On August 30, 2010, Idaho Power issued $100 million of 3.40% first mortgage bonds, Series I due 2020 and $100 million of 4.85% first mortgage bonds, Series I due 2040 under a shelf registration statement.
On December 1, 2009, Idaho Power repaid at maturity $80 million of its 7.2% first mortgage bonds. On November 20, 2009, Idaho Power issued $130 million of its 4.5% first mortgage bonds, Series H, due March 1, 2020. On August 20, 2009, Idaho Power completed the remarketing of its $166.1 million pollution control revenue refunding bonds and on August 25, 2009, Idaho Power used the proceeds from the remarketed bonds plus other funds to prepay its $170 million term loan credit agreement. On March 30, 2009, Idaho Power issued $100 million of its 6.15% first mortgage bonds, Series H due April 1, 2019. During 2009, IDACORP and Idaho Power reduced short-term debt by $94 million and $109 million, respectively.
Equity: IDACORP has entered into sales agency agreements as a means of selling its common stock from time to time in at-the-market offerings. IDACORP did not issue any shares under these agreements in 2011. In 2010, IDACORP received $34 million, net of agent's fees, from the issuance of 973,585 shares of IDACORP common stock at an average price of $35.47. In 2009, IDACORP received $14 million, net of agent's fees, from the issuance of 489,360 shares of IDACORP common stock at an average price of $28.79. IDACORP entered into a new sales agency agreement with BNY Mellon Capital Markets, LLC on December 16, 2011, replacing a December 2008 sales agency agreement that provided for the sale of up to 3 million shares of IDACORP common stock. At the time of expiration of the December 2008 sales agency agreement, 1,165,233 shares were unissued. As of February 17, 2012, there were 3 million shares available for issuance under the current sales agency agreement.
IDACORP issues common stock under its Dividend Reinvestment and Stock Purchase Plan and the Idaho Power Company Employee Savings Plan (a 401(k) plan), which provides additional common equity to IDACORP's capital structure. Under these plans, IDACORP issued 211,276 shares in 2011, 250,030 shares in 2010, and 366,673 shares in 2009, for proceeds of $8.2 million, $8.6 million, and $9.6 million, respectively.
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IDACORP issued 255,746 shares of IDACORP common stock in 2011, 194,860 shares in 2010, and 25,800 shares in 2009, in connection with the exercise of stock options, for proceeds of $9.4 million, $5.4 million, and $0.6 million, respectively.
IDACORP and Idaho Power paid dividends of $60 million, $58 million, and $57 million in 2011, 2010, and 2009, respectively. IDACORP made capital contributions of $16 million, $50 million, and $20 million to Idaho Power in 2011, 2010, and 2009, respectively.
Financing Programs
Shelf Registrations: IDACORP has an effective shelf registration statement on file with the U.S. Securities and Exchange Commission (SEC) that, as of the date of this report, can be used for the issuance of up to $539 million of debt securities and common stock. Idaho Power has an effective shelf registration statement on file with the SEC that, as of the date of this report, can be used for the issuance of up to $300 million of first mortgage bonds and unsecured debt. Refer to Note 4 - “Long-Term Debt” to the consolidated financial statements included in this report for more information regarding long-term financing arrangements.
The issuance of first mortgage bonds requires that Idaho Power meet interest coverage and security provisions set forth in the Indenture of Mortgage and Deed of Trust securing the bonds. Future issuances of first mortgage bonds are subject to satisfaction of covenants and security provisions set forth in the Indenture of Mortgage and Deed of Trust, market conditions, and regulatory authorizations, and satisfaction of covenants and tests contained in other financing agreements. The Indenture of Mortgage and Deed of Trust limits the amount of additional first mortgage bonds that Idaho Power may issue to the sum of (a) the principal amount of retired first mortgage bonds and (b) 60 percent of total unfunded property additions, as defined in the Indenture of Mortgage and Deed of Trust. As of December 31, 2011, Idaho Power could issue approximately $1.3 billion of additional first mortgage bonds based on retired first mortgage bonds and total unfunded property additions. However, the Indenture of Mortgage and Deed of Trust further limits the maximum amount of first mortgage bonds at any one time outstanding to $2.0 billion, and as a result the maximum amount of first mortgage bonds Idaho Power could issue as of December 31, 2011 was limited to approximately $539 million. Idaho Power may increase the $2.0 billion limit on the maximum amount of first mortgage bonds outstanding by filing a supplemental indenture with the trustee as provided in the Indenture of Mortgage and Deed of Trust.
Credit Facilities: As described above, on October 26, 2011, IDACORP and Idaho Power executed new credit agreements that amended and restated their existing $100 million and $300 million credit facilities, respectively. Each of the new credit facilities mature on October 26, 2016, and may be used for general corporate purposes and commercial paper back-up. IDACORP's facility permits borrowings under a revolving line of credit of up to $125 million at any one time outstanding, including swingline loans not to exceed $15 million at any time and letters of credit not to exceed $50 million at any time. IDACORP's facility may be increased, subject to specified conditions, to $150 million. Idaho Power's facility permits borrowings through the issuance of loans and standby letters of credit of up to $300 million at any one time outstanding, including swingline loans not to exceed $30 million at any one time. Idaho Power's facility may be increased, subject to specified conditions, to $450 million. Each company may request up to two one-year extensions of the then-existing maturity date. The interest rates for any borrowings under the facilities are 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 applicable margin is based on IDACORP's or Idaho Power's, as applicable, 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 agreements. The companies also pay a facility fee based on the respective company's credit rating for senior unsecured long-term debt securities.
Each facility contains a covenant requiring each company to maintain a leverage ratio of consolidated indebtedness to consolidated total capitalization equal to or less than 0.65 as of the end of each fiscal quarter. In determining the leverage ratio, “consolidated indebtedness” broadly includes all indebtedness of the respective borrower and its subsidiaries, including, in some instances, indebtedness evidenced by certain hybrid securities (as defined in the credit agreement). “Consolidated total capitalization” is calculated as the sum of all consolidated indebtedness, consolidated stockholders' equity of the borrower and its subsidiaries, and the aggregate value of outstanding hybrid securities. At December 31, 2011, the leverage ratios for IDACORP and Idaho Power were 48 percent and 49 percent, respectively. IDACORP's and Idaho Power's ability to utilize the credit facilities is conditioned upon their continued compliance with the leverage ratio covenants included in the credit facilities, which could limit the ability of the companies to issue first mortgage bonds and debt securities. There are additional 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 from any material subsidiary. At February 17, 2012, IDACORP and Idaho Power were in compliance with all facility covenants.
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The events of default under both facilities include, without limitation, non-payment of principal, interest, or fees; materially false representations or warranties; breach of covenants; bankruptcy or insolvency events; condemnation of property; cross-default to certain other indebtedness; failure to pay certain judgments; change of control; failure of IDACORP to own free and clear of liens the voting stock of Idaho Power; the occurrence of specified events or the incurring of specified liabilities relating to benefit plans; and the incurrence of certain environmental liabilities, subject, in certain instances, to cure periods.
Upon any event of default relating to the voluntary or involuntary bankruptcy of IDACORP or Idaho Power or the appointment of a receiver, the obligations of the lenders to make loans under the applicable facility and to issue letters of credit will automatically terminate and all unpaid obligations will become due and payable. Upon any other event of default, the lenders holding greater than 50 percent of the outstanding loans or greater than 50 percent of the aggregate commitments (required lenders) or the administrative agent with the consent of the required lenders may terminate or suspend the obligations of the lenders to make loans under the facility and to issue letters of credit under the facility and/or declare the obligations to be due and payable. During an event of default under the facilities, the lenders may, at their option, increase the applicable interest rates then in effect and the letter of credit fee by 2.0 percent per annum. A ratings downgrade would result in an increase in the cost of borrowing, but would not result in a default or acceleration of the debt under the facilities. However, if Idaho Power's ratings are downgraded below investment grade, Idaho Power must extend or renew its authority for borrowings under its IPUC and OPUC regulatory orders.
Without additional approval from the IPUC, the OPUC, and the Public Service Commission of Wyoming, the aggregate amount of short-term borrowings by Idaho Power at any one time outstanding may not exceed $450 million.
The following table outlines available short-term borrowing liquidity as of the dates specified:
Revolving credit facilityCommercial paper outstandingIdentified for other use(1)
Net balance available(1) Port of Morrow and American Falls bonds that holders may put to Idaho Power(2) These amounts represent the IDACORP facility only.
December 31, 2011
IDACORP(2)
$ 125,000(54,200)
—$ 70,800
IdahoPower
$ 300,000—
(24,245)$ 275,755
December 31, 2010
IDACORP(2)
$ 100,000(66,900)
—$ 33,100
IdahoPower
$ 300,000—
(24,245)$ 275,755
At February 17, 2012, IDACORP had no amounts outstanding under its credit facility and $51.5 million of commercial paper outstanding, and Idaho Power had no amounts outstanding under its credit facility and no commercial paper outstanding. The following table presents additional information about short-term borrowing during the years ended December 31, 2011 and 2010:
Commercial paper:Year end:
Amount outstandingWeighted average interest rate
Daily average amount outstanding during the yearWeighted average interest rate during the yearMaximum month-end balance(1) These amounts represent IDACORP only.
December 31, 2011IDACORP (1)
$ 54,2000.47%
$ 65,5740.41%
$ 74,400
Idaho Power
$ ——%
$ ——%
$ —
December 31, 2010IDACORP(1)
$ 66,9000.43%
$ 19,7540.40%
$ 66,900
Idaho Power
$ ——%
$ 3480.43%
$ 5,500
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Impact of Credit Ratings on Liquidity IDACORP’s and Idaho Power’s access to capital markets, including the commercial paper market, and their respective financing costs in those markets, may depend on their respective credit ratings. The following table outlines the ratings of Idaho Power’s and IDACORP’s securities, and the ratings outlook, by Standard & Poor’s Ratings Services and Moody’s Investors Service as of the date of this report:
These security ratings reflect the views of the ratings agencies. An explanation of the significance of these ratings may be obtained from each rating agency. Such ratings are not a recommendation to buy, sell, or hold securities. Any rating can be revised upward or downward or withdrawn at any time by a rating agency if it decides that the circumstances warrant the change. Each rating agency has its own methodology for assigning ratings and, accordingly, each rating should be evaluated independently of any other rating. Idaho Power maintains margin agreements relating to its wholesale commodity contracts that allow performance assurance collateral to be requested of and/or posted with certain counterparties. As of December 31, 2011, Idaho Power had posted no performance assurance collateral. Should Idaho Power experience a reduction in its credit rating on Idaho Power’s unsecured debt to below investment grade Idaho Power could be subject to additional requests by its wholesale counterparties to post performance assurance collateral. Counterparties to derivative instruments and other forward contracts could request immediate payment or demand immediate ongoing full daily collateralization on derivative instruments and contracts in net liability positions. Based upon Idaho Power’s current energy and fuel portfolio and market conditions as of December 31, 2011, the approximate amount of collateral that could be requested upon a downgrade to below investment grade is approximately $7 million. Idaho Power actively monitors the portfolio exposure and the potential exposure to additional requests for performance assurance collateral calls, through sensitivity analysis, to minimize capital requirements. Capital Requirements Idaho Power's construction expenditures were $338 million during the year ended December 31, 2011. The following table presents Idaho Power's estimated cash requirements for construction, excluding AFUDC, for 2012 through 2014 (in millions of dollars):
Ongoing capital expendituresLangley Gulch Power Plant (detailed below)
Total
2012$200-205
30-35$230-240
2013-2014$490-500
-$490-500
Major Infrastructure Projects: Idaho Power is undertaking a number of significant infrastructure projects, described below.
Langley Gulch Power Plant: The Langley Gulch Power Plant is a natural gas-fired combined cycle combustion turbine generating plant with a summer nameplate capacity of approximately 300 MW and a winter capacity of approximately 330 MW. Construction of the plant, substation, and transmission lines is in process. The plant is being constructed near New Plymouth, Idaho and is contracted to achieve commercial operation by November 1, 2012. Based on the current project status, Idaho Power estimates that the plant will be in service by July 1, 2012. The commitment estimate for the project is $427.4 million, $355 million of which Idaho Power incurred from inception in 2009 through December 31, 2011. AFUDC is included in both amounts. As of the date of this report, the overall project remains on schedule and Idaho Power expects the total project cost to be below the commitment estimate. Throughout 2011, significant progress was made constructing the plant and most equipment, facilities, and systems are complete. The construction contractor is preparing for commissioning of the plant, with
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testing planned to start in the first quarter of 2012. The step-up transformers were commissioned and energized from the substation in the fourth quarter of 2011. The plant will be connected to Idaho Power's existing grid through a new substation and two new transmission lines. The substation and one of the transmission lines have been completed. The second transmission line is under construction and is expected to be completed by May 2012.
Transmission Projects: As described in its 2011 Integrated Resource Plan (IRP), Idaho Power continues to focus on expansion of its existing transmission system in an effort to improve system reliability and resource adequacy. Idaho Power is involved in two significant transmission projects -- the Boardman-to-Hemingway line, a proposed 300-mile, 500-kV transmission project between a station near Boardman, Oregon and the Hemingway station near Boise, Idaho, and the Gateway West project, a joint development with PacifiCorp to build transmission lines between a station located near Douglas, Wyoming and the Hemingway station.
Boardman to Hemingway Line. The Boardman-to-Hemingway line will provide transmission service to meet needs identified in the 2011 IRP and other requests pursuant to Idaho Power's OATT. The Oregon Department of Energy's Energy Facility Siting Council (EFSC) process and the National Environmental Policy Act (NEPA) process are under way. Idaho Power is working with the EFSC to develop a phased approach to the EFSC's process so it can run concurrently with the NEPA process. Idaho Power expects to receive the EFSC project order in the first quarter of 2012. Idaho Power is preparing the preliminary application for site certificate pursuant to that process and anticipates filing the application in December 2012. The U.S. Bureau of Land Management (BLM) is in the process of publishing the draft environmental impact statement (DEIS) that Idaho Power expects will include both Idaho Power's proposed route and other alternative routes. Idaho Power anticipates the DEIS will be published in February 2013. In January 2012, Idaho Power entered into a joint funding agreement with PacifiCorp and BPA, described below, to jointly pursue the permitting of the project. Idaho Power's estimated share of the cost of the permitting phase of the project, after reflecting the terms of the joint funding agreement, is $11 million, including AFUDC. Total cost estimates for the project are approximately $820 million, including AFUDC. This cost estimate excludes the impacts of inflation and price changes of materials and labor resources that may occur following the date of the estimate. Idaho Power's share of the permitting phase of the project (excluding AFUDC) is included in the capital requirements table above. Construction costs beyond the initial phase are not included in the table above. The preferred portfolio in the 2011 IRP provides for a 2016 in-service date for the transmission line, as immediate system reliability benefits could be realized by construction of the transmission line by that date. However, the actual completion date of the project is subject to siting, permitting, regulatory approvals, individual participant's in-service requirements, the terms of any resulting joint construction agreements, and other conditions. Idaho Power will continue to work with the BLM, Oregon Department of Fish and Wildlife, and other agencies to address environmental issues, which could delay the project, alter the proposed siting, and result in significantly higher costs.
Gateway West Line. Idaho Power and PacifiCorp are pursuing the joint development of the Gateway West project. In January 2012, Idaho Power and PacifiCorp entered a new joint funding agreement for permitting the project as described below. Idaho Power's estimated cost for the permitting phase of the Gateway West project is approximately $24 million, including AFUDC. As of the date of this report, Idaho Power estimates the total cost for its share of the project (including both permitting and construction) to be between $150 million and $300 million, including AFUDC. Idaho Power's share of the permitting phase of the project (excluding AFUDC) is included in the capital requirements table above. Construction costs are not included in the table above. Timing of the construction of each segment of the project is subject to siting, permitting, regulatory approvals, individual participant's in-service requirements, the terms of any resulting joint construction agreements, and other conditions.
On July 29, 2011, the BLM issued for public review and comment a DEIS for the Gateway West project. The DEIS did not identify a preferred route for the project. Idaho Power provided input for comments relating to the DEIS that PacifiCorp submitted to the BLM in October 2011. As of the date of this report, the BLM continues to work through its NEPA process to address the lack of an agency preferred route and to address sage grouse and other resource issues.
Rapid Response Team for Transmission. The Obama Administration announced on October 5, 2011 the Rapid Response Team for Transmission (RRTT) pilot program to streamline federal permitting and increase cooperation at the federal, state, and tribal levels for several transmission projects. The Boardman-to-Hemingway and Gateway West projects are included in the RRTT pilot projects. Idaho Power is participating in the RRTT process for both the Boardman-to-Hemingway and Gateway West projects, but is unable to predict whether the RRTT will have a positive impact on the timing or ultimate cost of either project.
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Agreements Relating to Transmission Projects:
March 2010 Memorandum of Understanding. In March 2010, Idaho Power and PacifiCorp entered into a Memorandum of Understanding (2010 MOU) under which Idaho Power and PacifiCorp agreed to negotiate in good faith to reach arrangements pertaining to, among other items, the sale by the parties to one another of an undivided ownership interest in certain transmission facilities, and joint development and construction of three transmission projects, including the Boardman-to-Hemingway and Gateway West projects. In April 2010, Idaho Power and PacifiCorp entered into an arrangement pursuant to which they agreed to sell to one another interests in certain high-voltage transmission-related and interconnection equipment, and in May 2010 executed agreements pertaining to the joint ownership and operation of portions of those facilities. In subsequent months, Idaho Power and PacifiCorp sought to negotiate the terms and conditions of the other arrangements contemplated by the 2010 MOU, including the Boardman-to-Hemingway and Gateway West transmission projects, but were unable to reach agreement on those arrangements, and the 2010 MOU was ultimately terminated in April 2011. However, on January 12, 2012, Idaho Power, PacifiCorp, and the Bonneville Power Administration (BPA) entered into arrangements pertaining to the Boardman-to-Hemingway project and meeting BPA's eastern Idaho load service obligations, described below. Idaho Power and PacifiCorp also entered into an arrangement pertaining to the Gateway West project, as described below. Boardman to Hemingway Transmission Project Joint Permit Funding Agreement, dated January 12, 2012, among Idaho Power, PacifiCorp, and the Bonneville Power Administration (B2H Funding Agreement). The B2H Funding Agreement provides that the parties will seek to jointly fund and support the process of completing environmental studies, including an environmental impact statement pursuant to the National Environmental Policy Act, and obtaining governmental authorizations and permits for rights-of-way over public lands, necessary to develop the project. The planning, design, procurement, and acquisition of private rights-of-way, private easements, and similar private property interests are not within the scope of the B2H Funding Agreement. Idaho Power is designated as the project manager under the B2H Funding Agreement, responsible for administering and overseeing the project and for the day-to-day activities involved in advancing the project. The B2H Funding Agreement assigns each party a permitting interest based on each party's specified capacity ownership interests. The agreement provides for permitting interests of 21.21 percent for Idaho Power, 24.24 percent for BPA, and 54.55 for PacifiCorp in the Boardman-to-Hemingway transmission project. The agreement further provides that during future negotiations pertaining to development and construction agreements, the parties will seek to retain interests in the project equal to their respective permitting interests. PacifiCorp or BPA may withdraw from the B2H Funding Agreement at any time. Idaho Power has no right to withdraw from the B2H Funding Agreement.
Gateway West Transmission Project Development Agreement, dated January 12, 2012, between Idaho Power and PacifiCorp (Gateway Funding Agreement). The Gateway Funding Agreement outlines the terms under which the parties will jointly own, develop, design, permit, site, 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. PacifiCorp is designated as the project manager under the agreement. The Gateway Funding Agreement provides that the project manager may seek to reconfigure portions of the federal permitting project, including segments in which Idaho Power has an interest, subject to certain limitations. Further, PacifiCorp retains the right to remove specified segments from the federal permitting project, including segments in which Idaho Power has an interest, subject to certain limitations and Idaho Power's ability to continue with the permitting and construction of certain removed segments. 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 percent for each of segments 8, 9, and 10, with a federal permitting interest in the project of 11 percent. PacifiCorp has a 100 percent state permitting interest in segments 1, 2, 3, 4, 5, and 7, and a 67 percent state permitting interest in segments 8, 9, and 10, and has a federal permitting interest of 89 percent in the project. Information on the segments in which Idaho Power has an interest is as follows:
Segment No.68910
Connected SubstationsBorah to Midpoint
Midpoint to HemingwayCedar Hill to Hemingway
Midpoint to Cedar Hill
Length of Line (Miles)8812615234
Size of Line500-kV500-kV500-kV500-kV
StateIdahoIdahoIdahoIdaho
The Gateway Funding Agreement provides for the parties to subsequently meet to negotiate the terms and conditions of one or more definitive development and construction agreements for the Gateway West transmission line. The agreement specifies that the parties intend that the terms of any construction agreement would provide that Idaho Power is entitled to one-third of
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the anticipated bi-directional transmission capacity on segments 8, 9, and 10, and one-third of any total incremental system capacity on those segments, and that PacifiCorp is entitled to the remaining two-thirds interest. A party may withdraw from the federal permitting project, all or a portion of the state permitting project (relating to one or two of segments 8, 9, and 10), or the agreement in its entirety. Upon withdrawal, the withdrawing party forfeits its rights, title, and interest in the agreement and associated tangible and intangible property rights or, if withdrawing from less than all segments, its rights, title, and interest in those segments.
Idaho Power was previously a party to an existing memorandum of understanding, dated May 7, 2007, relating to transmission project development, and a permitting cost sharing agreement, dated September 5, 2008, to share with PacifiCorp the costs of certain Gateway West project permitting activities. The prior memorandum of understanding and permitting agreement terminated upon execution of the Gateway Funding Agreement.
Memorandum of Understanding, dated January 12, 2012, among Idaho Power, PacifiCorp, and BPA (2012 MOU). The 2012 MOU provides that the parties will negotiate in good faith the terms of mutually satisfactory definitive agreements that would allow BPA to meet its load service obligations in southeast Idaho. It provides that the parties will explore opportunities to establish eastern Idaho load service from the Hemingway substation in exchange for similar service from the Federal Columbia River Transmission System, and will consider whether to replace certain transmission arrangements involving existing assets with joint ownership transmission or other arrangements. The 2012 MOU outlines at least two potential alternatives for further negotiation, including a network service option and an asset ownership rights option on certain of Idaho Power's and PacifiCorp's transmission systems. Any party may terminate the 2012 MOU at any time, without penalty, and the 2012 MOU automatically expires on December 31, 2014. AMI/Smart Grid and American Recovery and Reinvestment Act of 2009 (ARRA): The advanced metering infrastructure (AMI) project provides the means to automatically retrieve energy consumption information, eliminating manual meter reading expense. In December 2011, Idaho Power completed the installation of this technology for approximately 99 percent of its customers, installing approximately 488,000 AMI meters at a cost of $71.8 million.
Under the ARRA, Idaho Power was awarded a grant of $47 million from the U.S. Department of Energy (DOE). This grant matches a $47 million investment by Idaho Power in Smart Grid technology, including AMI. The grant was signed by the DOE on April 2, 2010 and applies to project costs incurred beginning in August 2009 for a three-year term. As of December 31, 2011, Idaho Power had invoiced approximately $33.2 million from the DOE, of which $32.8 million had been received, and expects to continue billing and collecting monthly over the remaining term of the award. The costs to be reimbursed by the grant are not included in the Capital Requirements table above.
Environmental Regulation Costs: As of the date of this report, Idaho Power estimates incurring approximately $60 million in capital and operating costs for environmental facilities during 2012. Hydroelectric facility expenses, including costs for relicensing the HCC, and thermal plant expenses account for approximately $33 million and $27 million, respectively. From 2013 through 2014, total environmental-related operating and capital costs are estimated to be approximately $205 million. Expenses related to the hydroelectric facilities during that period are expected to be $79 million and include costs associated with the relicensing of the HCC. Thermal plant expenses are expected to total $126 million during this period. The capital portion of these amounts are included in the Capital Requirements table above but do not include costs related to possible changes in current or new environmental laws or regulations and enforcement policies that may be enacted in response to issues such as climate change and emissions from coal-fired and gas-fired generation plants.
Other Capital Requirements: IDACORP's non-regulated capital expenditures have primarily related to IFS's tax-structured investments. As of the date of this report, IDACORP does not anticipate any significant expenditures for 2012 through 2014.
Retirement Benefit Plans
Idaho Power made a $60 million contribution in 2010 and an $18.5 million contribution in 2011 to its defined benefit pension plan. In 2012 and beyond, Idaho Power expects significant contribution obligations under its retirement benefit plans. Refer to Note 11 - "Benefit Plans" to the consolidated financial statements included in this report and to the section titled "Contractual Obligations" below in this MD&A for information relating to those obligations.
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Contractual Obligations
The following table presents IDACORP’s and Idaho Power’s contractual cash obligations for the respective periods in which they are due:
Idaho Power:Long-term debt(1)
Future interest payments(2)
Operating leasesPurchase obligations:
Cogeneration and small power productionLarge power production(3)
Fuel supply agreementsPurchased power & transmission(4)
Other(5)
Pension and postretirement benefit plans(6)
Other long-term liabilities - Idaho PowerTotal Idaho Power
OtherTotal IDACORP
(1) For additional information, see Note 4 – “Long-Term Debt” to the consolidated financial statements included in this report.(2) Future interest payments are calculated based on the assumption that all debt is outstanding until maturity. For debt instruments with variable rates, interest is calculated for all future periods using the rates in effect at December 31, 2011.(3) Large power production relates to the Langley Gulch power plant and includes two contracts with Siemens Energy, Inc. relating to the purchase of a gas turbine and the purchase of a steam turbine, and an Engineering, Procurement and Construction Services Agreement with Boise Power Partners Joint Venture, a joint venture consisting of Kiewit Power Engineers Co. and TIC-The Industrial Company, for design, engineering, procurement, construction management, and construction services for Langley Gulch.(4) Approximately $9 million of the obligations included in purchased power and transmission have contracts that do not specify terms related to expiration. As these contracts are presumed to continue indefinitely, 10 years of information estimated based on current contract terms has been included in the table for presentation purposes.(5) Approximately $81 million of the amounts in other purchase obligations are contracts that do not specify terms related to expiration. As these contracts are presumed to continue indefinitely, 10 years of information, estimated based on current contract terms, has been included in the table for presentation purposes.(6) Idaho Power estimates pension contributions based on actuarial data. As of the date of this report, Idaho Power cannot estimate pension contributions beyond 2016 with any level of precision, and amounts through 2016 are estimates only. For more information on pension and postretirement plans, refer to Note 11 – "Benefit Plans" to the consolidated financial statements included in this report.
Payment Due by PeriodTotal
(millions of dollars)$ 1,492
1,26827
4,673
1934027
160286
18,293
1$ 8,294
2012
$ 101792
1471979115141—
530—
$ 530
2013-2014
$ 72145
6
405—
1318
43103—
9131
$ 914
2015-2016
$ 2141
3
433—324
25100—
740—
$ 740
Thereafter
$ 1,31790316
3,688
—984
41421
6,110—
$ 6,110
Dividends The amount and timing of dividends paid on IDACORP’s common stock are within the discretion of IDACORP’s board of directors. IDACORP's board of directors reviews the dividend rate periodically to determine its appropriateness in light of IDACORP’s current and long-term financial position and results of operations, capital requirements, rating agency requirements, contractual and regulatory restrictions, legislative and regulatory developments affecting the electric utility industry in general and Idaho Power in particular, competitive conditions, and any other factors the board of directors deems relevant. The ability of IDACORP to pay dividends on its common stock is dependent upon dividends paid to it by its subsidiaries, primarily Idaho Power. At its November 2011 meeting, the IDACORP board of directors adopted a dividend policy for IDACORP that provides for a target long-term dividend payout ratio of between 50 and 60 percent of sustainable IDACORP earnings, with the flexibility to achieve that payout ratio over time and to adjust the payout ratio or to deviate from the target payout ratio from time to time based on the various factors that drive the board's dividend decisions. Notwithstanding the dividend policy adopted by the IDACORP board, the dividends IDACORP pays remain in the discretion of the board of directors who, when evaluating the dividend amount, will continue to take into account the foregoing factors, among others. On January 19, 2012, IDACORP's board of directors voted to increase the quarterly dividend payable February 29, 2012 to $0.33 per share of IDACORP common stock, from the prior quarterly dividend amount of $0.30 per share of IDACORP common stock. For additional information relating to IDACORP and Idaho Power dividends, including restrictions on IDACORP’s and Idaho Power’s payment of dividends, see Note 6 – “Common Stock” to the consolidated financial statements included in this report.
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Contingencies and Proceedings
IDACORP and Idaho Power are involved in a number of litigation, alternative dispute resolution, and administrative proceedings, and are subject to claims and legal actions arising in the ordinary course of business, that could affect their future earnings and financial condition. Certain legal proceedings to which IDACORP or Idaho Power are parties or are otherwise involved are described in Note 10 - "Contingencies" to the consolidated financial statements included in this report. Except where noted in Note 10, IDACORP and Idaho Power are unable to predict the outcomes of the matters or estimate the impact the proceedings may have on their financial positions, results of operations, or cash flows.
Off-Balance Sheet Arrangements
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. At 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.
REGULATORY MATTERS Overview
Idaho Power continues to focus on timely recovery of its costs through filings with the IPUC, OPUC, and the FERC. The discussion below highlights certain notable regulatory determinations and pending matters or issues that may have a material impact on IDACORP's and Idaho Power's business or results. Regulatory matters, and in many cases their financial impact on IDACORP and Idaho Power, are also discussed in Note 3 - “Regulatory Matters” to the consolidated financial statements included in this report, which should be read in conjunction with the discussion below.
Idaho and Oregon Significant Rate Changes
As a regulated utility, the prices that the IPUC and OPUC authorize Idaho Power to charge for its retail services is a major factor in determining IDACORP’s and Idaho Power’s results of operations and financial condition. The table below summarizes notable rate increases and decreases, shown on an annualized basis, in recent years. Certain of the regulatory actions that resulted in the rate increases and decreases are described in more detail in this section of MD&A or in Note 3 - “Regulatory Matters” to the consolidated financial statements included in this report.
Description2008 Idaho general rate case2008 Idaho general rate case2009 Idaho PCA2009 Idaho AMI2009 Oregon APCU2009 Oregon general rate case settlement2010 Idaho settlement2010 Idaho PCA2010 Idaho pension expense recovery2011 Idaho PCA2011 Idaho pension expense recovery2011 Idaho general rate case settlement
Change in Deferred (Accrued) Net Power Supply Costs Deferred power supply costs represent certain differences between Idaho Power's actual net power supply costs and the costs included in its retail rates, the latter being based on annual estimates of power supply costs. Deferred power supply costs are recorded on the balance sheets for future recovery or refund through customer rates. The table below summarizes the change in deferred net power supply costs over the last two years.
Balance at December 31, 2009Costs deferred through PCA and PCAMPrior costs expensed and recovered through ratesSO2 allowances credited to accountInterest and otherBalance at December 31, 2010Current period net power supply costs accruedPrior costs expensed and recovered through ratesTransfer of energy efficiency expendituresSO2 allowance and renewable energy certificate (REC) salesInterest and otherBalance at December 31, 2011(1) Oregon power supply cost deferrals are subject to a statute that specifically limits rate amortizations of deferred costs to six percent of gross Oregon
revenue per year (approximately $2 million). Deferrals are amortized sequentially.
Idaho$ 71,412
14,324(63,757)(4,504)
8417,559
(27,768)(6,849)10,000(5,884)
(179)$ (13,121)
Oregon(1)
$ 13,221—
(1,792)79
68612,194(1,523)(2,357)
—(447)623
$ 8,490
Total$ 84,633
14,324(65,549)(4,425)
77029,753
(29,291)(9,206)10,000(6,331)
444$ (4,631)
2011 Idaho General Rate Case 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. In its general rate case application, Idaho Power requested an additional $82.6 million in annual revenues in Idaho-jurisdictional base rates, comprised of approximately $71.3 million related to revenue requirement categories other than net power supply expenses (non-NPSE) and $11.3 million associated with net power supply expenses (NPSE).
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. The settlement stipulation provided for a reduction of approximately $25.8 million to the requested non-NPSE recovery, resulting in a $45.5 million increase in the non-NPSE components of Idaho-jurisdictional base rates. The settlement stipulation also provided that approximately $22.8 million of Idaho-jurisdictional revenue associated with the recovery of NPSE associated with PURPA power costs would not be included in base rates, but would instead be eligible for 100 percent recovery through the Idaho PCA mechanism if the costs are incurred. Idaho Power's requested Idaho jurisdictional base rate increase and the adjustments reflected in the settlement stipulation are summarized in the table below (in millions).
As filed in general rate caseAdjustments in settlement stipulationTotal settlement stipulation
Non-NPSE$ 71.3
(25.8)$ 45.5
NPSE$ 11.3
(22.8)$ (11.5)
Total$ 82.6
(48.6)$ 34.0
The settlement stipulation provided for a 7.86 percent authorized rate of return on an Idaho-jurisdictional rate base of approximately $2.36 billion. On December 30, 2011, the IPUC issued an order approving the settlement stipulation, with new rates effective January 1, 2012. Neither the order nor the settlement stipulation specified an authorized rate of return on equity. Additional details relating to the 2011 Idaho general rate case and settlement are included in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.
December 2011 Idaho Settlement Agreement
On January 13, 2010, the IPUC approved a settlement agreement among Idaho Power, several of Idaho Power’s customers, the IPUC Staff, and others, in connection with a general rate case. Significant elements of the January 2010 settlement agreement included, among other items:
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• a provision to share with Idaho customers 50 percent of any Idaho-jurisdiction earnings in excess of a 10.5 percent Idaho ROE 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 ROE is below 9.5 percent in any calendar year from 2009 to 2011 in its Idaho jurisdiction. Idaho Power was permitted to amortize additional ADITC in an amount up to $45 million over the three-year period, with specified annual limits.
Because Idaho Power’s Idaho ROE was between 9.5 and 10.5 percent in 2009 and 2010, the sharing and accelerated amortization 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 2011 Idaho ROE and contributed to the triggering of the sharing mechanism. In accordance with the January 2010 settlement agreement, Idaho Power recorded a $27.1 million regulatory liability in 2011, reflecting 50 percent of Idaho Power's 2011 Idaho-jurisdictional earnings above a 10.5 percent Idaho ROE required to be shared with Idaho customers. The sharing and amortization provisions of the January 2010 settlement agreement terminated on December 31, 2011.
On December 27, 2011, the IPUC issued an order 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 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 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 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.
In consideration of these terms, the settlement stipulation provided that Idaho Power will allocate to customers 75 percent of Idaho Power's share of 2011 Idaho-jurisdictional earnings over a 10.5 percent Idaho ROE. As a result, Idaho Power recorded a pre-tax charge to pension expense of approximately $20.3 million in 2011, representing the additional amount to be allocated to Idaho customers. After the combined effect of the 50 percent sharing mechanism in the January 2010 settlement agreement and the December 2011 settlement order that provided for additional sharing, Idaho Power retained 12.5 percent of Idaho-jurisdiction earnings exceeding a 10.5 percent Idaho ROE.
OPUC Deferral Request: On November 17, 2011, the OPUC Staff filed an application seeking authorization from the OPUC to defer in the Oregon jurisdiction $2.9 million of the benefit resulting from the uniform capitalization tax method change. Idaho Power is opposing the application, and hearings and briefs are scheduled for mid-2012.
Idaho Defined Benefit Pension Plan Contribution Recovery
In September 2010, Idaho Power made a $60 million contribution to its defined benefit pension plan. To provide for timely recovery in rates of that contribution, 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 June 1, 2011. Idaho Power also expects to continue to make additional significant cash contributions to its defined benefit pension plan through at least 2016. For estimated defined benefit pension plan funding obligations, refer to Note 11 - "Benefit Plans" to the consolidated financial statements included in this report and "Critical Accounting Policies and Estimates - Pension and Other Postretirement Benefits" in this MD&A.
The order issued by the IPUC pertaining to the December 2011 Idaho settlement agreement described above provided that Idaho Power's allocation to customers of 75 percent of Idaho Power's share of 2011 Idaho ROE over 10.5 percent would be in the form of a $20.3 million reduction to Idaho Power's pension regulatory asset to reduce the future customer obligation.
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Langley Gulch Power Plant Ratemaking
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. Based on the current project status, Idaho Power estimates that the plant will be in service by July 1, 2012. Idaho Power plans to time the filing of its applications with the IPUC and OPUC for recovery of construction costs such that regulatory authority for collection of those costs is issued, and customer rates adjusted, as near as practicable to the project's commercial in-service date.
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. 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.
2011 Integrated Resource Plan
As a public utility under the jurisdiction of the FERC, the IPUC, and the OPUC, Idaho Power is obligated to plan for and expand its transmission system to provide requested firm transmission service to third parties, to construct and place in service sufficient generation and transmission capacity to reliably deliver resources to network customers and the company’s retail customers, and otherwise take actions to fulfill its obligation to provide safe and reliable electric service. As part of its resource planning, and in accordance with regulatory requirements, Idaho Power prepares and publishes an IRP every two years. The IRP addresses available supply-side and demand-side resource options, planning period load forecasts, potential resource portfolios, a risk analysis, and near-term and long-term action plans.
Idaho Power filed its 2011 IRP with the IPUC and OPUC on June 30, 2011. In developing its 2011 IRP, Idaho Power forecast the number of customers in Idaho Power’s service area will increase approximately 1.5 percent per year, from approximately 492,000 at the end of 2010 to over 650,000 by the end of the IRP's 20-year planning period in 2030. The 2011 IRP expected-case load forecast projects peak-hour load will grow 69 MW annually and average-system load will increase annually 29 average MW (aMW) over the 20-year planning period, with an expected-case, average annual system load of 2,362 aMW by 2030.
Idaho Power intends to meet the anticipated increase in demand through energy efficiency and demand response programs, the development of transmission capacity and additional generation resources, such as its 300 MW Langley Gulch natural gas-fired power plant currently under construction, and from the purchase of power from third parties, including from renewable energy projects and market power purchases. Idaho Power stated in the 2011 IRP that it expects energy efficiency programs to result in 233 aMW of load reduction by 2030, and that demand response programs are targeted to reduce peak summer load by 351 MW by summer 2016. The 2011 IRP also identifies transmission constraints as a significant issue for Idaho Power. Idaho Power is in the process of developing the Boardman-to-Hemingway transmission project in an effort to alleviate in part its transmission capacity constraint from the Pacific Northwest.
On December 30, 2011, the IPUC issued an order accepting Idaho Power's 2011 IRP. The order directed Idaho Power to continue to address a number of items, including: (a) comparing the risk, cost, and environmental benefits of strategies that directly reduce emissions from its resource mix to the purchase of emission offsets or offset options, (b) redoubling its efforts to realize the achievable potential for savings from efficiency and DSM programs, and (c) addressing the risks of reliance on natural gas in its resource portfolio. The order also directs Idaho Power to provide as part of its 2013 IRP additional information and/or analyses related to the Gateway West transmission project involvement, Idaho Power's proposed solar demonstration project, HCC relicensing efforts, early retirement of existing coal plants, and the quantification of transmission siting and market price risks.
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PURPA Power Purchase Contracts
Pursuant to the requirements of Section 210 of PURPA, the IPUC and OPUC have each issued orders and rules regulating Idaho Power's purchase of power from cogeneration and small power production facilities. A key component of the PURPA power purchase contracts is the energy price contained within the agreements. Regulatory-mandated execution of PURPA agreements may result in Idaho Power acquiring energy it does not need at above wholesale market prices and require additional operational integration measures, thus increasing costs to Idaho Power's customers. Substantially all PURPA power purchase costs are recovered through base rates and Idaho Power's power supply cost mechanisms, and thus the primary impact of the PURPA agreements is on customer rates.
Idaho Proceedings: In response to a November 5, 2010 application filed by Idaho Power and two other electric utilities with Idaho service territories, on February 7, 2011, the IPUC issued an order temporarily reducing the eligibility cap for PURPA projects entitled to published avoided cost rates from 10 aMW to 100 kW for wind and solar PURPA projects while the IPUC further investigated the implications of large projects disaggregating into smaller projects to qualify for higher published avoided cost rates and other benefits. On June 8, 2011, the IPUC issued an order maintaining the 100 kW eligibility cap for published avoided cost rates for wind and solar PURPA projects, and initiating additional proceedings to allow the parties to investigate and analyze the methodologies used in determining the appropriate power purchase price for PURPA projects. On that same date, the IPUC issued orders disapproving 13 wind power purchase agreements. Idaho Power estimates that the payments over the lives of the disapproved agreements would have totaled approximately $1.3 billion.
Idaho Power remains engaged in proceedings at the IPUC relating to the determination of appropriate power purchase prices and other terms of PURPA power purchase agreements. The IPUC has established a timeline for various informational filings by all parties to the case, with hearings scheduled for August 2012. On January 31, 2012, Idaho Power submitted written testimony in the PURPA proceedings, in support of Idaho Power's request that the IPUC (a) change the methodology used to establish power purchase prices for PURPA projects, (b) reduce the maximum authorized PURPA power purchase agreement term from the existing 20 years to a maximum of five years, and (c) authorize a curtailment strategy that would allow Idaho Power to optimize use of its cost-effective resources.
Oregon Proceedings: In response to two filings Idaho Power made with the OPUC in January 2012, on February 14, 2012 the OPUC issued an order effectively imposing a 60 day prohibition on Idaho Power's entering into standard contracts with qualified PURPA facilities, allowing Idaho Power time to update its avoided cost rate through the IRP process prior to executing standard PURPA contracts. In the same order, the OPUC declined to reduce the eligibility cap for standard contracts from its current level of 10 MW to 100 kW. Idaho Power expects to be engaged in proceedings at the OPUC to resolve the same or similar issues being presented in the IPUC PURPA matters. Bonneville Power Administration Residential Exchange Program The Pacific Northwest Electric Power Planning and Conservation Act of 1980, through the Residential Exchange Program (REP), provides for access to the benefits of low-cost federal hydroelectric power to residential and small farm customers of the region's investor-owned utilities (IOUs). The program is administered by the BPA. Pursuant to agreements between the BPA and Idaho Power, benefits from the REP were passed through to Idaho Power’s Idaho and Oregon residential and small farm customers in the form of electricity bill credits. However, on May 3, 2007, the U.S. Court of Appeals for the Ninth Circuit ruled that the settlement agreements entered into between the BPA and the IOUs (including Idaho Power) were inconsistent with the Northwest Power Act. As a result, on May 21, 2007, the BPA notified Idaho Power and six other IOUs that it was immediately suspending the REP payments. Subsequently, Idaho Power worked with other northwest IOUs and consumer-owned utilities, Pacific Northwest public utility commissions, and the BPA to craft an agreement so that residential and small farm customers of Idaho Power can resume sharing in the benefits of the federal Columbia River power system. The BPA approved an REP settlement agreement in a Record of Decision dated July 26, 2011 and committed the BPA to perform its obligations under the settlement agreement in accordance with its terms. Updated rates became effective January 1, 2012. Since any benefits will pass directly through to Idaho Power's eligible residential and small farm customers, the settlement is not expected to have a material effect on Idaho Power's financial condition or results of operations.
FERC Compliance Programs
The FERC has approved an extensive number of reliability standards developed by the North American Electric Reliability Corporation and the WECC, including critical infrastructure protection (CIP) standards and regional standard variations. As part of its compliance program, Idaho Power periodically reviews its operations for compliance with FERC rules, orders, and standards and self-reports compliance issues to the FERC and the WECC. Recent reports Idaho Power has submitted to the
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FERC have generally focused on Standards of Conduct and Idaho Power’s FERC OATT. Consistent with prior years, during the year ended December 31, 2011, Idaho Power self-reported to the FERC and received notices of alleged violations from the FERC and the WECC. Idaho Power has also received notification that the FERC intends to take no further action regarding several issues previously reported by Idaho Power.
Consistent with its historical practice, Idaho Power is working with the FERC and the WECC to resolve alleged violations and items it self-reported to the FERC and the WECC. Idaho Power is unable to predict what action, if any, the WECC or the FERC will take on those unresolved matters, but based on the nature of the potential violations Idaho Power does not expect any material adverse effect from currently alleged violations on its financial position, results of operations, or cash flows. Idaho Power plans to continue its efforts to reduce potential violations through its compliance program and its approach of self-reporting compliance issues to, and working with, the FERC and the WECC.
Relicensing of Hydroelectric Projects Idaho Power, like other utilities that operate nonfederal hydroelectric projects on qualified waterways, obtains licenses for its hydroelectric projects from the FERC. These licenses last for 30 to 50 years depending on the size, complexity, and cost of the project. Idaho Power is actively pursuing the relicensing of the HCC and the Swan Falls project (SFP). In addition, in July 2010 Idaho Power received a license amendment to expand the Shoshone Falls hydroelectric project and to potentially extend the term of the license beyond its 2034 expiration date. Hells Canyon Complex: The most significant ongoing relicensing effort is the HCC, which provides approximately 68 percent of Idaho Power’s hydroelectric generating nameplate capacity and 36 percent of its total generating nameplate capacity. In July 2003, Idaho Power filed an application for a new license in anticipation of the July 2005 expiration of the then-existing license. In connection with the relicensing process, in August 2007 the FERC Staff issued a final EIS for the HCC, which the FERC will use to determine whether, and under what conditions, to issue a new license for the project. The purpose of the final EIS is to inform the FERC, federal and state agencies, Native American tribes, and the public about the environmental effects of Idaho Power’s operation of the HCC. Certain portions of the final EIS involve issues that may be influenced by water quality certifications for the project under section 401 of the Clean Water Act (CWA) and formal consultations under the Endangered Species Act (ESA), which remain unresolved. Because the HCC is located on the Snake River where it forms the border between Idaho and Oregon, Idaho Power has filed Water Quality Certification Applications, required under section 401 of the CWA, with the States of Idaho and Oregon requesting that each state certify that any discharges from the project comply with applicable state water quality standards. Water quality issues are of interest to various federal and state agencies, Native American tribes, and other parties who may provide input to the states’ certification process. Section 401 of the CWA requires that a state either approve or deny a 401 water quality certification application within one year of the filing of the application or the state may be considered to have waived its certification authority under the CWA. As a consequence, Idaho Power has been filing and withdrawing its section 401 certification applications with Oregon and Idaho on an annual basis while it has been working with the states to identify measures that will provide reasonable assurance that discharges from the HCC will adequately address applicable water quality standards. On September 13, 2007, in connection with the issuance of its final EIS, the FERC notified the NMFS and the USFWS of its determination that the licensing of the HCC was likely to adversely affect ESA-listed species under the NMFS’s and USFWS’s jurisdiction and requested that the NMFS and USFWS initiate formal consultation under Section 7 of the ESA on the licensing of the HCC. Each of the NMFS and USFWS responded to the FERC that the conditions relating to the licensing of the HCC were not fully described or developed in the final EIS as the measures to address the water quality effects of the project were yet to be fully defined by the Section 401 certification process pending before the Oregon and Idaho Departments of Environmental Quality. The NMFS and USFWS therefore recommended that formal consultation under the ESA be delayed until the Section 401 certification process is completed. Idaho Power continues to work with Idaho and Oregon in the development of measures to provide reasonable assurance that any discharges from the HCC will comply with applicable state water quality standards so that appropriate water quality certifications can be issued for the project, and continues to cooperate with the USFWS, NMFS, and the FERC in an effort to address ESA concerns.
Idaho Power expects the FERC to issue a license order for the HCC once the ESA consultation and the state water quality certification processes are completed. Idaho Power is currently operating under an annual license issued by the FERC and expects to continue operating under annual licenses until a new multi-year license is issued. Swan Falls Project: The existing license for the SFP expired in June 2010. Idaho Power is currently operating the SFP under
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an annual license while its application for a multi-year license is pending before the FERC. In August 2010, the FERC issued a final EIS in connection with the relicensing of the SFP. The Snake River physa snail, a species listed as endangered under the ESA, was found in the area during the EIS review. In February 2012, the USFWS issued a biological opinion to address the project's effects on the Snake River physa snail. The biological opinion includes a provision for the incidental take of the snail for purposes of licensing and continued operation of the project. Idaho Power is required to study the status of the Snake River physa snail and its habitat within and downstream of the project area for the term of the new license, which Idaho Power anticipates will be between 30 and 50 years. Idaho Power expects the FERC to issue a license for the SFP in the second quarter of 2012. Treatment of Relicensing Costs: Relicensing costs are recorded in construction work in progress until new multi-year licenses are issued by the FERC, at which time the charges are transferred to electric plant in service. Relicensing costs and costs related to new licenses will be submitted to regulators for recovery through the ratemaking process. Relicensing costs of $145 million and $5 million for HCC and SFP, respectively, were included in construction work in progress at December 31, 2011. As of the date of this report, the IPUC authorizes Idaho Power to include in its Idaho-jurisdictional rates approximately $6.5 million annually ($10.7 million grossed up for income taxes) of AFUDC relating to the HCC relicensing project, and collecting these amounts will reduce the relicensing amount submitted to regulators for recovery through the ratemaking process. Through December 31, 2011, Idaho Power has collected $31 million of AFUDC related to the HCC relicensing project through customer rates.
Shoshone Falls Expansion: On July 1, 2010, the FERC amended the license for the Shoshone Falls project to expand its generating capacity to approximately 61 MW. The amended license has an expiration date of 2034, but provides that the license will be extended to 2044 following completion of the proposed generation capacity expansion project. Idaho Power filed a request for a two-year schedule extension with the FERC in January 2012 as it continues to evaluate the project and the associated license requirements, costs, and operating issues, which if granted would change Idaho Power's estimated in-service date for the upgrades (if ultimately undertaken) from 2015 to 2017.
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ENVIRONMENTAL MATTERS Overview
Idaho Power is subject to regulations by federal, state, and local authorities governing the protection of the environment, including at the federal level the CAA; the CWA; the Comprehensive Environmental Response, Compensation and Liability Act; the Emergency Planning and Community Right-to-Know Act; the ESA; the Federal Land Policy and Management Act; the National Environmental Policy Act; and the Resource Conservation and Recovery Act. These laws and regulations are continuously changing and are generally becoming more restrictive. Idaho Power monitors legislative and regulatory developments at all levels of government for environmental issues, particularly those with the potential to alter the operation and productivity of power generating plants and other assets. Environmental laws and regulations may, among other things, increase the cost of operating power generation plants and constructing new facilities; require that Idaho Power install additional pollution control devices at existing generating plants; or require that Idaho Power discontinue operating certain power generation plants. While there can be no assurance of recovery, Idaho Power intends to seek recovery of any such costs through the ratemaking process. Idaho Power co-owns three coal-fired power plants and owns two natural gas combustion turbine power plants that are subject to air quality regulation. Additionally, Idaho Power is in the process of construction and start-up of the Langley Gulch power plant, a natural gas-fired generating plant. The CAA establishes controls on the emissions from stationary sources like those owned by Idaho Power. The EPA adopts many of the standards and regulations under the CAA, while states have the primary responsibility for implementation and administration of these air quality programs. Also, the FERC licenses issued for Idaho Power's hydroelectric generating plants impose numerous environmental requirements, such as aeration of water discharged through turbines to meet dissolved gas and temperature standards in the tail waters downstream from the plants. Idaho Power monitors these issues and reports the results to the appropriate regulatory agencies. Idaho Power continues to actively monitor, evaluate, and work on water quality and air quality issues. These items are discussed in greater detail below.
Idaho Power continues to actively monitor pollution control standards as they are promulgated and their associated costs to Idaho Power as they relate to the economic and operational feasibility of generation plants. In its order acknowledging Idaho Power’s 2009 IRP, the OPUC directed Idaho Power to analyze (a) any potential EPA, state, and other federal agency regulations associated with air quality, fly ash, and water that may affect Idaho Power’s generation facilities, and (b) coal curtailment and the costs associated with coal plant retirement, and include the results of this analysis in its 2011 IRP. Idaho Power filed its 2011 IRP in June 2011 with the IPUC and OPUC, and the IRP contains the analysis requested by OPUC. While not currently quantifiable, Idaho Power anticipates that a number of impending EPA rulemakings addressing, among other things, ozone and fine particulate matter pollution, emissions, and disposal of coal combustion residuals could result in substantially increased operating and compliance costs.
In addition to the items below, also refer to Note 10 - "Contingencies" to the consolidated financial statements included in this report for additional information regarding certain environmental proceedings affecting Idaho Power's properties and Item 1- "Business - Environmental Regulation and Costs" in this report. Global Climate Change and GHG Emission Intensity Reduction Goal
There is concern nationally and internationally about climate change and the possible contribution of greenhouse gas (GHG) emissions to climate change. Long-term climate change could significantly affect Idaho Power’s business in a variety of ways, including:
• changes in temperature and precipitation could affect customer demand; • extreme weather events could increase service interruptions, outages, maintenance costs, and the need for additional
backup systems, and can affect the supply of, and demand for, electricity and natural gas, which may impact the price of energy commodities;
• changes in the amount and timing of snowpack and stream flows could adversely affect hydroelectric generation; • legislative and/or regulatory developments related to climate change could affect plans and operations, including
restrictions on the construction of new generation resources, the expansion of existing resources, or the operation of generation resources in general; and
• consumer preference for, and resource planning decisions requiring, renewable or low GHG-emitting sources of energy could impact usage of existing generation sources and require significant investment in new generation and transmission infrastructure.
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Idaho Power does not currently operate in coastal areas and, while there may be secondary impacts, it is not directly exposed to the effects of potential sea level rises that some experts predict may result from global climate change. Despite the current absence of a national mandatory GHG reduction program, Idaho Power is engaged in voluntary GHG emission intensity reduction efforts. In September 2009, IDACORP’s and Idaho Power’s boards of directors approved guidelines that established a goal to reduce the CO2 emission intensity of Idaho Power’s utility operations. Idaho Power’s goal is to reduce its resource portfolio’s average CO2 emission intensity for the 2010 through 2013 time period to a level of 10 to 15 percent below Idaho Power’s 2005 CO2 emission intensity of 1,194 lbs CO2/MWh. The guidelines are intended to reduce Idaho Power’s average CO2 emission intensity in a manner that minimizes the costs of those reductions to Idaho Power’s customers. In May 2010 and May 2011, Idaho Power submitted information to the Carbon Disclosure Project, an independent, not-for-profit organization that claims the largest database of corporate climate change information in the world. Idaho Power’s estimated CO2 emission intensity (lbs/MWh) from its generation facilities as submitted to the Carbon Disclosure Project was 1,051, 1,004, 1,097, and 1,150 lbs/MWh for 2010, 2009, 2008, and 2007 respectively. In 2008, Idaho Power and Ida-West together ranked as the 32nd lowest emitter of CO2 per MWh produced and the 31st lowest emitter of CO2 by tons of emissions among the nation’s 100 largest electricity producers, according to a June 2010 collaborative report from Ceres, the Natural Resources Defense Council, Public Service Enterprise Group, Constellation Energy, and Entergy using publicly reported 2008 generation and emissions data. According to the report, out of the 100 companies named, Idaho Power and Ida-West together ranked as the 55th largest power producer based on fossil fuel, nuclear, and renewable energy facility total electricity generation. Environmental Regulation
Regulation of Greenhouse Gas Emissions: In recent years, there have been a number of bills introduced in the U.S. Congress relating to GHG emissions, renewable energy, energy efficiency, carbon capture and sequestration, and other matters. However, given the complexities of this form of legislation and other competing legislative priorities, the timing and elements of any future legislation addressing GHG emission reduction requirements are uncertain. There are also state and regional initiatives (including the Western Regional Climate Action Initiative) considering market-based mechanisms to reduce GHG emissions. Further, in support of international efforts to reduce GHG emissions, in January 2010 the Obama Administration pledged to cut GHG emissions in the United States from 2005 levels by 17 percent by 2020 and 80 percent by 2050. However, any international treaty creating mandatory GHG emission reduction requirements in the United States would require Congressional approval. In June and December 2010, the EPA issued final rules regulating GHG emissions through its pre-construction and operating permit programs under the CAA. These rules are referred to as the “Tailoring Rule” and GHG Permitting Rules. The first phase of the rules took effect in January 2011 and required imposition of Best Available Control Technology (BACT) for GHG emissions if a new major source or modification of an existing major source is projected to result in GHG emissions of at least 75,000 tons per year (CO2 equivalent). In addition, existing major sources were required to include applicable requirements relating to GHGs in their operating permits when the permits are renewed or the major source is modified. Idaho Power believes that its owned and co-owned generation plants are in compliance with the new GHG emission regulations. In August 2007, the Oregon legislature enacted legislation establishing goals for the reduction of GHG emissions, which sought to cease the growth of Oregon GHG emissions by 2010, and seek to (a) by 2020, reduce GHG levels to 10 percent below 1990 levels; and (b) by 2050, reduce GHG levels to at least 75 percent below 1990 levels. The legislation also calls for state government-developed policy recommendations in the future to assist in the monitoring and achievement of these goals. Idaho Power will continue to monitor and evaluate proposed international, federal, state, and regional GHG legislation or initiatives as well as judicial decisions that could affect its generating facilities and operations. Some recent initiatives regarding GHG emissions contemplate market-based compliance programs, such as cap-and-trade programs or emission offsets. The regulation of GHG emissions under the CAA could result in GHG emission limits on stationary sources that do not provide market-based compliance options. Such a program could raise uncertainty about the future viability of fossil fuels, specifically coal, as an economical energy source for new and existing electric generation facilities because new technologies for reducing CO2 emissions from coal, including carbon capture and storage, are still in the development stage and are not yet proven. Emission standards could require significant increases in capital expenditures and operating costs, which may accelerate the retirement of older, less-efficient coal-fired units. There are financial, regulatory, and logistical uncertainties related to GHG reductions and the implementation of renewable
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energy mandates. The impact on Idaho Power of currently proposed legislation relating to GHG emissions would depend on a variety of factors, including the specific GHG emissions limits or renewable energy requirements, the timing of implementation of these limits or requirements, the level of emissions allowances allocated and the level that must be purchased, the purchase price of emissions allowances, the development and commercial availability of technologies for renewable energy and for the reduction of emissions, the degree to which offsets may be used for compliance, provisions for cost containment (if any), the impact on coal and natural gas prices, and cost recovery through rates. Accordingly, Idaho Power cannot meaningfully predict the effect on its results of operations, financial position, or cash flows of any GHG emission, renewable energy mandate, or other global climate change requirements that may be adopted, although the costs to implement and comply with any such requirements could be substantial. Idaho Power would seek to recover these costs and expenditures from customers as costs of doing business but is unable to predict whether it would be permitted to recover some or all of the increased costs and expenditures from customers through rates. In its 2011 IRP, Idaho Power did not include any new conventional coal resources in the resource portfolio due to the uncertainty regarding future GHG regulations. IDACORP and Idaho Power’s boards of directors continue to review environmental issues on a regular basis and in connection with the review of the companies’ strategic plans. The boards of directors are also periodically informed of any new material environmental issues, including updates on any proposed legislation. Renewable Portfolio Standards: Legislation has been introduced in the U.S. Congress that would require utilities to obtain a specified percentage of their electricity from renewable sources, commonly referred to as a "renewable portfolio standard" or "RPS." However, as of the date of this report no federal RPS is in effect. Idaho Power will be required to comply with a 10 percent RPS in Oregon beginning in 2025, and Idaho Power expects to meet these requirements with the RECs from the Elkhorn Valley wind project. No RPS requirement currently exists in Idaho. Idaho Power continues to monitor proposed federal RPS legislation and the possibility of additional state RPS legislation. Utility Maximum Achievable Control Technology (MACT): In April 2010, the U.S. District Court for the District of Columbia approved a timetable that required the EPA to finalize a standard to control mercury emissions from coal-fired power plants by November 2011. In March 2011, the EPA released the proposed Utility Maximum Achievable Control Technology rule (Utility MACT Rule) to control emissions of mercury and other hazardous air pollutants (HAPs) from coal- and oil-fired electric utility steam generating units (EGUs) under the federal CAA. In the same notice, the EPA further proposed to revise the NSPS for fossil fuel-fired EGUs. In December 2011, the EPA finalized the Utility MACT Rule. The final Utility MACT Rule remains largely the same as the proposal. The final regulation imposes maximum achievable control technology and NSPS standards on all coal-fired EGUs and replaces the former Clean Air Mercury Rule. Specifically, the final regulation sets numeric emission limitations on coal-fired EGUs for total particulate matter (a surrogate for non-mercury HAPs), hydrogen chloride, and mercury. In addition, the final regulation imposes a work practice standard for organic HAPs, including dioxins and furans. The final regulation also sets work-practice standards to reduce emissions during start-up and shut-down. For the revised NSPS, for EGUs commencing construction of a new source after publication of the regulation, the EPA has established amended emission limitations for particulate matter, sulfur dioxide, and nitrogen oxides. Mercury continuous emission monitoring systems have been installed on all of the coal-fired units at the Jim Bridger, Boardman, and Valmy generating plants. However, Idaho Power is in the process of determining how these regulations will impact the Bridger, Boardman, and Valmy generating plants and what additional controls, if any, will need to be installed in order to comply with the regulations. Based on its evaluation as of the date of this report, Idaho Power does not foresee any plant closures due to the Utility MACT Rule and expects related compliance costs will not be substantial. National Ambient Air Quality Standards (NAAQS): In July 1997, the EPA adopted new NAAQS for ozone (8-hour ozone standard) and fine particulate matter of less than 2.5 micrometers in diameter (PM2.5 standard). In December 2006, the EPA revised the NAAQS for PM2.5. This new standard is the subject of a legal challenge by a number of groups. However, all of the counties in Idaho, Nevada, Oregon, and Wyoming where Idaho Power’s power plants are currently located were designated as meeting attainment with the revised PM2.5 NAAQS. In January 2010, the EPA adopted a new NAAQS for NO2 at a level of 100 parts per billion averaged over a 1-hour period. In addition, in June 2010 the EPA adopted a new NAAQS for SO2 at a level of 75 parts per billion averaged over a one-hour period. The various states and the EPA have not yet completed the designation of areas as attaining or not attaining these new NAAQS. As a result, Idaho Power is unable to predict what impact the adoption and implementation of these standards may have on its operations. Regional Haze – Best Available Retrofit Technology (RH BART): In accordance with federal regional haze rules, coal-fired utility boilers are subject to RH BART if they were built between 1962 and 1977 and affect any Class I areas. This includes all four units at the Jim Bridger plant and the Boardman plant. The two units at the Valmy plant were constructed after 1977 and are not, as of the date of this report, subject to the federal regional haze rule. The Wyoming Department of Environmental
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Quality (WDEQ) and the Oregon Department of Environmental Quality (ODEQ) have conducted assessments of the Jim Bridger and Boardman plants pursuant to an RH BART process. These states have also evaluated the need for additional controls at Jim Bridger and Boardman to achieve reasonable progress toward a long term strategy beyond RH BART to reduce regional haze in Class I areas to natural conditions by the year 2064. Jim Bridger Plant: In December 2009, the WDEQ issued a RH BART permit to PacifiCorp for the Jim Bridger plant. The WDEQ determined that low NOx burners with over-fire air is RH BART for NOx for all four Bridger units and that RH BART is not required for SO2 for the Jim Bridger plant. As part of the WDEQ’s long term strategy for regional haze, the permit requires that PacifiCorp install selective catalytic reduction (SCR) for NOx control at Jim Bridger Units 3 and 4 by December 31, 2015 and December 31, 2016, respectively, and submit an application by January 15, 2015 to install add-on NOx controls at Jim Bridger Units 1 and 2 by December 31, 2023. PacifiCorp is already in the process of installing low NOx burners and SO2 scrubber upgrades at the Jim Bridger plant. The SO2 scrubber upgrade project has been completed on all four Jim Bridger units. Idaho Power expects to spend approximately $2 million in 2012 to complete these pollution control projects. Idaho Power’s estimated share of the cost to install SCR on Jim Bridger Units 3 and 4 is $120 million. Installation of SCR also could require extended maintenance outages. Design and cost estimates for add-on NOx controls at Jim Bridger Units 1 and 2 are not yet available.
In February 2010, PacifiCorp filed an administrative appeal of the Jim Bridger RH BART permit with the Wyoming Environmental Quality Council (WEQC). PacifiCorp argued that the WDEQ lacked the legal and technical basis to require the SCR and add-on NOx controls required by the permit. In November 2010, PacifiCorp and the WDEQ signed a settlement agreement under which PacifiCorp has agreed to install SCR, alternative add-on NOx controls, or otherwise achieve a 0.07 lb/mmBtu 30-day rolling average NOx emission rate by December 31, 2015 for Unit 3 and December 31, 2016 for Unit 4. In addition, PacifiCorp has agreed to install SCR, alternative add-on NOx controls, or otherwise achieve a 0.07 lb/mmBtu 30-day rolling average NOx emission rate by December 31, 2021 for Unit 2 and December 31, 2022 for Unit 1. The settlement agreement is conditioned on the EPA ultimately approving those portions of the Wyoming Regional Haze State Implementation Plan (RH SIP) that are consistent with the terms of the settlement agreement. In light of the settlement agreement, PacifiCorp received a revised RH BART permit for Jim Bridger on November 24, 2010. In September 2011, a federal district court in Colorado approved a consent decree in the case of Wildearth Guardians v. Jackson pursuant to which the EPA must either propose to approve the Wyoming RH SIP or propose an alternate Federal Implementation Plan (FIP) by April 15, 2012. In addition, the EPA must either grant final approval to the Wyoming RH SIP or finalize an RH FIP for Wyoming by October 15, 2012. Boardman Power Plant: Following the introduction of various plans and an extensive public process, in December 2010 the OEQC approved a plan to cease coal-fired operations at the Boardman power plant not later than December 31, 2020. The rules implementing the plan were approved by the EPA and published in the Federal Register in July 2011, and require the installation of a number of emissions controls. The new rules repeal the OEQC's 2009 Best Available Retrofit Technology rule, which would have allowed continued operation of the Boardman plant through at least 2040 with installation of a more extensive suite of emissions controls. The estimated combined total capital cost of the required controls under the plan approved by the OEQC is approximately $60 million. Idaho Power is a 10 percent owner of the Boardman plant, and thus Idaho Power’s estimated share of the capital cost is $6 million, which is in addition to normal capital expenditures and maintenance costs. As of December 31, 2011, Idaho Power had paid $2.8 million of its total estimated share of the capital cost. In September 2011, the federal district court in Oregon approved a consent decree that settled a citizen suit brought by the Sierra Club against PGE alleging certain violations of the requirements of the CAA at the Boardman plant. Under the terms of the settlement, beginning in 2015 through 2020 PGE has agreed to cap and reduce annual sulfur dioxide emissions to levels lower than those specified in the OEQC plan described above and further agreed to pay certain public interest groups a total of $2.5 million for various air quality projects.
The scheduled 2020 shutdown of coal-fired operations at the Boardman plant results in increased revenue requirements for Idaho Power related to accelerated depreciation expense, additional plant investments, and decommissioning costs. As a result, in response to an application Idaho Power filed in September 2011, on February 14, 2012 the IPUC issued an order accepting Idaho Power's regulatory accounting and cost recovery plan associated with the early shut-down and approving the establishment of a balancing account whereby incremental costs and benefits associated with the early shut-down will be tracked for recovery in a subsequent proceeding. On February 15, 2012, Idaho Power filed an application with the IPUC requesting a $1.6 million annual increase in Idaho jurisdiction base rates to recover the incremental Idaho jurisdictional annual revenue deficiency associated with early shut-down. As of December 31, 2011, Idaho Power's net book value in the Boardman plant was approximately $25.9 million with annual depreciation of approximately $1.3 million.
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New Source Review (NSR): Since 1999, the EPA and the U.S. Department of Justice have been pursuing a national enforcement initiative focused on the compliance status of coal-fired power plants with the NSR permitting requirements and NSPS of the CAA. This initiative has resulted in both enforcement litigation and significant settlements with a large number of public utilities and other owners of coal-fired power plants across the country. The EPA sent information requests under the CAA, requesting information relevant to NSR and NSPS compliance, to the Jim Bridger plant in 2003, the Valmy plant in 2009, and the Boardman plant in 2008 with a follow up request for information in 2009. In September 2010, the EPA issued a Notice of Violation to PGE, alleging that PGE has violated the NSPS under Section III of the CAA and operating permit requirements under Title V of the CAA at the Boardman coal-fired plant as a result of certain modifications made to the plant in 1998 and 2004. See Note 10 - "Contingencies" to the consolidated financial statements included in this report for a discussion of the Boardman EPA Notice of Violation. Coal Combustion Residuals (CCRs): In December 2008, the breach of a dike at the Tennessee Valley Authority’s Kingston Station resulted in a spill of several million cubic yards of ash into a nearby river and onto private properties. In June 2010, the EPA proposed regulations pursuant to the Resource Conservation and Recovery Act governing the disposal and management of CCRs. The EPA requested comments on two options for regulating CCRs. The first would regulate CCRs as a new “special waste” subject to many of the requirements for hazardous waste, while the second would regulate CCRs in a manner similar to typical solid waste, subject to fewer and less stringent environmental requirements. The EPA initiated a public comment period and held public hearings, which ended in November 2011. Either of the EPA’s proposed options represents a shift toward more comprehensive and potentially more expensive requirements for CCRs disposal and management. If this or other new legislation or regulations increase the cost of managing and disposing of CCRs or create additional liability with respect to historic disposal practices, they could have an adverse impact on Idaho Power’s consolidated financial position, results of operations, or cash flows. However, the financial and operational consequences cannot be determined until final legislation is passed or regulations are enacted. Polychlorinated Biphenyls (PCBs): In April 2010, the EPA issued an advance notice of proposed rulemaking pursuant to the Toxic Substances Control Act regarding the use of PCBs. The EPA is considering revisiting the use authorization allowing the continued use of PCBs in equipment. If new regulations require the replacement of existing equipment, they could have an adverse effect on Idaho Power’s consolidated financial position, results of operations, or cash flows. However, the financial and operational consequences cannot be determined until final regulations are enacted. Idaho Power currently records asset retirement obligation liabilities and associated regulatory assets for the estimated retirement costs of equipment containing PCBs. Proposed regulations could accelerate Idaho Power’s estimated timing of the retirements of equipment with PCBs.
Clean Water Act Section 316(b): In March 2011, the EPA issued a proposed rule that would establish requirements under section 316(b) of the CWA for all existing power generating facilities and existing manufacturing and industrial facilities that withdraw more than 2 million gallons per day (MGD) of water from waters of the U.S. and use at least 25 percent of the water they withdraw exclusively for cooling purposes. The proposed rules would establish national requirements applicable to the location, design, construction, and capacity of cooling water intake structures at these facilities by setting requirements that reflect the best technology available (BTA) for minimizing adverse environmental impact. The existing facility may choose one of two options for meeting BTA requirements for impingement mortality under this proposed rule. The owner or operator may monitor to show the specified performance standards for impingement mortality of fish and shellfish have been met, or they may demonstrate that the intake velocity meets specified design criteria. For entrainment mortality, this proposed rule establishes requirements for studies and information as part of the permit application, and then establishes a process by which the BTA for entrainment mortality would be implemented at each facility. Idaho Power expects the draft rule to be issued in the first half of 2012. Based on the qualification criteria, Idaho Power expects that the new requirements would apply to the Jim Bridger plant, but is unable to determine the potential increased costs that may result from implementation of the rule until final rules are issued and it has performed cost studies.
Public Nuisance-Related Suits for GHGs
In December 2010, the U.S. Supreme Court granted certiorari in Connecticut v. American Electric Power, Inc., to review the opinion from the U.S. Court of Appeals for the Second Circuit granting plaintiffs standing to bring climate change-related public nuisance suits against six major emitters of greenhouse gases (GHGs). In June 2011, the U.S. Supreme Court held that federal courts do not have jurisdiction to hear federal common law nuisance claims relating to GHG emissions, because the legal authority to regulate GHGs has been delegated by Congress to the EPA, not to federal courts. Even though the Court rejected the merits of the plaintiffs' claim, the Court nevertheless held that the plaintiffs had the requisite legal standing to bring the claims. Finally, the Court remanded to the Second Circuit the issue of whether state common law nuisance claims would also be barred by the federal CAA. Accordingly, the decision of the Supreme Court in this case does not eliminate the potential
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for future nuisance-related suits based on GHG emissions.
Renewable Energy Certificates and Emission Allowances
Pursuant to an IPUC order, Idaho Power is selling its near-term RECs and returning to customers their share (shared 95% with customers in the Idaho jurisdiction) of those proceeds through the PCA. For the year ended December 31, 2011, Idaho Power’s REC sales totaled $6.5 million. Idaho Power has sold all of its 2010 and earlier vintage RECs. Idaho Power has sold a portion of its 2011 RECs and intends to continue selling its 2011 and later RECs as they are generated and become available for sale. Ordinarily, Idaho Power does not receive the RECs associated with PURPA projects.
Endangered Species The listing of a species as threatened or endangered may have an adverse impact on Idaho Power's ability to construct generation, transmission, or distribution facilities or to relicense its hydroelectric projects. Several notable matters pertaining to threatened or endangered species and affecting Idaho Power are discussed below.
Slickspot Peppergrass: This southwestern Idaho plant species was listed as threatened by the USFWS in 2009. While critical habitat for the plant was not designated at the time of listing, approximately 98 percent of the plant species is located on federal land owned by the BLM and the U.S. Department of Defense. Parts of the Boardman-to-Hemingway and Gateway West 500-kV transmission lines will cross BLM land. This listing will add an additional requirement and species for consideration in the ESA Section 7 consultation. A Section 7 consultation is a process used to determine a proposed action’s effects on any ESA-listed species that may be within the project area. This listing may increase the expense and delay the timing of permitting for these projects. Sage Grouse: The sage grouse is considered a “candidate species” under the ESA, which allows land management agencies to implement additional conservation measures in an effort to prevent a formal ESA listing. In March 2010, the USFWS announced that listing of the greater sage grouse as threatened or endangered under the ESA is warranted, but precluded by higher priority listing actions. On February 2, 2012, a federal district court in Idaho issued an order denying a request to expedite the listing of the sage grouse under the ESA. As a result, the USFWS has until 2015 to make a final listing determination under the ESA. On February 6, 2012, the same court issued an order holding that the BLM had violated the National Environmental Policy Act and other federal laws in connection with the granting of livestock grazing permit renewals in sage grouse habitat. Due to the presence of sage grouse in the vicinity, siting of the Boardman-to-Hemingway and Gateway West 500-kV transmission lines has required more extensive, costly, and time consuming evaluation, permitting, and engineering. Any required additional conservation measures may increase the costs of existing operations and impact the cost and timing of siting, permitting, and construction of the Boardman-to-Hemingway and Gateway West transmission lines and other construction and transmission projects. Listing of the greater sage grouse as threatened or endangered under the ESA would add an additional requirement and species for consideration in ESA Section 7 consultations for those projects, and may increase the expense and adversely affect the cost and timing of those projects. Hells Canyon Project: In 2007, the FERC requested initiation of formal consultation under the ESA with the National Marine Fisheries Service (NMFS) and the USFWS regarding potential effects of HCC relicensing on several listed aquatic and terrestrial species. Formal consultation has not yet been initiated and NMFS and USFWS continue to gather and consider information relative to the effects of relicensing on relevant species. Idaho Power continues to cooperate with the USFWS, the NMFS, and the FERC in an effort to address ESA concerns. Idaho Power may be required to modify operations pursuant to the biological opinion that will result from formal consultation. However, the issuance of a final biological opinion during 2012 is unlikely. Bliss and Lower Salmon Falls Projects: As part of a settlement agreement, Idaho Power has finalized a snail protection plan for the Bliss and Lower Salmon Falls projects in cooperation with the USFWS. Idaho Power has filed applications with the FERC to amend the licenses for the projects that will maintain operating flexibility at both projects for the remainder of their licenses. The FERC and USFWS are conducting an ESA Section 7 consultation on two ESA listed snails, the Bliss Rapids snail and the Snake River physa snail. Idaho Power has been working closely with USFWS to develop the necessary biological information to complete the consultation. A biological assessment for the Snake River physa snail, jointly developed between the USFWS and Idaho Power, was filed with the FERC in September 2011. The biological assessment evaluates the potential impacts of the license amendment on the Snake River physa snail. Idaho Power anticipates that the FERC will request formal consultation with the USFWS during the second half of 2012. The USFWS will then develop a biological opinion on the effects of load-following on both types of snails.
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Swan Falls Project: In August 2010, the FERC issued a final EIS in connection with the relicensing of the SFP. The Snake River physa snail, a species listed as endangered under the ESA, was found in the area during the EIS review. While the biological opinion includes a provision for the incidental take of the snail, Idaho Power is required to study the status of the Snake River physa snail and its habitat within and downstream of the project area for the term of the new license.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES When preparing financial statements in accordance with generally accepted accounting principles (GAAP), IDACORP’s and Idaho Power’s management must apply accounting policies and make estimates that affect the reported amounts of assets, liabilities, revenues, and expenses and related disclosure of contingent assets and liabilities. These estimates often involve judgment about factors that are difficult to predict and are beyond management’s control. Management adjusts these estimates based on historical experience and on other assumptions and factors that are believed to be reasonable under the circumstances. Actual amounts could materially differ from the estimates.
Management believes the following accounting policies and estimates are the most critical to the portrayal of their financial condition and results of operations and require management’s most difficult, subjective, or complex judgments, often as a result of the need to make estimates about the effect of matters that are inherently uncertain and may change in subsequent periods. Accounting for Rate Regulation
Entities that meet specific conditions are required by GAAP to reflect the impact of regulatory decisions in their consolidated financial statements and to defer certain costs as regulatory assets until matching revenues can be recognized. Similarly, certain items may be deferred as regulatory liabilities. Idaho Power must satisfy three conditions to apply regulatory accounting: (1) an independent regulator must set rates; (2) the regulator must set the rates to cover specific costs of delivering service; and (3) the service territory must lack competitive pressures to reduce rates below the rates set by the regulator. Idaho Power has determined that it meets these conditions, and its financial statements reflect the effects of the different rate making principles followed by the jurisdictions regulating Idaho Power. The primary effect of this policy is that Idaho Power has recorded $987 million of regulatory assets and $362 million of regulatory liabilities at December 31, 2011. Idaho Power expects to recover these regulatory assets from customers through rates and refund these regulatory liabilities to customers through rates, but recovery or refund is subject to final review by the regulatory bodies. If future recovery or refund of these amounts ceases to be probable, or if Idaho Power determines that it no longer meets the criteria for applying regulatory accounting, or if accounting rules change to no longer provide for regulatory assets and liabilities, Idaho Power would be required to eliminate those regulatory assets or liabilities, unless regulators specify some other means of recovery or refund. Either circumstance could have a material effect on Idaho Power’s results of operations and financial position. Income Taxes
IDACORP and Idaho Power use judgment and estimation in developing the provision for income taxes and the reporting of tax-related assets and liabilities. The interpretation of tax laws can involve uncertainty, since tax authorities may interpret such laws differently. Actual income taxes could vary from estimated amounts and may result in favorable or unfavorable impacts to net income, cash flows, and tax-related assets and liabilities. 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 impacts currently for rate making and financial reporting. In September 2009, the IRS issued IDD #5, 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. Since that time, the IRS and Idaho Power agreed to a method consistent with the IDD guidance and changed Idaho Power’s uniform capitalization method. In 2010, Idaho Power provided a current uncertain tax position liability equal to the net tax benefit recorded for the method change until the agreement with the IRS was approved by the Joint Committee. This approval occurred in the third quarter of 2011, which effectively settled the issue for financial reporting purposes. No material uncertain tax positions remained at December 31, 2011.
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Asset Impairment
Available-for-sale Securities: Idaho Power is required to evaluate available-for-sale securities periodically to determine whether a decline in fair value below cost is other than temporary. If the decline in fair value is other than temporary, the cost of the investment is written down to fair value and the loss is recorded as a realized loss. Two significant factors that are considered when evaluating investments for impairment are the length of time and the extent to which the market value has been less than cost. Idaho Power has investments in four mutual funds that experienced a significant decline in fair value in 2008. Idaho Power’s investments had lost between 32 percent and 43 percent of their value, primarily during the stock market downturn in September and October 2008, and had been in loss positions from 6 to 12 months at December 31, 2008. Because of the severity of the declines in value, Idaho Power determined that the loss in value was other-than-temporary and recorded a pre-tax loss of $6.8 million in the fourth quarter of 2008. At December 31, 2011 and 2010, the fair values of these investments were at or above their new cost bases and no impairment was recorded. Equity-Method Investments: IFS has affordable housing investments with a net book value of $63 million at December 31, 2011, and Ida-West has investments in four joint ventures that own electric power generation facilities. Except for one investment which is consolidated, these investments are accounted for under the equity method of accounting. The standard for determining whether impairment must be recorded for these investments is whether the investment has experienced a loss in value that is considered an other-than-temporary decline in value. Impairment analyses are performed on these investments when indicators of impairment are noted. An immaterial impairment was recorded on one of the Ida-West joint ventures in 2011, and no impairments were recorded in 2010 or in 2009. These estimates required IDACORP to make assumptions about future revenues, cash flows, and other items that are inherently uncertain. Actual results could vary significantly from the assumptions used, and the impact of such variations could be material. Pension and Other Postretirement Benefits
Idaho Power maintains a tax-qualified, noncontributory defined benefit pension plan covering most employees, an unfunded nonqualified deferred compensation plan for certain senior management employees and directors called the Senior Management Security Plan (SMSP), and a postretirement benefit plan (consisting of health care and death benefits). The costs IDACORP and Idaho Power record for these plans depend on the provisions of the plans, changing employee demographics, actual returns on plan assets, and several assumptions used in the actuarial valuations from which the expense is derived. The key actuarial assumptions that affect expense are the expected long-term return on plan assets and the discount rate used in determining future benefit obligations. Management evaluates the actuarial assumptions on an annual basis, taking into account changes in market conditions, trends, and future expectations. Estimates of future stock market performance, changes in interest rates, and other factors used to develop the actuarial assumptions are uncertain, and actual results could vary significantly from the estimates. The assumed discount rate is based on reviews of market yields on high-quality corporate debt. Specifically, IDACORP and Idaho Power determined the discount rate for each plan through the construction of hypothetical portfolios of bonds selected from high-quality corporate bonds available as of December 31, 2011, with maturities matching the projected cash outflows of the plans. The discount rate used to calculate the 2012 pension expense will be decreased to 4.9 percent from the 5.4 percent used in 2011. 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 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. The long-term rate of return used to calculate the 2012 pension expense will be 7.75 percent, compared to the 8.25 percent rate used for 2011.
Gross pension and other postretirement benefit expense for these plans totaled $39 million, $39 million, and $40 million for the years ended December 31, 2011, 2010, and 2009, respectively, including amounts allocated to capitalized labor and amounts deferred as regulatory assets. For 2012, gross pension and other postretirement benefit costs are expected to total approximately $52 million, which takes into account the change in the discount rate noted above, as well as a decrease in expected return on plan assets. No changes were made to the other key assumptions used in the actuarial calculation.
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Had different actuarial assumptions been used, pension expense could have varied significantly. The following table reflects the sensitivities associated with changes in the discount rate and rate-of-return on plan assets actuarial assumptions on historical and future pension and postretirement expense:
Effect of 0.5% increase on net periodic benefit costEffect of 0.5% decrease on net periodic benefit cost
Discount rate2012
(millions of dollars)$ (5.7)
6.6
2011
$ (4.8)5.2
Rate of return2012
$ (2.2)2.2
2011
$ (2.1)2.1
Additionally a 0.5 percent increase in the plans' discount rates would have resulted in a $55 million decrease in the combined benefit obligations of the plans as of December 31, 2011. A 0.5 percent decrease in the plans' discount rates would have resulted in a $61 million increase in the combined benefit obligations of the plans as of December 31, 2011.
No cash contributions were made to the defined benefit pension plan in 2009. Contributions of $60 million and $18.5 million were made in 2010 and 2011, respectively. Contributions required to be made during 2012 are estimated to be $34 million. Payments of $44 million, $44 million, $42 million, and $42 million are estimated to be due in 2013, 2014, 2015, and 2016, respectively. Under the SMSP, Idaho Power makes payments directly to participants in the plan. Benefit payments are expected to be $3.6 million in 2012 and averaged $3.3 million per year from 2009 to 2011. Postretirement benefit plan contributions are expected to be $3.7 million in 2012, and averaged $2.3 million from 2009 to 2011. The IPUC has authorized Idaho Power to account for its defined benefit pension plan expense on a cash basis, and to defer and account for accrued pension expense as a regulatory asset. The IPUC acknowledged that it is appropriate for Idaho Power to seek recovery in its revenue requirement of reasonable and prudently incurred pension expense based on actual cash contributions. In 2007, Idaho Power began deferring pension expense to a regulatory asset account to be matched with revenue when future pension contributions are recovered through rates. At December 31, 2011, $58 million of expense was deferred as a regulatory asset. Approximately $22 million is expected to be deferred in 2012. Idaho Power recorded pension expense in 2011, 2010, and 2009 of $34 million, $5 million, and $1 million, respectively. Refer to Note 11 – “Benefit Plans” of the consolidated financial statements included in this report for additional information relating to pension and postretirement benefit plans. Contingent Liabilities
An estimated loss from a loss contingency is charged to income if (a) it is probable that a liability had been incurred at the date of the financial statements and (b) the amount of the loss can be reasonably estimated. If a probable loss cannot be reasonably estimated, no accrual is recorded but disclosure of the contingency in the notes to the financial statements is required. Gain contingencies are not recorded until realized. IDACORP and Idaho Power have a number of unresolved issues related to regulatory and legal matters. If the recognition criteria have been met, liabilities have been recorded. Estimates of this nature are highly subjective and the final outcome of these matters could vary significantly from the amounts that have been included in the financial statements.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
There have been no recently issued accounting pronouncements that have had or are expected to have a material impact on IDACORP's or Idaho Power's results of operations or financial condition. See Note 1 - “Summary of Significant Accounting Policies” to the consolidated financial statements included in this report for a summary of significant accounting policies.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK IDACORP and Idaho Power are exposed to market risks, including changes in interest rates, changes in commodity prices, credit risk, and equity price risk. The following discussion summarizes these risks and the financial instruments, derivative instruments, and derivative commodity instruments sensitive to changes in interest rates, commodity prices, and equity prices that were held at December 31, 2011.
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Interest Rate Risk IDACORP and Idaho Power manage interest expense and short- and long-term liquidity through a combination of fixed rate and variable rate debt. Generally, the amount of each type of debt is managed through market issuance, but interest rate swap and cap agreements with highly rated financial institutions may be used to achieve the desired combination. Variable Rate Debt: As of December 31, 2011, IDACORP and Idaho Power had $78.3 million and $24.1 million, respectively, in net floating-rate debt. The fair market value of this debt was $78.3 million and $24.1 million, respectively. Assuming no change in financial structure, if variable interest rates were to average one percentage-point higher than the average rate on December 31, 2011, interest rate expense would increase and pre-tax earnings would decrease by approximately $0.8 million for IDACORP and $0.2 million for Idaho Power. Fixed Rate Debt: As of December 31, 2011, IDACORP and Idaho Power each had $1.5 billion in fixed rate debt, with a fair market value equal to $1.7 billion. These instruments are fixed rate and, therefore, do not expose the companies to a loss in earnings due to changes in market interest rates. However, the fair value of these instruments would increase by approximately $193 million for both IDACORP and Idaho Power if interest rates were to decline by one percentage point from their December 31, 2011 levels. Commodity Price Risk Idaho Power's exposure to changes in commodity prices is related to its ongoing utility operations that produce electricity to meet the demand of its retail electric customers. To supplement its generation resources and balance its supply of power with the demand of its retail customers, Idaho Power participates in the wholesale marketplace. These purchased power arrangements allow Idaho Power to respond to fluctuations in the demand for electricity and variability in generating plant operations. Idaho Power also enters into arrangements for the purchase of fuel for natural gas and coal-fired generating plants. Idaho Power anticipates that the additional volume of natural gas needed to operate the Langley Gulch power plant will increase its exposure in the future to natural gas commodity price risk. These contracts for the purchase of power and fuel expose Idaho Power to commodity price risk. A number of factors associated with the structure and operation of the energy markets influence the level and volatility of prices for energy commodities and related derivative products. The weather is a major uncontrollable factor affecting the local and regional demand for electricity and the availability and cost of production. Other factors include the occurrence and timing of demand peaks due to seasonal, daily, and hourly power demand; power supply; power transmission capacity; changes in federal and state regulation and compliance obligations; fuel supplies; and market liquidity. Idaho Power’s exposure to commodity price risk is largely offset by the PCA mechanisms in Idaho and Oregon. Therefore, the primary objectives of Idaho Power’s energy purchase and sale activity are 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. Idaho Power has adopted a risk management program, which has been reviewed and accepted by the IPUC, designed to reduce exposure to power supply cost-related uncertainty, further mitigating commodity price risk. Idaho Power’s Energy Risk Management Policy (Policy) and associated standards implementing the Policy describe a collaborative process with customers and regulators via a committee called the Customer Advisory Group (CAG). The Risk Management Committee (RMC), comprised of selected Idaho Power officers and other senior staff, oversees the risk management program. The RMC is responsible for communicating the status of risk management activities to the Idaho Power Board of Directors and to the CAG, and Idaho Power’s Audit Committee is responsible for approving the Policy and associated standards. The RMC is also responsible for conducting an ongoing general assessment of the appropriateness of Idaho Power’s strategies for energy risk management activities. In its risk management process, Idaho Power considers both demand-side and supply-side options consistent with its IRP. The primary tools for risk mitigation are physical and financial forward power transactions and fueling alternatives for utility-owned generation resources. Idaho Power does not engage in trading activities for non-retail purposes. The Policy requires monitoring monthly volumetric electricity position and total monthly dollar (net power supply cost) exposure on a rolling 18-month forward view. The Power Supply business unit produces and evaluates projections of the operating plan based on factors such as forecasted resource availability, stream flows, and load, and orders risk mitigating actions, including resource optimization and hedging strategies, dictated by the limits stated in the Policy to bring exposures within pre-established risk guidelines. The RMC evaluates the actions initiated by Power Supply for consistency and compliance with the Policy. Idaho Power representatives meet with the CAG at least annually to assess effectiveness of the limits. Changes to the limits can be endorsed by the CAG and referred to the board of directors for approval.
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Credit Risk Idaho Power is subject to credit risk based on its activity with market counterparties. Idaho Power is exposed to this risk to the extent that a counterparty may fail to fulfill a contractual obligation to provide energy, purchase energy, or complete financial settlement for market activities. Idaho Power mitigates this exposure by actively establishing credit limits; measuring, monitoring, and reporting credit risk using appropriate contractual arrangements; and transferring of credit risk through the use of financial guarantees, cash or letters of credit. Idaho Power maintains a current list of acceptable counterparties and credit limits. The use of performance assurance collateral in the form of cash, letters of credit, or guarantees is common industry practice. Idaho Power maintains margin agreements relating to its wholesale commodity contracts that allow performance assurance collateral to be requested of and/or posted with certain counterparties. As of December 31, 2011, Idaho Power had posted no performance assurance collateral. Should Idaho Power experience a reduction in its credit rating on Idaho Power’s unsecured debt to below investment grade, Idaho Power could be subject to requests by its wholesale counterparties to post performance assurance collateral. Counterparties to derivative instruments and other forward contracts could request immediate payment or demand immediate ongoing full daily collateralization on derivative instruments and contracts in net liability positions. Based upon Idaho Power’s current energy and fuel portfolio and market conditions as of December 31, 2011, the approximate amount of collateral that could be requested upon a downgrade to below investment grade is approximately $7 million. Idaho Power actively monitors the portfolio exposure and the potential exposure to additional requests for performance assurance collateral calls, through sensitivity analysis, to minimize capital requirements. Idaho Power is obligated to provide service to all electric customers within its service area. Credit risk for Idaho Power’s retail customers is managed by credit and collection policies that are governed by rules issued by the IPUC or OPUC. Idaho Power records a provision for uncollectible accounts, based upon historical experience, to provide for the potential loss from nonpayment by these customers. Idaho Power will continue to monitor the impact of the current economic conditions on nonpayment from customers and will make any necessary adjustments to its provision for uncollectible accounts. Idaho utility customer relations rules prohibit Idaho Power from terminating electric service during the months of December through February to any residential customer who declares that he or she is unable to pay in full for utility service and whose household includes children, elderly, or infirm persons. Idaho Power’s provision for uncollectible accounts could be affected by changes in future prices as well as changes in IPUC or OPUC regulations.
Equity Price Risk IDACORP and Idaho Power are exposed to price fluctuations in equity markets, primarily through their defined benefit pension plan assets, a mine reclamation trust fund owned by an equity-method investment of Idaho Power, and other equity investments at Idaho Power. During 2011, the fair value of the defined benefit pension plan’s assets decreased slightly; however, increases in the benefit liabilities were greater than the increases in the plan’s assets, therefore resulting in an increase in future amounts required to be contributed to the plan. Based on current laws, Idaho Power estimates that the minimum contribution to the defined benefit pension plan in 2012 will be approximately $36 million. A hypothetical ten percent decrease in equity prices would result in an approximate $2.2 million decrease in the fair value of financial instruments that are classified as available-for-sale securities as of December 31, 2011.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index to Financial Statements and Financial Statement Schedules
Consolidated Financial Statements
IDACORP, Inc.:Consolidated Statements of Income for the Years Ended December 31, 2011, 2010 and 2009Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2011, 2010 and 2009Consolidated Balance Sheets as of December 31, 2011 and 2010Consolidated Statements of Cash Flows for the Years Ended December 31, 2011, 2010 and 2009Consolidated Statements of Equity for the Years Ended December 31, 2011, 2010 and 2009
Idaho Power Company:Consolidated Statements of Income for the Years Ended December 31, 2011, 2010 and 2009Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2011, 2010 and 2009Consolidated Balance Sheets as of December 31, 2011 and 2010Consolidated Statements of Capitalization as of December 31, 2011 and 2010Consolidated Statements of Cash Flows for the Years Ended December 31, 2011, 2010 and 2009Consolidated Statements of Retained Earnings for the Years Ended December 31, 2011, 2010 and 2009
Notes to the Consolidated Financial StatementsReports of Independent Registered Public Accounting Firm
Supplemental Financial Information and Financial Statement Schedules
Supplemental Financial Information (unaudited)Financial Statement Schedules for the Years Ended December 31, 2011, 2010 and 2009
IDACORP, Inc. - Schedule I - Condensed Financial Information of RegistrantIDACORP, Inc. - Schedule II - Consolidated Valuation and Qualifying AccountsIdaho Power Company - Schedule II - Consolidated Valuation and Qualifying Accounts
Page
7677788081
828384868788
89130
132
147149150
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IDACORP, Inc.Consolidated Statements of Income
Operating Revenues:Electric utility:
General businessOff-system salesOther revenues
Total electric utility revenuesOther
Total operating revenues
Operating Expenses:Electric utility:
Purchased powerFuel expensePower cost adjustmentOther operations and maintenanceEnergy efficiency programsDepreciationTaxes other than income taxes
Total electric utility expensesOther
Total operating expenses
Operating IncomeOther Income, NetEarnings (Losses) of Unconsolidated Equity-Method Investments
Interest Expense:Interest on long-term debtOther interest, net of AFUDC
Total interest expense, net
Income Before Income Taxes
Income Tax (Benefit) Expense
Net IncomeAdjustment for (income) loss attributable to noncontrolling interests
Net Income Attributable to IDACORP, Inc.
Weighted Average Common Shares Outstanding - Basic (000’s)Weighted Average Common Shares Outstanding - Diluted (000’s)Earnings Per Share of Common Stock:Earnings Attributable to IDACORP, Inc. - BasicEarnings Attributable to IDACORP, Inc. - DilutedDividends Declared Per Share of Common Stock
Year Ended December 31,2011
(thousands of dollars except for per share amounts)
$ 834,545101,60286,581
1,022,7284,028
1,026,756
163,336131,54238,497
338,64037,663
119,78928,895
858,3624,146
862,508
164,24821,209
798
79,349(7,823)71,526
114,729
(52,133)
166,862(169)
$ 166,693
49,45749,558
$ 3.37$ 3.36$ 1.20
2010
$ 870,37178,13384,548
1,033,0522,977
1,036,029
143,769159,67351,226
293,92544,184
115,92124,046
832,7444,615
837,359
198,67015,1653,008
80,490(5,376)75,114
141,729
(731)
142,460338
$ 142,798
48,19348,340
$ 2.96$ 2.95$ 1.20
2009
$ 883,76594,37367,858
1,045,9963,804
1,049,800
167,198149,56666,710
292,81331,821
110,62621,069
839,8036,414
846,217
203,58316,997(1,033)
73,371(561)
72,810
146,737
22,362
124,375(25)
$ 124,350
47,12447,182
$ 2.64$ 2.64$ 1.20
The accompanying notes are an integral part of these statements.
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IDACORP, Inc.Consolidated Statements of Comprehensive Income
Net IncomeOther Comprehensive Income:Net unrealized holding (losses) gains arising during the year, net of tax of ($257), $738, and $1,169Unfunded pension liability adjustment, net of tax of ($1,062), ($1,573), and ($885)Total Comprehensive IncomeComprehensive (income) loss attributable to noncontrolling interestsComprehensive Income Attributable to IDACORP, Inc.
Year Ended December 31,2011
(thousands of dollars)
$ 166,862
(400)
(1,654)164,808
(169)$ 164,639
2010
$ 142,460
1,149
(2,450)141,159
338$ 141,497
2009
$ 124,375
1,820
(1,380)124,815
(25)$ 124,790
The accompanying notes are an integral part of these statements.
78
IDACORP, Inc.Consolidated Balance Sheets
Assets
Current Assets:Cash and cash equivalentsReceivables:
Customer (net of allowance of $1,239 and $1,499, respectively)Other (net of allowance of $196 and $1,471, respectively)
Income taxes receivableAccrued unbilled revenuesMaterials and supplies (at average cost)Fuel stock (at average cost)PrepaymentsDeferred income taxesCurrent regulatory assetsOther
Total current assets
Investments
Property, Plant and Equipment:Utility plant in serviceAccumulated provision for depreciation
Utility plant in service - netConstruction work in progressUtility plant held for future useOther property, net of accumulated depreciation
Property, plant and equipment - net
Other Assets:American Falls and Milner water rightsCompany-owned life insuranceRegulatory assetsLong-term receivables (net of allowance of $2,743 and $1,861, respectively)Other
The accompanying notes are an integral part of these statements.
79
IDACORP, Inc.Consolidated Balance Sheets
Liabilities and Equity
Current Liabilities:Current maturities of long-term debtNotes payableAccounts payableIncome taxes accruedInterest accruedUncertain tax positionsCurrent regulatory liabilitiesOther
Total current liabilities
Other Liabilities:Deferred income taxesRegulatory liabilitiesPension and other postretirement benefitsOther
Total other liabilities
Long-Term Debt
Commitments and Contingencies
Equity:IDACORP, Inc. shareholders’ equity:
Common stock, no par value (shares authorized 120,000,000; 49,964,172 and 49,419,452 shares issued, respectively)Retained earningsAccumulated other comprehensive lossTreasury stock (12,177 and 14,302 shares at cost, respectively)
Total IDACORP, Inc. shareholders’ equityNoncontrolling interests
Total equity
Total
The accompanying notes are an integral part of these statements.
December 31,2011(thousands of dollars)
$ 101,06454,200
100,432505
21,797—
29,73860,511
368,247
772,047332,057363,20975,805
1,543,118
1,387,550
828,389840,916(11,622)
(29)1,657,654
4,0401,661,694
$ 4,960,609
2010
$ 122,57266,900
103,100—
23,93774,4368,011
50,103449,059
566,473298,094263,68874,470
1,202,725
1,488,287
807,842733,879
(9,568)(40)
1,532,1133,871
1,535,984
$ 4,676,055
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IDACORP, Inc.Consolidated Statements of Cash Flows
Operating Activities:Net incomeAdjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortizationDeferred income taxes and investment tax creditsChanges in regulatory assets and liabilitiesPension and postretirement benefit plan expenseContributions to pension and postretirement benefit plans(Earnings) losses of unconsolidated equity-method investmentsDistributions from unconsolidated equity-method investmentsAllowance for equity funds used during constructionOther non-cash adjustments to net income, netChange in:
Accounts receivable and prepaymentsAccounts payable and other accrued liabilitiesTaxes accrued/receivableOther current assetsOther current liabilities
Other assetsOther liabilitiesNet cash provided by operating activities
Investing Activities:Additions to property, plant and equipmentProceeds from the sale of utility assetsProceeds from the sale of non-utility assetsProceeds from the sale of emission allowances and RECsProceeds from sale of available-for-sale securitiesInvestments in affordable housingInvestments in unconsolidated affiliatesPurchase of available-for-sale securitiesMaturity of held-to-maturity securitiesOther
Net cash used in investing activitiesFinancing Activities:Issuance of long-term debtRemarketing of pollution control bondsDecrease in term loansRetirement of long-term debtDividends on common stockNet change in short-term borrowingsIssuance of common stockAcquisition of treasury stockOther
Net cash (used in) provided by financing activitiesNet (decrease) increase in cash and cash equivalentsCash and cash equivalents at beginning of the yearCash and cash equivalents at end of the yearSupplemental Disclosure of Cash Flow Information:Cash (received) paid during the year for:
Income taxesInterest (net of amount capitalized)
Non-cash investing activities:Additions to property, plant and equipment in accounts payableInvestments in affordable housing
Purchased powerFuel expensePower cost adjustmentOther operations and maintenanceEnergy efficiency programs
DepreciationTaxes other than income taxes
Total operating expenses
Income from Operations
Other Income (Expense):Allowance for equity funds used during constructionEarnings of unconsolidated equity-method investmentsOther (expense) income, net
Total other income
Interest Charges:Interest on long-term debtOther interestAllowance for borrowed funds used during construction
Total interest charges
Income Before Income Taxes
Income Tax (Benefit) Expense
Net Income
Year Ended December 31,2011
(thousands of dollars)
$ 834,545101,60286,581
1,022,728
163,336131,54238,497
338,64037,663
119,78928,895
858,362
164,366
25,4849,018
(4,462)30,040
79,3495,039
(13,333)71,055
123,351
(41,399)
$ 164,750
2010
$ 870,37178,13384,548
1,033,052
143,769159,67351,226
293,92544,184
115,92124,046
832,744
200,308
16,55111,281(2,868)24,964
80,4904,110
(10,675)73,925
151,347
10,713
$ 140,634
2009
$ 883,76594,37367,858
1,045,996
167,198149,56666,710
292,81331,821
110,62621,069
839,803
206,193
7,5558,2568,008
23,819
73,2704,060
(5,398)71,932
158,080
35,521
$ 122,559
The accompanying notes are an integral part of these statements.
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Idaho Power CompanyConsolidated Statements of Comprehensive Income
Net IncomeOther Comprehensive Income:Net unrealized holding (losses) gains arising during the year, net of tax of ($257), $738, and $1,169Unfunded pension liability adjustment, net of tax of ($1,062), ($1,573), and ($885)Total Comprehensive Income
Year Ended December 31,2011
(thousands of dollars)
$ 164,750
(400)
(1,654)$ 162,696
2010
$ 140,634
1,149
(2,450)$ 139,333
2009
$ 122,559
1,820
(1,380)$ 122,999
The accompanying notes are an integral part of these statements.
84
Idaho Power CompanyConsolidated Balance Sheets
Assets
Electric Plant:In service (at original cost)Accumulated provision for depreciation
In service - netConstruction work in progressHeld for future use
Electric plant - net
Investments and Other Property
Current Assets:Cash and cash equivalentsReceivables:
Customer (net of allowance of $1,239 and $1,499, respectively)Other (net of allowance of $196 and $142, respectively)
Income taxes receivableAccrued unbilled revenuesMaterials and supplies (at average cost)Fuel stock (at average cost)PrepaymentsDeferred income taxesCurrent regulatory assetsOther
Total current assets
Deferred Debits:American Falls and Milner water rightsCompany-owned life insuranceRegulatory assetsOther
Total deferred debits
Total
December 31,2011(thousands of dollars)
$ 4,466,873(1,677,609)2,789,264
591,4756,974
3,387,713
128,674
19,316
66,2968,0114,644
46,44146,49047,86512,27414,09934,2794,606
304,321
20,01524,060
953,06838,988
1,036,131
$ 4,856,839
2010
$ 4,332,054(1,614,013)2,718,041
416,9507,076
3,142,067
120,641
224,233
62,1148,835
21,06347,96445,60127,54710,9107,3346,2161,238
463,055
22,12026,672
753,17240,666
842,630
$ 4,568,393
The accompanying notes are an integral part of these statements.
85
Idaho Power CompanyConsolidated Balance Sheets
Capitalization and Liabilities
Capitalization:Common stock equity:
Common stock, $2.50 par value (50,000,000 shares authorized; 39,150,812 shares outstanding)Premium on capital stockCapital stock expenseRetained earningsAccumulated other comprehensive loss
Total common stock equityLong-term debt
Total capitalization
Current Liabilities:Long-term debt due within one yearAccounts payableAccounts payable to related partiesInterest accruedUncertain tax positionsCurrent regulatory liabilitiesOther
Total current liabilities
Deferred Credits:Deferred income taxesRegulatory liabilitiesPension and other postretirement benefitsOther
Total deferred credits
Commitments and Contingencies
Total
The accompanying notes are an integral part of these statements.
December 31,2011(thousands of dollars)
$ 97,877704,758
(2,097)735,304(11,622)
1,524,2201,387,5502,911,770
101,06499,7161,512
21,797—
29,73859,785
313,612
863,044332,057363,20973,147
1,631,457
$ 4,856,839
2010
$ 97,877688,758
(2,097)630,259
(9,568)1,405,2291,488,2872,893,516
121,064102,474
1,11023,93074,4368,011
48,733379,758
661,165298,094263,68872,172
1,295,119
$ 4,568,393
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Idaho Power CompanyConsolidated Statements of Capitalization
Common Stock Equity:Common stockPremium on capital stockCapital stock expenseRetained earningsAccumulated other comprehensive loss
Total common stock equity
Long-Term Debt:First mortgage bonds:
6.60% Series due 20114.75% Series due 20124.25% Series due 20136.025% Series due 20186.15% Series due 20194.50 % Series due 20203.40% Series due 20206% Series due 20325.50% Series due 20335.50% Series due 20345.875% Series due 20345.30% Series due 20356.30% Series due 20376.25% Series due 20374.85% Series due 2040
Total first mortgage bondsAmount due within one year
Net first mortgage bonds
Pollution control revenue bonds:5.15% Series due 20245.25% Series due 2026Variable Rate Series 2000 due 2027
Total pollution control revenue bonds
American Falls bond guaranteeMilner Dam note guaranteeNote guarantee due within one yearUnamortized premium/discount - net
The accompanying notes are an integral part of these statements.
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Idaho Power CompanyConsolidated Statements of Cash Flows
Operating Activities:Net incomeAdjustments to reconcile net income to net cash provided by
operating activities:Depreciation and amortizationDeferred income taxes and investment tax creditsChanges in regulatory assets and liabilitiesPension and postretirement benefit plan expenseContributions to pension and postretirement benefit plansEarnings of unconsolidated equity-method investmentsDistributions from unconsolidated equity-method investmentsAllowance for equity funds used during constructionOther non-cash adjustments to net incomeChange in:
Accounts receivables and prepaymentsAccounts payableTaxes accrued/receivableOther current assetsOther current liabilities
Other assetsOther liabilitiesNet cash provided by operating activities
Investing Activities:Additions to utility plantProceeds from the sale of utility assetsProceeds from the sale of non-utility assetsProceeds from the sale of emission allowances and RECsInvestments in unconsolidated affiliatesPurchase of available for sale securitiesOther
Net cash used in investing activitiesFinancing Activities:Issuance of long-term debtRetirement of long-term debtRemarketing of pollution control revenue bondsDecrease in term loansDividends on common stockNet change in short term borrowingsCapital contribution from parentOther
Net cash (used in) provided by financing activitiesNet (decrease) increase in cash and cash equivalentsCash and cash equivalents at beginning of the yearCash and cash equivalents at end of the yearSupplemental Disclosure of Cash Flow Information:Cash (received) paid during the year for:
Income taxesInterest (net of amount capitalized)
Non-cash investing activities:Additions to property, plant and equipment in accounts payable
The accompanying notes are an integral part of these statements.
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Idaho Power CompanyConsolidated Statements of Retained Earnings
Retained Earnings, Beginning of YearNet IncomeDividends on Common StockRetained Earnings, End of Year
Year Ended December 31,2011
(thousands of dollars)
$ 630,259164,750(59,705)
$ 735,304
2010
$ 547,695140,634(58,070)
$ 630,259
2009
$ 482,047122,559(56,911)
$ 547,695
The accompanying notes are an integral part of these statements.
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IDACORP, INC. AND IDAHO POWER COMPANYNOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES This Annual Report on Form 10-K is a combined report of IDACORP, Inc. (IDACORP) and Idaho Power Company (Idaho Power). Therefore, the Notes to the Consolidated Financial Statements apply to both IDACORP and Idaho Power. However, Idaho Power makes no representation as to the information relating to IDACORP’s other operations.
Nature of Business IDACORP is a holding company formed in 1998 whose principal operating subsidiary is Idaho Power. Idaho Power 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. (IERCo), 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. IDACORP’s other subsidiaries include IDACORP Financial Services, Inc. (IFS), an investor in affordable housing and other real estate investments; Ida-West Energy Company (Ida-West), an operator of small hydroelectric generation projects that satisfy the requirements of the Public Utility Regulatory Policies Act of 1978 (PURPA); and IDACORP Energy (IE), a marketer of energy commodities, which wound down operations in 2003. Principles of Consolidation IDACORP’s and Idaho Power’s consolidated financial statements include the accounts of each company, the subsidiaries that the companies control, and any variable interest entities (VIEs) for which the companies are the primary beneficiaries. Intercompany balances have been eliminated in consolidation. Investments in subsidiaries that the companies do not control and investments in VIEs for which the companies are not the primary beneficiaries, but have the ability to exercise significant influence over operating and financial policies, are accounted for using the equity method of accounting. The entities that IDACORP and Idaho Power consolidate consist primarily of the wholly-owned subsidiaries discussed above. In addition, IDACORP consolidates one VIE, Marysville Hydro Partners (Marysville), which is a joint venture owned 50 percent by Ida-West and 50 percent by Environmental Energy Company (EEC). At December 31, 2011, Marysville had approximately $20 million of assets, primarily a hydroelectric plant, and approximately $15 million of intercompany long-term debt, which is eliminated in consolidation. EEC has borrowed amounts from Ida-West to fund a portion of its required capital contributions to Marysville. The loans are payable from EEC’s share of distributions and are secured by the stock of EEC and EEC’s interest in Marysville. Ida-West is the primary beneficiary because the ownership of the intercompany note and the EEC note result in it controlling the entity. Creditors of Marysville have no recourse to the general credit of IDACORP and there are no other arrangements that could require IDACORP to provide financial support to Marysville or expose IDACORP to losses. Through IERCo, Idaho Power holds a variable interest in BCC, a VIE for which it is not the primary beneficiary. IERCo is not the primary beneficiary because the power to direct the activities that most significantly impact the economic performance of BCC is shared with the joint venture partner. The carrying value of BCC was $102 million at December 31, 2011, and Idaho Power's maximum exposure to loss is the carrying value, any additional future contributions to BCC, and a $63 million guarantee for mine reclamation costs, which is discussed further in Note 9. Through IFS, IDACORP also holds variable interests in VIEs for which it is not the primary beneficiary. These VIEs are affordable housing developments and other real estate investments in which IFS holds limited partnership interests ranging from 5 to 99 percent. As a limited partner, IFS does not control these entities and they are not consolidated. These investments were acquired between 1996 and 2010. IFS’s maximum exposure to loss in these developments is limited to its net carrying value, which was $63 million at December 31, 2011. 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
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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
IDACORP’s and 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. Other receivables, primarily notes receivable from business transactions, are also reviewed for impairment periodically, based upon transaction-specific facts. When it is probable that IDACORP or 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
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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, 2.84 percent in 2010, and 2.81 percent in 2009. 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, 2010, or 2009. 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, 2010, and 2009 were 7.8 percent, 8.0 percent, and 6.7 percent, respectively. Idaho Power’s reductions to interest expense for AFUDC were $13 million for 2011, $11 million for 2010, and $5 million for 2009. Other income included $25 million, $17 million, and $8 million of AFUDC for 2011, 2010, and 2009, respectively. Income Taxes
IDACORP and Idaho Power account 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.
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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 IDACORP’s and Idaho Power’s accumulated other comprehensive loss balance at December 31 (net of tax):
Unrealized holding gains on available-for-sale securitiesSenior Management Security PlanTotal
2011(thousands of dollars)
$ 2,569(14,191)
$ (11,622)
2010
$ 2,969(12,537)
$ (9,568)
Other Accounting Policies
Debt discount, expense, and premium are deferred and are being amortized over the terms of the respective debt issues. Reclassifications Certain prior year amounts have been reclassified to conform to the current year presentation. Net income, cash flows, and shareholders' equity were not affected by these reclassifications.
• Certain amounts related to regulatory assets and liabilities that were included in noncurrent regulatory assets and liabilities were reclassified as current regulatory assets and liabilities in the consolidated balance sheets.
• Pension and other postretirement benefits of $264 million were reclassified from other noncurrent liabilities to a separate line in the consolidated balance sheets.
New Accounting Pronouncements The Financial Accounting Standards Board (FASB) has issued the following accounting guidance, which is effective for years beginning after December 15, 2011:
• In May 2011, the FASB issued guidance to provide a consistent definition of fair value and ensure that the fair value measurement and disclosure requirements are similar between generally accepted accounting principles in the United States and International Financial Reporting Standards. The guidance changes certain fair value measurement principles and enhances the disclosure requirements, particularly for Level 3 fair value measurements. IDACORP and Idaho Power are currently assessing the impact of the guidance but do not believe that the adoption of this guidance will have a material effect on their consolidated financial statements.
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2. INCOME TAXES A reconciliation between the statutory federal income tax rate and the effective tax rate is as follows:
Federal income tax expense at 35% statutory rateChange in taxes resulting from:
AFUDCCapitalized interestInvestment tax creditsRepair allowanceRemoval costsCapitalized overhead costsCapitalized repair costsTax method change – uniform capitalizationTax method change – capitalized repairsUncertain tax positions – establishedUncertain tax positions – settledState income taxes, net of federal benefitDepreciationAffordable housing tax creditsOther, net
Total income tax (benefit) expenseEffective tax rate
IDACORP2011
(thousands of dollars)$ 40,096
(13,586)6,465
(3,355)—
(2,244)(5,950)
(14,000)———
(63,138)1,375
14,100(6,438)(5,458)
$ (52,133)(45.5)%
2010
$ 49,723
(9,529)3,674
(3,378)—
(2,850)(3,500)
(10,500)(65,333)(44,466)74,436(1,138)4,565
13,138(7,309)1,736
$ (731)(0.5)%
2009
$ 51,349
(4,533)1,529
(3,404)(3,500)(3,810)(3,500)
———
1,138(4,119)1,2163,895
(7,870)(6,029)
$ 22,36215.2%
Idaho Power2011
$ 43,173
(13,586)6,465
(3,355)—
(2,244)(5,950)
(14,000)———
(63,138)1,846
14,100—
(4,710)$ (41,399)(33.6)%
2010
$ 52,972
(9,529)3,674
(3,378)—
(2,850)(3,500)
(10,500)(65,333)(44,466)74,436(1,138)5,074
13,138—
2,113$ 10,713
7.1%
2009
$ 55,328
(4,533)1,529
(3,404)(3,500)(3,810)(3,500)
———
1,138(4,119)1,9033,895
—(5,406)
$ 35,52122.5%
The items comprising income tax (benefit) expense are as follows:
Income taxes currently payable:FederalState
TotalIncome taxes deferred:
FederalState
TotalUncertain tax positions:
FederalState
TotalInvestment tax credits:
DeferredRestored
TotalTotal income tax (benefit) expense
IDACORP2011
(thousands of dollars) $ (10)
790780
23,940(1,285)22,655
(66,225)(8,211)
(74,436)
2,223(3,355)(1,132)
$ (52,133)
2010
$ (39,518)
(5,960)(45,478)
(22,582)(4,436)
(27,018)
65,2228,076
73,298
1,845(3,378)(1,533)
$ (731)
2009
$ 6,199
1086,307
23,309(4,509)18,800
(2,496)
(485)(2,981)
3,640
(3,404)236
$ 22,362
Idaho Power2011
$ 9,234
7,29616,530
24,559(6,920)17,639
(66,225)(8,211)
(74,436)
2,223(3,355)(1,132)
$ (41,399)
2010
$ (62,338)
(5,580)(67,918)
10,902(4,036)6,866
65,2228,076
73,298
1,845(3,378)(1,533)
$ 10,713
2009
$ 21,035
2,38523,420
20,638(5,792)14,846
(2,496)
(485)(2,981)
3,640
(3,404)236
$ 35,521
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The components of the net deferred tax liability are as follows:
Property, plant and equipmentRegulatory assetsConservation programsPower cost adjustmentsPartnership investmentsRetirement benefitsOther
TotalNet deferred tax liabilities
IDACORP2011
(thousands of dollars)
$ 45,4735,118
22,17212,9581,711
119,31010,594
122,4455,380
345,161
333,335599,992
3,464—
19,749122,71221,797
1,101,049$ 755,888
2010
$ 46,199
7,06121,2998,292
—120,229
—88,8278,617
300,524
284,794422,216
7,61111,83318,38093,99717,451
856,282$ 555,758
Idaho Power2011
$ 45,473
5,11822,06712,9581,7118,571
10,594122,445
3,758232,695
333,335599,992
3,464—
6,181122,71215,956
1,081,640$ 848,945
2010
$ 46,199
7,06121,0458,292
—6,471
—88,8274,422
182,317
284,794422,216
7,61111,8334,551
93,99711,146
836,148$ 653,831
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, IDACORP had $94.1 million of general business credit carryforward for federal income tax purposes and $25.2 million of Idaho investment tax credit carryforward. The general business credit carryforward period expires from 2024 to 2031, and the Idaho investment tax credit expires from 2019 to 2025. Uncertain Tax Positions
A reconciliation of the beginning and ending amount of unrecognized tax benefits for IDACORP and Idaho Power is as follows (in thousands of dollars):
Balance at January 1,Additions for tax positions of the current yearAdditions for tax positions of prior yearsReductions for tax positions of prior yearsSettlements with taxing authoritiesBalance at December 31,
2011$ 74,436
——
(66,379)(8,057)
$ —
2010$ 1,138
2,82271,614(1,138)
—$ 74,436
2009$ 4,119
—1,138
(4,119)—
$ 1,138
IDACORP and Idaho Power recognize interest accrued related to unrecognized tax benefits as interest expense and penalties as other expense. Both companies recognized a net reduction in interest expense of $0.2 million in 2011, interest expense of $0.2 million in 2010, and a net reduction in interest expense of $0.2 million in 2009. Accrued interest at both companies was zero as
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of December 31, 2011, $0.2 million as of December 31, 2010, and zero as of December 31, 2009. 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 open tax years are 2011 for federal and 2008-2011 for Idaho. In May 2009, IDACORP formally entered the U.S. Internal Revenue Service (IRS) Compliance Assurance Process (CAP) program for its 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. IDACORP and Idaho Power believe 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 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.
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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, IDACORP and Idaho Power paid previously accrued income tax liabilities of $3.9 million and $8.1 million, respectively, related to the capitalized repairs examination agreement. The difference in liabilities is primarily due to IDACORP's utilization of deferred federal general business tax credits. 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, IDACORP and Idaho Power realized federal and state cash benefits associated with the 2009 capitalized repairs and uniform capitalization method changes of $33 million and $42 million, respectively. 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.
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3. REGULATORY MATTERS Regulatory Assets and Liabilities Regulatory assets represent incurred costs that have been deferred because it is probable 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):
(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 11.(3) These items are discussed in more detail below.(4) Asset retirement obligations and removal costs are discussed in Note 13.(5) Mark-to-market assets and liabilities are discussed in Note 16.
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
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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.
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 PURPA 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 each of the years ended December 31, 2011, 2010, and 2009.
EffectiveDate
June 1, 2011
June 1, 2010
June 1, 2009
$ Change(millions)
$ (40.4)
$ (146.9)
$ 84.3
NotesThe reduction to Idaho PCA rates was net of $10.0 million of Idaho Power’s energyefficiency rider deferral balance that the IPUC authorized for recovery in Idaho Power’sIdaho PCA rates.The IPUC’s order was made in conjunction with a January 2010 rate settlement agreementdescribed below in “January 2010 and December 2011 Idaho Settlement Agreements.”Concurrent with the PCA rate decrease, the IPUC authorized an $88.7 million increase inbase 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 APCU 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 each of the three years ended December 31, 2011, 2010, and 2009 were as follows:
Year andMechanism2011 PCAM2011 APCU2010 PCAM2010 APCU2009 PCAM2009 APCU
APCU or PCAM AdjustmentActual net power supply costs were below the deadband, resulting in a $1.5 million deferral.A rate decrease of $2.2 million annually took effect June 1, 2011.Actual net power supply costs were within the deadband, resulting in no deferral.A rate increase of $2.6 million annually took effect June 1, 2010.Actual net power supply costs were within the deadband, resulting in no deferral.A rate increase of $3.9 million annually took effect June 1, 2009.
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In May 2009, the OPUC adopted a stipulation allowing Idaho Power to defer excess net power supply costs of $6.4 million (including interest through the date of the order) for the period May 1 through December 31, 2007. Idaho Power recorded the $6.4 million deferral in 2009 as a reduction to PCA expense. The amount to be recovered was reduced by $0.9 million of previously deferred SO2 emission allowance sales (including interest) during the same period. Effective January 2011, these costs are being collected through rates and amortized.
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.
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Because Idaho Power’s actual Idaho ROE was between 9.5 and 10.5 percent in 2009 and 2010, the sharing and amortization 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. 2008 Idaho General Rate Case: On January 30, 2009, the IPUC issued an order approving an increase in Idaho base rates, effective February 1, 2009, of approximately $20.9 million annually, a return on equity of 10.5 percent, and an overall rate of return of 8.18 percent. On February 19, 2009, Idaho Power filed a request for reconsideration with the IPUC and on March 19, 2009, the IPUC issued an order that increased Idaho Power’s Idaho base rates by an additional $6.1 million to approximately $27 million for this rate case. The January 30, 2009 order authorized approximately $15 million related to increases in base net power supply costs. It also allowed Idaho Power to include in Idaho-jurisdictional rates approximately $6.5 million ($10.7 million including income tax gross-up) of 2009 AFUDC relating to the Hells Canyon Complex relicensing project. Typically, AFUDC is not included in rates until a project is in use and benefiting customers, but the IPUC determined that including this amount in current rates is in the public interest. Because AFUDC is already recorded on an accrual basis, this portion of the rate increase improves cash flows but does not have a current impact on Idaho Power’s net income. The amounts collected are being deferred as a regulatory liability and will be recognized in revenues over the life of the new license once it has been issued.
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.
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The following table summarizes FCA rate adjustments since inception:
FCA Year2010200920082007
Period rates in effectJune 1, 2011-May 31, 2012June 1, 2010-May 31, 2011June 1, 2009-May 31, 2010June 1, 2008-May 31, 2009
Annual Amount (in millions)
9.36.32.7
(2.4)
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.
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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 Ratemaking 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 (AMI)
The AMI project provides the means to automatically retrieve energy consumption information, eliminating manual meter reading 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 AMI 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
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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, 2010, and 2009 was $10.6 million, $10.6 million, and $6.2 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 2008 and 2009 Idaho Power filed revisions to its depreciation rates with the IPUC, the OPUC, and the FERC. The commissions approved the new rates, which reduce depreciation expense approximately $8.5 million annually. Idaho Power began applying the new depreciation rates in August 2008.
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 OATT, which allows transmission rates to be updated annually based on financial and operational data Idaho Power files with the FERC. Idaho Power's OATT rates submitted to the FERC in Idaho Power's four most recent annual OATT Final Informational Filings were as follows:
Applicable Period
October 1, 2008 to September 30, 2009October 1, 2009 to September 30, 2010October 1, 2010 to September 30, 2011October 1, 2011 to September 30, 2012
OATT Rate (perKW-year)*
$ 13.81$ 15.83$ 19.60$ 19.79
* In September 2010, Idaho Power made corrections to its OATT 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.
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4. LONG-TERM DEBT The following table summarizes long-term debt at December 31 (in thousands of dollars):
First mortgage bonds:6.60% Series due 20114.75% Series due 20124.25% Series due 20136.025% Series due 20186.15% Series due 20194.50% Series Due 20203.40% Series Due 20206% Series due 20325.50% Series due 20335.50% Series due 20345.875% Series due 20345.30% Series due 20356.30% Series due 20376.25% Series due 20374.85% Series due 2040
Total first mortgage bondsPollution control revenue bonds:
5.15% Series due 2024(1)
5.25% Series due 2026(1)
Variable Rate Series 2000 due 2027Total pollution control revenue bonds
American Falls bond guaranteeMilner Dam note guaranteeUnamortized premium/discount - net
Total Idaho Power outstanding debt(2)
Debt related to investments in affordable housingTotal IDACORP outstanding debt
Current maturities of long-term debtTotal long-term debt
(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 $1.461 billion.(2) At December 31, 2011 and 2010, the overall effective cost of Idaho Power's outstanding debt was 5.43 percent and 5.53 percent, respectively.
At December 31, 2011, the maturities for the aggregate amount of IDACORP and Idaho Power long-term debt outstanding were (in thousands of dollars):
2012$ 101,064
2013$ 71,064
2014$ 1,064
2015$ 1,064
2016$ 1,064
Thereafter$ 1,316,407
IDACORP Long-Term Financing
As of December 31, 2011, IDACORP had approximately $539 million remaining on a shelf registration statement filed with the U.S. Securities and Exchange Commission (SEC) that can be used for the issuance of debt securities or IDACORP common stock. Common stock is discussed further in Note 6.
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Idaho Power Long-Term Financing
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, IDACORP and Idaho Power entered into amended and restated credit agreements, which amended and restated their existing $100 million and $300 million credit facilities, respectively. The new credit facilities may be used for general corporate purposes and commercial paper backup. IDACORP's credit facility consists of a revolving line of credit not to exceed the aggregate principal amount at any one time outstanding of $125 million, including swingline loans in an aggregate principal amount at any time outstanding not to exceed $15 million, and letters of credit in an aggregate principal amount at any time outstanding not to exceed $50 million. 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 amount at any time outstanding not to exceed $30 million. IDACORP and Idaho Power have the right to request an increase in the aggregate principal amount of the
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facilities to $150 million and $450 million, respectively, in each case subject to certain conditions. The credit facilities mature on October 26, 2016, although IDACORP and Idaho Power have the right to request up to 2 one-year extensions of the credit agreement, in each case subject to certain conditions.
The IDACORP and Idaho Power credit facilities have similar terms and conditions. The interest rates for any borrowings under the facilities are 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 IDACORP's or Idaho Power's, as applicable, 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 agreements. Under their respective facilities, the companies pay a facility fee on the commitment based on the respective company's credit rating for senior unsecured long-term debt securities. At December 31, 2011, no amounts were outstanding under either IDACORP's or Idaho Power's facilities. 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):
Commercial paper balances:At the end of yearAverage during the yearWeighted-average interest rateAt the end of the year
IDACORP2011
$ 54,200$ 65,574
0.47%
2010
$ 66,900$ 19,754
0.43%
Idaho Power2011
$ —$ —
—%
2010
$ —$ 348
—%
Total2011
$ 54,200$ 65,574
0.47%
2010
$ 66,900$ 20,102
0.43% 6. COMMON STOCK IDACORP Common Stock
The following table summarizes common stock transactions during the last three years and shares reserved at December 31, 2011:
Balance at beginning of yearContinuous equity programDividend reinvestment and stock purchase planEmployee savings planLong-term incentive and compensation planRestricted stock plan
Balance at end of year
Shares issued2011
49,419,452—
119,99991,277
333,444—
49,964,172
201047,925,882
973,585144,655105,375256,66213,293
49,419,452
200946,929,203
489,360209,859156,814112,12828,518
47,925,882
Shares reservedDecember 31, 2011
3,000,0002,638,8073,618,9031,703,842
256,154
IDACORP enters into sales agency agreements as a means of selling its common stock from time to time pursuant to a continuous equity program. IDACORP's current sales agency agreement is with BNY Mellon Capital Markets, LLC. As of December 31, 2011, there were approximately 3 million shares remaining available to be sold under the current sales agency agreement. No shares were issued under the sales agency agreement in 2011. IDACORP sold 973,585 shares under the program in 2010 at an average price of $35.47 and 489,360 shares in 2009 at an average price of $28.79.
Idaho Power Common Stock
In 2011, 2010, and 2009, IDACORP contributed $16 million, $50 million, and $20 million, respectively, of additional equity to Idaho Power. No additional shares of Idaho Power common stock were issued in exchange for the contributions.
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Restrictions on Dividends A covenant under IDACORP’s credit facility and Idaho Power’s credit facility requires IDACORP and Idaho Power to maintain leverage ratios 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 IDACORP and IDACORP’s ability to pay dividends on its common stock are 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 ratios for IDACORP and Idaho Power were 48 percent and 49 percent, respectively. Based on these restrictions, IDACORP’s and Idaho Power’s dividends were limited to $827 million and $723 million, respectively, 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 undefined 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. 7. STOCK-BASED COMPENSATION IDACORP 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.
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A summary of restricted stock and performance share activity is presented below. Idaho Power share amounts represent the portion of IDACORP amounts related to Idaho Power employees:
Nonvested shares at January 1, 2011Shares grantedShares forfeitedShares vestedNonvested shares at December 31, 2011
IDACORP
Number ofShares
351,953136,644(11,451)
(137,208)339,938
Weighted-Average
Grant DateFair Value
$ 26.3530.3027.3225.28
$ 26.40
Idaho Power
Number ofShares
329,501135,016(11,451)
(115,883)337,183
Weighted-Average
Grant DateFair Value
$ 26.3530.3027.3225.28
$ 26.40 The total fair value of shares vested during the years ended December 31, 2011, 2010, and 2009 was $4.1 million, $3.3 million, and $3.9 million, respectively. At December 31, 2011, IDACORP had $4 million of total unrecognized compensation cost related to nonvested share-based compensation that was expected to vest. Idaho Power’s share of this amount was $4 million. These costs are expected to be recognized over a weighted-average period of 1.68 years. IDACORP uses 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. 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. IDACORP uses original issue and/or treasury shares to satisfy exercised options.
IDACORP’s and Idaho Power’s stock option transactions are summarized below. Idaho Power share amounts represent the portion of IDACORP amounts related to Idaho Power employees:
IDACORPOutstanding at December 31, 2010ExercisedExpiredOutstanding at December 31, 2011Vested and exercisable at December 31, 2011
Idaho PowerOutstanding at December 31, 2010ExercisedExpiredOutstanding at December 31, 2011
Vested and exercisable at December 31, 2011
Numberof
Shares
385,785(255,746)(102,233)
27,80627,806
202,634(90,945)
(102,233)9,456
9,456
Weighted-AverageExercise
Price
$ 37.4736.8439.89
$ 32.29$ 32.29
$ 38.0535.5439.89
$ 33.67
$ 33.67
WeightedAverage
RemainingContractualTerm (Years)
1.12
1.751.75
1.13
1.58
1.58
AggregateIntrinsic
Value(000s)
$ 541
$ 281$ 281
$ 314
$ 83
$ 83
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The following table presents information about options vested and exercised (in thousands of dollars):
Fair value of options vestedIntrinsic value of options exercisedCash received from exercisesTax benefits realized from exercises
IDACORP2011
$ —884
9,423345
2010$ 110
1,4915,475
583
2009$ 266
20459180
Idaho Power2011
$ —535
3,838209
2010$ 96
1,4755,394
577
2009$ 208
20459180
Compensation Expense: The following table shows the compensation cost recognized in income and the tax benefits resulting from these plans, as well as the amounts allocated to Idaho Power for those costs associated with Idaho Power’s employees (in thousands of dollars):
Compensation costIncome tax benefit
IDACORP2011
$ 4,2071,645
2010$ 3,706
1,449
2009$ 4,199
1,642
Idaho Power2011
$ 4,0821,596
2010$ 3,489
1,364
2009$ 3,986
1,587 No equity compensation costs have been capitalized. 8. EARNINGS PER SHARE The following table presents the computation of IDACORP’s basic and diluted earnings per share (EPS) for the years ended December 31, 2011, 2010, and 2009 (in thousands, except for per share amounts):
Numerator:
Net income attributable to IDACORP, Inc.Denominator:
Weighted-average common shares outstanding - basicEffect of dilutive securities:
OptionsRestricted Stock
Weighted-average common shares outstanding - dilutedBasic earnings per shareDiluted earnings per share
Year Ended December 31,2011
$ 166,693
49,457
1685
49,558$ 3.37$ 3.36
2010
$ 142,798
48,193
32115
48,340$ 2.96$ 2.95
2009
$ 124,350
47,124
1642
47,182$ 2.64$ 2.64
The diluted EPS computation excludes 137,880, 332,182, and 594,107 options for the years ended December 31, 2011, 2010 and 2009, respectively, because the options’ exercise prices were greater than the average market price of the common stock during that year. In total, 27,806 options were outstanding at December 31, 2011, with expiration dates between 2012 and 2015.
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9. COMMITMENTS 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 thousand of dollars):
Cogeneration and power productionPower and transmission rightsFuel
2012$ 165,693
10,77279,138
2013$ 196,261
4,24364,852
2014$ 209,295
3,18866,309
2015$ 214,960
2,21022,661
2016$ 218,220
1,8798,909
Thereafter$3,687,810
4,40198,212
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, and 970,419 MWh at a cost of $59 million in 2009. In addition, IDACORP has the following long-term commitments for lease guarantees, equipment, maintenance and services, and industry related fees (in thousand of dollars:
Operating leasesEquipment, maintenance, and service agreementsFERC and other industry-related fees
2012$ 2,041
38,55312,391
2013$ 2,875
15,27112,031
2014$ 2,768
6,1699,745
2015$ 2,199
4,8979,745
2016$ 1,203
3,7006,596
Thereafter$ 15,711
8,25432,981
IDACORP’s expense for operating leases was approximately $5.3 million in 2011, $3.4 million in 2010, and $3.5 million in 2009. 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. IDACORP and Idaho Power enter 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. IDACORP and Idaho Power periodically evaluate 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 IDACORP or Idaho Power would be required to perform under such indemnification provisions or otherwise incur any significant losses with respect to such indemnification obligations. Neither IDACORP nor Idaho Power has recorded any liability on their respective consolidated balance sheets with respect to these indemnification obligations.
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10. CONTINGENCIES IDACORP and Idaho Power have in the past and expect in the future to become involved in various claims, controversies, disputes, and other contingent matters, including the items described in this Note 10. Some of these claims, controversies, disputes, and other contingent matters involve litigation and regulatory or other contested proceedings. IDACORP and Idaho Power intend 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, IDACORP and Idaho Power, as applicable, establish 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 cases, there may be a possible exposure to loss in excess of any amounts accrued. IDACORP and Idaho Power monitor 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, IDACORP and Idaho Power do 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, IDACORP's and 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. IDACORP's and 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 IDACORP and Idaho Power are able to estimate the loss may change, and the estimates themselves may change.
For certain of those matters described in this report for which IDACORP or Idaho Power have determined a loss contingency may, in the future, be at least reasonably possible, IDACORP and Idaho Power have 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 IDACORP or 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 IDACORP's and 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 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. Pacific 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
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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 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 IDACORP's or 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
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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 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 SRBA in 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 IDACORP and Idaho Power are parties to legal claims, actions, and proceedings in addition to those discussed above. However, as of the date of this report the companies believe that resolution of these matters will not have a material adverse effect on their consolidated financial positions, results of operations, or cash flows. 11. 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. Idaho Power was not required to contribute to the plan in 2009. 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.
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The following table summarizes the changes in benefit obligations and plan assets of these plans (in thousands of dollars):
Change in benefit obligation:Benefit obligation at January 1Service costInterest costActuarial lossBenefits paidBenefit obligation at December 31Change in plan assets:Fair value at January 1Actual return on plan assetsEmployer contributionsBenefits paidFair value at December 31Funded status at end of yearAmounts recognized in the statement of financial positionconsist of:Other current liabilitiesNoncurrent liabilitiesNet amount recognized
Amounts recognized in accumulated other comprehensiveincome consist of:Net lossPrior service costSubtotalLess amount recorded as regulatory assetNet amount recognized in accumulatedother comprehensive incomeAccumulated benefit obligation
Pension Plan2011
$ 569,934
20,47830,32255,535
(20,830)655,439
397,003
(4,592)18,500
(20,830)390,081
$ (265,358)
$ —(265,358)
$ (265,358)
$ 245,6321,335
246,967(246,967)
$ —$ 549,503
2010
$ 506,744
17,67129,11935,909
(19,509)569,934
313,47443,03860,000
(19,509)397,003
$ (172,931)
$ —(172,931)
$ (172,931)
$ 161,8551,855
163,710(163,710)
$ —$ 482,448
SMSP2011
$ 59,126
1,9503,0944,251
(3,378)65,043
—————
$ (65,043)
$ (3,496)(61,547)
$ (65,043)
$ 21,7991,502
23,301—
$ 23,301$ 59,836
2010
$ 52,719
1,5413,0045,186
(3,324)59,126
—————
$ (59,126)
$ (3,289)(55,837)
$ (59,126)
$ 18,8401,744
20,584—
$ 20,584$ 54,213
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The following table shows the components of net periodic benefit cost for these plans (in thousands of dollars):
Service costInterest costExpected return on assetsAmortization of net lossAmortization of prior service costNet periodic pension cost
Adjustment to cost recognized due to the effects of regulation(1)
Net periodic benefit cost recognized forfinancial reporting
Pension Plan2011
$ 20,47830,322
(32,322)8,673
51927,670
6,662
$ 34,332
2010$ 17,671
29,119(26,463)
7,675650
28,652
(24,104)
$ 4,548
2009$ 16,514
27,865(23,965)
8,857650
29,921
(28,669)
$ 1,252
SMSP2011
$ 1,9503,094
—1,293
2426,579
—
$ 6,579
2010$ 1,541
3,004—
931233
5,709
—
$ 5,709
2009$ 1,610
2,854—
659232
5,355
—
$ 5,355
(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 2012, IDACORP and Idaho Power expect to recognize as components of net periodic benefit cost $15.9 million from 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 $0.2 million of amortization of prior service cost for the SMSP.
The following table summarizes the expected future benefit payments of these plans (in thousands of dollars):
Pension PlanSMSP
2012$ 22,360
3,578
2013$ 24,001
3,707
2014$ 25,684
3,899
2015$ 27,597
4,063
2016$ 29,761
4,084
2017-2021$ 186,450
22,797 As of December 31, 2011, IDACORP's and 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. IDACORP and 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.
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The following table summarizes the changes in benefit obligation and plan assets (in thousands of dollars):
Change in accumulated benefit obligation:Benefit obligation at January 1Service costInterest costActuarial lossBenefits paid(1)
Plan amendmentsBenefit obligation at December 31Change in plan assets:Fair value of plan assets at January 1Actual return on plan assetsEmployer contributionsBenefits paid(1)
Fair value of plan assets at December 31Funded status at end of year (included in noncurrent liabilities)
2011
$ 68,0481,3233,434
(2,850)(2,968)
(318)66,669
33,1761,065
628(2,968)31,901
$ (34,768)
2010
$ 62,6471,2763,5783,291
(3,373)629
68,048
30,8923,3812,276
(3,373)33,176
$ (34,872)
(1) Benefits paid are net of $3,405 and $2,971 of plan participant contributions, and $444 and $415 of Medicare Part D subsidy receipts for 2011 and 2010, respectively.
Amounts recognized in accumulated other comprehensive income consist of the following (in thousands of dollars):
Net lossPrior service creditTransition obligationSubtotalLess amount recognized in regulatory assetsLess amount included in deferred tax assetsNet amount recognized in accumulated other comprehensive income
2011$ 14,112
(323)2,040
15,829(15,536)
(293)$ —
2010$ 15,963
(426)4,080
19,617(19,032)
(585)$ —
The net periodic postretirement benefit cost was as follows (in thousands of dollars):
Service costInterest costExpected return on plan assetsAmortization of net lossAmortization of prior service costAmortization of unrecognized transition obligationNet periodic postretirement benefit cost
2011$ 1,323
3,434(2,641)
577(421)
2,040$ 4,312
2010$ 1,276
3,578(2,503)
562(482)
2,040$ 4,471
2009$ 1,221
3,565(2,146)
842(535)
2,040$ 4,987
In 2012, IDACORP and Idaho Power expect to recognize as components of net periodic benefit cost $2.2 million from amortizing amounts recorded 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 $2.0 million of transition obligation.
Medicare Act: The Medicare Prescription Drug, Improvement and Modernization Act of 2003 was signed into law in December 2003 and established a prescription drug benefit, as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare’s prescription drug coverage.
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The following table summarizes the expected future benefit payments of the postretirement benefit plan and expected Medicare Part D subsidy receipts (in thousands of dollars):
Expected benefit paymentsExpected Medicare Part D subsidy receipts
2012$ 4,176
478
2013$ 4,261
524
2014$ 4,415
563
2015$ 4,543
612
2016$ 4,620
671
2017-2021$ 23,849
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:
Discount rateRate of compensation increase(1)
Medical trend rateDental trend rateMeasurement date
Pension Plan2011
4.90%4.35%
——
12/31/2011
20105.40%4.50%
——
12/31/2010
SMSP2011
5.10%4.50%
——
12/31/2011
20105.40%4.50%
——
12/31/2010
PostretirementBenefits
20115.05%
—7.0%
5%12/31/2011
20105.40%
—7.5%
5%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:
Discount rateExpected long-term rate of return
on assetsRate of compensation increaseMedical trend rateDental trend rate
Pension Plan20115.40%
8.25%4.50%
——
20105.90%
8.25%4.50%
——
20096.10%
8.50%4.50%
——
SMSP20115.40%
—4.50%
——
20105.90%
—4.50%
——
20096.10%
—4.50%
——
PostretirementBenefits
20115.40%
8.25%—7.0%5.0%
20105.90%
8.25%—7.5%5.0%
20096.10%
8.50%—8.0%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 December 31, 2011 (in thousands of dollars):
Effect on total of cost componentsEffect on accumulated postretirement benefit obligation
One-Percentage-PointIncrease
$ 3422,939
Decrease$ (255)
(2,300)
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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 ClassDebt securitiesEquity securitiesReal estateOther plan assetsTotal
TargetAllocation
24%54%6%
16%100%
ActualAllocation
December 31, 2011
25%54%6%
15%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.
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.
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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):
(1) Subsequent to the issuance of the 2010 consolidated financial statements, IDACORP and 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.
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The following table presents a reconciliation of the beginning and ending balances of the fair value measurements using significant unobservable inputs (Level 3):
Beginning balance - January 1, 2010Realized lossesUnrealized gainsPurchases, issuances, and settlements, netEnding balance - December 31, 2010Realized gainsRealized lossesUnrealized gainsPurchases, issuances, and settlements, netEnding balance - December 31, 2011
PrivateEquity
$ 20,202—
1,2848,446
29,932—
(133)1,425
(3,438)$ 27,786
RealEstate
$ 20,783(47)
2,211(878)
22,069598—
1,854598
$ 25,119
Total$ 40,985
(47)3,4957,568
52,001598
(133)3,279
(2,840)$ 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 fund 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 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 both 2010 and 2009.
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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 IDACORP’s and Idaho Power’s consolidated balance sheets at December 31, 2011 and 2010 are $3.8 million and $4.5 million, respectively.
12. 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):
ProductionTransmissionDistributionGeneral and OtherTotal in serviceAccumulated provision for depreciationIn service - net
2011Balance
$ 1,832,287871,784
1,434,925327,877
4,466,873(1,677,609)
$ 2,789,264
Avg Rate2.22%2.06%3.12%7.32%2.83%
2010Balance
$ 1,792,305855,202
1,377,239307,308
4,332,054(1,614,013)
$ 2,718,041
Avg Rate2.23%2.03%3.13%7.41%2.84%
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 PlantJim Bridger Units 1-4BoardmanValmy Units 1 and 2
LocationRock Springs, WYBoardman, ORWinnemucca, NV
UtilityPlant inService
$ 539,29479,714
350,582
ConstructionWork in Progress
$ 8,334940
7,352
AccumulatedProvision for Depreciation$ 276,375
53,843202,811
Ownership%331050
MW (1)
77164284
(1) 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, $76 million, and $66 million in 2011, 2010, and 2009, respectively. Idaho Power has contracts to purchase the energy from four PURPA qualified facilities that are 50 percent owned by Ida-West. Idaho Power’s power purchases from these facilities were $9 million, $8 million, and $9 million in 2011, 2010, and 2009, respectively. See Note 1 for a discussion of the property of IDACORP’s consolidated VIE.
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13. 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 a liability 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 polychlorinated 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 $3.9 million in the recorded AROs. The primary cause of the increase in the AROs was the decision to decommission the Boardman generating facility at December 31, 2020. A decommissioning study was performed, and now that a removal date has been determined and the fair value of the associated liabilities can be estimated, ARO amounts related to the Boardman decommissioning are being recognized in the consolidated financial statements. Idaho Power also has additional AROs associated with its transmission system, hydroelectric facilities, and jointly owned coal-fired generation facilities; however, due to the indeterminate removal date, the fair value of the associated liabilities currently cannot be estimated and no amounts are recognized in the consolidated financial statements. The regulated operations of Idaho Power also collect removal costs in rates for certain assets that do not have associated AROs. Idaho Power is required to redesignate these removal costs as regulatory liabilities. See Note 3 for the costs recorded as regulatory liabilities on IDACORP’s and Idaho Power’s Consolidated Balance Sheets as of December 31, 2011 and 2010. The following table presents the changes in the carrying amount of AROs (in thousands of dollars):
Balance at beginning of yearAccretion expenseRevisions in estimated cash flowsLiability settledBalance at end of year
2011$ 16,952
9363,930(451)
$ 21,367
2010$ 16,240
819929
(1,036)$ 16,952
14. INVESTMENTS IN DEBT AND EQUITY SECURITIES The table below summarizes IDACORP’s and Idaho Power’s investments as of December 31 (in thousands of dollars).
Total Idaho Power investmentsInvestments in affordable housingEquity method investmentsExecutive deferred compensation plan
Total IDACORP investments
2011
$ 102,15822,2053,439
2127,80462,55610,782
—$ 201,142
2010
$ 90,49524,5614,746
3119,80573,58310,795
615$ 204,798
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Equity Method Investments
Idaho Power, through its subsidiary IERCo, is a 33 percent owner of BCC. Ida-West, through separate subsidiaries, owns 50 percent of three electric generation projects that are accounted for using the equity method: South Forks Joint Venture; Hazelton/Wilson Joint Venture, and Snow Mountain Hydro LLC. IFS invests in affordable housing developments. All projects are reviewed periodically for impairment. The table below presents IDACORP’s and Idaho Power’s earnings (loss) of unconsolidated equity-method investments (in thousands of dollars).
$ (1,033) Investments in Debt and Equity Securities
Investments in securities classified as available-for-sale securities are reported at fair value, using either specific identification or average cost to determine the cost for computing gains or losses. Any unrealized gains or losses on available-for-sale securities are included in other comprehensive income. The table below summarizes investments in equity securities by IDACORP and Idaho Power as of December 31, 2011 and December 31, 2010 (in thousands of dollars).
Available-for-sale securities
December 31, 2011Gross
UnrealizedGain
$ 4,220
GrossUnrealized
Loss$ 1
FairValue
$ 22,205
December 31, 2010Gross
UnrealizedGain
$ 4,876
GrossUnrealized
Loss$ —
FairValue
$ 24,561
At the end of each reporting period, IDACORP and Idaho Power analyze 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, 2010, or 2009.
15. 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 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.
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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).
December 31, 2011Current:
Financial swapsFinancial swapsForward contracts
Long-term:Financial swaps
TotalDecember 31, 2010Current:
Financial swapsFinancial swapsForward contracts
Long-term:Financial swapsTotal
Asset DerivativesBalance Sheet
Location
Other current assetsOther current liabilitiesOther current assets Other assets
Other current assetsOther current liabilities
Other liabilities
FairValue
$ 4,361
1,52670
359
$ 6,316
$ 930
2,440
100
$ 3,470
Liability DerivativesBalance Sheet
Location
Other current assetsOther current liabilitiesOther current liabilities Other liabilities
Other current assetsOther current liabilitiesOther current liabilities Other liabilities
FairValue
$ 1,036
4,7551,370
108$ 7,269
$ 356
4,172508
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$ 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) onDerivatives Recognized in Income
Off-system salesPurchased power
Fuel expenseOther operations and maintenance
Fuel Expense
Gain/(Loss) on Derivatives Recognized in Income(1)
2011$ 9,594
(7,124)501425—
2010$ 4,499
(12,240)(101)
—(721)
(1) 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 16 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.
CommodityElectricity purchasesElectricity salesNatural gas purchasesNatural gas salesDiesel purchases
UnitsMWhMWh
MMBtuMMBtuGallons
December 31,2011
225,6001,298,4207,928,311
352,1291,273,997
2010347,400338,200647,900
—1,061,969
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Credit Risk 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 collateralization 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. 16. FAIR VALUE MEASUREMENTS IDACORP and Idaho Power have 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 measurement of the instrument. Financial assets and liabilities recorded on the consolidated balance sheets 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 IDACORP and 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; andd) 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.
IDACORP and 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
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are actively traded money market and equity funds with quoted prices in active markets.
The table below presents information about IDACORP’s and 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). IDACORP’s and 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.
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 notes receivable and long-term debt are based upon quoted market prices of the same or similar issues or discounted cash flow analysis as appropriate.
IDACORPAssets:
Notes receivableLiabilities:
Long-term debtIdaho PowerLiabilities:
Long-term debt
December 31, 2011CarryingAmount
(thousands of dollars)
$ 3,097
1,491,727
$ 1,491,727
EstimatedFair Value
$ 3,097
1,737,912
$ 1,737,912
December 31, 2010CarryingAmount
$ 2,946
1,614,299
$ 1,612,790
EstimatedFair Value
$ 2,946
1,622,924
$ 1,621,425
17. SEGMENT INFORMATION IDACORP’s only reportable segment is utility operations. The utility operations segment’s primary source of revenue is the regulated operations of Idaho Power. Idaho Power’s regulated operations include the generation, transmission, distribution, purchase, and sale of electricity. This segment also includes income from IERCo, a wholly-owned subsidiary of Idaho Power that is also subject to regulation and is a thirty-three percent owner of BCC, an unconsolidated joint venture. IDACORP’s other operating segments are below the quantitative and qualitative thresholds for reportable segments and are included in the “All Other” category in the table below. This category is comprised of IFS’s investments in affordable housing developments and historic rehabilitation projects, Ida-West’s joint venture investments in small hydroelectric generation projects, the remaining activities of energy marketer IE, which wound down its operations in 2003, and IDACORP’s holding company expenses.
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The table below summarizes the segment information for IDACORP’s utility operations and the total of all other segments, and reconciles this information to total enterprise amounts (in thousands of dollars).
2011RevenuesOperating income (loss)Other incomeInterest incomeEquity method income (loss)Interest expenseIncome (loss) before income taxesIncome tax benefitIncome attributable to IDACORP, Inc.Total assetsExpenditures for long-lived assets
2010RevenuesOperating income (loss)Other incomeInterest incomeEquity method income (loss)Interest expenseIncome (loss) before income taxesIncome tax expense (benefit)Income attributable to IDACORP, Inc.Total assetsExpenditures for long-lived assets
2009RevenuesOperating income (loss)Other incomeInterest incomeEquity method income (loss)Interest expenseIncome (loss) before income taxesIncome tax expense (benefit)Income attributable to IDACORP, Inc.Total assetsExpenditures for long-lived assets
UtilityOperations
$ 1,022,728
164,36618,8762,1469,018
71,055123,351(41,399)164,750
4,856,839337,765
$ 1,033,052
200,30811,5672,116
11,28173,925
151,34710,713
140,6344,568,393
338,252 $ 1,045,996
206,19310,7044,8598,256
71,932158,08035,521
122,5594,073,390
251,937
AllOther
$ 4,028
(118)30
233(8,220)
547(8,622)
(10,734)1,943
122,6785
$ 2,977
(1,638)558
1,023(8,273)1,288
(9,618)(11,444)
2,164131,553
— $ 3,804
(2,610)1,227
490(9,289)1,161
(11,343)(13,159)
1,791192,699
14
Eliminations $ —
——
(76)—
(76)———
(18,908)—
$ —
——
(99)—
(99)———
(23,891)—
$ —
——
(283)—
(283)———
(27,362)—
ConsolidatedTotal
$ 1,026,756
164,24818,9062,303
79871,526
114,729(52,133)166,693
4,960,609337,770
$ 1,036,029
198,67012,1253,0403,008
75,114141,729
(731)142,798
4,676,055338,252
$ 1,049,800
203,58311,9315,066
(1,033)72,810
146,73722,362
124,3504,238,727
251,951
129
18. OTHER INCOME AND EXPENSE The following table presents the components of IDACORP’s other income, net (in thousands of dollars):
Allowance for funds used during construction-equityInvestment income, netCarrying charges on regulatory assetsOther incomeSMSP expenseLife insurance proceeds, net of premiumsOther expenseOther income, net
2011$ 25,484
2,3051,665
107(6,579)
757(2,530)
$ 21,209
2010$ 16,551
3,046921
2,199(5,709)
(93)(1,750)
$ 15,165
2009$ 7,555
5,0714,4713,967
(5,355)4,197
(2,909)$ 16,997
19. RELATED PARTY TRANSACTIONS IDACORP: 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, $0.8 million, and $0.9 million in 2011, 2010, and 2009, respectively. 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, $8 million, and $9 million to Ida-West in 2011, 2010, and 2009, respectively.
130
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Shareholders ofIDACORP, Inc.Boise, Idaho We have audited the accompanying consolidated balance sheets of IDACORP, Inc. and subsidiaries (the “Company”) as of December 31, 2011 and 2010, and the related consolidated statements of income, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2011. Our audits also included the financial statement schedules listed in the Index at Item 8. These financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedules based on our audits.
We conducted our audits in accordance with the 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 misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of IDACORP, Inc. and subsidiaries at December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2011, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 22, 2012 expressed an unqualified opinion on the Company’s internal control over financial reporting. /s/ DELOITTE & TOUCHE LLP Boise, IdahoFebruary 22, 2012
131
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Shareholder ofIdaho Power CompanyBoise, Idaho We have audited the accompanying consolidated balance sheets and statements of capitalization of Idaho Power Company and subsidiary (the “Company”) as of December 31, 2011 and 2010, and the related consolidated statements of income, comprehensive income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2011. Our audits also included the financial statement schedule listed in the Index at Item 8. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits. We conducted our audits in accordance with the 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 misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Idaho Power Company and subsidiary at December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein. We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2011, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 22, 2012 expressed an unqualified opinion on the Company’s internal control over financial reporting. /s/ DELOITTE & TOUCHE LLP Boise, IdahoFebruary 22, 2012
132
SUPPLEMENTAL FINANCIAL INFORMATION, UNAUDITED QUARTERLY FINANCIAL DATA The following unaudited information is presented for each quarter of 2011 and 2010 (in thousands of dollars, except for per share amounts). In the opinion of each company, all adjustments necessary for a fair statement of such amounts for such periods have been included. The results of operations for the interim periods are not necessarily indicative of the results to be expected for the full year. Accordingly, earnings information for any three-month period should not be considered as a basis for estimating operating results for a full fiscal year. Amounts are based upon quarterly statements and the sum of the quarters may not equal the annual amount reported.
IDACORP, Inc.2011
RevenuesOperating incomeNet incomeNet income attributable to IDACORP, Inc.Basic earnings per shareDiluted earnings per share
2010RevenuesOperating incomeNet incomeNet income attributable to IDACORP, Inc.Basic earnings per shareDiluted earnings per share
Idaho Power Company2011
RevenuesIncome from operationsNet income
2010RevenuesIncome from operationsNet income
Quarter EndedMarch 31
$ 251,49450,09129,48829,740
0.600.60
$ 252,963
34,04715,85716,063
0.340.34
$ 251,06250,71329,848
$ 252,460
34,38418,221
June 30
$ 234,98334,29920,97720,901
0.420.42
$ 241,753
36,60539,23739,209
0.820.82
$ 233,92434,15320,701
$ 240,790
36,39138,828
September 30
$ 309,63071,393
107,414107,067
2.162.16
$ 309,357
88,99367,12567,135
1.401.39
$ 308,04570,415
104,872
$ 308,46889,56664,650
December 31
$ 230,6488,4648,9838,9850.180.18
$ 231,956
39,02520,24120,391
0.410.41
$ 229,6979,0869,330
$ 231,333
39,96618,935
133
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None
ITEM 9A. CONTROLS AND PROCEDURES Disclosure Controls and Procedures - IDACORP, Inc.
The Chief Executive Officer and Chief Financial Officer of IDACORP, Inc., based on their evaluation of IDACORP, Inc.’s disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of December 31, 2011, have concluded that IDACORP, Inc.’s disclosure controls and procedures are effective as of that date.
Internal Control Over Financial Reporting - IDACORP, Inc.
Management’s Annual Report on Internal Control Over Financial Reporting The management of IDACORP is responsible for establishing and maintaining adequate internal control over financial reporting for IDACORP. Internal control over financial reporting is defined in Rule 13a-15(f) promulgated under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, the company’s principal executive and principal financial officers and effected by the company’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America and includes those policies and procedures that:
• pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the company;
• provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America, and that receipts and expenditures of the company are being made only in accordance with the authorizations of management and directors of the company; and
• provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. IDACORP’s management assessed the effectiveness of the company’s internal control over financial reporting as of December 31, 2011. In making this assessment, the company’s management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework. Based on its assessment, management concluded that, as of December 31, 2011, IDACORP’s internal control over financial reporting is effective based on those criteria. IDACORP’s independent registered public accounting firm has audited the financial statements included in this Annual Report on Form 10-K for the year ended December 31, 2011 and issued a report, which appears on the next page and expresses an unqualified opinion on the effectiveness of IDACORP’s internal control over financial reporting as of December 31, 2011. February 22, 2012
134
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Shareholders ofIDACORP, Inc.Boise, Idaho We have audited the internal control over financial reporting of IDACORP, Inc. and subsidiaries (the “Company”) as of December 31, 2011, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedules as of and for the year ended December 31, 2011 of the Company and our report dated February 22, 2012 expressed an unqualified opinion on those financial statements and financial statement schedules. /s/ DELOITTE & TOUCHE LLP Boise, IdahoFebruary 22, 2012
135
Disclosure Controls and Procedures - Idaho Power Company
The Chief Executive Officer and Chief Financial Officer of Idaho Power Company, based on their evaluation of Idaho Power Company's disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of December 31, 2011, have concluded that Idaho Power Company's disclosure controls and procedures are effective as of that date.
Internal Control Over Financial Reporting - Idaho Power Company
Management’s Annual Report on Internal Control Over Financial Reporting The management of Idaho Power Company (Idaho Power) is responsible for establishing and maintaining adequate internal control over financial reporting of Idaho Power. Internal control over financial reporting is defined in Rule 13a-15(f) promulgated under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, the company’s principal executive and principal financial officers and effected by the company’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America and includes those policies and procedures that:
• pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the company;
• provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America, and that receipts and expenditures of the company are being made only in accordance with the authorizations of management and directors of the company; and
• provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Idaho Power’s management assessed the effectiveness of the company’s internal control over financial reporting as of December 31, 2011. In making this assessment, the company’s management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework. Based on its assessment, management concluded that, as of December 31, 2011, Idaho Power’s internal control over financial reporting is effective based on those criteria. Idaho Power’s independent registered public accounting firm has audited the financial statements included in this Annual Report on Form 10-K for the year ended December 31, 2011 and issued a report which appears on the next page and expresses an unqualified opinion on the effectiveness of Idaho Power’s internal control over financial reporting as of December 31, 2011. February 22, 2012
136
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Shareholder ofIdaho Power CompanyBoise, Idaho We have audited the internal control over financial reporting of Idaho Power Company and subsidiary (the “Company”) as of December 31, 2011, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule as of and for the year ended December 31, 2011 of the Company and our report dated February 22, 2012 expressed an unqualified opinion on those financial statements and financial statement schedule. /s/ DELOITTE & TOUCHE LLP Boise, IdahoFebruary 22, 2012
137
Changes in Internal Control Over Financial Reporting - IDACORP, Inc. and Idaho Power Company There have been no changes in IDACORP, Inc.’s or Idaho Power Company’s internal control over financial reporting during the quarter ended December 31, 2011 that have materially affected, or are reasonably likely to materially affect, IDACORP, Inc.’s or Idaho Power Company’s internal control over financial reporting.
ITEM 9B. OTHER INFORMATION None.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE The portions of IDACORP’s definitive proxy statement appearing under the captions “Proposal No. 1: Election of Directors - Nominees for Election - Terms Expire 2015,” “Continuing Directors – Terms Expire 2014,” “Continuing Directors - Terms Expire 2013,” “Section 16(a) Beneficial Ownership Reporting Compliance,” “Corporate Governance - Audit Committee,” and “Corporate Governance - Code of Ethics,” to be filed pursuant to Regulation 14A for the 2012 annual meeting of shareholders are hereby incorporated by reference. Information regarding IDACORP’s executive officers required by this item appears in Item 1 of this report under “Executive Officers of the Registrants.”
ITEM 11. EXECUTIVE COMPENSATION The portion of IDACORP’s definitive proxy statement appearing under the caption “Executive Compensation” to be filed pursuant to Regulation 14A for the 2012 annual meeting of shareholders is hereby incorporated by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The portion of IDACORP’s definitive proxy statement appearing under the caption “Security Ownership of Directors, Executive Officers and Five Percent Shareholders” to be filed pursuant to Regulation 14A for the 2012 annual meeting of shareholders is hereby incorporated by reference. The following table includes information as of December 31, 2011 with respect to equity compensation plans where equity securities of IDACORP may be issued. These plans are the 1994 Restricted Stock Plan (RSP) and the IDACORP 2000 Long-Term Incentive and Compensation Plan (LTICP).
Plan CategoryEquity compensation plans approved by shareholders (1)
Equity compensation plans not approved by shareholdersTotal(1) Consists of the RSP and the LTICP.(2) In addition to being available for future issuance upon exercise of options, 1,503,861 shares under the LTICP may instead be issued inconnection with stock appreciation rights, restricted stock, restricted stock units, performance units, performance shares, or other equity-basedawards as of December 31, 2011. 15,796 shares remain available for future issuance under the RSP.
(a)Number of
securities to be issued upon
exerciseof outstanding
options, warrants and
rights27,806
—27,806
(b)Weighted-
averageexercise price of
outstanding options,
warrants and rights
$ 32.29$ —$ 32.29
(c)Number of securities
remaining available for future issuance
under equity compensation
plans (excluding securities reflected
in column (a))1,519,657
—1,519,657
(2)
138
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE The portions of IDACORP’s definitive proxy statement appearing under the captions “Related Person Transaction Disclosure” and “Corporate Governance – Director Independence” to be filed pursuant to Regulation 14A for the 2012 annual meeting of shareholders are hereby incorporated by reference.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES IDACORP: The portion of IDACORP’s definitive proxy statement appearing under the caption “Independent Accountant Billings” in the proxy statement to be filed pursuant to Regulation 14A for the 2012 annual meeting of shareholders is hereby incorporated by reference. Idaho Power: The table below presents the aggregate fees our principal independent registered public accounting firm, Deloitte & Touche LLP, billed or are expected to bill to Idaho Power for the fiscal years ended December 31, 2011 and 2010:
Audit feesAudit-related fees(1)
Tax fee(2)
All other fees(3)
Total(1) Audits of Idaho Power’s benefit plans and compliance audit for the U.S. DOE Smart Grid grant.(2) Includes fees for benefit plan tax returns and consultation related to tax accounting method changes.(3) Accounting research tool subscription.
2011$ 1,047,708
91,70087,6482,200
$ 1,229,256
2010$ 1,003,947
65,930259,423
2,200$ 1,331,500
Policy on Audit Committee Pre-Approval: Idaho Power and the Audit Committee are committed to ensuring the independence of the independent registered public accounting firm, both in fact and in appearance. In this regard, the Audit Committee has established and periodically reviews a pre-approval policy for audit and non-audit services. For 2010 and 2011, all audit and non-audit services and all fees paid in connection with those services were pre-approved by the Audit Committee. In addition to the audits of Idaho Power’s consolidated financial statements, the independent public accounting firm may be engaged to provide certain audit-related, tax, and other services. The Audit Committee must pre-approve all services performed by the independent public accounting firm to assure that the provision of those services does not impair the public accounting firm’s independence. The services that the Audit Committee will consider include: audit services such as attest services, changes in the scope of the audit of the financial statements, and the issuance of comfort letters and consents in connection with financings; audit-related services such as internal control reviews and assistance with internal control reporting requirements; attest services related to financial reporting that are not required by statute or regulation, and accounting consultations and audits related to proposed transactions and new or proposed accounting rules, standards and interpretations; and tax compliance and planning services. Unless a type of service to be provided by the independent public accounting firm has received general pre-approval, it will require specific pre-approval by the Audit Committee. In addition, any proposed services exceeding pre-approved cost levels will require specific pre-approval by the Audit Committee. Under the pre-approval policy, the Audit Committee has delegated to the Chairman of the Audit Committee pre-approval authority for proposed services; however, the Chairman must report any pre-approval decisions to the Audit Committee at its next scheduled meeting. Any request to engage the independent public accounting firm to provide a service which has not received general pre-approval must be submitted as a written proposal to Idaho Power’s Chief Financial Officer with a copy to the General Counsel. The request must include a detailed description of the service to be provided, the proposed fee, and the business reasons for engaging the independent public accounting firm to provide the service. Upon approval by the Chief Financial Officer, the General Counsel, and the independent public accounting firm that the proposed engagement complies with the terms of the pre-approval policy and the applicable rules and regulations, the request will be presented to the Audit Committee or the Committee Chairman, as the case may be, for pre-approval.
139
In determining whether to pre-approve the engagement of the independent public accounting firm, the Audit Committee or the Committee Chairman, as the case may be, must consider, among other things, the pre-approval policy, applicable rules and regulations, and whether the nature of the engagement and the related fees are consistent with the following principles:
• the independent public accounting firm cannot function in the role of management of Idaho Power; and• the independent public accounting firm cannot audit its own work.
The pre-approval policy and separate supplements to the pre-approval policy describe the specific audit, audit related, tax, and other services that have the general pre-approval of the Audit Committee. The term of any pre-approval is 12 months from the date of pre-approval, unless the Audit Committee specifically provides for a different period. The Audit Committee will periodically revise the list of pre-approved services, based on subsequent determinations.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES (1) and (2) Please refer to Part II, Item 8 - “Financial Statements and Supplementary Data” for a complete listing of all consolidated financial statements and financial statement schedules. (3) Exhibits. The agreements filed as exhibits to this Annual Report on Form 10-K are filed to provide information regarding their terms and are not intended to provide any other factual or disclosure information about IDACORP, Inc., Idaho Power Company, or the other parties to the agreements. Some of the agreements contain representations and warranties by each of the parties to the applicable agreement. These representations and warranties have been made solely for the benefit of the other parties to the applicable agreement and (a) should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties to the agreement if those statements prove to be inaccurate; (b) have been qualified by disclosures that were made to the other party, which disclosures are not necessarily reflected in the agreement; (c) may apply standards of materiality in a way that is different from what may be viewed as material to investors; and (d) were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments. * Previously filed and incorporated herein by reference
Exhibit No.*2
*3.1
*3.2
*3.3
*3.4
*3.5
*3.6
DescriptionAgreement and Plan of Exchange between IDACORP, Inc., and Idaho Power Company dated as of February 2,1998. File number 333-48031, Form S-4, filed on 3/16/98, as Exhibit A.
Restated Articles of Incorporation of Idaho Power Company as filed with the Secretary of State of Idaho onJune 30, 1989. File number 33-00440, Post-Effective Amendment No. 2 to Form S-3, filed on 6/30/89, asExhibit 4(a)(xiii).
Statement of Resolution Establishing Terms of Flexible Auction Series A, Serial Preferred Stock, Without ParValue (cumulative stated value of $100,000 per share) of Idaho Power Company, as filed with the Secretary ofState of Idaho on November 5, 1991. File number 33-65720, Form S-3, filed on 7/7/93, as Exhibit 4(a)(ii).
Statement of Resolution Establishing Terms of 7.07% Serial Preferred Stock, Without Par Value (cumulativestated value of $100 per share) of Idaho Power Company, as filed with the Secretary of State of Idaho on June30, 1993. File number 33-65720, Form S-3, filed on 7/7/93, as Exhibit 4(a)(iii).
Articles of Amendment to Restated Articles of Incorporation of Idaho Power Company, as filed with theSecretary of State of Idaho on June 15, 2000. File number 1-3198, Form 10-Q for the quarter ended June 30,2000, filed on 8/4/00, as Exhibit 3(a)(iii).
Articles of Amendment to Restated Articles of Incorporation of Idaho Power Company, as filed with theSecretary of State of Idaho on January 21, 2005. File number 1-3198, Form 8-K, filed on 1/26/05, as Exhibit3.3.
Articles of Amendment to Restated Articles of Incorporation of Idaho Power Company, as amended, as filedwith the Secretary of State of Idaho on November 19, 2007. File number 1-3198, Form 8-K, filed on 11/19/07,as Exhibit 3.3.
140
Exhibit No. Description
*3.7
*3.8
*3.9
*3.10
*3.11
*3.12
*4.1
*4.2
Articles of Share Exchange, as filed with the Secretary of State of Idaho on September 29, 1998. File number33-56071-99, Post-Effective Amendment No. 1 to Form S-8, filed on 10/1/98, as Exhibit 3(d).
Amended Bylaws of Idaho Power Company, amended on November 15, 2007 and presently in effect. Filenumber 1-3198, Form 8-K, filed on 11/19/07, as Exhibit 3.2.
Articles of Incorporation of IDACORP, Inc. File number 333-64737, Amendment No. 1 to Form S-3, filed on11/4/98, as Exhibit 3.1.
Articles of Amendment to Articles of Incorporation of IDACORP, Inc. as filed with the Secretary of State ofIdaho on March 9, 1998. File number 333-64737, Amendment No. 1 to Form S-3, filed on 11/4/98, as Exhibit3.2.
Articles of Amendment to Articles of Incorporation of IDACORP, Inc. creating A Series Preferred Stock,without par value, as filed with the Secretary of State of Idaho on September 17, 1998. File number333-00139-99, Post-Effective Amendment No. 1 to Form S-3, filed on 9/22/98, as Exhibit 3(b).
Amended Bylaws of IDACORP, Inc., amended on November 15, 2007 and presently in effect. File number1-14456, Form 8-K, filed on 11/19/07, as Exhibit 3.1.
Mortgage and Deed of Trust, dated as of October 1, 1937, between Idaho Power Company and Deutsche BankTrust Company Americas (formerly known as Bankers Trust Company) and R. G. Page, as Trustees. Filenumber 2-3413, as Exhibit B-2.
Idaho Power Company Supplemental Indentures to Mortgage and Deed of Trust:File number 1-MD, as Exhibit B-2-a, First, July 1, 1939File number 2-5395, as Exhibit 7-a-3, Second, November 15, 1943File number 2-7237, as Exhibit 7-a-4, Third, February 1, 1947File number 2-7502, as Exhibit 7-a-5, Fourth, May 1, 1948File number 2-8398, as Exhibit 7-a-6, Fifth, November 1, 1949File number 2-8973, as Exhibit 7-a-7, Sixth, October 1, 1951File number 2-12941, as Exhibit 2-C-8, Seventh, January 1, 1957File number 2-13688, as Exhibit 4-J, Eighth, July 15, 1957File number 2-13689, as Exhibit 4-K, Ninth, November 15, 1957File number 2-14245, as Exhibit 4-L, Tenth, April 1, 1958File number 2-14366, as Exhibit 2-L, Eleventh, October 15, 1958File number 2-14935, as Exhibit 4-N, Twelfth, May 15, 1959File number 2-18976, as Exhibit 4-O, Thirteenth, November 15, 1960File number 2-18977, as Exhibit 4-Q, Fourteenth, November 1, 1961File number 2-22988, as Exhibit 4-B-16, Fifteenth, September 15, 1964File number 2-24578, as Exhibit 4-B-17, Sixteenth, April 1, 1966File number 2-25479, as Exhibit 4-B-18, Seventeenth, October 1, 1966File number 2-45260, as Exhibit 2(c), Eighteenth, September 1, 1972File number 2-49854, as Exhibit 2(c), Nineteenth, January 15, 1974File number 2-51722, as Exhibit 2(c)(i), Twentieth, August 1, 1974File number 2-51722, as Exhibit 2(c)(ii), Twenty-first, October 15, 1974File number 2-57374, as Exhibit 2(c), Twenty-second, November 15, 1976File number 2-62035, as Exhibit 2(c), Twenty-third, August 15, 1978File number 33-34222, as Exhibit 4(d)(iii), Twenty-fourth, September 1, 1979File number 33-34222, as Exhibit 4(d)(iv), Twenty-fifth, November 1, 1981File number 33-34222, as Exhibit 4(d)(v), Twenty-sixth, May 1, 1982File number 33-34222, as Exhibit 4(d)(vi), Twenty-seventh, May 1, 1986File number 33-00440, as Exhibit 4(c)(iv), Twenty-eighth, June 30, 1989File number 33-34222, as Exhibit 4(d)(vii), Twenty-ninth, January 1, 1990File number 33-65720, as Exhibit 4(d)(iii), Thirtieth, January 1, 1991File number 33-65720, as Exhibit 4(d)(iv), Thirty-first, August 15, 1991File number 33-65720, as Exhibit 4(d)(v), Thirty-second, March 15, 1992File number 33-65720, as Exhibit 4(d)(vi), Thirty-third, April 1, 1993
141
Exhibit No. Description
*4.3
*4.4
*4.5
*4.6
*4.7
*4.8
*4.9
*4.10
*10.1
*10.2
*10.3
*10.4
*10.5
File number 1-3198, Form 8-K, filed on 12/20/93, as Exhibit 4, Thirty-fourth, December 1, 1993File number 1-3198, Form 8-K, filed on 11/21/00, as Exhibit 4, Thirty-fifth, November 1, 2000File number 1-3198, Form 8-K, filed on 10/1/01, as Exhibit 4, Thirty-sixth, October 1, 2001File number 1-3198, Form 8-K, filed on 4/16/03, as Exhibit 4, Thirty-seventh, April 1, 2003File number 1-3198, Form 10-Q for the quarter ended June 30, 2003, filed on 8/7/03, as Exhibit
4(a)(iii), Thirty-eighth, May 15, 2003File number 1-3198, Form 10-Q for the quarter ended September 30, 2003, filed on 11/6/03, as
Exhibit 4(a)(iv), Thirty-ninth, October 1, 2003File number 1-3198, Form 8-K filed on 5/10/05, as Exhibit 4, Fortieth, May 1, 2005File number 1-3198, Form 8-K filed on 10/10/06, as Exhibit 4, Forty-first, October 1, 2006File number 1-3198, Form 8-K filed on 6/4/07, as Exhibit 4, Forty-second, May 1, 2007File number 1-3198, Form 8-K filed on 9/26/07, as Exhibit 4, Forty-third, September 1, 2007File number 1-3198, Form 8-K filed on 4/3/08, as Exhibit 4, Forty-fourth, April 1, 2008File number 1-3198, Form 10-K filed on 2/23/10, as Exhibit 4.10, Forty-fifth, February 1, 2010File number 1-3198, Form 8-K filed on 6/18/10, as Exhibit 4, Forty-sixth, June 1, 2010
Instruments relating to Idaho Power Company American Falls bond guarantee (see Exhibit 10.4). File number1-3198, Form 10-Q for the quarter ended June 30, 2000, filed on 8/4/00, as Exhibit 4(b).
Agreement of Idaho Power Company to furnish certain debt instruments. File number 33-65720, Form S-3,filed on 7/7/93, as Exhibit 4(f).
Agreement of IDACORP, Inc. to furnish certain debt instruments. File number 1-14465, Form 10-Q for thequarter ended September 30, 2003, filed on 11/6/03, as Exhibit 4(c)(ii).
Agreement and Plan of Merger dated March 10, 1989, between Idaho Power Company, a Maine Corporation,and Idaho Power Migrating Corporation. File number 33-00440, Post-Effective Amendment No. 2 to FormS-3, filed on 6/30/89, as Exhibit 2(a)(iii).
Indenture for Senior Debt Securities dated as of February 1, 2001, between IDACORP, Inc. and Deutsche BankTrust Company Americas (formerly known as Bankers Trust Company), as trustee. File number 1-14465, Form8-K, filed on 2/28/01, as Exhibit 4.1.
First Supplemental Indenture dated as of February 1, 2001 to Indenture for Senior Debt Securities dated as ofFebruary 1, 2001 between IDACORP, Inc. and Deutsche Bank Trust Company Americas (formerly known asBankers Trust Company), as trustee. File number 1-14465, Form 8-K, filed on 2/28/01, as Exhibit 4.2.
Indenture for Debt Securities dated as of August 1, 2001 between Idaho Power Company and Deutsche BankTrust Company Americas (formerly known as Bankers Trust Company), as trustee. File number 333-67748,Form S-3, filed on 8/16/01, as Exhibit 4.13.
Idaho Power Company Instrument of Further Assurance relating to Mortgage and Deed of Trust, dated as ofAugust 3, 2010. File number 1-3198, Form 10-Q for the quarter ended June 30, 2010, filed on 8/5/10, asExhibit 4.12.
Agreements, dated September 22, 1969, between Idaho Power Company and Pacific Power & Light Company,relating to the operation, construction, and ownership of the Jim Bridger Project. File number 2-49584, asExhibit 5(b).
Amendment, dated February 1, 1974, relating to the operation agreement filed as Exhibit 10.1. File number2-51762, as Exhibit 5(c).
Agreement, dated as of October 11, 1973, between Idaho Power Company and Pacific Power & LightCompany. File number 2-49584, as Exhibit 5(c).
Guaranty Agreement, dated April 11, 2000, between Idaho Power Company and Bank One Trust Company,N.A., as Trustee, relating to $19,885,000 American Falls Replacement Dam Refinancing Bonds of theAmerican Falls Reservoir District, Idaho. File number 1-3198, Form 10-Q for the quarter ended June 30, 2000,filed on 8/4/00, as Exhibit 10(c).
Guaranty Agreement, dated as of August 30, 1974, between Idaho Power Company and Pacific Power & LightCompany. File number 2-62034, Form S-7, filed on 6/30/78, as Exhibit 5(r).
142
Exhibit No. Description
*10.6
*10.7
*10.8
*10.9
*10.10
*10.11
*10.12
*10.13
*10.14
*10.15
*10.16
*10.17
*10.18
*10.19
*10.201
10.211
*10.221
*10.231
Letter Agreement, dated January 23, 1976, between Idaho Power Company and Portland General ElectricCompany. File number 2-56513, as Exhibit 5(i).
Agreement for Construction, Ownership and Operation of the Number One Boardman Station on CartyReservoir, dated as of October 15, 1976, between Portland General Electric Company and Idaho PowerCompany. File number 2-62034, Form S-7, filed on 6/30/78, as Exhibit 5(s).
Amendment, dated September 30, 1977, relating to agreement filed as Exhibit 10.6. File number 2-62034,Form S-7, filed on 6/30/78, as Exhibit 5(t).
Amendment, dated October 31, 1977, relating to agreement filed as Exhibit 10.6. File number 2-62034, FormS-7, filed on 6/30/78, as Exhibit 5(u).
Amendment, dated January 23, 1978, relating to agreement filed as Exhibit 10.6. File number 2-62034, FormS-7, filed on 6/30/78, as Exhibit 5(v).
Amendment, dated February 15, 1978, relating to agreement filed as Exhibit 10.6. File number 2-62034, FormS-7, filed on 6/30/78, as Exhibit 5(w).
Amendment, dated September 1, 1979, relating to agreement filed as Exhibit 10.6. File number 2-68574, FormS-7, filed on 7/23/80, as Exhibit 5(x).
Participation Agreement, dated September 1, 1979, relating to the sale and leaseback of coal handling facilitiesat the Number One Boardman Station on Carty Reservoir. File number 2-68574, Form S-7, filed on 7/23/80, asExhibit 5(z).
Agreements for the Operation, Construction and Ownership of the North Valmy Power Plant Project, datedDecember 12, 1978, between Sierra Pacific Power Company and Idaho Power Company. File number2-64910, Form S-7, filed on 6/29/79, as Exhibit 5(y).
Framework Agreement, dated October 1, 1984, between the State of Idaho and Idaho Power Company relatingto Idaho Power Company's Swan Falls and Snake River water rights. File number 33-65720, Form S-3, filedon 7/7/93, as Exhibit 10(h).
Agreement, dated October 25, 1984, between the State of Idaho and Idaho Power Company, relating to theagreement filed as Exhibit 10.15. File number 33-65720, Form S-3, filed on 7/7/93, as Exhibit 10(h)(i).
Settlement Agreement, dated March 25, 2009, between the State of Idaho and Idaho Power Company relatingto the agreement filed as Exhibit 10.15. File number 1-14465, 1-3198, Form 10-Q for the quarter ended March31, 2009, filed on 5/7/09, as Exhibit 10.58.
Contract to Implement, dated October 25, 1984, between the State of Idaho and Idaho Power Company, relatingto the agreement filed as Exhibit 10.15. File number 33-65720, Form S-3, filed on 7/7/93, as Exhibit 10(h)(ii).
Agreement Regarding the Ownership, Construction, Operation and Maintenance of the Milner HydroelectricProject (FERC No. 2899), dated January 22, 1990, between Idaho Power Company and the Twin Falls CanalCompany and the Northside Canal Company Limited. File number 33-65720, Form S-3, filed on 7/7/93, asExhibit 10(m).
Idaho Power Company Security Plan for Senior Management Employees I, amended and restated effectiveDecember 31, 2004, and as further amended November 20, 2008. File number 1-14465, 1-3198, Form 10-Kfor the year ended December 31, 2008, filed on 2/26/09, as Exhibit 10.15.
Idaho Power Company Security Plan for Senior Management Employees II, effective January 1, 2005, asamended and restated November 30, 2011.
IDACORP, Inc. Restricted Stock Plan, as amended and restated September 20, 2007. File number 1-14465,1-3198, Form 10-Q for the quarter ended September 30, 2007, filed on 10/31/07, as Exhibit 10(h)(iii).
IDACORP, Inc. Restricted Stock Plan - Form of Restricted Stock Agreement (time-vesting) (July 20, 2006). File number 1-14465, 1-3198, Form 10-Q for the quarter ended September 30, 2006, filed on 11/2/06, asExhibit 10(h)(vi).
143
Exhibit No. Description*10.241
*10.251
10.261
*10.271
*10.281
*10.291
*10.301
*10.311
10.321
*10.331
*10.341
*10.351
*10.361
*10.371
*10.381
*10.391
*10.401
IDACORP, Inc. Restricted Stock Plan - Form of Performance Stock Agreement (performance vesting) (July 20,2006). File number 1-14465, 1-3198, Form 10-Q for the quarter ended September 30, 2006, filed on 11/2/06,as Exhibit 10(h)(vii).
Idaho Power Company Security Plan for Board of Directors - a non-qualified deferred compensation plan, asamended and restated effective July 20, 2006. File number 1-14465, 1-3198, Form 10-Q for the quarter endedSeptember 30, 2006, filed on 11/2/06, as Exhibit 10(h)(viii).
IDACORP, Inc. Non-Employee Directors Stock Compensation Plan, as amended January 19, 2012.
Form of Officer Indemnification Agreement between IDACORP, Inc. and Officers of IDACORP, Inc. andIdaho Power Company, as amended July 20, 2006. File number 1-14465, 1-3198, Form 10-Q for the quarterended September 30, 2006, filed on 11/2/06, as Exhibit 10(h)(xix).
Form of Director Indemnification Agreement between IDACORP, Inc. and Directors of IDACORP, Inc., asamended July 20, 2006. File number 1-14465, 1-3198, Form 10-Q for the quarter ended September 30, 2006,filed on 11/2/06, as Exhibit 10(h)(xx).
Form of Amended and Restated Change in Control Agreement between IDACORP, Inc. and Officers ofIDACORP and Idaho Power Company (senior vice president and higher), approved November 20, 2008. Filenumber 1-14465, 1-3198, Form 10-K for the year ended December 31, 2008, filed on 2/26/09, as Exhibit 10.24.
Form of Amended and Restated Change in Control Agreement between IDACORP, Inc. and Officers ofIDACORP and Idaho Power Company (below senior vice president), approved November 20, 2008. Filenumber 1-14465, 1-3198, Form 10-K for the year ended December 31, 2008, filed on 2/26/09, as Exhibit 10.25.
Form of Amended and Restated Change in Control Agreement between IDACORP, Inc. and Officers ofIDACORP, Inc. and Idaho Power Company, approved March 17, 2010. File number 1-14465, 1-3198, Form 8-K, filed on 3/24/10, as Exhibit 10.1.
IDACORP, Inc. and/or Idaho Power Company Executive Officers with Amended and Restated Change inControl Agreements chart, as of January 1, 2012.
IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan, as amended November 18, 2010.
IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Stock Option Award Agreement(July 20, 2006). File number 1-14465, 1-3198, Form 10-Q for the quarter ended September 30, 2006, filed on11/2/06, as Exhibit 10(h)(xvi).
IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Restricted Stock AwardAgreement (time vesting) (July 20, 2006). File number 1-14465, 1-3198, Form 10-Q for the quarter endedSeptember 30, 2006, filed on 11/2/06, as Exhibit 10(h)(xvii).
IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Restricted Stock AwardAgreement (performance vesting) (July 20, 2006). File number 1-14465, 1-3198, Form 10-Q for the quarterended September 30, 2006, filed on 11/2/06, as Exhibit 10(h)(xviii).
IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Performance Share AwardAgreement (performance with two goals) (November 20, 2008). File number 1-14465, 1-3198, Form 10-K forthe year ended December 31, 2008, filed on 2/26/09, as Exhibit 10.30.
IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Performance Share AwardAgreement (performance with two goals) (February 25, 2011). File number 1-14465, 1-3198, Form 10-Q forthe quarter ended March 31, 2011, filed on 5/5/11, as Exhibit 10.69.
IDACORP, Inc. Executive Incentive Plan, as amended March 18, 2010 and approved May 20, 2010. Filenumber 1-14465, 1-3198, Form 8-K, filed on 5/21/10, as Exhibit 10.1.
Idaho Power Company Executive Deferred Compensation Plan, effective November 15, 2000, as amendedNovember 20, 2008. File number 1-14465, 1-3198, Form 10-K for the year ended December 31, 2008, filed on2/26/09, as Exhibit 10.32.
144
Exhibit No. Description*10.411
*10.421
*10.431
*10.441
*10.451
*10.461
*10.471
*10.481
*10.491
*10.501
*10.511
*10.52
*10.53
*10.54
*10.55
IDACORP, Inc. and Idaho Power Company Compensation for Non-Employee Directors of the Board ofDirectors, as amended January 21, 2010. File number 1-14465, 1-3198, Form 10-K for the year endedDecember 31, 2009, filed on 2/23/10, as Exhibit 10.33.
Form of IDACORP, Inc. Director Deferred Compensation Agreement, as amended November 20, 2008. Filenumber 1-14465, 1-3198, Form 10-K for the year ended December 31, 2008, filed on 2/26/09, as Exhibit 10.46.
Form of Letter Agreement to Amend Outstanding IDACORP, Inc. Director Deferred Compensation Agreement(November 16, 2008). File number 1-14465, 1-3198, Form 10-K for the year ended December 31, 2008, filedon 2/26/09, as Exhibit 10.47.
Form of Amendment to IDACORP, Inc. Director Deferred Compensation Agreement, as amended November20, 2008. File number 1-14465, 1-3198, Form 10-K for the year ended December 31, 2008, filed on 2/26/09,as Exhibit 10.48.
Form of Termination of IDACORP, Inc. Director Deferred Compensation Agreement, as amended November20, 2008. File number 1-14465, 1-3198, Form 10-K for the year ended December 31, 2008, filed on 2/26/09,as Exhibit 10.49.
Form of Idaho Power Company Director Deferred Compensation Agreement, as amended November 20, 2008. File number 1-14465, 1-3198, Form 10-K for the year ended December 31, 2008, filed on 2/26/09, as Exhibit10.50.
Form of Letter Agreement to Amend Outstanding Idaho Power Company Director Deferred CompensationAgreement (November 16, 2008). File number 1-14465, 1-3198, Form 10-K for the year ended December 31,2008, filed on 2/26/09, as Exhibit 10.51.
Form of Amendment to Idaho Power Company Director Deferred Compensation Agreement, as amendedNovember 20, 2008. File number 1-14465, 1-3198, Form 10-K for the year ended December 31, 2008, filed on2/26/09, as Exhibit 10.52.
Form of Termination of Idaho Power Company Director Deferred Compensation Agreement, as amendedNovember 20, 2008. File number 1-14465, 1-3198, Form 10-K for the year ended December 31, 2008, filed on2/26/09, as Exhibit 10.53.
Idaho Power Company Employee Savings Plan, as amended and restated as of January 1, 2010 (revised). Filenumber 1-14465, 1-3198, Form 10-K for the year ended December 31, 2009, filed on 2/23/10, as Exhibit 10.63.
Amendment to the Idaho Power Company Employee Savings Plan, dated August 31, 2011. File number1-14465, 1-3198, Form 10-Q for the quarter ended September 30, 2011, filed on November 3, 2011, as Exhibit10.72.
Second Amended and Restated Credit Agreement, dated October 26, 2011, among IDACORP, Inc., variouslenders, Wells Fargo Bank, National Association, as administrative agent, swingline lender, and LC issuer,JPMorgan Chase Bank, N.A., as syndication agent and LC issuer, KeyBank National Association and UnionBank, N.A., as documentation agents, and Wells Fargo Securities, LLC, J.P. Morgan Securities Inc., KeybancCapital Markets, and Union Bank, N.A. as joint lead arrangers and joint book runners. File number 1-14465,Form 8-K, filed on 10/28/11, as Exhibit 10.70.
Second Amended and Restated Credit Agreement, dated October 26, 2011, among Idaho Power Company,various lenders, Wells Fargo Bank, National Association, as administrative agent, swingline lender, and LCissuer, JPMorgan Chase Bank, N.A., as syndication agent and LC issuer, KeyBank National Association andUnion Bank, N.A., as documentation agents, and Wells Fargo Securities, LLC, J.P. Morgan Securities Inc.,Keybanc Capital Markets, and Union Bank, N.A. as joint lead arrangers and joint book runners.. File number1-3198, Form 8-K, filed on 10/28/11, as Exhibit 10.71.
Loan Agreement, dated October 1, 2006, between Sweetwater County, Wyoming and Idaho Power Company. File number 1-3198, Form 8-K, filed on 10/10/06, as Exhibit 10.1.
Guaranty Agreement, dated February 10, 1992, between Idaho Power Company and New York Life InsuranceCompany, as Note Purchaser, relating to $11,700,000 Guaranteed Notes due 2017 of Milner Dam Inc. Filenumber 33-65720, Form S-3, filed on 7/7/93, as Exhibit 10(m)(i).
145
Exhibit No. Description*10.56
*10.57
*10.58
*10.59
*10.60
12.1
12.2
*21.1
23.1
31.1
31.2
31.3
31.4
32.1
32.2
32.3
32.4
95.1
101.INS2
101.SCH2
101.CAL2
101.LAB2
Contract for Engineering, Procurement and Construction Services, dated May 7, 2009, between Idaho PowerCompany and Boise Power Partners Joint Venture, a joint venture consisting of Kiewit Power Engineers Co.and TIC-The Industrial Company, for Langley Gulch Power Plant (Portions of this exhibit have been redactedand filed separately with the Securities and Exchange Commission ("Commission") in accordance with (i) arequest for, and related Order by the Commission dated October 21, 2009, File No. 001-14465 - CF#23941,granting, confidential treatment for portions of the EPC Agreement and Exhibit A thereto pursuant to Rule24b-2 under the Securities Exchange Act of 1934, as amended (the "Exchange Act"), and (ii) a request for, andrelated Order by the Commission dated December 21, 2010, File No. 001-14465 - CF#25857, granting,confidential treatment pursuant to Rule 24b-2 under the Exchange Act for portions of Exhibits B, C, D, F, I, L,M, and P to the EPC Agreement). File number 1-14465, 1-3198, Form 10-Q/A for the quarter ended September30, 2010, filed on 12/13/10 as Exhibit 10.44.
Amended and Restated Electric Service Agreement between Idaho Power Company and Hoku Materials, Inc.,dated June 19, 2009. File number 1-14465, 1-3198, Form 10-Q for the quarter ended June 30, 2009, filed on8/6/09, as Exhibit 10.45.
Joint Purchase and Sale Agreement, dated April 30, 2010, by and between Idaho Power Company andPacifiCorp. File number 1-14465, 1-3198, Form 10-Q for the quarter ended June 30, 2010, filed on 8/5/10, asExhibit 10.69.
Hemingway Joint Ownership and Operating Agreement, dated May 3, 2010, by and between Idaho PowerCompany and PacifiCorp. File number 1-14465, 1-3198, Form 10-Q for the quarter ended June 30, 2010, filedon 8/5/10, as Exhibit 10.70.
Populus Joint Ownership and Operating Agreement, dated May 3, 2010, by and between Idaho PowerCompany and PacifiCorp. File number 1-14465, 1-3198, Form 10-Q for the quarter ended June 30, 2010, filedon 8/5/10, as Exhibit 10.71.
IDACORP, Inc. Statement Re: Computation of Ratio of Earnings to Fixed Charges and Supplemental Ratio ofEarnings to Fixed Charges.
Idaho Power Company Statement Re: Computation of Ratio of Earnings to Fixed Charges and SupplementalRatio of Earnings to Fixed Charges.
Subsidiaries of IDACORP, Inc. File number 1-14465, 1-3198, Form 10-K for the year ended December 31,2007, filed on 2/28/08, as Exhibit 21.
Consent of Independent Registered Public Accounting Firm.
IDACORP, Inc. Rule 13a-14(a) CEO certification.
IDACORP, Inc. Rule 13a-14(a) CFO certification.
Idaho Power Company Rule 13a-14(a) CEO certification.
Idaho Power Company Rule 13a-14(a) CFO certification.
IDACORP, Inc. Section 1350 CEO certification.
IDACORP, Inc. Section 1350 CFO certification.
Idaho Power Company Section 1350 CEO certification.
Idaho Power Company Section 1350 CFO certification.
1 Management contract or compensatory plan or arrangement
2 Includes data files for the following materials from the annual report on Form 10-K of IDACORP, Inc. for the year ended December 31, 2011, formatted inExtensible Business Reporting Language (XBRL): (i) the Consolidated Statements of Income; (ii) the Consolidated Balance Sheets; (iii) the ConsolidatedStatements of Cash Flows; (iv) the Consolidated Statements of Comprehensive Income; (v) the Consolidated Statements of Equity; and (vi) the Notes toConsolidated Financial Statements. Also includes data files for the following materials from the annual report on Form 10-K of Idaho Power Company forthe year ended December 31, 2011 formatted in XBRL: (i) Consolidated Statements of Income; (ii) Consolidated Balance Sheets; (iii) ConsolidatedStatements of Capitalization; (iv) Consolidated Statements of Cash Flows; (v) Consolidated Statements of Comprehensive Income; and (vi) the Notes toConsolidated Financial Statements tagged as blocks of text. Detailed tags for information in the Notes to Condensed Consolidated Financial Statements arebeing furnished only by IDACORP, Inc. and not by its subsidiary, Idaho Power Company. Pursuant to Rule 406T of SEC Regulation S-T, these interactivedata files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, are deemed notfiled for purposes of Section 18 of the Securities Exchange Act of 1934, and otherwise are not subject to liability under those sections.
IDACORP, INC.SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED STATEMENTS OF INCOME
Income:Equity in income of subsidiariesInvestment income (losses)Total incomeExpenses:Operating expensesInterest expenseOther expensesTotal expensesIncome from Before Income TaxesIncome Tax BenefitNet Income Attributable to IDACORP, Inc.
The accompanying note is an integral part of these statements.
Year Ended December 31,2011
(thousands of dollars)
$ 166,716161
166,877
1,011534—
1,545165,332
(1,361)$ 166,693
2010
$ 143,414
602144,016
1,1301,023
572,210
141,806(992)
$ 142,798
2009
$ 125,567
404125,971
2,629
91966
3,614122,357
(1,993)$ 124,350
IDACORP, INC.CONDENSED STATEMENTS OF CASH FLOWS
Operating Activities:Net cash provided by operating activitiesInvesting Activities:Contributions to subsidiariesSale of investmentsNet cash used in investing activitiesFinancing Activities:Issuance of common stockDividends on common stockIncrease (decrease) in short-term borrowingsChange in intercompany notes payableOtherNet cash used in financing activitiesNet (decrease) increase in cash and cash equivalentsCash and cash equivalents at beginning of yearCash and cash equivalents at end of year
The accompanying note is an integral part of these statements.
Year Ended December 31,2011
(thousands of dollars)
$ 74,618
(16,000)621
(15,379)
17,501(59,668)(12,700)
(805)(1,612)
(57,284)1,9551,231
$ 3,186
2010
$ 29,303
(50,000)
553(49,447)
48,644
(57,872)13,150(8,266)(1,051)(5,395)
(25,539)26,770
$ 1,231
2009
$ 65,406
(20,000)
48(19,952)
24,328
(56,819)15,350(3,425)(1,659)
(22,225)23,2293,541
$ 26,770
148
IDACORP, INC.CONDENSED BALANCE SHEETS
Assets
Current Assets:Cash and cash equivalentsReceivablesDeferred income taxesOther
Total current assets
Investment in subsidiaries
Other Assets:Deferred income taxesOther
Total other assets
Total assets
Liabilities and Shareholders’ EquityCurrent Liabilities:Notes payableAccounts payableTaxes accruedOther
Total current liabilities
Other Liabilities:Intercompany notes payableOther
Total other liabilitiesIDACORP, Inc. Shareholders’ Equity
Total Liabilities and Shareholders' Equity
The accompanying note is an integral part of these statements.
December 31,2011
(thousands of dollars)
$ 3,186
2,7512,048
1188,103
1,641,479
82,250473
82,723
$ 1,732,305
$ 54,2006,1834,376
66965,428
7,1492,0749,223
1,657,654
$ 1,732,305
2010
$ 1,231
2,2843,370
7517,636
1,523,520
92,934
14993,083
$ 1,624,239
$ 66,9005,9457,852
71481,411
7,9542,761
10,7151,532,113
$ 1,624,239
NOTE TO CONDENSED FINANCIAL STATEMENTS
1. BASIS OF PRESENTATION Pursuant to rules and regulations of the Securities and Exchange Commission, the unconsolidated condensed financial statements of IDACORP, Inc. do not reflect all of the information and notes normally included with financial statements prepared in accordance with accounting principles generally accepted in the United States of America. Therefore, these financial statements should be read in conjunction with the consolidated financial statements and related notes included in the 2011 Form 10-K, Part II, Item 8. Accounting for Subsidiaries: IDACORP has accounted for the earnings of its subsidiaries under the equity method in the unconsolidated condensed financial statements. Included in net cash provided by operating activities in the condensed statements of cash flows are dividends of $63 million, $61 million, and $60 million that IDACORP subsidiaries paid to IDACORP in 2011, 2010, and 2009, respectively.
149
IDACORP, INC.SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTSYears Ended December 31, 2011, 2010, and 2009
Column A
Classification
2011:Reserves deducted from applicable assets
Reserve for uncollectible accountsReserve for uncollectible notes
Other Reserves:Injuries and damagesMiscellaneous operating reserves
2010:Reserves deducted from applicable assets
Reserve for uncollectible accountsReserve for uncollectible notes
Other Reserves:Injuries and damagesMiscellaneous operating reserves
2009:Reserves deducted from applicable assets
Reserve for uncollectible accountsReserve for uncollectible notes
Other Reserves:Rate refundsInjuries and damagesMiscellaneous operating reserves
Column B
Balance atBeginning
of Year(thousands of dollars)
$ 1,6403,190
1,8822,611
$ 1,990
3,045
3,4132,926
$ 1,7241,879
13,3451,965
—
Column CAdditions
Charged
toIncome
$ 4,277(447)
783—
$ 5,764
444
40010
$ 5,314
566
—4,8672,926
Charged(Credited)to OtherAccounts
$ 161—
——
$ (324)
—
——
$ 122
600
———
Column D
Deductions(1)
$ 4,643—
7402,611
$ 5,790299
1,931
325
$ 5,170—
13,3453,419
—
Column E
Balance atEnd
of Year
$ 1,4352,743
1,925
—
$ 1,6403,190
1,8822,611
$ 1,9903,045
—
3,4132,926
(1) Represents deductions from the reserves for purposes for which the reserves were created. In the case of uncollectible accounts, and notes reserves, includes reversals of amounts previously written off.
150
IDAHO POWER COMPANYSCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTSYears Ended December 31, 2011, 2010, and 2009
Column A
Classification
2011:Reserves deducted from applicable assets
Reserve for uncollectible accountsOther Reserves:
Injuries and damagesMiscellaneous operating reserves
2010:Reserves deducted from applicable assets
Reserve for uncollectible accountsOther Reserves:
Injuries and damagesMiscellaneous operating reserves
2009:Reserves deducted from applicable assets
Reserve for uncollectible accountsOther Reserves:
Rate refundsInjuries and damagesMiscellaneous operating reserves
(1) Represents deductions from the reserves for purposes for which the reserves were created. In the case of uncollectible accounts, includes reversals of amounts previously written off.
Column B
Balance atBeginning
of Year(thousands of dollars)
$ 1,640
1,8822,611
$ 1,990
3,4132,926
$ 1,724
13,3451,965
—
Column CAdditions
Charged
toIncome
$ 4,277
783—
$ 5,764
40010
$ 5,314
—
4,8672,926
Charged(Credited)to OtherAccounts
$ 161
——
$ (324)
——
$ 122
———
Column D
Deductions(1)
$ 4,643
7402,611
$ 5,790
1,931325
$ 5,170
13,3453,419
—
Column E
Balance atEnd
of Year
$ 1,435
1,925—
$ 1,640
1,8822611
$ 1,990
—3,4132,926
151
SIGNATURES Pursuant to the requirements of Section 13 and 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
February 22, 2012Date
By:
IDACORP, INC. /s/ J. LaMont Keen
J. LaMont KeenPresident and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature /s/ Gary G. MichaelGary G. Michael
/s/ J. LaMont KeenJ. LaMont KeenPresident and Chief Executive Officer andDirector
/s/ Darrel T. AndersonDarrel T. AndersonExecutive Vice President-AdministrativeServices and Chief Financial Officer
/s/ Kenneth W. PetersenKenneth W. PetersenCorporate Controller and Chief AccountingOfficer
/s/ C. Stephen AllredC. Stephen Allred
/s/ Richard J. DahlRichard J. Dahl
/s/ Judith A. JohansenJudith A. Johansen
/s/ Christine KingChristine King
/s/ Jan B. PackwoodJan B. Packwood
/s/ Richard G. ReitenRichard G. Reiten
/s/ Joan H. SmithJoan H. Smith
/s/ Robert A. TinstmanRobert A. Tinstman
/s/ Thomas J. WilfordThomas J. Wilford
Title
Chairman of the Board
(Principal Executive Officer)
(Principal Financial Officer)
(Principal Accounting Officer)
Director
Director
Director
Director
Director
Director
Director
Director
Director
Date
February 22, 2012
February 22, 2012
February 22, 2012
February 22, 2012
February 22, 2012
February 22, 2012
February 22, 2012
February 22, 2012
February 22, 2012
February 22, 2012
February 22, 2012
February 22, 2012
February 22, 2012
152
SIGNATURES Pursuant to the requirements of Section 13 and 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
February 22, 2012Date
By:
Idaho Power Company /s/ J. LaMont Keen
J. LaMont KeenChief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature /s/ Gary G. MichaelGary G. Michael
/s/ J. LaMont KeenJ. LaMont KeenChief Executive Officer and Director
/s/ Darrel T. AndersonDarrel T. AndersonPresident and Chief Financial Officer
/s/ Kenneth W. PetersenKenneth W. PetersenCorporate Controller and Chief Accounting
Officer
/s/ C. Stephen AllredC. Stephen Allred
/s/ Richard J. DahlRichard J. Dahl
/s/ Judith A. JohansenJudith A. Johansen
/s/ Christine KingChristine King
/s/ Jan B. PackwoodJan B. Packwood
/s/ Richard G. ReitenRichard G. Reiten
/s/ Joan H. SmithJoan H. Smith
/s/ Robert A. TinstmanRobert A. Tinstman
/s/ Thomas J. WilfordThomas J. Wilford
Title
Chairman of the Board
(Principal Executive Officer)
(Principal Financial Officer)
Director
Director
Director
Director
Director
Director
Director
Director
Director
Date
February 22, 2012
February 22, 2012
February 22, 2012
February 22, 2012
February 22, 2012
February 22, 2012
February 22, 2012
February 22, 2012
February 22, 2012
February 22, 2012
February 22, 2012
February 22, 2012
February 22, 2012
Cover and narrative pages
These pages were printed on Opus 30 Sheets manufactured by Sappi Fine Paper North America with:
FSC® Chain of Custody Certification
A minimum of 30% Post Consumer Waste (PCW) fiber
100% Green-e certified renewable energy
Financial pages
These pages were printed on Accent Sheets manufactured by International Paper with:
FSC® Chain of Custody Certification
IDACORP, Inc. is committed to doing its part to be responsible stewards of our environment. This annual report was printed on a combination of environmentally friendly papers using soy-based inks.
By printing on post-consumer fiber in place of virgin timber, we achieved the following savings:
10 trees preserved for the future
29 pounds of water-borne waste not created
4,228 gallons of wastewater flow saved
468 pounds of solid waste not generated
921 pounds net greenhouse gases prevented
As compared to the industry average, the amount of greenhouse gas emissions avoided are equivalent to one of the following:
Gary G. Michael* (2001) Boise, Idaho Chairman of the Board, IDACORP, Inc. and Idaho Power; Director, The Clorox Co., Questar Corporation, Questar Gas, Questar Pipeline and Graham Packaging Co.; and formerly Chief Executive Officer of Albertsons, Inc.
Jan B. Packwood (1997) Boise, Idaho Formerly President and Chief Executive Officer of IDACORP, Inc.; Director of Westmoreland Coal Company
Richard G. Reiten (2004) Portland, Oregon Director, U.S. Bancorp; National Fuel Gas Co.; formerly President and Chief Executive Officer of Northwest Natural Gas Company; and formerly President and Chief Operating Officer of Portland General Electric
Joan H. Smith (2004) Portland, Oregon Self-employed consultant, consulting on regulatory strategy and telecommunications; and formerly Oregon Public Utility Commissioner
Robert A. Tinstman (1999) Boise, Idaho Director, Primoris Services Corp.; Home Federal Bancorp, Inc. and CNA Surety Corp.; and formerly President and Chief Executive Officer of Morrison-Knudsen Corporation
Thomas J. Wilford (2004) Boise, Idaho President of Alscott, Inc.; Chief Executive Officer of J.A. and Kathryn Albertson Foundation, Inc.; former Director, K12, Inc.
( ) year elected to the board * Chairman of the Board
Board of DirectorsIDACORP and Idaho Power
C. Stephen Allred (2009) Boise, Idaho Formerly Assistant Secretary for U.S. Land and Minerals Management; formerly Director of the Idaho Department of Environmental Quality; formerly Director of Idaho Department of Water Resources; and formerly President of Morrison-Knudson’s Environmental and Government Services Group
Richard J. Dahl (2008) Kapolei, Hawaii Chairman of the Board, President and Chief Executive Officer of James Campbell Company, LLC; Chairman of the Board, International Rectifiers Corp; Director, Dine Equity, Inc.; and formerly President and Chief Operating Officer of Dole Food Company
Judith A. Johansen (2007) Lake Oswego, Oregon President of Marylhurst University; Director, Cascade Bancorp, Schnitzer Steel and Roseburg Forest Products; formerly President and Chief Executive Officer of PacifiCorp; and formerly Chief Executive Officer and Administrator of Bonneville Power Administration
J. LaMont Keen (2004) Boise, Idaho President and Chief Executive Officer, IDACORP, Inc. and Chief Executive Officer, Idaho Power; Board of Directors, Cascade Bancorp
Christine King (2006) Hauppague, New York President and Chief Executive Officer of Standard Microsystems Corporation; Director, Atheros Communications, Inc., Open-Silicon, Inc., and Standard Microsystem Corporation; and formerly President and Chief Executive Officer of AMI Semiconductor; formerly Director of Atheros Communications, Inc.
above photo by Idaho Power customer Lisa Kidd, www.facebook.com/LisaKiddPhotography
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