2010Annual Report.pdf

IPC-E
Form 1 Approved
OMS No. 1902-0021
(Expires 12/31/2011)
Form 1-F Approved
OMS No. 1902-0029
(Expires 12/31/2011)
Form 3-Q Approved
OMS No. 1902-0205
(Expires 1/31/2012)
THIS FILING IS
Item 1: 00 An Initial (Original)
Submission
OR D Resubmission No.
~~ ~
~ ~~ ~'~
1: 'r.:~..~
FERC FINANCIAL REPORT
FERC FORM No.1: Annual Report of
Major Electric Utilities, Licensees
and Others and Supplemental
Form 3-Q: Quarterly Financial Report
These reports are mandatory under the Federal Power Act, Sectons 3, 4(a), 304 and 309, and
18 CFR 141.1 and 141.400. Failure to report may result in criminal fines, civil penalties and
other sanctions as provided by law. The Federal Energy Regulatory Commission does not
consider these reports to be of confidential nature
Exact Legal Name of Respondent (Company)
Idaho Power Company
Year/Period of Report
End of 2010/Q4
FERC FORM No.1/3-Q (REV. 02-04)
Deloitte.R...i:Ci:I\!. '\ t.. t".,,, ¡ "Deloitte & Touche LLP
Suite 1700
101 South Capitol Boulevard
Boise, 1083702-7717
USA
Tel: [phone]
ww.deloitte.com
ißH ~\PR 22 Ptf¡ \2i 43
INDEPENDENT AUDITORS' REPORT
Idao Power Company
Boise, Idao
We have audited the balauce sheet - reguatory basis ofIdao Power Company (the"Compauy") as of
December 31, 2010; and the related statements of income - regulatory basis; retained eargs -
reguatory basis, and cash flows - regulatory basis, for the year ended December 31,2010, included on
pages 110 though 123 of the accompanyig Federal Energy Reguatory Commssion Form 1. These
fiancial statements are the responsibility of the Company's maagement. Our responsibility is to express
an opinon on these fiancial statements based on our audit.
We Conducted our audit in accordace with generally accepted auditing stadads as established by the
Auditig Stadads Board (United States ) and in accordance with the auditig standads of the Public
Company Accountig Oversight Board (United States). Those stadads require that we plan and pedorm
the audi to obta reasonable assurance about whether the financial statements are free of material
misstatement. The Company is not required to have, nor were we engaged to pedorm, an audit of its
internal control over fiancial reportg. Ou audit included considertion of internal control over
fiancial reportg as a basis for designing audit procedures that are appropriate in the circumtaces, but
not for the purose of expressing an opinon on the effectiveness of the Company's internal control over
fiancial reportg. Accordigly, we express no such opinon. An audit also includes examg, on a test
basis, evidence supportg the amounts and disclosures in the fiancial statements, assessing the
accoUntig priciples used and significant estiates made by maagement, as well as evaluatig the
overall fiancial statement presentation. We believe that our audit provides a reasonable basis for our
opinon.
As discussed in Note 1, these fiancial statements were prepared in accordace with the accountig
requiements of the Federal Energy Reguatory Commssion as set fort in its applicable Uniform System
of Accounts and published accounting releases, which is a comprehensive basis of accounting other than
accountig priciples generally accepted in the United States of Amerca.
In out opinon, such regulatory-basis fiancial statements present fairly, in all materal respects, the
assets, liabilties, and proprietary capital of the Company as of December 31,2010, and the results of its
operations and its cash flows for the year ended December 31, 2010, in accordace with the accounting
requiements of the Federal Energy Reguatory Commssion as set fort in its applicable Uniform System
of Accounts and publihed accountig releases.
Ths reportis intended solely for the information and use of the board of directors and maagement of the
Coaipany and fot filing with the Federal Energy Regulatory Commssion and is not intended to be and
should not be used by anyone other than these specified paries.
f):. ..~ Li."i
Februar 23,2011
Member of
Deloitte Touche Tohmatsu
THIS PAGE INTENTIONALLY LEFT BLANK
,.
IDENTIFICATION
01 Exact Legal Name of Respondent 02 Year/Period of Report
Idaho Power Company End of 2010/Q4
03 Previous Name and Date of Change (if name changed during year)
1 1
04 Address of Principal Offce at End of Period (Street, City, State, Zip Code)
1221 W Idaho Street, P.O. Box 70 Boise, Id 83707-0070
05 Name of Contact Person 06 Title of Contact Person
Ken Petersen Corporate Controller and CAO
07 Address of Contact Person (Street, City, State, Zip Code)
1221 W Idaho Street, P.O. Box 70 Boise, Id 83707-0070
08 Telephone of Contact Person,fnc/uding 09 This Report Is 10 Date of Report
Area Code (1) 00 An Original (2) D A Resubmission (Mo, Da, Yr)
[phone] 04/15/2011
ANNUAL CORPORATE OFFICER CERTIFICATION
The undersigned offcer certifies that:
I have examined this report and to the best of my knowledge, information, and belief all statements of fact contained in this report are correct statements
of the business affairs of the respondent and the financial statements, and other financial information contained in this report, conform in all material
respects to the Uniform System of Accunts.
.
':!
01 Name 03Signatu~04 Date Signed
Ken Petersen zZ .I_.~(Mo, Da, Yr)02 Title
Corporate Controller and CAO Ken Petersen 04/15/2011
Title 18, U.S.C. 1001 makes it a crime for any person to knowingly and willngly to make w any Agency or Department of the United States any
false, ficttious or fraudulent statements as to any matter within its jurisdiction.
FERC FORM NO. 1/3-Q:
REPORT OF MAJOR ELECTRIC UTILITIES LICENSEES AND OTHER
FERC FORM No.1/3-Q (REV. 02-04)Page 1
Name of Respondent This Report Is:Date of Report Year/Period of Report
Idaho Power Company (1) (!An Original (Mo, Da, Yr)End of 2010/Q4
(2) FíA Resubmission 04/15/2011
LIST OF SCHEDULES (Electic Utilty)
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
Line Title of Schedule Reference Remarks
No.Page No.
(a)(b)(c)
1 General Information 101
2 Control Over Respondent 102
3 Corporations Controlled by Respondent 103
4 Offcers 104
5 Directors 105
6 Information on Formula Rates 106(a)(b)
7 Important Changes During the Year 108-109
8 Comparative Balance Sheet 110-113
9 Statement of Income for the Year 114-117
10 Statement of Retained Earnings for the Year 118-119
11 Statement of Cash Flows 120-121
12 Notes to Financial Statements 122-123
13 Statement of Accum Comp Income, Comp Income, and Hedging Activities 122(a)(b)
14 Summary of Utilty Plant & Accmulated Provisions for Dep, Amort & Dep 200-201
15 Nuclear Fuel Materials 202-203 None
16 Electric Plant in Service 204-207
17 Electric Plant Leased to Others 213 None
18 Electric Plant Held for Future Use 214
19 Constructon Work in Progress-Electric 216
20 Accumulated Provision for Depreciation of Electric Utiity Plant 219
21 Investment of Subsidiary Companies 224-225
22 Materials and Supplies 227
23 Allowances 228(ab )-229(ab)None
24 Extraordinary Propert Losses 230
25 Unrecovered Plant and Regulatory Study Costs 230
26 Transmission Service and Generation Interconnection Study Costs 231 None
27 Other Regulatory Assets 232
28 Miscellaneous Deferred Debits 233
29 Accmulated Deferred Income Taxes 234
30 Capital Stock 250-251
31 Other Paid-in Capital 253
32 Capital Stock Expense 254
33 Long-Term Debt 256-257
34 Reconciliation of Reported Net Income with Taxable Inc for Fed Inc Tax 261
35 Taxes Accued, Prepaid and Charged During the Year 262-263
36 Accmulated Deferred Investment Tax Credits 266-267
FERC FORM NO.1 (ED. 12-96)Page 2
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1). An Original (Mo, Da, Yr)End of 2010/Q4
(2) n A Resubmission 04/15/2011
LIST OF SCHEDULES (Electnc Utility) (continued)
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
Line Title of Schedule Reference Remarks
No.Page No.
(a)(b)(c)
37 Other Deferred Credits 269
38 Accmulated Deferred Income Taxes-Acclerated Amortization Propert 272-273
39 Accmulated Deferred Income Taxes-Other Propert 274-275
40 Accmulated Deferred Income Taxes-Other 276-277
41 Other Regulatory Liabilties 278
42 Electnc Operating Revenues 300-301
43 Sales of Electicity by Rate Schedules 304
44 Sales for Resale 310-311
45 Electric Operation and Maintenance Expenses 320-323
46 Purchased Power 326-327
47 Transmission of Electricity for Others 328-330
48 Transmission of Electricity by ISO/RTOs 331 None
49 Transmission of Electncity by Others 332
50 Miscellaneous General Expenses-Electc 335
51 Depreciation and Amortzation of Electric Plant 336-337
52 Regulatory Commission Expenses 350-351
53 Research, Development and Demonstration Activities 352-353
54 Distribution of Salaries and Wages 354-355
55 Common Utility Plant and Expenses 356 None
56 Amounts included in ISO/RTO Settement Statements 397 None
57 Purchase and Sale of Ancillary Service 398 None
58 Monthly Transmission System Peak Load 400
59 Monthly ISO/RTO Transmission System Peak Load 400a None
60 Electric Energy Accunt 401
61 Monthly Peaks and Output 401
62 Steam Electnc Generating Plant Statistics 402-403
63 Hydroelectric Generating Plant Statistics 406-407
64 Pumped Storage Generating Plant Statistics 408-09 None
65 Generating Plant Statistics Pages 410-411
66 Transmission Line Statistics Pages 422-423
FERC FORM NO.1 (ED. 12-96)Page 3
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2010/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) CíA Resubmission 04/15/2011
LIST OF SCHEDULES (Electric Utiity) (continued)
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for
certin pages. Omit pages where the respondents are "none," "not applicable," or "NA".
Line
No.
Title of Schedule Reference
Page No.
(b)
424-425
426-427
429
450
Remarks
(a)
67 Transmission Lines Added During the Year
68 Substations
69 Transactons with Asociated (Affliated) Companies
70 Footnote Data
Stockholders' Reports Check appropriate box:
~ Two copies wil be submitted
o No annual report to stockholders is prepared
(c)
FERC FORM NO.1 (ED. 12-96)Page 4
Name of Respondent
Idaho Power Company
This Report Is:
(1) 00 An Original
(2) D A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2011
Year/Period of Report
End of 2010/Q4
GENERAL INFORMATION
1. Provide name and title of offcer having custody of the general corporate books of account and address of
offce where the general corporate books are kept, and address of offce where any other corporate books of account
are kept, if different from that where the general corporate books are kept.
Ken Petersen Corporate Controller and CA, Idao Power Company
1221 W. Idao Street, P.O. Box 70, Boise, Idao 83707-0070
2. Provide the name of the State under the laws of which respondent is incorporated, and date of incorporation.
If incorporated under a special law, give reference to such law. If not incorporated, state that fact and give the type
of organization and the date organized.
Idao, June 30, 1989
3. If at any time during the year the property of respondent was held by a recelver or trustee, give (a) name of
receiver or trustee, (b) date such receiver or trustee took possession, (c) the authority by which the receivership or
trusteeship was created, and (d) date when possession by receiver or trustee ceased.
Not Applicable
4. State the classes or utility and other services furnished by respondent during the year in each State in which
the respondent operated.
Class of Utility Service
Electric StateIdao
Oregon
5. Have you engaged as the principal accountant to audit your financial statements an accountant who is not
the principal accountant for your previous year's certified financial statements?
(1) D Yes...Enter the date when such independent accountant was initially engaged:
(2) (l No
FERC FORM No.1 (ED. 12-87)PAGE 101
Name of Respondent
Idaho Power Company
This Report Is:
(1) IX An Original
(2) D A Resubmission
Date of Report
(Mo,Da, Yr)
04/15/2011
Year/Period of Report
End of 2010/Q4
CONTROL OVER RESPONDENT
1. If any corporation, business trust, or similar organization or a combination of such organizations jointly held
control over the repondent at the end of the year, state name of controllng corporation or organization, manner in
which control was held, and extent of control. If control was in a holding company organization, show the chain
of ownership or control to the main parent company or organization. If control was held by a trustee(s), state
name of trustee(s), name of beneficiary or beneficiearies for whom trust was maintained, and purpose of the trust.
Idaho Power Company is a subsidiary of IDACORP, INC
IDACORP owns 100% of Idaho Power Company's Common Stock.
IDACORP is a public utilty Holding Company incorporated effective 10-1-1998
FERC FORM NO.1 (ED. 12-96)Page 102
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo. Da, Yr)End of 2010/Q4
(2) nA Resubmission 04/15/2011
CORPORATIONS CONTROLLED BY RESPONDENT
1. Report below the names of all corporations, business trusts, and similar organizations, controlled directly or indirectly by respondent
at any time during the year. If control ceased prior to end of year, give particulars (details) in a footnote.
2. If control was by other means than a direct holding of voting rights, state in a footnote the manner in which control was held, naming
any intermediaries involved.
3. If control was held jointly with one or more other interests, state the fact in a footnote and name the other interests.
Definitions
1. See the Uniform System of Accounts for a definition of control.
2. Direct control is that which is exercised without interposition of an intermediary.
3. Indirect control is that which is exercised by the interposition of an intermediary which exercises direct control.
4. Joint control is that in which neither interest can effectively control or direct action without the consent of the other, as where the
voting control is equally divided between two holders, or each part holds a veto power over the other. Joint control may exist by
mutual agreement or understanding between two or more parties who together have control within the meaning of the definition of
control in the Uniform System of Accounts, regardless of the relative voting rights of each part.
Line Name of Company Controlled Kind of Business Percent Voting Footnote
No.Stock Owned Ref.
(a)(b)(c)(d)
1 Direct Control
2 Idaho Energy Resources Company Coal mining and mineral 100%
3 development
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
FERC FORM NO.1 (ED. 12-96)Page 103
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) FiA Resubmission 04/15/2011
OFFICERS
1. Report below the name, title and salary for each executive offcer whose salary is $50,000 or more. An "executive offcer" of a
respondent includes its president, secretary, treasurer, and vice president in charge of a principal business unit, division or function
(such as sales, administration or finance), and any other person who performs similar policy making functions.
2. If a change was made during the year in the incumbent of any position, show name and total remuneration of the previous
incumbent, and the date the change inincumbency was made.
Line Title -Name of Officer .::alary
No.for Year
(a)(b)(c)
1
2 President and Chief Executive Offcer J. LaMont Keen 620,000
3
4 Executive VP, Administrative Service & CFO Darrel T. Anderson 365,000
5
6 Executive Vice President, Operations Dan Minor 340,000
7
8 Senior Vice President, Corporate Responsibilty (1 )Ric Gale 235,000
9
10 Vice President and Chief Information Ofcer Dennis Gribble 205,000
11
12 Vice President, Human Resources & Corp Services (1)Luci McDonald 215.000
13
14 Vice President Finance and Treasurer (1)Steven R. Keen 221,000
15
16 Senior Vice President, General Counsel Rex Blackburn 245,000
17
18 Vice President Chief Risk Offcer (1)Lori Smith 200,000
19
20 Senior Vice President, Power Supply Lisa Grow 220,000
21
22 Vice President Public Affairs Jeffrey Malmen 192,500
23
24 Vice President, Customer Operations (1 )Warren Kline 175,000
25
26 Vice President Engineering & Operations Vern Porter 175,000
27
28 Corporate Controller & Chief Accunting Ofcer (1)Ken Petersen 160,000
29
30 Vice President, Supply Chain (1)Naomi Crafton-Shankel 159,000
31
32 Corporate Secretary Patrck Harrngton 159,000
33
34
35 (1) Title/Position Change effective 5/29/10
36
37
38
39
40
41
42
43
44
FERC FORM NO.1 (ED. 12-96)Page 104
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) nA Resubmission 04/15/2011
DIRECTORS
1. Report below the information called for concerning each director of the respondent who held offce at any time during the year. Include in column (a), abbreviated
titles of the directors who are offcers of the respondent.
2. Deignate members of the Executive Committee by a triple asterisk and the Chairman of the Executive Committee by a double asterisk.
i L.ine Name (and Title) of Director Principal Business AddressNo.(a)(b)
1
2 Judith A Johansen 2786 Glenmorrie Dr. Lake Oswego, Oregon 97034
3
4 Chnstine King Standard Microsystems Corporation
5 80 Arkay Dr, Hauppauge, NY 11788
6
7 Gary Michael ***P.O. Box 1718, Boise, Idaho 83701
8
9 Stephen Allred 4642 W Dawson Dr Meridian, Id 83646
10
11 Jan B. Packwood 900 W. Bogus View Dnve, Eagle, Idaho 83616
12
13 J. laMont Keen, President and Chief Executive Offcer**Idaho Power Company, 1221 W. Idaho Street,
14 P.O. Box 70, Boise, Idaho 83707-0070
15
16 Richard G. Reiten Pacwest Center, 1211 SW Fift Ave., Suite 1600
17 Portand, Oregon 97204
18
19 Joan Smith 2309 S.W. First Avenue, No. 1141, Portand, Oregon 97201
20
21 Robert A. Tinstman ***4433 W. Quail Point Court, Boise, Idaho 83703
22
23 Thomas Wilford Alscott Inc, P.O. Box 70001, Boise, Idaho 83701
24
25 Richard Dahl ***11659 Presila Road, Santa Rosa Valley Ca, 93012
26
27 Jon H. Miller*.* (1)P.O.Box 1557, Boise, Idaho 83701
28
29
30
31 (1) Retired May 20,2010
32
33
34
35
36
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47
48
FERC FORM NO.1 (ED. 12-95)Page 105
Name of Respondent This wort Is:Date of Report Year/Penod of Report
Idaho Power Company (1) An Onginal (Mo, Da, Yr)End of 2010/Q4
(2) Fi A Resubmission 04/15/2011
INFORMATION ON FORMULA RATES
FERC Rate SchedulelTanff Number FERC Proceeding
Does the respondent have formula rates?(! Yes
o No
1. Please list the Commission accpted formula rates including FERC Rate Schedule or Tanff Number and FERC proceding (Le. Docket No)
accpting the rate(s) or changes in the accpted rate.
Line
No.FERC Rate Schedule or Tanff Number FERC Proceeding
1 FERC Electnc Tanff First Revised Volume NO.6 FERC Docket No. ER06-787-Q02,003
2
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FERC FORM NO.1 (NEW. 12-08)Page 106
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) 0 A Resubmission 04/15/2011
INFORMATION ON FORMULA RATES
FERC Rate SchedulelTariff Number FERC Proceding
Does the respondent file with the Commission annual (or more frequent)(2 Yesfilings containing the inputs to the formula rate(s)?
D No
2. If yes, provide a listing of such filings as contained on the Commission's eLibrary website
Formula Rate FERC Rate
Line Document Date Schedule Number or
No.Accssion No.\ Filed Date Docket No.Descrption Tariff Number
1 20100826-5058 08/26/2010 ER09-1641-000 Idaho Power Company's FERC Electrc Tariff
2 2010-2011 Annual first revised volume
3 informational filing
4 under ER09-1641
5
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FERC FORM NO.1 (NEW. 12-08)Page 106a
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) 0 A Resubmission 04/15/2011
INFORMATION ON FORMULA RATES
Formula Rate Variances
1. If a respondent does not submit such filings then indicate in a footnote to the applicable Form 1 schedule where formula rate inputs differ from
amounts reported in the Form 1.
2. The footnote should provide a narrtive description explaining how the "rate" (or biling) was derived if different from the reported amount in the
Form 1.
3. The footnote should explain amounts excluded from the ratebase or where labor or other allocation factors, operating expenses, or other items
impacting formula rate inputs differ from amounts reported in Form 1 schedule amounts.
4. Where the Commission has provided guidance on formula rate inputs, the specific proceeding should be noted in the footnote.
Line
No.Page No(s).Schedule Column Line No
1 NIA
2
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FERC FORM NO.1 (NEW. 12-08)Page 106b
Name of Respondent
Idaho Power Company
Date of Report YearlPeriod of Report
End of 2010/Q4
This Report Is:
(1) 12 An Original
(2) 0 A Resubmission
IMPORTANT CHANGES DURING THE QUARTERIEAR
Give particulars (details) concerning the matters indicated below. Make the statements explicit and precise, and number them in
accordance with the inquiries. Each inquiry should be answered. Enter "none," "not applicable," or "NA" where applicable. If
information which answers an inquiry is given elsewhere in the report, make a reference to the schedule in which it appears.
1. Changes in and important additions to franchise rights: Describe the actual consideration given therefore and state from whom the
franchise rights were acquired. If acquired without the payment of consideration, state that fact.
2. Acquisition of ownership in other companies by reorganization, merger, or consolidation with other companies: Give names of
companies involved, particulars concerning the transactions, name of the Commission authorizing the transaction, and reference to
Commission authorization.
3. Purchase or sale of an operating unit or system: Give a brief description of the propert, and of the transactions relating thereto,
and reference to Commission authorization, if any was required. Give date journal entries called for by the Uniform System of Accounts
were submitted to the Commission.
4. Important leaseholds (other than leaseholds for natural gas lands) that have been acquired or given, assigned or surrendered: Give
effective dates, lengths of terms, names of parties, rents, and other condition. State name of Commission authorizing lease and give
reference to such authorization.
5. Important extension or reduction of transmission or distribution system: State territory added or relinquished and date operations
began or ceased and give reference to Commission authorization, if any was required. State also the approximate number of
customers added or lost and approximate annual revenues of each class of service. Each natural gas company must also state major
new continuing sources of gas made available to it from purchases, development, purchase contract or otherwise, giving location and
approximate total gas volumes available, period of contracts, and other parties to any such arrangements, etc.
6. Obligations incurred as a result of issuance of securities or assumption of liabilities or guarantees including issuance of short-term
debt and commercial paper having a maturity of one year or less. Give reference to FERC or State Commission authorization, as
appropriate, and the amount of obligation or guarantee.
7. Changes in articles of incorporation or amendments to charter: Explain the nature and purpose of such changes or amendments.
8. State the estimated annual effect and nature of any important wage scale changes during the year.
9. State briefly the status of any materially important legal proceedings pending at the end of the year, and the results of any such
proceedings culminated during the year.
10. Describe briefly any materially important transactions of the respondent not disclosed elsewhere in this report in which an offcer,
director, security holder reported on Page 106, voting trustee, associated company or known associate of any of these persons was a
part or in which any such person had a material interest.
11. (Reserved.)
12. If the important changes during the year relating to the respondent company appearing in the annual report to stockholders are
applicable in every respect and furnish the data required by Instructions 1 to 11 above, such notes may be included on this page.
13. Describe fully any changes in offcers, directors, major security holders and voting powers of the respondent that may have
occurred during the reporting period.
14. In the event that the respondent participates in a cash management program(s) and its proprietary capital ratio is less than 30
percent please describe the significant events or transactions causing the proprietary capital ratio to be less than 30 percent, and the
extent to which the respondent has amounts loaned or money advanced to its parent, subsidiary, or affliated companies through a
cash management program(s). Additionally, please describe plans, if any to regain at least a 30 percent proprietary ratio.
04/15/2011
PAGE 108 INTENTIONALLY LEFT BLANK
SEE PAGE 109 FOR REQUIRED INFORMATION.
FERC FORM NO.1 (ED. 12-96)Page 108
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2011 2010104
IMPORTANT CHANGES DURING THE OUARTERNEAR (Continued)
1. None
2. None
3. In April 2010, Idaho Power Company sold Goshen capacitor bank to Pacificorp. The plant
investment balance was $7.4 million and net book value was $6.5 million. Oregon Public
Service Commission #10-010 and Idaho Public Utility Commission Case # IPC-E-09-32.
In March 2010, Idaho Power Company sold Border Feeder to Raft River Electric for
$43,191. Idaho Public Utility Commission Case # IPC-E-09-31.
4. None
5. New station Hemingway Transmission Station, Owyhee County Idaho. 500Kv
New transmissin line- Line #725 230Kv Hemingway to Bowmont 41.34 miles
Addition to existing line - Line #221 69Kv extended thry Sage Station to Ontario
Junction 39.38 miles.
In connection with the Memorandum of Understanding (MOU), on April 30, 2010, Idaho
Power entered into a Joint Purchase and Sale Agreement with PacifiCorp, pursuant to which
Idaho Power agreed to sell to PacifiCorp a 59.0 percent interest in certain high-voltage
transmission-related and interconnection equipment located at the Hemingway station south
of Boise, Idaho, and PacifiCorp agreed to sell to Idaho Power a 20.8 percent interest in
certain high-voltage transmission-related and interconnection equipment located at
PacifiCorp's Populus station in southeast Idaho. Closing of the purchase and sale occured
on May 3, 2010. Construction of the Hemingway and Populus station is substantially
complete. Upon final completion, the estimated purchase price PacifiCorp will have paid to
Idaho Power for PacifiCorp' s interest in the Hemingway station is $13.4 million, and the
estimated purchase price Idaho Power will pave paid to PacifiCorp for Idaho Power's
interest in the Populus station is $14.3 million.
6. 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. As of December 31, 2010, $300 million remained on Idaho Power's shelf
registration for the issuance of first mortgage bonds and debt securities. State
Commission order number is the same for both issuance OPUC UF4263, IPC-E-10-10,
WPSC 20005-32-ES-10.
7. None
8. Effective 1/9/10 a 2.5% general wage increase was approved.
9. See pages 123.19 to 123.24
10. None
11. None
12. None
13. Refer to pages 104 & 105 for changes in officers and directors. There were a couple of
changes in the major security holders for 2010. The top ten institutional shareholders
list saw 2 changes from 3rd quarter to 4th quarter. In 4th quarter Zimmer Lucas Partners
LLC and TIAA - CREF replaced American Century Investment Mgmt and Northern TrustInvestments.
I FERC FORM NO.1 (ED. 12-96)Page 109.1
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2Ç An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2011 2010104
IMPORTANT CHANGES DURING THE OUARTERIEAR (Continued).
14. Idaho Power and its unregulated parent, IdaCorp have seperate cash management
programs. (Seperate bank accounts, liquidity facilities, short-term debt and investment
programs). No money has been loaned or advanced from Idaho power to IdaCorp through a cash
management program.
I FERC FORM NO.1 (ED. 12-96)Page 109.2
Name of Respondent This Report Is: Date of Report Year/Period of Report
(1) (Z An Original (Mo, Da, Yr)
(2) D A Resubmission 04/15/2011 End of 2010104
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Idaho Power Company
Line
No.Title of Accunt
(a)
UTILITY PLANT
Ref.
Page No.
(b)
Current Year
End of OuarterlYear
Balance
(c)
Prior Year
End Balance
12/31
(d)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
Utilty Plant (101-106, 114)
Constructon Work in Progress (107)
TOTAL Utilty Plant (Enter Total of lines 2 and 3)
(Less) Accm. Provo for Depr. Amort. Depl. (108,110,111,115)
Net Utility Plant (Enter Total of line 4 less 5)
Nuclear Fuel in Process of Ref., Conv.,Enrich., and Fab. (120.1)
Nuclear Fuel Materials and Assemblies-Stock Accunt (120.2)
Nuclear Fuel Assemblies in Reactor (120.3)
Spent Nuclear Fuel (120.4)
Nuclear Fuel Under Capital Leases (120.6)
(Less) Accm. Provo for Amort. of Nucl. Fuel Assemblies (120.5)
Net Nuclear Fuel (Enter Total of lines 7-11 less 12)
Net Utilty Plant (Enter Total of lines 6 and 13)
Utility Plant Adjustments (116)
Gas Stored Underground - Noncurrent (117)
OTHER PROPERTY AND INVESTMENTS
Nonutility Propert (121)
(Less) Accm. Provo for Depr. and Amort. (122)
Investments in Asociated Companies (123)
Investment in Subsidiary Companies (123.1)
(For Cost of Accunt 123.1, See Footnote Page 224, line 42)
Noncurrent Portion of Allowances
Other Investments (124)
Sinking Funds (125)
Depreciation Fund (126)
Amortzation Fund - Federal (127)
Other Special Funds (128)
Special Funds (Non Major Only) (129)
Long-Term Portion of Derivative Assets (175)
Long-Term Portion of Derivative Asets - Hedges (176)
TOTAL Other Propert and Investments (Lines 18-21 and 23-31)
CURRENT AND ACCRUED ASSETS
Cash and Working Funds (Non-major Only) (130)
Cash (131)
Special Deposits (132-134)
Working Fund (135)
Temporary Cash Investments (136)
Notes Receivable (141)
Customer Accunts Receivable (142)
Other Accunts Receivable (143)
(Less) Accm. Provo for Uncollectble Acc.-Credit (144)
Notes Receivable from Asociated Companies (145)
Accunts Receivable from Assc. Companies (146)
Fuel Stock (151)
Fuel Stock Expenses Undistributed (152)
Residuals (Elec) and Extrcted Products (153)
Plant Materials and Operating Supplies (154)
Merchandise (155)
Other Materials and Supplies (156)
Nuclear Materials Held for Sale (157)
Allowances (158.1 and 158.2)
200-201
200-201
200-201
202-203
202-203
224-225
228-229
227
227
227
227
227
227
202-203/227
228-229
~----- - - -- ----~ ~~-------
4,339,130,398 4,167,328,769
416,949,593 289,188,358
4,756,079,991 4,456,517,127
1,771,654,52 1,713,943,062
2,984,425,462 2,742,574,065
0 0
0 0
0 0
0 0
0 0
0 0
0 0
2,984,425,462 2,742,574,065
0 0
0 0
2,074,99 1,335,962
0 0
0 0
72,561,774 65,015,441
0 0
2,511 266,768
0 0
0 0
0 0
29,306,774 24,059,095
0 0
0 212,580
0 0
103,946,055 90,889,846
0 0
73,015,293 2,485,630
2,802,631 1,496,698
44,850 39,350
151,172,575 19,100,000
303,143 636,667
63,612,796 76,792,157
6,166,234 9,087,713
1,641,302 1,990,343
14,384,928 18,894,101
0 0
27,546,983 25,633,645
0 0
0 0
42,221,176 43,342,060
0 0
0 0
0 0
0 0
FERC FORM NO.1 (REV. 12-03)Page 110
Name of Respondent This Report Is:Date of Report Year/Period of Report
Idaho Power Company (1 )(Z An Original (Mo,Da, Yr)
(2)D A Resubmission 04/15/2011 End of 2010/Q4
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBlT~ntinued)
Line Current Year PnorYear
No.Ref.End of QuarterlYear End Balance
Title of Accunt Page No.Balance 12/31
(a)(b)(c)(d)
53 (Less) Noncurrent Portion of Allowances 0 0
54 Stores Expense Undistnbuted (163)227 3,379,745 4,711,966
55 Gas Stored Underground - Current (164.1)0 0
56 Liquefied Natural Gas Stored and Held for Processing (164.2-164.3)0 0
57 Prepayments (165)10,910,213 10,959,775
58 Advances for Gas (166-167)0 0
59 Interest and Dividends Receivable (171)8,128 0
60 Rents Receivable (172)0 0
61 Acced Utilty Revenues (173)47,964,339 51,271,984
62 Miscellaneous Current and Acced Assets (174)0 0
63 Derivative Instrument Assets (175)573,226 715.249
64 (Less) Long-Term Portion of Denvative Instrument Asets (175)0 212,580
65 Denvative Instrment Assets - Hedges (176)0 0
66 (Less) Long-Term Portion of Denvative Instrument Assets - Hedges (176 0 0
67 Total Current and Acced Asets (Lines 34 through 66)442,464.958 262,964,072
68 DEFERRED DEBITS
69 Unamortized Debt Expenses (181)15,869,453 11,520,092
70 Extaordinary Propert Losses (182.1 )230a 0 0
71 Unrecovered Plant and Regulatory Study Costs (182.2)230b 0 0
72 Other Regulatory Assets (182.3)232 761,425,884 715,831,853
73 Prelim. Survey and Investigation Charges (Electic) (183)454,727 442,448
74 Preliminary Natural Gas Survey and Investigation Charges 183.1)0 0
75 Other Preliminary Survey and Investigation Charges (183.2)0 0
.76 Cleanng Accunts (184)564,213 523,636
77 Temporary Facilities (185)0 0
78 Miscellaneous Deferred Debits (186)233 55,131,472 58,492,874
79 Def. Losses from Disposition of Utilty PIt. (187)0 0
80 Research, Devel. and Demonstration Expend. (188)352-353 0 0
81 Unamortzed Loss on Reaquired Debt (189)14,524,712 15,439,928
82 Accumulated Deferred Income Taxes (190)234 157,346,772 170,110,978
83 Unrecovered Purchased Gas Costs (191)0 0
84 Total Deferred Debits (lines 69 through 83)1,005,317,233 972,361,809
85 TOTAL ASSETS (lines 14-16, 32, 67, and 84)4,536,153,708 4,068,789,792
FERC FORM NO.1 (REV. 12-03) Page 111
Name of Respondent This Report is:Date of Report Year/Period of Report
Idaho Power Company (1 )~An Original (mo, da, yr)
(2)D A Resubmission 04/15/2011 end of 2010/04
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
Line Current Year Prior Year
No.Ref.End of OuarterlYear End Balance
Title of Accunt Page No.Balance 12/31
(a)(b)(c)(d)
1 PROPRIETARY CAPITAL
2 Common Stock Issued (201)250-251 97,877,030 97,877,030
3 Preferred Stock Issued (204)250-251 0 0
4 Capital Stock Subscribed (202, 205)0 0
5 Stock Liabilty for Conversion (203, 206)0 0
6 Premium on Capital Stock (207)688,757,435 638,757,435
7 Other Paid-In Capital (208-211)253 0 0
8 Installments Received on Capital Stock (212)252 0 0
9 (Less) Discount on Capital Stock (213)254 0 0
10 (Less) Capital Stock Expense (214)254b 2,096,925 2,096,925
11 Retained Earnings (215, 215.1, 216)118-119 560,160,116 485,143,115
12 Unappropriated Undistributed Subsidiary Earnings (216.1)118-119 70,098,680 62,552,348
13 (Less) Reaquired Capital Stock (217)250-251 0 0
14 Noncorporate Proprietorship (Non-major only) (218)0 0
15 Accmulated Other Comprehensive Income (219)122(a)(b)-9,567,515 -8,266,663
16 Total Proprietary Capital (lines 2 through 15)1,405,228,821 1,273,966,340
17 LONG-TERM DEBT
18 Bonds (221)256-257 1,585,460,000 1,385,460,000
19 (Less) Reaquired Bonds (222)256-257 0 0
20 Advances from Associated Companies (223)256-257 0 0
21 Other Long-Term Debt (224)256-257 27,330,455 28,394,091
22 Unamortized Premium on Long-Term Debt (225)0 0
23 (Less) Unamortzed Discount on Long-Term Debt-Debit (226)3,439,753 3,060,748
24 Total Long-Term Debt (lines 18 through 23)1,609,350,702 1,410,793,343
25 OTHER NONCURRENT LIABILITIES
26 Obligations Under Capital Leases - Noncurrent (227)0 0
27 Accmulated Provision for Propert Insurance (228.1)0 0
28 Accmulated Provision for Injuries and Damages (228.2)1,881,776 3,412,806
29 Accmulated Provision for Pensions and Benefits (228.3)268,433,659 279,806,510
30 Accmulated Miscellaneous Operating Provisions (228.4)0 916,667
31 Accmulated Provision for Rate Refunds (229)21,210,538 9,894,077
32 Long-Term Portion of Derivative Instrument Liabilties 0 0
33 Long-Term Portion of Derivative Instrument Liabilties - Hedges 0 0
34 Asset Retirement Obligations (230)16,951,914 16,239,594
35 Total Other Noncurrent Liabilties (lines 26 through 34)308,477,887 310,269,654
36 CURRENT AND ACCRUED LIABILITIES
37 Notes Payable (231)0 0
38 Accunts Payable (232)100,785,053 81,164,595
39 Notes Payable to Associated Companies (233)0 0
40 Accounts Payable to Associated Companies (234)1,110,373 1,735,649
41 Customer Deposits (235)1,366,711 464,233
42 Taxès Acced (236)262-263 -12,242,872 -3,253,927
43 Interest Acced (237)24,038,150 20,383,712
44 Dividends Declared (238)0 0
45 Matured Long-Term Debt (239)0 0
FERC FORM NO.1 (rev. 12-03)Page 112
Name of Respondent This Report is:Date of Report Year/Period of Report
Idaho Power Company (1 )(K An Original (mo, da, yr)
(2)D A Resubmission 04/15/2011 end of 2010104
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDI1&)itinued)
Line Current Year Prior Year
No.Ref.End of OuarterlYear End Balance
Title of Accunt Page No.Balance 12/31
(a)(b)(c)(d)
46 Matured Interest (240)0 0
47 Tax Collectons Payable (241)1,689,273 1,963,189
48 Miscellaneous Current and Acced Liabilities (242)112,230,437 29,912,569
49 Obligations Under Capital Leases-Current (243)0 0
50 Derivative Instrment Liabilties (244)508,141 280,459
51 (Less) Long-Term Portion of Derivative Instrument Liabilties 0 0
52 Derivative Instrment Liabilties - Hedges (245)0 0
53 (Less) Long-Term Porton of Derivative Instrment Liabilties-Hedges 0 0
54 Total Current and Accued Liabilties (lines 37 through 53)229,485,266 132,650,479
55 DEFERRED CREDITS
56 Customer Advance for Constructon (252)23,054,017 25,180,998
57 Accmulated Deferred Investment Tax Credits (255)266-267 71,972,336 73,505,525
58 Deferred Gains frm Disposition of Utiity Plant (256)0 0
59 Other Deferred Credits (253)269 26,668,269 19,363,271
60 Other Regulatory Liabilties (254)278 55,279,902 49,478,079
61 Unamortzed Gain on Reaquired Debt (257)0 0
62 Accm. Deferred Income Taxes-Accl. Amort.(281)272-277 0 0
63 Accm. Deferred Income Taxes-Other Propert (282)707,009,34f 664,169,740
64 Accm. Deferred Income Taxes-Other (283)99,627,160 109,412,363
65 Total Deferred Credits (lines 56 through 64)983,611,032 ~1,109,976
66 TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65)4,536,153,708 4,068,789,792
,
FERC FORM NO.1 (rev. 12-03)Page 113
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) 0 A Resubmission 04/15/2011
STATEMENT OF INCOME
Quarterly
1. Report in column (c) the current year to date balance. Column (c) equals the total of adding the data in column (g) plus the data in column (i) plus the
data in column (k). Report in column (d) similar data for the previous year. This information is reported in the annual filing only.
2. Enter in column (e) the balance for the reporting quarter and in column (f) the balance for the same three month period for the prior year.
3. Report in column (g) the quarter to date amounts for electc utility function; in column (i) the quarter to date amounts for gas utility, and in column (k)
the quarter to date amounts for other utilty function for the current year quarter.
4. Report in column (h) the quarter to date amounts for electric utilty functon; in column ü) the quarter to date amounts for gas utilty, and in column (I)
the quarter to date amounts for other utilty function for the prior year quarter.
5. If additional columns are needed, place them in a footnote.
Annual or Quarterly if applicable
5. Do not report fourth quarter data in columns (e) and (f)
6. Report amounts for accunts 412 and 413, Revenues and Expenses from Utility Plant Leased to Others, in another utility columnin a similar manner to
a utilty departent. Spread the amount(s) over lines 2 thru 26 as appropriate. Include these amounts in columns (c) and (d) totals.
7. Report amounts in accunt 414, Other Utility Operating Income, in the same manner as accunts 412 and 413 above.
Line Total Total Currnt 3 Months Prior 3 Months
No.Currt Year to Prior Year to Ended Ended
(Ref.)Date Balance for Date Balance for Quartrly Only Quartrl Only
Title of Accunt Page No.QuarterlY ear QuartrlY ear No 4th Quartr No 4th Quartr
(a)(b)(c)(d)(e)(f)
1 UTILITY OPERATING INCOME
2 Operating Revenues (400)300-301 1,033,052,120 1,045,996,381
3 Operating Expenses
4 Operation Expenses (401)320-323 622,124,906 638,946,792
5 Maintenance Expenses (402)320-323 71,096,344 69,458,827
6 Depreciation Expense (403)336-337 109,099,197 103,587,447
7 Depreciation Expense for Asset Retirement Costs (403.1)336-337
8 Amort. & Depl. of Utility Plant (404-405)336-337 6,857,301 7,061,068
9 Amort. of Utilit Plant Acq. Adj. (406)336-337 -22,723 -22,723
10 Amort Propert Loses, Unrecov Plant and Regulatory Study Costs (407)
11 Amort. of Conversion Expenses (407)
12 Regulatory Debits (407.3)21,955
13 (Less) Regulatory Credit (407.4)
14 Taxes Oter Than Income Taxes (408.1)262-263 24,046,035 21,069,235
15 Income Taxes - Federal (409.1)262-263 5,967,393 15,555,364
16 - Other (409.1)262-263 3,057,226 1,547,326
17 Provision for Deferrd Income Taxes (410.1)234, 272277 83,335,948 76,729,161
18 (Less) Provision for Deferred Income Taxes-Cr. (411.1)234, 272-277 80,939,819 63,176,136
19 InvestmentTax Credit Adj. - Net (411.4)266 -1,533,190 235,447
20 (Less) Gains frm Disp. of Utility Plant (411.6)34,607
21 Losses from Disp. of Utility Plant (411.7)
22 (Les) Gains frm Dispoiton of Allowances (411.8)444,212 297,616
23 Losses from Dispositon of Allowances (411.9)
24 Accretion Expense (411.10)
25 TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24)842,631,754 870,694,192
26 Net Util Oper Inc (Enter Tot line 2 less 25) Carr to Pg117,line 27 190,420,366 175,302,189
FERC FORM NO. 1/3-Q (REV. 02-04)Page 114
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2010/Q4
This Report Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2011
STATEMENT OF INCOME FOR THE YEAR (Continued)
9. Use page 122 for important notes regarding the statement of income for any accunt thereof.
10. Give concise explanations concerning unsettled rate proceedings where a contingency exists such that refunds of a material amount may need to be
made to the utility's customers or which may result in material refund to the utility with respect to power or gas purchases. State for each year effected
the gross revenues or costs to which the contingency relates and the tax effects together with an explanation of the major factors which affect the rights
of the utility to retain such revenues or recover amounts paid with respect to power or gas purchases.
11 Give concise explanations concerning significant amounts of any refunds made or received during the year resulting from settlement of any rate
proceeding affecting revenues received or costs incurred for power or gas purches, and a summary of the adjustments made to balance sheet, income,
and expense accunts.
12. If any notes appearing in the report to stokholders are applicable to the Statement of Income, such notes may be included at page 122.
13. Enter on page 122 a concise explanation of only those changes in accunting methods made during the year which had an effect on net income,
including the basis of allocations and apportonments 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 insuffcient for reportng additional utility departments, supply the appropriate accunt titles report thè information in a footnote to
this schedule.
ELECTRIC UTILITY
Current Year to Date Previous Year to Date
(in dollars) (in dollars)(g) (h)
GAS UTILITY
Current Year to Date Previous Year to Date
(in dollars) (in dollars)(i) ü)
OTHER UTILITY
Currnt Year to Date Previous Year to Date
(in dollars) (in dollars)(k) (I)Line
No.
444,212 297,616
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
622,124,906
71,096,344
109,099,197
638,946,792
69,458,827
103,587,447
6,857,301
-22,723
7,061,068
-22,723
21,955
24,046,035
5,967,393
3,057,226
83,335,948
80,939,819
-1,533,190
34,607
21,069,235
15,555,364
1,547,326
76,729,161
63,176,136
235,447
842,631,754
190,420,366
870,694,192
175,302,189
FERC FORM NO.1 (ED. 12-96)Page 115
Name of Respondent
Idaho Power Company
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2011
STATEMENT OF INCOME FOR THE YEAR (continued)
TOTALLine
No.
Year/Period of Report
End of 2010/Q4
Previous Year
(d)
urrn! Months
Ended
Quarterl Only
No 4th Quartr
(e)
Prior 3 Months
Ended
Quartrl Only
No 4th Quarter
(Q
Title of Accunt
(a)
(Ref.)
Page No.
(b)
Current Year
(c)
27 Net Utility Operating Income (Carred foiward frm page 114)
28 Oter Income and Deductons
29 Oter Income
30 Nonutilt Operating Income
31 Revenues From Merchandising, Jobbing and Contrct Work (415)
32 (Less) Costs and Exp. of Merchandising, Job. & Contrct Work (416)
33 Revenues From Nonutility Operations (417)
34 (Less) Expenses of Nonutility Operations (417.1)
35 Nonoperating Rental Income (418)
36 Equit in Earnings of Subsidiary Companies (418.1)
37 Interest and Dividend Income (419)
38 Allowance for Oter Funds Used During Constrcton (419.1)
39 Miscellaneous Nonoperating Income (421)
40 Gain on Dispositon of Propert (421.1)
41 TOTAL Other Income (Enter Total of lines 31 thru 40)
42 Oter Income Deductns
43 Loss on Dispositon of Propert (421.2)
44 Miscellaneous Amortzation (425)
45 Donations (426.1)
46 Life Insurance (426.2)
47 Penalts (426.3)
48 Exp. for Certin Civic, Politcal & Related Activities (426.4)
49 Other Deductons (426.5)
50 TOTAL Other Income Deductons (Total of lines 43 thru 49)
51 Taxes Applic. to Other Income and Deductions
52 Taxes Oter Than Income Taxes (408.2)
53 Income Taxes-Federal (409.2)
54 Income Taxes-Other (409.2)
55 Provision for Deferrd Inc. Taxes (410.2)
56 (Less) Provision for Deferred Income Taxes-Cr. (411.2)
57 InvestmentTax Credit Adj.-Net (411.5)
58 (Less) Investment Tax Credil (420)
59 TOTAL Taxes on Oter Income and Deductons (Total of lines 52-58)
60 Net Other Income and Deductions (Total of lines 41, 50, 59)
61 Interet Charges
62 Interest on Long-Tenn Debt (427)
63 Amort. of Debt Disc. and Expense (428)
64 Amortzation of Loss on Reaquired Debt (428.1)
65 (Less) Amort. of Premium on Debt-Credit (429)
66 (Less) Amortzation of Gain on Reaquired Debt-Creit (429.1)
67 Interest on Debt to Assoc. Companies (430)
68 Oter Interest Expense (431)
69 (Less) Allowance for Borrowed Funds Used During Constrctn-Cr. (432)
70 Net Interet Charges (Total of lines 62 thru 69)
71 Income Before Extrordinary Items (Total of lines 27, 60 and 70)
72 Extrordinary Items
73 Extrordinary Income (434)
74 (Less) Extraordinary Deductons (435)
75 Net Extrordinary Items (Total of line 73 les line 74)
76 Income Taxes-Federal and Oter (409.3)
77 Extrordinary Items After Taxes (line 75 less line 76)
78 Net Income (Total of line 71 and 77)
190,420,366
119
802,483
625,141
58,915
657,070
-6,040
7,546,332
2,167,147
16,551,145
1,928,056
122,735
27,888,562
175,302,189
782,667
737,018
66,599
1,076,858
-8,226
4,957,254
5,214,598
7,554,922
7,178,192
122,587
24,054,717 ---
3,355 3,973
440,052 420,891
93,378 -4,197,136
-453,479 328,368
1,098,260 1,050,861
5,601,967 5,541,928
6,783,533 3,148,885
262-263 19,582 34,431
262-263 -2,812,996 1,681,539
262-263 -559,924 352,526
234, 272-277 1,739,465 3,224,256
234, 272-277 1,420,220 3,576,029
-3,034,093
24,139,122 ----1,716,723
19,189,109
80,490,049
1,487,918
915,215
1,707,178
10,675,095
73,925,265
140,634,223
73,269,850
1,225,978
776,937
2,057,420
5,397,871
71,932,314
122,558,984 -
262-263
140,634,223 122,558,984
FERC FORM NO. 1/3-Q (REV. 02-04)Page 117
THIS PAGE INTENTIONALLY LEFT BLANK
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2010/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da. Yr)
(2) A Resubmission 04/15/2011
STATEMENT OF RETAINED EARNINGS
1. Do not report Lines 49-53 on the quarterly version.
2. Report all changes in appropriated retained earnings. unappropriated retained earnings. year to date, and unappropriated
undistributed subsidiary earnings for the year.
3. Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436
- 439 inclusive). Show the contra primary account affected in column (b)
4. State the purpose and amount of each reservation or appropriation of retained earnings.
5. List first account 439, Adjustments to Retained Eamings. reflecting adjustments to the opening balance of retained earnings. Follow
by credit, then debit items in that order.
6. Show dividends for each class and series of capital stock.
7. Show separately the State and Federal income tax effect of items shown in account 439, Adjustments to Retained Earnings.
8. Explain in a footnote the basis for determining the amount reserved or appropriated. If such reservation or appropriation is to be
recurrent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated.
9. If any notes appearing in the report to stockholders are applicable to this statement, include them on pages 122-123.
Line ItemNo. (a)
UNAPPROPRIATED RETAINED EARNINGS (Accunt 216)
1 Balance-Beginning of Period
2 Changes
3 Adjustments to Retained Earnings (Accunt 439)
4
5
6
7
8
9 TOTAL Credits to Retained Earnings (Acc. 439)
10
11
12
13
14
15 TOTAL Debits to Retained Earnings (Acc. 439)
16 Balance Transferred from Income (Accunt 433 less Accunt 418.1)
17 Appropriations of Retained Earnings (Accl. 436)
18
19 Reserve for excess Earnings for Cascade Project 2010
20 Reserve for exec Earnings for Twin Falls & American Falls
21
22 TOTAL Appropriations of Retained Earnings (Acc. 436)
23 Dividends Declared-Preferred Stock (Accunt 437)
24
25
26
27
28
29 TOTAL Dividends Declared-Preferred Stock (Acc. 437)
30 Dividends Declared-Common Stock (Accunt 438)
31
32
33
34
35
36 TOTAL Dividends Declared-Common Stock (Acc. 438)
37 Transfers from Acc 216.1, Unapprop. Undistrib. Subsidiary Earnings
38 Balance - End of Period (Total 1 ,9,15,16,22,29,36,37)
APPROPRIATED RETAINED EARNINGS (Accunt 215)
Contra Primary
Accunt Affected
(b)
Current
QuarterlYear
Year to Date
Balance
(c)
Previous
QuarterlYear
Year to Date
Balance
(d)----r-~~------------~..~---~-r~-~--
133,087,891 117.601,730~---
~------~
-58,070.890 ( 56,910,568)
-58,070.890 56,910,568)
558,128,446 483,599.149~--
FERC FORM NO. 1/3-Q (REV. 02-04)Page 118
Name of Respondent
Idaho Power Company
Year/Penod of Report
End of 2010/Q4
This ~ort Is: Date of Report(1) ~An Onginal (Mo, Da, Yr)
(2) A Resubmission 04/15/2011
STATEMENT OF RETAINED EARNINGS
1. Do not report Lines 49-53 on the quarterly version.
2. Report all changes in appropriated retained earnings, unappropriated retained earnings, year to date, and unappropriated
undistributed subsidiary earnings for the year.
3. Each credit and debit during the year should be identifed as to the retained earnings account in which recorded (Accounts 433, 436
- 439 inclusive). Show the contra prirnary account affected in column (b)
4. State the purpose and amount of each reservation or appropriation of retained earnings.
5. List first account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow
by credit, then debit items in that order.
6. Show dividends for each class and series of capital stock.
7. Show separately the State and Federal income tax effect of items shown in account 439, Adjustments to Retained Earnings.
8. Explain in a footnote the basis for determining the amount reserved or appropriated. If such reservation or appropriation is to be
recurrent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated.
9. If any notes appearing in the report to stockholders are applicable to this statement, include them on pages 122-123..
Current Previous
QuarterlY ear QuarterlYear
Contra Pnmary Year to Date Year to Date
Line Item ccunt Affected Balance Balance
No.(a)(b)(c)(d)
39
40
41
42
43
44
45 TOTAL Appropriated Retained Earnings (Accunt 215)
APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Accunt 215.1)
46 TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Acc. 215.1)
47 TOTAL Approp. Retained Earnings (Acc. 215, 215.1) (Total 45,46)
48 TOTAL Retained Earnings (Acct. 215, 215.1,216) (Total 38, 47) (216.1)
UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Accunt
Report only on an Annual Basis, no Quarterly
49 Balance-Beginning of Year (Debit or Credit)
50 Equity in Earnings for Year (Credit) (Accunt 418.1)
51 (Less) Dividends Received (Debit)
52
53 BalanceEnd of Year (Total lines 49 thru 52)
~--
2,031,670
2,031,670
560,160,116
1,543,966
1,543,966
485,143,115~--~--~----
62,552,348
7,546,332
57,595,094
4,957,254
70,098,680 62,552,348
FERC FORM NO. 1/3-Q (REV. 02-04)Page 119
THIS PAGE INTENTIONALLY LEFT BLANK
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2011 2010/Q4
FOOTNOTE DATA
~chedu/e~age: 118 Line No.: 20 __ÇolutrIJLÇ_____ n .._________________________.._____________~__~____________
The excess earnings for these projects occurred in 1998 and 2000. Because the adjustment relates to prior years, the
transfer was not recorded through account 436. Instead, it was recorded as a direct transfer to 215.1.
I FERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent
Idaho Power Company
This ~ort Is:
(1) ~An Original
(2) A Resubmission
STATEMENT OF CASH FLOWS
Date of Report
(Mo, Da, Yr)
04/15/2011
Year/Period of Report
End of 2010/04
(1) Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial paper; and (d) Identif separately such items as
investments, fixed assets, intangibles, etc.
(2) Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconcilation between "Cash and Cash
Equivalents at End of Period" with related amounts on the Balance Sheet.
(3) Operating Actvities - Other: Include gains and losses pertining to operating activities only. Gains and losses pertining to investing and financing activities should be reported
in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taes paid.
(4) Investing Activities: Include at Other (line 31) net cash outfow to acquire other companies. Provide a reconciliation of assets acquired with liabilities assumed in the Notes to
the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General Instruction 20; instead provide a renciliation of the
dollar amount of leases capitalized with the plant cost.
Line
No.
Description (See Instruction NO.1 for Explanation of Codes)Current Year to Date
OuarterlYear
(b)
Previous Year to Date
OuarterlYear
(c)(a)
1 Net Cash Flow from Operating Actvities:
2 Net Income (Line 78( c) on page 117)
3 Noncash Charges (Credits) to Income:
4 Depreciation and Depletion
5 Amortization of
6
7
8 Deferred Income Taxes (Net)
9 Investment Tax Credit Adjustment (Net)
10 Net (Increase) Decrease in Receivables
11 Net (Increase) Decrease in Inventory
12 Net (Increase) Decrease in Allowances Inventory
13 Net Increase (Decrease) in Payables and Accued Expenses
14 Net (Increase) Decrease in Other Regulatory Assets
15 Net Increase (Decrease) in Other Regulatory Liabilties
16 (Less) Allowance for Other Funds Used During Construction
17 (Less) Undistributed Earnings from Subsidiary Companies
18 Other (provide details in footnote):
19
20
21
22 Net Cash Provided by (Used in) Operating Actvities (Total 2 thru 21)
23
24 Cash Flows from Investment Actvities:
25 Construction and Acquisition of Plant (including land):
26 Gross Additions to Utilty Plant (less nuclear fuel)
27 Gross Additions to Nuclear Fuel
28 Gross Additions to Common Utilty Plant
29 Gross Additions to Nonutilty Plant
30 (Less) Allowance for Other Funds Used During Construction
31 Other (provide details in footnote):
32
33
34 Cash Outfows for Plant (Total of lines 26 thru 33)
35
36 Acquisition of Other Noncurrent Assets (d)
37 Proceeds from Disposal of Noncurrent Assets (d)
38
39 Investments in and Advances to Assoc. and Subsidiary Companies
40 Contributions and Advances from Assoc. and Subsidiary Companies
41 Disposition of Investments in (and Advances to)
42 Associated and Subsidiary Companies
43
44 Purchase of Investment Securities (a)
45 Proceeds from Sales of Investment Securities (a)
75,464,788
-984,156
13,653,023
539,767
10,594,321
2.842,380
-15.306,466
-6,714,633
11,916,674
47,611,061
10,225,050
7,554,923
4,957,304
-24,413,966
325,912,762 264,678,714
-246,539,337
5,397,871
2,381,759
-312,861,977 -249,555,449
~ - - - -~~~----- -- r - ------~ -- - - --
2,250,259
I ----~~~~ ----~ ---
-7,000,000
FERC FORM NO.1 (ED. 12-96)Page 120
Name of Respondent
Idaho Power Company
This ~ort Is:
(1) ~An Original
(2) A Resubmission
STATEMENT OF CASH FLOWS
Date of Report
(Mo, Da, Yr)
04/15/2011
Year/Period of Report
End of 2010/04
(1) Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial paper; and (d) Identify separately such items as
investments, fixed assets, intangibles, etc.
(2) Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliation between "Cash and Cash
Equivalents at Em;l of Period" with related amounts on the Balance Sheet.
(3) Operating Activities - Other: Include gains and losses pertining to operating activities only. Gains and losses pertining to investing and financing activities should be reported
in those actvities. 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 Oter (line 31) net cash outfow to acquire other companies. Provide a reconciliation of assets acquired with liabilties assumed in the Notes to
the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General Instruction 20; instead provide a recnciliation of the
dollar amount of leases capitalized with the plant cost.
(a)
Current Year to Date
OuarterlYear
(b)
Previous Year to Date
OuarterlYear
(c)
Line
No.
Description (See Instrction NO.1 for Explanation of Codes)
46 Loans Made or Purchased
47 Collections on Loans
48
49 Net (Increase) Decrease in Receivables
50 Net (Increase) Decrease in Inventory
51 Net (Increase) Decrease in Allowances Held for Speculation
52 Net Increase (Decrease) in Payables and Accued Expenses
53 Other (provide details in footnote):
54
55
56 Net Cash Provided by (Used in) Investing Activities
57 Total of lines 34 thru 55)
58
59 Cash Flows from Financing Activities:
60 Proceeds from Issuance of:
61 Long-Term Debt (b)
62 Preferred Stock
63 Common Stock
64 Other (provide details in footnote):
65
66 Net Increase in Short-Term Debt (c)
67 Other (provide details in footnote):
68
69
70 Cash Provided by Outside Sources (Total 61 thru 69)
71
72 Payments for Retirement of:
73 Long-term Debt (b)
74 Preferred Stock
75 Common Stock
76 Other (provide details in footnote):
77
78 Net Decrease in Short-Term Debt (c)
79
80 Dividends on Preferred Stock
81 Dividends on Common Stock
82 Net Cash Provided by (Used in) Financing Activities
83 (Total of lines 70 thru 81)
84
85 Net Increase (Decrease) in Cash and Cash Equivalents
86 (Total of lines 22,57 and 83)
87
88 Cash and Cash Equivalents at Beginning of Period
89
90 Cash and Cash Equivalents at End of period
333,525 922,056
1,514,798
-1,266,217
200,000,000 396,100,000
50,000,000 20,000,000
250,000,000 416,100,000
r-- ---~-----~r----- - ---
-1,063,636 -251,063,636
-3,183,141 -6,921,974
-101,264,330
-58,070,890 -56,910,568
224,232,718 21,624,929
FERC FORM NO.1 (ED. 12-96)Page 121
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) 2S An Original (Mo, Da, Yr)
Idaho Power Company (2) A Resubmission 04/15/2011 2010/Q4
FOOTNOTE DATA
~çllecLu!eJ!llge;~1?Jl_Llne-''lQ.: 5 Column:b
Amortization Twelve Months
Ended 12/31/10
Plant
Regulatory assets
Regulatory liability
Unamortized debt expense
Unamortized discount
Water rights
Other
6,834,579
2,002,795
(620,808)
2,368,760
289,995
1,042,009
202,855
12,120,185
i~checule PJJ~L'L2J!_J~Í!el!C!.L11~__ÇC)lumn: Ji___________. .__~ __~~~_________~~_~_.,._~.__,,______________..~__,~___J
Cash paid during the period for:
Income taxes
Interest (net of amount capitalized)
( 57,768,090)
67,867,693
!SçjiedlJJe Page.:J20____Line No.: 18 Column: b
Cash Flow from Operating Activities (Other)Twelve Months
Ended 12/31/10
Pension and postretirement plan expense
Non-cash pension expense
Gain on sale of renewable energy certificates
Unbiled revenues
Other noncash adjustments to net income
Accrued interest
Payroll liabilties
Other assets and liabilties
14,727,814
(65,601,212)
(444,213)
3,307,645
217,365
3,654,438
1,297,584
1,348,111
(41,492,468)
f$cllf!c!I.Le.Æ'_a..e:J?Q_LJne No.: 26 Column: b - - -----~-.--------.----~--~----~------------~------~----I
Non-cash investing activities:
Additions to PP&E in accounts payable 33,949,485
lSçtif!c!Ylf!~a.ge:1?fL_J.lfle!lC)-"Ll!__ÇQlcl.r!,-n:._p._ .
Other Cash Flows from Plant
._---~
Twelve Months
Ended 12/31/10
Sale of utilty propert
Sale of emission allowances and renewable energy certificates
18,982,212
6,407,871
25,390,083
isçlJeiiiieF'JlIle~iiJi~_=iJni!lQ~:)_3:-~ç()liimiJ-:i~---~=~~_=~-=-~==_=~-=====~======-==-==========-=
Other Investing Cash Flows Twelve Months
Ended 12131/10
I FERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2011 2010/Q4
FOOTNOTE DATA
Disbursements from rabbi trust
Net change in notes receivable from subsidiary
Proceeds from the sale of money market investment
Miscellaneous other investing activities
3,808,604
4,509,173
263,567
(40,198)
8,541,146
IFERC FORM NO.1 (ED. 12-87) Page 450.2
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2010/04
(2) Fi A Resubmission 04115/2011
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
1. Report in columns (b),(c),(d) and (e) the amounts of accumulated other comprehensive income items, on a net-of-tax basis, where appropriate.
2. Report in columns (f) and (g) the amounts of other categories of other cash flow hedges.
3. For each category of hedges that have been accunted for as "fair value hedges", report the accunts affected and the related amounts in a footnote.
4. Report data on a year-to-date basis.
Line Item Unrealized Gains and Minimum Pension Foreign Currency Other
No.Losses on Available-Liabilty adjustment Hedges Adjustments
for-Sale Securities (net amount)
(a)(b)(c)(d)(e)
1 Balance of Accunt 219 at Beginning of
Preceing Year 24 (8,706,639)
2 Precding OtrlYr to Date Reclassifications
from Acct 219 to Net Income 542,886
3 Preceding OuarterlYear to Date Changes in
Fair Value 1,820,148 (1,923,082)
4 Total (lines 2 and 3)1,820,148 (1,380,196)
5 Balance of Accunt 219 at End of
Preceing OuarterlYear 1,820,172 (10,086,835)
6 Balance of Accunt 219 at Beginning of
Current Year 1,820,172 (10,086,835)
7 Current OtrlYr to Date Reclassifications
from Acct 219 to Net Income 708,772
8 Current OuarterlYear to Date Changes in
Fair Value 1,149,129 (3,158,753)
9 Total (lines 7 and 8)1,149,129 (2,449,981)
10 Balance of Accunt 219 at End of Current
OuarterlYear 2,969,301 (12,536,816)
FERC FORM NO.1 (NEW 06-02)Page 122a
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2010/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2011
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
Line
No.
1
2
3
4
5
6
7
8
9
10
Other Cash Flow
Hedges
Interest Rate Swaps
Totals for each
category of items
recorded in
Accunt 219
(h)
( 8,706,615)
542,886
102,934)
439,952
8,266,663)
8,266,663)
708,772
2,009,624)
1,300,852)
9,567,515)
Net Income (Carred
Forward from
Page 117, Line 78)
Total
Comprehensive
Income
Other Cash Flow
Hedges
¡Specify)
(f)(g)(i)0)
FERC FORM NO.1 (NEW 06-02)Page 122b
Name of Respondent
Idaho Power Company
Date of Report Year/Period of Report
End of 2010/Q4
This Report Is:
(1) !2 An Original
(2) 0 A Resubmission
NOTES TO FINANCIAL STATEMENTS
1. Use the space below for important notes regarding the Balance Sheet, Statement of Income for the year, Statement of Retained
Earnings for the year, and Statement of Cash Flows, or any account thereof. Classify the notes according to each basic statement,
providing a subheading for each statement except where a note is applicable to more than one statement.
2. Furnish particulars (details) as to any significant contingent assets or liabilties existing at end of year, including a brief explanation of
any action initiated by the Internal Revenue Service involving possible assessment of additional income taxes of material amount, or of
a claim for refund of income taxes of a material amount initiated by the utilty. Give also a brief explanation of any dividends in arrears
on cumulative preferred stock.
3. For Account 116, Utilty Plant Adjustments, explain the origin of such amount, debits and credits during the year, and plan of
disposition contemplated, giving references to Corm mission orders or other authorizations respecting classification of amounts as plant
adjustents and requirements as to disposition thereof.
4. Where Accounts 189, Unamortized Loss on Reacquired Debt, and 257, Unamortized Gain on Reacquired Debt, are not used, give
an explanation, providing the rate treatment given these items. See General Instruction 17 of the Uniform System of Accounts.
5. Give a concise explanation of any retained earnings restrictions and state the amount of retained earnings affected by such
restrictions.
6. If the notes to financial statements relating to the respondent company appearing in the annual report to the stockholders are
applicable and furnish the data required by instructions above and on pages 114-121, such notes may be included herein.
7. For the 3Q disclosures, respondent must provide in the notes suffcient disclosures so as to make the interim information not
misleading. Disclosures which would substantially duplicate the disclosures contained in the most recent FERC Annual Report may be
omitted.
8. For the 3Q disclosures, the disclosures shall be provided where events subsequent to the end of the most recent year have occurred
which have a material effect on the respondent. Respondent must include in the notes significant changes since the most recently
completed year in such items as: accounting principles and practices; estimates inherent in the preparation of the financial statements;
status of long-term contracts; capitalization including significant new borrowings or modifications of existing financing agreements; and
changes resulting from business combinations or dispositions. However were material contingencies exist, the disclosure of such
matters shall be provided even though a significant change since year end may not have occurred.
9. Finally, if the notes to the financial statements relating to the respondent appearing in the annual report to the stockholders are
applicable and furnish the data required by the above instructions, such notes may be included herein.
04/15/2011
PAGE 122 INTENTIONALLY LEFT BLANK
SEE PAGE 123 FOR REQUIRED INFORMATION.
FERC FORM NO.1 (ED. 12-96)Page 122
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
1. SUMARY OF SIGNIFICANT ACCOUNTING POLICIES:
Idao Power (IPC), a wholly-owned subsidiary of IDA CORP, Inc., is an electrc utility with a service terrtory coverig approximtely
24,000 square miles in southern Idaho and eastern Oregon. Idaho Power is regulated by the Federal Energy Regulatory Conussion
(FERC) and the state regulatory conussions ofIdaho and Oregon. Idaho Power is the parent ofIdao Energy Resources Co.
(IERCo), a joint ventuer in Bridger Coal Company (BCC), which mies and supplies coal to the Jim Bridger generatig plant owned
in par by Idaho Power. IERCO is accounted for using the equity method.
Basis of Reporting
The fiancial statements include the assets, liabilities, revenues and expenses of the Company and have been prepared in accordace
with the accounting requirements of the FERC as set fort in its applicable Uniform System of Accounts and published accountig
releases, which is a comprehenive basis of accounting other than accounting priciples generally accepted in the United States of
America (U.S. GAA). As required by the FERC, the Company accounts for its investment in its majority-owned subsidiar on the
equity method rather than consolidàting the assets, liabilties, revenues, and expenses of the subsidiar, as required by U.S. GAA.
The accompanyig fincial statements include the Company's proportionate share of utility plant and related operations resultig
from its interest in jointly owned plants. In addition, under the requirements of the FERC, there are differences from U.S. GAA in
the presentation of (I) curent portion of long-term debt, (2) assets and liabilities for cost of removal of assets, (3) regulatory assets and
liabilities, (4) deferred income taes, (5) income ta expense and (6) comprehensive income.
Management Estimates
Management makes estimates and assumptions when preparg fiancial statements in conformty with GAA. These estimates and
assumptions include those related to rate regulation, retirement benefits, contigencies, litigation, asset impairent, income taes,
unbiled revenues, and bad debt. These estimates and assumptions affect the reported amounts of assets and liabilities and the
disclosure of contingent assets and liabilities at the date of the fiancial statements, and the reported amounts of revenues and expenses
durg the reporting period. These estimates involve judgments with respect to, among other thgs, futue economic factors that are
diffcult to predict and are beyond mangement's control. As a result, actul results could differ from those estimates.
System of Accounts
The accountig records ofIdaho Power conform to the Uniform System of Accounts prescribed by the FERC and adopted by the
public utility conussions ofIdaho, Oregon, and Wyomig.
Regulation of Utity Operations
Idaho Power's fiancial statements reflect the effects of the different ratemakg priciples followed by the jurisdictions regulatig
Idaho Power. The application of accounting priciples related to regulated operations sometimes results in Idaho Power recording
expenses and revenues in a different period thn when an unegulated 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 retued in
rates. Additionally, regulators can impose regulatory liabilties upon a regulated company for amounts previously collected from
customers and for amounts that are expected to be refuded to customers. The effects of applyig these regulatory accounting
priciples 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 highy liquid temporar investments that mature with 90 days of the date of
acquisition.
Receivables and Alowance 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 wrte-off experience, agig 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 wrtten off though a charge to the allowance and a credit to accounts receivable.
Derivative Financial Instruments
Financial intrents such as commodity futues, forwards, options, and swaps are used to mage exposure to commodity price rik
I FERC FORM NO.1 (ED. 12-88)Page 123.1
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
in the electrcity and natual gas markets. All denvative instrents are recogned as either assets or liabilities at fair value on the
balance sheet. Idaho Power's physical forward contracts qualify for the normal purchases and norml sales exception to denvative
accounting requirements with the exception of forward contrcts for the purchase of natural gas for use at Idaho Power's natural gas
generation facilities. The objective of the nsk management program is to mitigate the pnce nsk associated with the purchase and sale
of electrcity and natual gas. Because ofIdaho Power's regulatory accounting mechansms, Idaho Power records the changes in fair
value of derivative instrents related to power supply as reguatory assets or liabilities.
Revenues
Operatig revenues related to Idaho Power's sale of energy are recorded when service is rendered or energy is delivered to customers.
Idaho Power accrues estiated unbiled revenues for electrc servces delivered to customers but not yet biled atpenod-end. Idaho
Power collects franchise fees and simlar taxes related to energy consumption. None of these collections are reported on the income
statement. Beging in Februry 2009, Idao Power is collecting in base rates a portion of the allowance for fuds used durg
constrction (AFUDC) related to its Hells Canyon relicensing project, as discussed in Note 3. Cash collected under this ratemakig
mechanism is not recorded as revenue, but is intead recorded as a regulatory liability.
Property, Plant and Equipment and Depreciation
The cost of utility plant in servce represents the original cost of contracted servces, direct labor and matenal, AFUDC, and indiect
charges for engieerig, supersion, and simar overhead items. Repair and maintenance costs associated with planed major
maintenance are expensed as the costs are incured, as are maintenance and repair of propert and replacements and renewals of items
determed to be less than unts of propert. For utilty propert replaced or renewed, the origial cost plus removal cost less salvage
is charged to accumulated provision for depreciation, while the cost of related replacements and renewals is added to propert, plant
and equipment.
Al utilty plant in servce is depreciated using the straight-line method at rates approved by regulatory authorities. Anual
depreciation provisions as a percent of average depreciable utility plant in service approximated 2.84 percent in 2010 and 2.81 percent
in 2009.
Long-lived assets are periodically reviewed for impairent when events or changes in circumtaces indicate that the carg amount
of an asset may not be recoverable. If the sum of the undiscounted expected futue cash flows from an asset is less than the carg
value of the asset, impairent must be recogned in the fiancial statements. There were no material impairents of these assets in
2010 or 2009.
Alowance for Funds Used During Construction
AFUDC represents the cost of financing constrction projects with borrowed funds and equity fuds. With one exception, cash is not
realized curently from such allowance, it is realized under the ratemakig process over the servce life of the related propert though
increased revenues resultig from a higher rate base and higher depreciation expense. The component of AFUDC attbutable to
borrowed fuds is included as a reduction to interest expense, while the equity component is included in other income. Idaho Power's
weighted-average monthy AFUDC rates for 2010 and 2009 were 8.0 percent and 6.7 percent, respectively. Idaho Power's reductions
to interest expense for AFUDC were $11 millon for 2010 and $5 million for 2009. Other income included $17 million and $8 miion
of AFUDC for 2010 and 2009, respectively.
Income Taxes
Idaho Power accounts for income taes under the asset and liability method, which requires the recogntion of deferred ta assets and
liabilities for the expected future ta consequences of events that have been included in the fiancial statements. Under ths method,
deferred ta assets and liabilities are determed based on the differences between the financial statements and tax basis of assets and
liabilities using enacted ta rates in effect for the year in which the differences are expected to reverse. The effect of a change in tax
rates on deferred tax assets and liabilities is recognzed in income in the penod that includes the enactment date.
Consistent with orders and directives of the Idao Public Utilities Commssion (IPUC), the regulatory authonty havig pricipal
jursdiction over Idaho Power's Idaho service terrtory, Idaho Power's deferred income taxes for plant-related items (commonly
referred to as normalized accounting) are priarly provided for the difference between income ta depreciation and book depreciation
used for fiancial statement puroses. Unless contrar to applicable income tax gudance, deferred income taes are not provided for
those income tax tig differences where the prescribed regulatory accountig methods direct Idaho Power to recognze the tax
I FERC FORM NO.1 (ED. 12-88)Page 123.2
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
impact curently for rate-makg and fiancial reporting. Regulated enterprises are required to recognze 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 ofIdaho allows a three-percent investment tax credit on qualifyg plant additions. Investment ta credits eared on
regulated assets are deferred and amortized to income over the estimated servce lives of the related properties. Credits eared on
non-regulated assets or investments are recogned in the year eamed.
Income taes are discussed in more detail in Note 2.
Comprehensive Income
Comprehensive income includes net income, unealized holding gain and losses on available-for-sale marketable securties, and
amounts related to a deferred compensation plan for certin senior mangement employees and directors called the Senor
Management Securty Plan (SMSP).
The followig table presents Idao Power's accumulated other comprehensive loss balance at December 31 (net of tax):
20092010
Unrealized holding gain on available-for-sale securties
Senior Management Security Plan
Total
$
(thousands of dollars)
2,969 $ 1,820
(12,537) (10,087)
(9,568) $ (8,267)$
Other Accounting Policies
Debt discount, expense, and premium are deferred and are being amortized over the terms of the respective debt issues.
2. INCOME TAXS:
The components of the net deferred ta liabilty are as follows:
2010 2009
(thousands of dollars)
Deferred ta assets:
Regulatory liabilities
Advances for constrction
Deferred compensation
Advanced payments
Tax credits
Retiement benefits
Other
Total
Deferred ta liabilities:
Propert, plant and equipment
Regulatory assets
Conservation programs
Power cost adjustment
Retirement benefits
Other
Total
IFERC FORM NO.1 (ED. 12-88)
$ 46,199 $
7,061
21,045
8,292
6,461
88,827
4,422
182,307
284,794
422,216
7,611
11,833
93,997
11,146
831,597
47,183
8,335
20,661
3,868
2,548
84,019
5,236
171,850
282,034
382,136
4,772
34,025
65,690
6,664
775,321
Page 123.3
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2011 2010/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Net deferred tax liabilities $649,290 $603,471
A reconciliation between the statutory federal income tax rate and the effective tax rate is as follows:
2010 2009
(thousands of dollars)
$ 51,614 $ 54,296Computed income taes based on statutory federal income ta rate
Change in taxes resulting from:
Equity eargs of subsidiary companies
AFDC
Capitalized interest
Investment tax credits
Repair allowance
Removal costs
Capitalized overhead costs
Capitalized repair costs
Tax method chage - unform capitalization
Tax method change - repairs
Uncertin ta positions
Settement of prior years tax retu
State income taes, net of federal benefit
Depreciation
Other, net
Total income tax expense
Effective ta rate
(2,641)
(9,529)
3,674
(3,378)
(2,850)
(3,500)
(10,500)
(65,333)
(44,466)
74,436
(1,138)
5,074
13,138
2,233
$6,834 $
4.6%
The items comprising income tax (benefit) expense are as follows:
(1,735)
(4,533)
1,529
(3,404)
(3,500)
(3,810)
(3,500)
1,138
(4,119)
1,903
3,895
(5,587)
32,573
21.0%
2010 2009
(thousands of dollars)
Income taxes currently payable (receivable):
Federal
State
Total
Income taxes deferred:
Federal
State
Total
Uncertain tax positions:
Federal
State
Total
Investment tax credits:
Deferred
Restored
Total
Total income tax expense
$(62,068) $
(5,579)
(67,647)
6,752
(4,036)
2,716
65,222
8,076
73,298
$
1,844
(3,377)
(1,533)
6,834 $
19,732
2,385
22,117
18,993
(5,792)
13,201
(2,496)
(485)
(2,981)
3,640
(3,404)
236
32,573
I FERC FORM NO.1 (ED. 12-88)Page 123.4
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2: An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
IDACORP's ta allocation agreement provides that each member of its consolidated group compute its income taes on a separte
company basis. Amounts payable or refundable are settled though IDACORP.
Tax Credits Carryorwards
As of December 31,2010, Idaho Power had 6.4 millon ofIdaho investment tax credit carrorward. The Idao investment ta credit
carorward period expires from 2023 to 2024.
Uncertain Tax Positions
A reconciliation of the beging and ending amount of unecognzed ta benefits for IDACORP and Idaho Power is as follows (in
thousands of dollars):
2010 2009
Balance at Janua i,$1,138 $4,119
Additions for ta positions of the curent year 2,822
Additions for tax positions of prior year 71,614 1,138
Reductions for tax positions of prior years (1,138)(4,119)
Settlements with taing authorities
Balance at December 31,$74,436 $1,138
Ifrecognzed, the $74.4 millon balance of unecogned ta benefits at December 31, 2010 would affect the effective ta rate.
Idaho Power recognzes interest accrued related to unrecogned tax benefits as interest expense and penalties as other expense. Idaho
Power recogned interest expense of $0.2 millon in 2010, and a net reduction in interest expense of$0.2 million in 2009. As of
December 31,2010, Idaho Power had accrued interest of$0.2 millon and none as of December 31,2009. No penalties are accrued.
IDACORP and Idao Power are subject to examiation by their major tax jursdictions - U.S. federal and the State ofIdao. The open
tax years are 2009-2010 for federal and 2007-2010 for Idaho. In May 2009, IDACORP and Idaho Power formally entered the Internal
Revenue Servce (IRS) Compliance Assurance Process (CAP) program for its 2009 tax year. The CAP program provides for IRS
examiation thoughout the year. In Januar 2010, IDACORP was accepted into CAP for its 2010 tax year. With the exception of
Idaho Power's capitalized repairs and unform capitalization tax accountig methods (discussed below), IDACORP and Idaho Power
believe there are no remaing tax uncertinties for the 2009 ta year and expect that the 2009 examiation may conclude durg fiscal
year 2011.
Tax Accountig Method Change for Repair-Related Expenditures
In June 2010, Idaho Power completed its evaluation of a ta accountig method change for its 2009 ta year that allows a curent
income tax deduction for repair-related expenditues on its utility assets that are curently capitalized for fmancial reportg and ta
puroses. In September 2010, Idaho Power adopted ths method followig the automatic consent procedures with the fiing of
IDACORP's 2009 consolidated federal income tax retu.
For the year ended December 31,2010, Idaho Power recorded a $44.5 millon ta benefit related to the fied deduction for the
cumulative method change adjustment and an additional $11.7 milion ta benefit for the anual deduction estimate included in its
2010 income tax provision. As of December 31, 2010, Idaho Power had a curent uncertin ta position liabilty of$14.7 millon
related to ths method. The estimated anual ta deduction related to capitalized repairs produces a net tax benefit of $9 millon
annually, which is approximately $5 millon higher than Idaho Power's prior repair deduction method reported in 2009. The reversal
of ths temporar difference will offset a portion of the ongoing anual benefit.
Idaho Power's prescribed regulatory accounting treatment requies imediate income recogntion for temporar ta differences of ths
tye. A reguatory asset is established to reflect Idaho Power's ability to recover increased income tax expens when such temporary
differences reverse.
I FERC FORM NO.1 (ED. 12-88)Page 123.5
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2) A Resubmission 04/15/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
The tax method is curently being audited under IDACORP' s 2009 CAP examation and, on a national level, aspects of the method
related to electrc utility generation, trmission, and distrbution propert are the subject of an IRS Industr Issue Resolution
program.
Tax Accounting Method Change for Uniform Capitaliation
In September 2009, the IRS issued Industr Director Directive #5 (IDD), which discusses the IRS's compliance priorities and audit
technques related to the allocation of mied servce costs in the unform capitalization methods of electrc utilities. Since that time the
IRS and Idaho Power worked though the impact the IDD guidace had on Idaho Power's unform capitalization method and reached
agreement durig the thd quarter of201 O. The agreement provided that Idaho Power change its unform capitalization method to the
agreed upon method under the IDD with the filing of IDA CORP's 2009 consolidated federal income tax retu. Due to the method
change agreement with the IRS, Idaho Power reversed the uncertin tax position liability for its 2009 uniform capitalization deduction,
resulting in a $1. million tax benefit for the year ended December 31, 2010.
The resulting ta deductions available under the agred upon unform capitaliation method are signficantly greater than Idaho
Power's prior method. For the year ended December 31, 2010, Idaho Power recorded a ta benefit of $65.3 millon related to the
cumulative method change adjustment (ta years 1986 though 2009) for ths method and $5.6 million of curent year tax expense from
the reversal of ths temporar difference. The prescribed regulatory accounting treatment for ths method is the same as discussed
earlier for the capitalized repairs method.
As of December 31,2010, Idaho Power had a curent uncertin ta position liability equal to the $59.7 milion net tax benefit recorded
for the method change. Whle Idaho Power has an agreement with the IRS for examiation and tax retu filing purses, it is awaitig
U.S. Congress Joint Commttee on Taxation approval of its method or approval of methods filed by other simlarly-situated companies
under the IDD before concluding that the new method is effectively settled for fiancial reporting puroses.
Tax Impacts of Health Care Acts
As discussed fuher in Note 11, the Patient Protection and Afordable Care Act and the Health Care and Education Reconciliation Act
were enacted in March 2010. As a result of this legislation, in the fist quaer of 20 1 0 Idaho Power reduced its deferred ta asset
related to futue Medicare Par D deductible retiree prescription drg expenses by $2.3 millon, increased reguatory assets by $2.4
millon, increased deferred tax liabilities by $1 millon, and incured a charge of$0.9 millon.
3. REGULATORY MATTERS:
Regulatory Assets and Liabilties
Regulatory assets represent incurred costs that have been deferred because it is probable they will be recovered though futue rates
collected from customers. Regulatory liabilities represent obligations to mae refuds to customers for previous collections, except for
cost of removal which represents the cost of removig futue electrc assets. The followig table presents a sumar of Idaho Power's
regulatory assets and liabilities (in thousands of dollars):
Description
Regulatory Asset:
Income taxes
Unfuded postretirement benefits (2)
Pension expense deferls (3)
Energy efciency progr costs (3)
Power supply costs (3)
Fixed cost adjustment (3)
Remaining
Amortization
Period
Earning
a Return(l)
Not
Earning
a Return
Total as of December 31,
2010 2009
$ - $
Varies
Varies
53,169
19,467
29,753
12,340
429,457 $429,457 $389,910
182,742 182,742 168,026
10,664 63,833 39,251
19,467 12,207
29,753 84,633
12,340 7,836
I FERC FORM NO.1 (ED. 12-88)Page 123.6
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Asset retirement obligations (4)
Mark-to-market liabilities (5)
Other
Total (6)$
204
114,933 $
15,372
2,278
5,980
646,493 $
15,372
2,278
6,184
761,426 $
14,749
280
3,789
720,681
2011-2015
Regulatory Liabilities:
Income taxes
Removal costs (4)
Investment tax credits
Defered revenue-AFUDC
Mark-to-market assets (5)
Other
Total (7)
$- $53,440 $53,440 $54,958
157,642 157,642 155,405
71,972 71,972 73,506
7,953 21,211 9,894
573 573 715
7,721 8,508 1,579
299,301 $313,346 $296,057
13,258
2011
$
787
14,045 $
(I) Eaing a retur includes either interest or a ret on the investment as a component of rate base at the allowed rate of retrn.
(2) Represents the unfunded obligation of Idao Power's pension and postretirement beneft plans, which are discussed in Note i i.
(3) These items are discussed in more detail below.
(4) Asset retirement obligations and removal costs are discussed in Note 13.
(5) Mark-to-maket assets and liabilities are discussed in Note 16.
(6) Includes $2,240 and $601 for 2010 and 2009, respectively, reprted in other curent assets on the balance sheets.
(7) Includes $8,0 ii and $8,972 for 20 10 and 2009, resectively, reprted in other curent liabilities on the balace shee.
The majority ofIdaho Power's regulatory assets and liabilities are reflected in customer rates and are amortized over the period in
which they are reflected in customer rates. In the event that recovery ofIdao Power's costs though rates becomes unely or
uncertin, 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 wrte off the applicable portion,
which could have a signficant fiancial impact.
Deferred Net Power Supply Costs
Deferred power supply costs are recorded as a deferred charge on the balance sheets for futue recovery though retail rates. The
power supply costs deferred include certin differences between actual net power supply costs incurred by Idaho Power and the costs
included in retail rates. This difference in net power supply costs priarly results from changes in short-term wholesale market prices
and sales and purchase volumes, the level of hydroelectrc generation, the level of thermal generation, and retail loads. Changes in
deferred power supply costs over the last two years were as follows:
Idaho Oregon(l)Total
Balance at Januar 1, 2009 $140,821 $8,278 $149,099
Costs deferred though PCA and PCAM 42,533 (184)42,349
Prior costs expensed and recovered though rates (113,134)(2,283)(1l5,417)
S02 allowances credited to account (2,034)(83)(2,1l7)
Interest and other 3,226 1,135 4,361
2007 Excess power costs order 6,358 6,358
Balance at December 31, 2009 $71,412 $13,221 $84,633
Costs deferred though PCA and PCAM 14,324 14,324
Prior costs expensed and recovered though rates (63,757)(1,792)(65,549)
S02 allowances credited to account (4,504)79 (4,425)
I FERC FORM NO.1 (ED. 12-88)Page 123.7
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2Ç An Original (Mo, Da, Yr)
Idaho Power Company (2) A Resubmission 04/15/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Interest and other
Balance at December 31, 2010 $
84
17,559 $
686
12,194 $
770
29,753
(I) Oregon power supply cost deferals are subject to a sttute that speifically Iinuts rate amortizations of defered costs to six
percent of gross Oregon revenue per yea (approximately $2 nullon). Deferls are amortized sequentially.
Idaho Jurisdictin Power Cost Adjustment Mechanism:
In the Idaho jursdiction, Idaho Power has a PCA mechanism that provides for anual adjustments to the rates charged to its Idaho
retail customers. The PCA tracks Idaho Power's actul net power supply costs (priarly fuel and purchased power less off-system
sales) and compares these amounts to net power supply costs curently being recovered in retail rates. The annual PCA adjustments
are based on two components:
. a forecast component, based on a forecast of net power supply costs in the comig year as compared to net power supply costs
in base rates; and
. a tre-up component, based on the difference between the previous year's actul net power supply costs and the previous
year's forecast. This component also includes a balancing mechanism so that, over time, the actul collection or refud of
authoried tre-up dollars matches the amounts authoried. The tre-up component is calculated monthly, and interest is
applied to the balance.
The followig table summarzes PCA rate adjustments in the thee year ended December 31, 2009, and 2010:
Effective
Date
June 1,2010
$ Change
(mions)
$(146.9)
June 1,2009 $84.3
Notes
The IPUC's order was made in conjunction with a Januar 2010 rate settlement
agreement described below in "Idaho 2009 Settement Agreement and 2010 PCA
Order."
The increase was net of $4.5 million of gain from sales of excess S02 emission
allowances which the IPUC ordered be applied againt the PCA. The IPUC has
allowed Idaho Power to retain its PCA sharg percentage of the gain from sales of
excess S02 emission allowances as a shareholder benefit with the remainder recorded
as a customer benefit, substantially all of which was used to reduce the PCA.
Proceeds from the sale of renewable energy certficates (RCs) wil also be used to
reduce the PCA. RECs are acquired by Idaho Power though purchases of renewable
energy.
In its order approvig Idao Power's 2008-2009 PCA, the IPUC directed Idao Power to set up workshops with the IPUC Staff and
several ofIdaho Power's largest customers to address issues not resolved in that PCA filing. The workshops resulted in the followig
changes to the PCA mechansm:
. PCA sharg ratio - the PCA allocates the deviations in net power supply expenses between customers (95 percent) and
shareholders (5 percent). The previous sharg ratio was 90/10;
. LGAR - the LGAR is an element of the PCA formula that is intended to elimte recovery of power supply expenses
associated with load growt resulting from changig weather conditions, a growig customer base, or changing customer use
pattern. The 2007 general rate case reset the LGAR from $29.41 to $62.79 per MWh, but applied that rate to only 50
percent of the load growt beging in March 2008. The stipulation agreed on a new formula for calculating the LGAR.
Based on the fmal rates approved by the IPUC, as of the date of this report the LGAR is $26.63 per MW;
. use of Idaho Power's operation plan power supply cost forecast - the operation plan forecast may better match curent
collections with actual net power supply costs in the year they are incured and result in smaller amounts being included in the
followig year's "tre-up" rate, beging with the 2009-2010 PCA filing;
I FERC FORM NO.1 (ED. 12-88)Page 123.8
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
. inclusion of thd-par transmission expense - transmission expenses paid to thd pares to facilitate wholesale purchases
and sales of energy, including losses, are a necessar component of net power supply costs. Deviation in these costs from
levels included in base rates is now reflected in PCA computations; and
. adjusted distrbution of base net power supply costs - base net power supply costs are distrbuted thoughout the year based
upon the monthy shape of normlized revenues for puioses of the PCA deferral calculation.
In the IPUC's May 2010 order implementig new PCA rates for the period from June 1,2010 to May 31, 2011, the IPUC identified
the use of the LGAR in times of load decline as an issue of contention. However, the IPUC Staff recommended no change to the load
growt adjustment amounts or methodology, and the IPUC did not remove the LGAR adjustment to the PCA component. The IPUC's
order stated, however, that it expects the IPUC Staff Idaho Power, and interested parties to meet to address an appropriate change to
the LGAR mechansm to elimate a potential double recovery when loads decline. On January 14, 2011, Idaho Power submitted to
the IPUC comments in support of a revised methodology that was submitted for consideration by another utility. Idao Power's fiing
with the IPUC requested a new LGAR rate of $19.36 per MWh under the revised methodology effective April 1, 20 i 1. As of the date
of ths report, a determation and order from the IPUC is pending.
Oregon Jurisdiction Power Cost Adjustent Mechanism:
Idaho Power's power cost recovery mechanism in Oregon went into effect in 2008. It has two components: the anual power cost
update (APCD) and the power cost adjustment mechanism (PCAM). The combintion of the APCU and the PCAM allows Idaho
Power to recover excess net power supply costs in a more tiely fashion than though the previously existig deferral process.
The APCU allows Idaho Power to reestablish its Oregon base net power supply costs anually, separate from a general rate case, and
to forecast net power supply costs for the upcomig water year. The APCU has two components: the "October Update," Idaho
Power's calculation of estimated normalized net power supply expenses for the followig April though March test period, and the
"March Forecast," Idao Power's forecast of expected net power supply expenses for the same test period, updated for a number of
variables including the most recent stream flow data and futue wholesale electrc prices.
Base power supply cost changes since inception are as follows:
Year
2011
APCD Description
Idaho Power's October Update portion of the 2011 APCU indicates that revenues associated with Idaho
Power's base net power supply costs would be increased by $1.6 millon over the curent rates. The
actul impact will be determed once the March Forecast porton is filed in March 2011 and combined
with the October Update. Final rates are expected to become effective on June 1, 2011.
A rate increase of$2.6 million anually took effect June 1,2010.
A rate increase of $3.9 millon annually took effect June 1, 2009
2010
2009
The PCAM is a tre-up fied annually in February. The filing calculates the deviation between actual net power supply expenses
incured for the preceding calendar year and the net power supply expenses recovered though the APCU for the same period. Under
the PCAM, Idaho Power is subject to a porton of the business risk or benefit associated with ths deviation though application of an
asymetrcal deadband (or range of deviations) with 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 sharg of costs and benefits between customers and
Idaho Power. However, collection by Idaho Power will occur only to the extent that it results in Idao Power's actual return on equity
(ROE) for the year being no greater than 100 basis points below Idaho Power's last authoried ROE. A refud to customers will occur
only to the extent that it results in Idaho Power's actual ROE for that year being no less than 100 basis points above Idao Power's last
authoried ROE. Results of the PCAM since inception are as follows:
Year
2010
2009
PCAM Description
Actul net power supply costs were with the deadband, resulting in no deferrL.
Actul net power supply costs were with the deadband, resultig in no deferraL.
I FERC FORM NO.1 (ED. 12-88)Page 123.9
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Oregon Excess Power Cost Deferrals:
In May 2009, the OPUC adopted a stipulation allowig Idao Power to defer excess net power supply costs of$6.4 millon (including
interest though the date of the order) for the period May 1 through December 31,2007. Idaho Power recorded the $6.4 million
deferral in the second quaer of 2009 as a reduction to power cost adjustment expense. The amount to be recovered was reduced by
$0.9 million of previously deferred S02emission allowance sales (including interest) durg the same period. Effective Janua 201 i,
these costs are being collected though rates and amortized.
Fixed Cost Adjustment Mechanism (FCA)
The FCA mechansm began as a pilot program for Idaho Power's Idaho residential and small general service customers, rug from
2007 though 2009. The FCA is a rate mechanism designed to remove Idaho Power's disincentive to invest in energy effciency
program by separatig (or decoupling) the recovery of fied costs from the variable kiowatt-hour charge and ling it intead to a set
amount per customer. On April 29, 2010, the IPUC approved a two-year extension of the FCA pilot program, effective retroactively to
Januar 1,2010.
On May 29,2010, the IPUC approved the recovery of $6.3 millon of under-recovered fied costs related to 2009, with rates effective
June i, 2010 though May 31, 2010. In May 2009, the IPUC approved FCA rates effective June 1, 2009 though May 31, 2010, to
recover $2.7 millon of fied costs under-recovered durg 2008
Idaho Rate Cases
Idaho 2009 Settlement Agreement and 2010 PCA Order: On Januar 13, 2010, the IPUC approved a settlement agreement among
Idaho Power, several ofIdaho Power's customers, the IPUC Staff, and others. Signficant elements of the settlement agreement
include:
. a general rate moratorium in effect until January 1, 2012. The moratorium does not apply to other specified revenue
requirement proceedings, such as the PCA, the FCA, pension fuding, advanced meterig infrstrctue (AMI), energy
effciency rider, and governent imposed fees;
. a specified distrbution of the reduction in 2010 PCA tht would reduce customer rates, provide up to a $25 million general
increase in anual base rates, and reset base power supply costs for the PCA, effective with the June 1,2010 PCA rate
chage. This provision anticipated a signficant reduction in PCA rates for the 2010-2011 PCA year;
. a provision to share with Idaho customers 50 percent of any Idao-jursdiction earngs in excess of a 10.5 percent retu on
equity in any calendar year from 2009 to 2011; and
. a provision to allow the accelerated amortization of accumulated deferred investment ta credits (ADITC) ifIdao Power's
actual rate of retu on equity is below 9.5 percent in any calendar year from 2009 to 201 i in its Idaho jursdiction. Idao
Power would be permtted to amortize additional ADITC in an amount up to $45 million over the thee-year period, but could
use no more that $15 millon in anyone year uness there is a carover. Carrover amounts are added to the $15 million
anual allowance up to a maximum amortzation of$25 million in anyone year.
Because Idao Power's Idaho-jursdiction retu on equity was between 9.5 and 10.5 percent in 2009 and 2010, the sharg and
accelerated amortization provisions were not trggered. In accordance with the settlement, Idaho Power has available $25 million of
additional ADITC amortization for use in 2011.
On April 15,2010, Idao Power filed its anual application with the IPUC to implement new PCA rates to be effective June 1,2010
though May 31, 20 i 1, and to chage base rates, puruant to the term of the January 2010 Idao settlement agreement. On May 28,
2010, the IPUC issued its order approvig a $146.9 millon 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 millon increase in base rates.
Idaho 2008 General Rate Case: On January 30,2009, the IPUC issued an order approvig an average annual increase in Idaho base
rates, effective Februry 1, 2009, 00.1 percent (approximately $20.9 million annually), a retu on equity of 10.5 percent, and an
IFERC FORM NO.1 (ED. 12-88) Page 123.10
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
overall rate of return of8.18 percent. On February 19,2009, Idao Power fied a request for reconsideration with the IPUC and on
March 19,2009, the IPUC issued an order that increased Idaho Power's Idaho revenue requirement by an additional $6.1 million to
approximately $27 millon for ths rate case, raising the average rate increase from 3. i percent to 4.0 percent.
The January 30, 2009 order authoried approximately $ i 5 million related to increases in base net power supply costs. It also allowed
Idaho Power to include in rates approximately $6.8 millon ($10.6 milion including income ta gross-up) of2009 AFC relating to
the Hells Canyon Complex relicensing project. Typically, AFUDC is not included in rates until a project is in use and benefitting
customers, but the IPUC determed that including this amount in curent rates is in the public interest. Because AFUDC is already
recorded on an accrul basis, ths portion of the rate increase will improve cash flows but will not have a curent impact on Idaho
Power's net income. The amounts collected are being deferred as a regulatory liability and will be recogned in revenues over the life
of the new license once it has been issued.
The IPUC denied reconsideration with respect to a refud of$3.3 million offees recovered by Idaho Power from the FERC. On April
2,2009, Idaho Power fied an application with the IPUC for an accounting order approvig amortzation of the fees over a five-year
period beging October 2006 when Idaho Power received the FERC credit. The IPUC approved Idao Power's requested
amortization period in an order issued on April 28, 2009. In the first quaer of2009, Idaho Power recorded a charge of approximately
$1.7 millon to electrc utility other operations expense and a corresponding regulatory liabilty for the amount to be refuded from
Februry 1, 2009, though the end of the amortization period, September 2011. As the regulatory liability is amortized it reduces
electrc utility other operations expense ratably over the remaing amortation period.
Retiement Benefits Plan: Idaho Power defers its pension expene as a regulatory asset. Idaho Power deferred approxiately $24
millon and $29 millon, of pension expense to a regulatory asset in 2010 and 2009, respectively. Deferred pension costs are expected
to be amortzed to expense to match the revenues received when futue pension contrbutions are recovered though rates. Idao
Power only records a carg charge recorded on the unecovered balance of cash contrbutions.
In May 2010, the IPUC approved Idaho Power's request to increase rates to allow recovery ofIdao Power's 2009 cash contrbution
to its defied benefit pension plan, which contrbution was made in September 2010. Idaho Power's application sought approval of
$5.4 millon in pension cost recovery over a one-year period to allow recovery contemporaneous with Idaho Power's expected cash
contrbutions to the plan. In the IPUC's May 2010 order approving an increase in rates to allow recovery of$5.4 millon ofIdaho
Power's $60 millon contrbution made in September 2010 to the defied benefit pension plan, the IPUC stated that "Idaho Power is
advised that, previous orders notwthstanding, approval ofIdaho Power's pension contrbutions in ths case does not gurantee IPUC
approval of futue pension plan contrbutions. Authority for the balancing account and regulatory account remain in place. However,
fuer justification is required before additional rate recovery for futue contrbutions will be authoried."
Followig the issuance of the IPUC's order, Idaho Power undertook its anual review of its current retirment benefits packages,
which included a thorough review of costs, benefits, and risks associated with the retirement benefits package, and considered
alternatives to its pension plan and the weightig of plans between defined benefit and defied contrbution. Followig that analysis,
in September 2010 Idao Power revised the defied benefit plan for persons hied on or after Janua 1, 2011 to reduce the company's
estimated cost of the plan for those employees by 20 percent. On October 1, 2010, Idaho Power filed an application with the IPUC
requesting an order acceptig Idao Power's 2011 retirement benefits package on or before February 28,2011. On December 14,
2010, the IPUC Staff and the Industral Customers of Idao Power (ICIP) filed comments with the IPUC recommending tht the IPUC
reject Idaho Power's request for acceptance of its 2011 retiement benefits package evi¡luation. The IPUC Staff stated in its comments
to the IPUC tht, among other items, it believed Idaho Power did not adequately consider available alternatives. On December 28,
2010, Idaho Power filed with the IPUC reply comments to the IPUC Staffs and ICIP's comments. In its reply comments, Idao Power
noted that based on its analysis it has set its 2011 retirement benefits package at a competitive cost level tht is less than the median
offerigs of simlarly situted utility peers, has carefully considered the allocation of costs and investment risk between customers and
employees, and the operational imperative to maintain safe, reliable servce with an engaged, qualified, experienced, and flexible
workforce, and thus requested anew that the IPUC issue an order accepting Idaho Power's 2011 retiement benefits package. On
Janua 26, 2011, the IPUC issued an order stating that Idaho Power is not precluded from filig for recovery of 20 1 0 contrbutions
before proceedings relatig to the 2011 retirement benefits package prudency have concluded.
Idaho Energy Effciency Rider: On March 16, 20 I 0, Idaho Power fied an application with the IPUC requesting an order
designatig energy effciency expenditus of $50.7 million incured in 2008 and 2009 as prudently incurred expenses. On November
I FERC FORM NO.1 (ED. 12-88)Page 123.11
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
16, 2010, the IPUC issued an order designating all $50.7 millon of energy effciency expenditues as prudently incurred and approved
for ratemakng puroses. Idaho Power's 2010 expenditues for rider-fuded energy effciency and demand response intiatives in its
Idao and Oregon jursdictions totaled $44.2 million.
Langley Gulch Power Plant Ratemaking Treatment: On September 1,2009, Idaho Power received pre-approval from the IPUC to
include $396.6 million of constrction costs in Idaho Power's rate base when the Laugley Gulch power plant achieves commercial
operation. Idaho Power may request recovery of additional costs if they exceed $396.6 million, provided tht the additional costs were
reasonably and prudently incured.
Oregon Rate Cases
Oregon 2009 General Rate Case: On Februry 24,2010, the OPUC approved a $5 millon, or 15.4 percent, increase in base rates in
the Oregon jursdiction. The new rates were effective March 1,2010, and are based on a retu on equity of 10.175 percent and an
overall rate of retu of8.061 percent. Idaho Power's previously authoried rate of retu in Oregon was 7.83 percent and its
requested rate of retu in the general rate case filing was 8.68 percent.
Other Regulatory Proceedings
Advanced Metering Infrastructure: The AMI project provides the means to automatically retreve energy consumption inormation,
elimting manual meter reading expense.
On Februry 12,2009, the IPUC approved Idao Power's application requestig a Certificate of Public Convenience and Necessity for
the deployment of AMI technology and approval of accelerated depreciation for the existing meterig equipment. The IPUC
subsequently clarfied tht Idaho Power can expect to include in rate base the Idaho portion of prudent capital costs of deployig AMI
as it is placed in service up to the capital cost commtment estimate of$70.9 millon, plus certin costs that the company could not
quantify with precision at the time of the application. The IPUC also clarified, as requested by Idaho Power, that it does not anticipate
that the imediate savings derived from the implementation of AMI thoughout Idao Power's servce terrtory will eliminate or
wholly offset the increase in Idaho Power's revenue requirement caused by the authoried depreciation period.
On May 29,2009, the IPUC approved anual recovery of$1O.5 million, effective June 1,2009. The order was based on Idao
Power's actul investment in AMI though the then-current date, annualized though December 3 i, 2009. The IPUC also allowed
Idao Power to begin thee-year accelerated depreciation of the existig meterig equipment on June 1,2009. The order reflects
annualized depreciation expense relatig to AMI of$9.2 million. Actual depreciation expense recorded in 2010 and 2009 were $10.6
million and $6.2 million, respectively.
On March 15, 2010, Idao Power fied an application with the IPUC requestig authority to implement a $2.4 millon base rate
increase for identified customer classes to recover costs relating to the AMI project. On May 28,2010, the IPUC approved Idaho
Power's application, authoriing the rate increase effective June 1,2010.
In the Oregon jursdiction, the OPUC approved accelerated depreciation and recovery of existing meters located in Oregon over an
18-month period beging Janua 2009. Idaho Power has substantially completed the deployment of the Oregon servce-terrtory
meters. The existing meters were fully depreciated prior to their removal from servce. The approval increased both rates and
depreciation expene $0.8 millon in 2009 and $0.4 milion in 2010.
Depreciation Filgs: In 2008 and 2009 Idaho Power fied revisions to its depreciation rates with the IPUC, the OPUC, and the
FERC. The commssions approved the new rates, which reduce depreciation expense approximately $8.5 million annually. Idao
Power began applyig the new depreciation rates in August 2008.
Federal Regulatory Matters
Open Access Transmission Tarif(OATT) Rates: In 2006, Idaho Power moved from a fied rate to a formula rate for its OATT,
which allows transmission rates to be updated anually based on financial and operational data Idaho Power files with the FERC. On
August 28, 2009, Idaho Power filed its anual inormtional fiing with the FERC that contain the annual update of the formula rate
I FERC FORM NO.1 (ED. 12-88)Page 123.12
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Dä, Yr)
Idaho Power Company (2)A Resubmission 04/15/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
based on the 2008 test year. The new rate included in the filing was $15.83 per kW-year, an increase of $2.02 per kW-year, or 14.6
percent. The rates were effective from October 1,2009 though September 30,2010. On August 26,2010, Idaho Power submitted its
anual information filing for its OATT to FERC. The new rate submitted by Idao Power was $19.60 per kW/year and was effective
as of October 1,2010 for a period of one year. For the years ended December 31, 2009 and 2010, revenues from the tranmission rate
for service under the OATT were $13.3 milion and $15.4 millon, respectively. In September 2010, Idaho Power made corrections to
its OATT rates for the period begig October 1,2007 through September 30, 2010, which resulted in the issuance of refunds,
including interest, to transmission customers of $0.5 million.
FERC OATT Proceedings and ITSA Amendment: On May 24,2010, Idaho Power and PacifiCorp entered into and filed an offer of
settlement with the FERC in connection with Idaho Power's request for authority to increase rates to PacifiCorp under the existig
Agreement for Interconnection and Transmission Servces (ITSA). Under the settlement, which the FERC approved in July 2010,
PacifiCorp will take and pay for 250 MW oflong-term firm point-to-point tranmission service, pursuant to the ITSA, the rates, term,
and conditions of which will be equivalent to Idaho Power's OATT. For the twelve month ended December 31, 2010, Idao Power
collected $4.2 million related to the ITSA with PacifiCorp.
FERC Transmission Rate Refunds and Shortfall Filing: On January 15,2009, the FERC issued an order that required Idaho Power
to reduce its tranmission service rates to FERC jursdictional customers and refud $13.3 million to these customers. Based on the
FERC order, Idaho Power reserved an additional $7.9 milion (including $0.7 million of interest) in 2008 to brig its reserve to the
$13.3 millon ordered refuded. Idaho Power made the refuds in Febru 2009 and filed a request for rehearig with the FERC. Of
the additional $7.9 millon ordered refuded, $2.3 millon related to transmission revenues recorded in 2007 and $ 1 .7 million related to
transmission revenues recorded in 2006. In March 2009, the FERC issued a tolling order that effectively relieved it from actig for an
indefite period of tie on Idaho Power's request for rehearig.
For Idaho jurisdictional revenue requirement determations, revenues from thd paries (non-state jurisdictional) received though the
OATT, referred to as revenue credits, are a direct offset to Idaho Power's overall revenue requirement. In the last two general rate
cases, Idaho Power included an estimate ofOATT revenues from thd parties based on the forecasted OATT rate. However, the
FERC order issued on January 15,2009 reduced actual thid-par tranmission revenues Idaho Power received staing in June 2006,
resulting in an overstatement of the revenue credits in the Idao jursdictional revenue requirement.
On October 30,2009, the IPUC approved Idaho Power's request for authorization to defer the difference between the revenue credits
in the last two general rate cases and the amount ofOATT revenues Idaho Power has received since March 2008 and expected to
receive though May 2010. The IPUC order authorized Idao Power to amortize the unecovered tranmission revenues on a
straight-line basis over a three-year period beging January 1, 2011 and did not authorize a carrg charge on the balance. Based on
actual and projected tranmission revenues from March 2008 though May 2010, Idaho Power recorded a $4.7 millon regulatory asset
in 2009 for potential futue recovery.
On October 13, 2010, Idaho Power refreshed its filing with the IPUC for its deferral related to unecovered transmission revenues.
Termtion of a transmission arrangement with PacifiCorp and adjustments to other tranmission arrangements allowed Idaho Power
to reduce its prior deferral amount to $2.1 million. Idaho Power requested to begin amortization of the $2.1 millon deferred amount
on January 1,2012, rather than Janua 1,2011, as origially ordered, because Idao Power's settlement agreement would not permt
potential inclusion of the deferral amount in rates until after January 1, 2012. On Februry 9,2011, the IPUC issued an order reducing
the deferral amount to $2.1 millon, as requested by Idaho Power, but denied the request to begin amortization on Janua 1, 2012,
instead orderig that Idaho Power advise the IPUC when the FERC has issued its order on rehearg. Thereafter, Idaho Power may
request a commencement date for the thee-year amortization period.
IFERC FORM NO.1 (ED. 12-88)Page 123.13
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2Ç An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
4. LONG- TERM DEBT
The following table sumarzes long-term debt at December 31:
First mortgage bonds:
6.60% Series due 2011
4.75% Series due 2012
4.25% Series due 2013
6.025% Series due 2018
6.15% Series due 2019
4.50% Series due 2020
3.40% Series due 2020
6% Series due 2032
5.50% Series due 2033
5.50% Series due 2034
5.875% Series due 2034
5.30% Series due 2035
6.30% Series due 2037
6.25% Series due 2037
4.85% Series due 2040
Total first mortgage bonds
Pollution control revenue bonds:
5.15% Series due 2024(1)
5.25% Series due 2026(1)
Varable Rate Series 2000 due 2027
Total pollution control revenue bonds
American Falls bond guartee
Milner Dam note guarantee
Unamortized discount - net
Total Idaho Power outstanding debt(2)
$
2010 2009
(thousands of dollars)
120,000 $120,000
100,000 100,000
70,000 70,000
120,000 120,000
100,000 100,000
130,000 130,000
100,000
100,000 100,000
70,000 70,000
50,000 50,000
55,000 55,000
60,000 60,000
140,000 140,000
100,000 100,000
100,000
1,415,000 1,215,000
49,800 49,800
116,300 116,300
4,360 4,360
170,460 170,460
19,885 19,885
7,446 8,509
(3,440)(3,060)
1,609,351 $1,410,794$
(l) Humboldt County and Sweeater County Pollution Contrl Revenue Bonds are secured by fit morgage bonds, bringing the total fit
mortgage bonds outstanding at December 31,2010, to $1.581 bilion.
(2) At Deember 31, 2010 and 2009, the overll effective cost ofldaho Power's outstading debt was 5.53 percent and 5.76 percent,
respectively.
At December 31, 2010, the maturities for the aggregate amount oflong-ter debt outstading were (in thousands of dollars):
2011 2012 2013 2014 2015 Thereafter
Idaho Power $ 121,064 $ 101,064 $71,064 $1,064 $1,064 $ 1,317,471
IFERC FORM NO.1 (ED. 12-88) Page 123.14
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Idaho Power Long-Term Financing
In May 2010, Idaho Power registered with the SEC the sale of up to $500 millon of fit mortgage bonds and debt securties. On June
17,2010, Idaho Power entered into a selling agency agreement with ten bank naed in the agreement in connection with the potential
issuance and sale from time to tie of up to $500 million aggregate pricipal amount offirst mortgage bonds. On August 30,2010,
Idaho Power issued $100 millon 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 regitration statement. As of
December 31,2010, $300 million remained on Idaho Power's shelf registration for the issuace offirst mortgage bonds and debt
securties.
Mortgage: As of December 31,2010, Idaho Power could issue under its Indenture of Mortgage and Deed of Trust, dated as of
October 1, 1937, between Idaho Power and Deutsche Ban Trust Company Americas (formerly known as Bankers Trust Company)
and R.G. Page, as Trustees (Stanley Burg, successor individual trstee) (Mortgage) approximately $407 milion of additional first
mortgage bonds based on total unfunded propert additions of approximtely $679 million. Idaho Power could issue an additional
$612 million of fit mortgage bonds based on retied fit mortgage bonds. These amounts are fuer limted by the maxium
amount of fit mortgage bonds set fort in the Mortgage.
The Mortgage secures all bonds issued under the indentue equally and ratably, without preference, priority, or distiction. First
mortgage bonds issued in the futue will also be secured by the Mortgage. The lien of the indentue constitutes a fist mortgage on all
the properties ofIdaho Power, subject only to certin lited exceptions including liens for taes and assessments that are not
delinquent and mior excepted encumbrances. Certin of the properties ofIdaho Power are subject to easements, leases, contracts,
covenants, workmen's compensation awards, and simar encumbrances and mior defects and clouds common to propertes. The
Mortgage does not create a lien on revenues or profits, or notes or accounts receivable, contracts or choses in action, except as
permtted by law durg a completed default, securties, or cash, except when pledged, or merchandise or equipment manufactued or
acquired for resale. The Mortgage creates a lien on the interest ofIdaho Power in propert subsequently acquired, other than excepted
propert, subject to limtations in the case of consolidation, merger, or sale of all or substatially all of the assets ofIdaho Power. The
Mortgage requies Idaho Power to spend or appropriate 15 percent of its anual gross operatig revenues for maintenance, retirement,
or amortization of its properties. Idaho Power may, however, anticipate or make up these expenditues or appropriations with the
five years that imediately follow or precede a paricular year.
On Febru 17,2010, Idao Power entered into the Fort-fift Supplemental Indentue, 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 bilion. The
amount issuable is also restricted by propert, earngs, and other provisions of the Mortgage and supplemental indentues to the
Mortgage. Idaho Power may amend the Mortgage and increase ths amount without consent of the holders of the fist mortgage bonds.
The Mortgage requies that Idaho Power's net earngs be at least twce the anual interest requirements on all outstanding debt of
equal or prior ran including the bonds that Idaho Power may propose to issue. Under certain circumtances, the net eargs test
does not apply, including the issuance of refuding bonds to retire outstading 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:
Idaho Power has a $300 millon credit facility that expires on April 25, 2012. Commercial paper may be issued up to the amounts
supported by the credit facilities. Under these facilities the companes pay a facility fee on the commtment, quaerly in arears, based
on its ratig for senior unecured long-term debt securities without thd-part credit enhcement as provided by Moody's Investors
Servce and Standard & Poor's Ratings Servces. At December 31, 2010, Idaho Power had reguatory authority to incur up to $450
millon of short-term indebtedness.
I FERC FORM NO.1 (ED. 12-88)Page 123.15
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
At December 31, 2010, no loans were outstanding on Idao Power's facilities. A sumry of notes payable is presented below:
2010 2009
(thousands of dollars)
Balances:
At the end of year
Average durng the yea
Weighted-average interest rate:
At the end of year
$
$
$
348 $ 46,386
6. COMMON STOCK:
Idaho Power Common Stock
In 2010 and 2009, IDACORP contrbuted $50 milion and $20 millon, respectively, of additional equity to Idao Power. No
additional shares ofIdaho Power common stock were issued.
Dividend Restrictions
A covenant under Idaho Power's credit facility requires Idaho Power to maintain a leverage ratio of consolidated indebtedness to
consolidated total capitalization, as defied therein, 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 Idao 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 are lited to the extent payment of such
dividends would violate the covenant or Idaho Power's Code of Conduct. At December 31, 2010, the leverage ratio for Idao Power
was 53 percent. Based on these restrctions, Idaho Power's dividends were limted to $538 milion, at December 31, 2010. There are
additional covenants, subject to exceptions, that prohibit or restrct certin investments or acquisitions, mergers, or sale or disposition
of propert without consent; the creation of certin liens; and any agreements restrctig dividend payments to the company from any
material subsidiar. At December 31, 2010, Idaho Power was in compliance with all facility covenants.
Idao Power's articles of incorporation contain restrctions on the payment of dividends on its common stock if preferrd stock
dividends are in arears. Idaho Power has no preferred stock outstanding.
Idaho Power must obtain approval of the OPUC before it could diectly or indirectly loan fuds or issue notes or give credit on its
books to IDACORP.
7. STOCK-BASED COMPENSATION:
Through its parent company IDACORP, Idaho Power has thee share-based compensation plans. The employee plans are the 2000
Long-Term Incentive and Compensation Plan (L TICP) and the 1994 Restrcted Stock Plan (RSP). These plan are intended to align
employee and shareholder objectives related to long-term growt. There is also one non-employee plan, the Non-Employee Directors
Stock Compensation Plan (DSP). The purse of the DSP is to increase directors' stock ownership though stock-based compensation.
The DSP was termated for puroses of new awards effective Febru 26, 2010, and grants to nonemployee directors subsequent to
that date have been made pursuant to the L TICP.
The L TICP (for offcers, key employees, and directors) permts the grant of nonqualified stock options, restrcted stock, pedormance
shares, and several other tyes of stock-based awards. The RSP permts only the grant of restrcted stock or pedormance-based
restrcted stock. At December 3 I, 20 I 0, the maximum number of shares available under the L TICP and RSP were 1,537,639 and
16,064, respectively.
IFERC FORM NO.1 (ED. 12-88) Page 123.16
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) .~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Stock Awards: Restrcted stock awards have three-year vestig periods and entitle the recipients to dividends and voting rights.
Unvested shares are restrcted as to disposition and subject to fodeitue under certin circumtaces. 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.
Pedormnce-based restrcted stock awards have thee-year vestig periods and entitle the recipients to votig rights. Unvested shares
are restrcted as to disposition, subject to fodeitue under certin circumstaces, and subject to meeting specific performance
conditions. Based on the attinent of the pedormance conditions, the ultimate award can range from zero to 150 percent of the taget
award. Dividends are accrued and paid out only on shares that eventully vest.
The performnce awards are based on two metrcs, cumulative earngs per share (CEPS) and total shareholder retu (TSR) relative
to a peer group. The fair value of the CEPS porton is based on the market value at the date of grant, reduced by the loss in time-value
of the estimated future dividend payments, using an expected quarterly dividend of $0.30. The fair value of the TSR porton is
estiated using a statistical model that incorporates the probability of meetig pedormance tagets based on historical returns relative
to the peer group. Both performce goals are measured over the thee-year vesting period and are charged to compensation expense
over the vesting period based on the number of shaes expected to vest.
Asummar of restrcted stock and performance share activity is presented below:
Nonvested shares at Januar 1, 2010
Shares grted
Shares forfeited
Shares vested
Nonvested shares at December 31, 2010
Number of
Shares
286,035
139,780
(41,026)
(55,288)
329,501
Weighted-
Average
Grant Date
Fair Value
$24.49
31.9
19.40
34.64
26.35$
The total fair value of shares vested durg the years ended December 31,2010 and 2009, was $3.3 millon and $3.9 milion,
respectively. At December 31, 2010, Idaho Power had $3.2 million of total unecogned compensation cost related to nonvested
share-based compensation that was expected to vest. These costs are expected to be recogned over a weighted-average period of
1.65 years. Idaho Power uses IDACORP's original issue and/or treasur shares for these awards.
In 2010, a total of 14,982 shares were awarded to directors at a grnt date fair value of$33.03 per share. Directors elected to defer
receipt of8,172 of these shares, which are being held as deferred stock unts with dividend equivalents reinvested in additional stock
units.
Stock Options: No stock options have been granted since 2006. The remaing 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,
2010, all compensation costs related to stock options has been recogned. Idaho Power uses IDACORP's original issue and/or
treasury shares to satisfy exercised options. The followig table presents inormation about options vested and exercised (in thousands
of dollars):
Fair value of options vested
Intrnsic value of options exercised
Cash received from exercises
Tax benefits realized from exercises
2010
$ 96
1,475
5,394
577
2009
$ 208
204
591
80
I FERC FORM NO.1 (ED. 12-88)Page 123.17
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Idaho Power's stock option tranactions are summarized below:
Weighted
Weighted-Average Aggregate
Number Average Remaining Intrinsic
of Exercise Contractual Value
Shares Price Term (OOOs)
Outstanding at December 31, 2009 413,964 $33.31 2.96 $862
Exercised (182,572)27.78
Expired (28,758)35.01
Outstanding at December 31, 2010 202,634 $38.05 1.3 $314
Vested and exercisable at December 31, 2010 202,634 $38.05 1.13 $314
Compensation Expense: The followig table shows the compenation cost recogned in income and the tax benefits resultig from
these plan for those costs associated with Idao Power's employees (in thousands of dollars):
Compensation cost
Income ta benefit
2010
$ 3,489
$ 1,364
2009
$ 3,986
$ 1,587
No equity compensation costs have been capitalized.
8. COMMITMENTS:
Purchase Obligations
At December 31, 2010, Idaho Power had the followig long-term commtments relatig to purchases of energy, capacity, transmission
rights, and fuel:
20ll 2012 2013 2014 2015 Thereafter
(thousands of dollars)
Cogenertion and power production $237,339 $156,696 $204,437 $217,247 $247,371 $4,681,321
Power and transmission rights 35,900 11,594 5,017 3,800 3,726 7,559
Fuel 79,602 68,047 68,365 68,311 22,113 100,172
As of December 31,2010, Idao Power had signed agreements to purchase energy from 126 CSPP facilities with contracts raging
from one to 35 years. Ninety-one of these facilities, with a combined nameplate capacity of 491 MW, were on-lie at the end of201O;
the other 35 facilities under contract, with a combined nameplate capacity of 697 MW, are projected to come on-lie by year end 20 14.
The majority of the new facilties will be wind resources which will generate on an intermttent basis. Dug 2010, Idaho Power
purchased 910,429 megawatt-hours (MWh) from these projects at a cost of$55 millon, resulting in a blended price of$60.38 per
MW and 970,419 MWh at a cost of$59 millon in 2009.
In addition, Idao Power has the followig long-term commtments for lease gurantees, equipment, maintenance and servces, and
industr related fees.
I FERC FORM NO.1 (ED. 12-88)Page 123.18
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(1) 2S An Original (Mo, Da, Yr)
Idaho Power Company (2) A Resubmission 04/15/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
2011 2012 2013 2014 2015 Thereafter
(thousands of dollars)
Operating leaes $3,509 $2,139 $2,047 $1,988 $2,029 $15,740
Equipment, maintenance, and serce
agreeents 53,735 15,724 10,356 6,291 6,083 6,465
FERC and other industr-related fees 8,514 7,575 7,527 5,222 5,1l4 25,647
Idaho Power's expene for operatig leases was approximately $3.3 millon in 2010 and $3.4 millon in 2009.
Guarantees
Idaho Power has agreed to guarantee the performance of reclamation activities and obligations at BCC, of which IERCo own a
one-thd interest. Ths guantee, which is renewed each December, was $63 million at December 31, 2010. BCC has a reclamation
trst fud set aside specifcally for the purse of paying these reclamation costs. BCC continually assesses the adequacy of the
reclamation trt fud and its estiate of futue reclamation costs. To ensure that the reclamation trst fud maintain adequate
reserves, BC.c has the ability to add a per-ton surcharge to coal sales. In 2010, BCC began applyig a nomil surcharge to coal sales
in order to maintain adequate reserves in the reclamation trst fud. Because of the existence of the fud and the ability to apply a
per-ton surcharge, the estimated fair value of ths gurantee is miaL.
Idaho Power enter into fiancial agreements and power purchase and sale agreements that include indemnfication provisions relatig
to varous form of claims or liabilties that may arse from the transactions contemplated by these agreements. Generally, a maximum
obligation is not explicitly stated in the indemnfication provisions and, therefore, the overall maximum amount of the obligation under
such indemnfications canot be reasonably estiated. Idao Power periodically evahiates the likelihood of incurrg costs under such
indemnties based on their historical experience and the evaluation of the specific indemnties. As of December 31, 20 i 0, management
believes the likelihood is remote that Idaho Power would be required to perform under such indemnfication provisions or otherwse
incur any signficant losses with respect to such indemnfication obligations. Idaho Power has not recorded any liability on their
respective consolidated balance sheets with respect to these indemnfication obligations.
9. CONTINGENCIES:
Legal Proceedings
Western Energy Proceedngs at the FERC:
In this report, the term "western energy situation" is used to refer to the Californa energy crisis that occured durg 2000 and 2001,
and the energy shortges, high prices, and blackouts in the western United States. High prices for electrcity in Californa and in
western wholesale markets durg 2000 and 2001 caused numerous purchasers of electrcity in those markets to intiate proceedings
seekig refuds or other forms of relief and the FERC to intiate its own investigations. Some of these proceedings (referred to in ths
report as the western energy proceedings) remain pendig before the FERC or on appeal to the United States Cour of Appeals for the
Ninth Circuit (Ninth Circuit).
There are more than 200 petitions pending in the Ninth Circuit for review of numerous FERC orders regarding the western energy
sitution. Decisions in these appeals may have implications with respect to other pendig cases, includig those to whch Idaho Power
or IE are parties. Idao Power and IE intend to vigorously defend their positions in these proceedings, but are unable to predict the
outcome of these matters. Except as to the matters described below under "Pacific Nortwest Refud," Idaho Power and IE believe
that settlement releases they have obtained that are described below under "Californa Refud" and "Market Manpulation" will restrct
potential claim that might result from the disposition of the pending Ninth Circuit review petitions and that these matters will not have
a material adverse effect on their consolidated fiancial positions, results of operations, or cash flows.
California Refund: This proceeding origiated with an effort by agencies of the State of California and investor-owned utilities in
IFERC FORM NO.1 (ED. 12-88) Page 123.19
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(1) ~ An Original (Mo, Da, Yr)
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NOTES TO FINANCIAL STATEMENTS (Continued)
Californa to obtain refuds for a portion of the spot market sales from sellers of electrcity into Californa markets from October 2,
2000, though June 20, 2001. The FERC has issued numerous orders establishig price mitigation plans for sales in the Californa
wholesale electrcity market, including the methodology for determng refuds. IE and numerous other partes have petitioned the
Ninth Circuit for review of the FERC's orders on Californa refuds. As additional FERC orders have been issued, fuer petitions
for review have been filed before the Ninth Circuit, which from tie to time has identified discrete cases that can proceed to briefig
and decision while it stayed action on the other consolidated cases.
On May 22, 2006, the FERC approved an Offer of Settlement between and among IE and Idaho Power, the Californa Paries
(consistig of Pacific Gas & Electrc Company, San Diego Gas & Electrc Company, Southern Californa Edison Company, the
Californa Public Utilities Commssion, the Californa Electrcity Oversight Board, the Californa Departent of Water Resources
(CDWR), and the Californa Attorney General) and additional paries that elected to be bound by the settlement. The settlement
disposed of matters encompassed by the Californa refund proceeding, as well as market manipulation claim and investigations
relating to the western energy situation among and between the pares agreeing to be bound by it. Although many market paricipants
agreed to be bound by the settlement, other market partcipants, representing a small miority of potential refund claim, intially
elected not to be bound by the settlement. From tie to time, as the Californa Paries have reached settlements with those other
maket participants, they have elected to opt into the IE-Idaho Power-Californa Pares' settlement. The settlement providedfor
approximately $23.7 million ofIE's and Idaho Power's estimated $36 milion rights to accounts receivable from the Californa
Independent System Operator (Cal ISO) and the California Power Exchange (CalPX) to be assigned to an escrow account for refuds
and for an additional $1.5 millon of accounts receivable to be retained by the CalPX until the conclusion of the litigation. The
additional $1.5 millon of accounts receivable retained by the CalPX is available to fud the claim of non-settlig paries if they
prevail in the remaing litigation of the Californa refud proceedig and the balance in the escrow account is inufcient, after
distrbution to setting paries, to satisfy the claim of the litigants. Any additional amounts owed to non-settling partes would be
fuded by other amounts owed to IE and Idaho Power by the Cal ISO and CalPX, or directly by IE and Idaho Power, and any excess
fuds remaing in the escrow and the amounts retained by the CalPX at the end of the case would be retued to IE and Idaho Power.
The remaing IE and Idaho Power receivables were paid to IE and Idaho Power under the settement.
In an August 2006 decision, the Ninth Circuit ruled that all transactions tht occurred with the CalPX and the Cal ISO markets from
October 2, 2000 to June 21, 2001 were proper subjects of the refud proceeding. In that decision the Ninth Circuit refused to expand
the proceedings into the bilateral market, required the FERC to consider claims that some market paricipants had violated governg
taff obligations at an earlier date than the refud effective date, and expanded the scope of the refud proceeding to include
transactions with the CalPX and Cal ISO markets outside the limted 24-hour spot maket and energy exchange trnsactions. Part of
the decision exposed sellers to increased claim for potential refuds. The Ninth Circuit issued its mandate on April 15,2009, thereby
offcially retug the cases to the FERC for fuer action consistent with the cour's decision.
On November 19,2009, the FERC issued an order to implement the Ninth Circuit's remand. The remand order established a tral-tye
hearg in which partcipants will be permtted to submit information regarding (i) specified tariff violations commtted by any public
utilty seller from January 1, 2000 to October 2,2000 resulting in a transaction that set a market clearig price for the trading period
when the violation occured, and (ii) claims for refuds for multi-day transactions and energy exchange tranactions entered into durg
the refud period (October 2, 2000 to June 2 i, 2001). Numerous paries, including IE and Idaho Power, filed motions to clarfy the
FERC's order and responses to these motions. In response to a solicitation from the FERC, on September 22,2010, IE and Idao
Power, along with a number of other parties, submitted comments to the FERC regarding the scope of the proceedings. Although IE
and Idao Power are unable to predict when or how the FERC will rule on these motions and the later comments, the effect of the
remand order for IE and Idaho Power is confied to the miority of market participants that are not bound by the IE-Idao
Power-Californa Pares' settlement described above. IE and Idaho Power believe the remanded proceedings will not have a material
adverse effect on their consolidated fincial positions, results of operations, or cash flows.
In 2005, the FERC established a framework for sellers wantig to demonstrate tht the generally applicable FERC refud methodology
intedered with the recovery of costs. IE and Idaho Power made such a cost fiing, which was rejected by the FERC. On June 18,
2009, FERC issued an order stating tht it was not ruling on IE's and Idaho Power's request for rehearg of the cost fiing rejection
because their request had been withdrawn in connection with the IE-Idaho Power-Californa Parties' settlement. On July 8, 2009, IE
and Idaho Power sought fuer rehearg at the FERC because their withdrawal pertined only to the paries with whom IE and Idao
Power had settled. On June 18, 2009, in a separate order, the FERC ruled that only net refud recipients were responsible for the costs
associated with cost fiings. Whle most net refud recipients are bound by the settlement, until the Cal ISO completes its refud
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(1) LÇ An Original (Mo, Da, Yr)
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NOTES TO FINANCIAL STATEMENTS (Continued)
calculations it is uncertin whether there are any net refund recipients who are not bound by the settlement. If there are no such
paries, then IE's and Idaho Power's request for rehearg will be moot. On May 18, 2010, the FERC denied rehearig. On June 25,
2010, IE and Idaho Power fied a petition for review of the pertinent FERC orders in the Ninth Circuit. Until the Cal ISO completes its
refud calculations, it is uncertin whether there are any parties who are not bound by the Californa refud settlement that might be
affected by the cost fiing and the review of its rejection. IE and Idaho Power are unable to predict how or when the Cal ISO's refud
calculations wil be completed and how or when the Ninth Circuit might rue, but the direct effect of any such calculations and ruing is
confed to obligations ofIE and Idaho Power to the small miority of claim of market partcipants that are not bound by the
settlement. Accordingly, IE and Idaho Power believe ths matter will not have a material adverse effect on their consolidated fiancial
positions, results of operations, or cash flows.
Market Manipulation: On June 25, 2003, the FERC ordered approximately 50 entities that parcipated in the western wholesale
power markets between Januar 1,2000 and June 20, 2001, includig Idao Power, to show cause why certin trding practices did
not constitute gamg or other forms of proscribed market behavior in concert with another part (parership) in violation of the Cal
ISO and CalPX Tariffs. In 2004, the FERC dismissed the parership show cause proceeding against Idaho Power. Later in 2004, the
FERC approved a settlement of the gamg proceeding without fiding of wrongdoing by Idaho Power.
The orders establishig the scope of the show cause proceedings are the subject of review petitions in the Ninth Circuit. Between
August and late November 2010, at the request of IE and Idaho Power, all 12 partes that fied petitions for review of the FERC's
orders establishig the scope of the show cause proceedings fied to withdrw their petitions solely as they relate to IE and Idao
Power. The Ninth Circuit granted all the motions to withdraw durig September though December 2010, dismissing with prejudice
these review proceedings as they pertain to IE and Idaho Power.
On June 25, 2003, the FERC also issued an order intituting an investigation of anomalous bidding behavior and practices in the
western wholesale markets forthe time period May 1, 2000 though October 1,2000, but the FERC termated its investigations as to
Idaho Power on May 12,2004. Californa governent agencies and Californa investor-owned utilities appealed the FERC's
termnation of ths investigation as to Idaho Power and more than 30 other market parcipants. On August 12,2010, in response to a
request by IE and Idao Power, the Californa governent agencies and Californa investor-owned utilities fied a request to withdraw
their petitions for review solely as they relate to IE and Idaho Power. The Ninth Circuit granted the motion in September 2010
dismissing these review proceedings with prejudice as they pertin to IE and Idao Power.
Pacifc Northwest Refund: On July 25,2001, the FERC issued an order establishig a proceeding separate from the Californa refud
proceeding to determe whether there may have been unjust and uneasonable chages for spot market sales in the Pacific Nortwest
durg the period December 25,2000 though June 20, 2001, because the spot market in the Pacific Nortwest was affected by the
dysfuction in the Californa maket. In 2003, the FERC termated the proceeding and declined to order refuds, but in 2007 the
Ninth Circuit issued an opinon, in Port o/Seattle, Washington v. FERC, remadig to the FERC the orders tht declined to require
refuds. The Ninth Circuit's opinion instrcted the FERC to consider whether evidence of market manpulation would have altered the
agency's conclusions about refuds and directed the FERC to include sales origiating in the Pacific Nortwest to the CDWR in the
scope of proceeding. The Ninth Circuit officially retued the case to the FERC on Apri 16, 2009. On September 4,2009, IE and
Idaho Power joined with a number of other paries in a joint petition for a wrt of certiorar to the U.S. Supreme Cour, which was
denied on Janua 11, 2010.
In several separate filings, the Californa Parties - which no longer include the Californa Electrcity Oversight Board - and the City of
Tacoma, Washigton (Tacoma) and the Port of Seattle, Washigton (Port of Seattle) asked the FERC to reorganize and restrcture the
case in different ways to enable them to pursue claims, as asserted by the Californa Partes, that all spot market sales in the Cal ISO
and CalPX markets and sales to CDWR made in the Pacific Nortwest, and, as asserted by Tacoma and Port of Seattle, other sales in
the Pacific Nortwest, from January 1,2000 through June 20, 2001, should be subject to refud and repriced, because market
manpulation and tariff violations affected spot market prices. Their requests would expand the scope of the refud period in the
Pacific Nortwest proceeding from the December 25,2000 though June 20, 2001 period previously considered by the FERC. On
May 22,2009, the Californa Pares filed a motion with the FERC to sever claims regarding sales originatig in the Pacific Nortwest
to CDWR from the remainder of the Pacific Northwest proceedings and to consolidate their claim regarding these sales with ongoing
proceedings in cases that IE and Idaho Power have settled, as well as with a new complaint fied on May 22, 2009 by the Californa
Attorney General againt paries with whom the Californa Parties have not settled (Brown Complaint). IE and Idaho Power, along
with a number of other partes, filed their opposition to the motion of the Californa Paries. Many other pares also filed responses to
I FERC FORM NO.1 (ED. 12-88)Page 123.21
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(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
the motion of the Californa Pares. Tacoma and the Port of Seattle jointly fied a motion on August 4, 2009 with the FERC in
connection with the Californa refud proceeding, the Lockyer remand pending before the FERC (involvig claim of failure to fie
quaerly traction reports with the FERC, from which IE and Idao Power previously were dismissed), the Brown Complaint, and
the Pacific Nortwest refud remand proceeding. The Tacoma and the Port of Seatte motion asks the FERC to require refuds from
all sellers in the Pacific Nortwest spot markets for the expanded period (January 1,2000 though June 20, 2001). IE and Idao Power
joined with a number of other sellers in the Pacific Nortwest markets durg 2000 and 2001 in opposing the motion of Tacoma and
the Port of Seattle. On April 19,2010, the Californa Paries filed a motion with the FERC renewig the requests contained in their
May 22,2009 motion and on May 3,2010, IE and Idaho Power joined with a number of other pares opposing the renewal request.
On July 21,2010, the Port of Seattle and Tacoma once again fied a motion requestig tht the FERC either sumarly dispose of the
case or set it for hearig, and the Californa Pares, anwerig a pleading in the Brown Complaint, renewed their request for
consolidation. The FERC has not acted on the Ninth Circuit remand or the motions.
IE and Idaho Power intend to vigorously defend their positions in these proceedigs but are unable to predict the outcome of these
matters or estimate the impact these matters may have on their consolidated financial positions, results of operations, or cash flows.
Sierra Club Lawsuit and EPA Notice of Violation - Boardman:
In September 2008, the Sierra Club and four other non-profit corporations filed a complaint againt Portand General Electrc
Company (PGE) in the u.s. Distrct Cour for the Distrct of Oregon alleging opacity permt limt and Clean Ai Act (CAA) violations
at the Boardman coal-fired plant located in Morrow County, Oregon. The complaint sought, in addition to injunctive remedies, civil
penalties of up to $32,500 per day per violation, and reimburement of plaintiffs' costs oflitigation, including reasonable attorneys'
fees. Idaho Power is not a par to ths proceeding but has a 10 percent ownership interest in the Boardman plant. PGE own 65
percent of the plant and is the operator of the plant.
In September 2010, the U.S. Envionmental Protection Agency (EPA) issued a Notice of Violation to PGE, allegig tht PGE has
violated the New Source Pedormance Standads (NSPS) and operatig permt requirements under the CAA, as a result of
modifications made to the plant in 1998 and 2004. The Notice of Violation states the maimum civi penalties the EPA is authoried
to impose under the CAA for violations of the NSPS (which range from $25,000 to $37,500 per day), but does not impose any
penalties, or specify the amount of any proposed penalties with respect to the alleged violations.
Idaho Power continues to monitor the status of these matters but is unable to predict their outcome or what effect these matters may
have on its consolidated fiancial position, results of operations, or cash flows.
Water Rights - Snake River Basin Adjudication:
Idaho Power holds water rights, acquired under applicable state law, for its hydroelectrc projects. In addition, Idao Power holds
water rights for domestic, irgation, commercial, and other necessary puroses related to project lands and other holdings withi the
states ofIdao and Oregon. Idao Power's water rights for power generation are, to varing degrees, subordinated to futue upstream
appropriations for irgation and other authorized consumptive uses.
Over time increased irgation development and other consumptive uses with 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 conflct between the exercise ofIdaho
Power's water rights at certin hydroelectrc projects on the Snake River and upstream consumptive diversions. The Swan Falls
Agrement, signed by Idaho Power and the State ofIdaho on October 25, 1984, resolved the confict and provided a level of protection
for Idao Power's hydropower water rights at specified projects on the Snake River though the establishment of mium stream
flows and an admstrative process governg futue development of water rights that may affect those mium stream flows. In
1987, Congress enacted legislation directig the FERC to issue an order approvig the Swan Falls settlement together with a fiding
that the agreement was neither inconsistent with the term and conditions ofIdaho Power's project licenses, nor the Federal Power Act.
The FERC entered an order implementing the legislation on March 25, 1988.
The Swan Falls Agrement provided that the resolution and recogntion of Idaho Power's water rights together with the State Water
Plan provided a sound comprehensive plan for management of the Snake River watershed. The Swan Falls Agreement also
recogned, however, tht in order to effectively manage the waters of the Snake River basin, a general adjudication to determe the
I FERC FORM NO.1 (ED. 12-88)Page 123.22
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NOTES TO FINANCIAL STATEMENTS (Continued)
natue, extent, and priority of the rights of all water uses in the basin was necessar. Consistent with that recogntion, in 1987 the State
ofIdaho intiated the Snake River Basin Adjudication (SRBA), and pursuant to the commencement order issued by the SRBA cour
that same year, all claimants to water rights with the basin were required to file water right claims in the SRBA. Idaho Power has
filed claim to its water rights and has been actively paricipating in the SRBA since its commencement. Questions concerng the
effect of the Swan Falls Agreement on Idaho Power's water right claim, including the natue and extent of the subordintion ofIdaho
Power's rights to upstream uses, resulted in the fiing oflitigation in the SRBA in 2007 between Idao Power and the State ofIdaho.
Ths litigation was resolved by the Framework Reaffg the Swan Falls Settlement (Framework) signed by Idao Power and the
State ofIdaho on March 25,2009. In that Framework, the pares acknowledged tht the effective management ofIdaho's water
resources remains critical to the public interest of the State ofIdaho by sustaing economic growt, maintaing reasonable electrc
rates, protecting and preservg existing water rights, and protecting water quality and envionmental values. The Framework fuer
provided that the State of Idaho and Idaho Power would cooperate in explorig approaches to resolve issues of mutul concern relatig
to the management ofIdaho's water resources. Idaho Power continues to work with the State ofIdaho and other interested paries on
these issues.
One such issue involves the management of the Eastern Snake Plain Aquifer (ESP A), a large underground aquifer in southeastern
Idaho that is hydrologically connected to the Snake River. House Concurent Resolution No. 28, adopted by the Idaho Legislatue in
2007, directed the Idaho Water Resource Board to pursue the development of a comprehensive magement plan for the ESP A, to
include measures that would enhance aquifer levels, sprigs, and river flows on the easter Snake River plain to the benefit of both
agrcultual development and hydropower generation. In May of 2007, the Idaho Water Resource Board appointed an advisory
commttee, charged with the responsibility of developing a management plan for the ESP A. Idaho Power was a member of tht
commttee. In Januar 2009, the Idaho Water Resources Board, based on the commttee's recommendations, adopted a
Comprehensive Aquifer Management Plan (CAM) for the ESP A. The Idaho Legislatue approved the CAM that same year. Idaho
Power is a member of the CAM Implementation Commttee, and is curently workig with the Board, other staeholders, and the
Legislatue in implementing the provisions of the CAMP management plan.
Idao Power also continues its active paricipation in the SRBA in seekig to ensure tht its water rights are protected and that the
operation of its hydroelectrc projects is not adversely impacted. Whle Idaho Power canot predict the outcome, Idao Power does
not curently anticipate any materially adverse modification of its water rights as a result of the SRBA process.
u.s. Bureau of Reclamation Proceedings:
Idaho Power fied a complaint on October 15, 2007, and an amended complaint on September 30,2008, in the u.S. Distrct Cour of
Federal Claim in Washigton, D.C. againt the U.S. Bureau of Reclamation (USBR). The complaint relates to a 1923 spaceholder
contract right for storage and delivery of water to Idaho Power from American Falls Reseroir, a USBR storage reservoir on the Snake
River. In the complaint, Idaho Power alleges that the USBR breached the contract by the failure to recognze certin seconda
storage rights referenced in the contract and claims daages for the lost generation resulting from the reduced flows downtream of the
Reservoir, and asks for a prospective declaration of the rights and obligations of the paries under the 1923 contract. The USBR
claim that the 1923 contract was abrogated or amended by the 1976 rebuild of American Falls Reservoir and that the seconda
storage provisions of the 1923 contract no longer apply. The water rights for, and the operation of, American Falls Reservoir are also
the subject oflitigation in the SRBA, described above. Idaho Power has been workig with the USBR and Idao interests (including
the State ofIdaho and upstream water users) in an effort to resolve the contested contrct issues tht are common to both the SRBA
and the pending federal case with the USBR. These efforts are focused on a recogntion in state policy and the Idao water plan tht
will promote more effcient operation of the upper Snake River reservoir system to optie the use of Snake River flows for
hydroelectrc generation downstream while recognzing and protectig in-reservoir spaceholder contract rights. In an effort to promote
judicial effciency, the parties agreed to stay the pending federal case and present certain legal issues associated with the 1923 contract
to the cour in the SRBA case, the resolution of which are expected to resolve issues in the pending federal case. These issues were
presented to the SRBA cour though motions for sumar judgment, which were argued in December 2010. However, as the paries
contiue to pursue a negotiated resolution to the 1923 contract issues, they have requested that the SRBA withold any ruling on the
motions pending the outcome of ongoing settlement negotiations. Idaho Power is unable to predict the outcome of ths matter or what
effect it may have on its fiancial position, results of operations, or cash flows.
IFERC FORM NO.1 (ED. 12-88) Page 123.23
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NOTES TO FINANCIAL STATEMENTS (Continued)
Oregon Trail Heights Fire:
On August 25, 2008, a fie ignted beneath an Idaho Power distrbution line in Boise, Idaho. It was faned by high wids and spread
rapidly, resultig in one death the destrction of 10 homes, and damage or alleged fie-related losses to approxiately 30 others.
Followig the investigation, the Boise Fire Departent determed that the fie was lined to a piece ofline hardware on one ofIdaho
Power's distrbution poles and that high winds contrbuted to the fire and its resultat damage. Idaho Power received notices of claim
from a number of the homeowners and their inurers and has reached settlements with most of the individuals or their inrers who
have alleged damages resulting from the fie. Idaho Power is inured up to policy limts against liabilty for claim in excess of its
self-inured retention, and believes ths matter will not have a material adverse effect on its consolidated fiancial position, results of
operations, or cash flows.
Other Legal Proceedings:
From tie to time Idao Power is part to legal claim, actions, and proceedings in addition to those discussed above. Resolution of
any of these matters wil take time and the companies canot predict the outcome of any of these proceedings. The companes
curently believe that resolution of these matters will not have a material adverse effect on Idaho Power's fiancial position, results of
operations, or cash flows.
10. BENEFIT PLANS:
Pension Plans
Idaho Power has a noncontrbutory defied benefit pension plan coverig most employees. The benefits under the plan are based on
years of servce and the employee's fial average eargs. Idao Power's policy is to fud, with an independent corporate trstee, at
least the mium required under the Employee Retirement Income Securty Act of 1974 (ERISA) but not more than the maximum
amount deductible for income tax puroses. In September 2010, Idaho Power contrbuted $60 millon to its defmed benefit pension
plan. The contrbution was in excess of the $6 million mium contrbution required to be made in 2010 for the 2009 plan year.
Idaho Power elected to contrbute more than the mium requiement in order to brig the plan to a more fuded position, to reduce
futue required contrbutions, and to reduce Pension Benefit Guaranty Corporation premium. Idao Power was not required to
contrbute to the plan in 2009 or 2008. The market-related value of assets for the plan is equal to the fair value of the assets. Fair
value is determed by utilizing publicly quoted maket values and independent pricing servces depending on the natue of the asset,
as reported by the trtee/custodian of the plan.
In addition, Idaho Power has a nonqualified, deferred compensation plan for certin senior management employees and directors called
the Senior Management Security Plan (SMSP). At December 31, 20 10 and 2009, approximately $46.2 millon and $40.3 million,
respectively, of life inurance policies and investments in marketable securties, all of which are held by a trtee, were designated to
satisfy the projected benefit obligation of the plan but do not qualify as plan assets in the acturial computation of the fuded status.
The following table sumarzes the changes in benefit obligations and plan assets of these plans:
I FERC FORM NO.1 (ED. 12-88)
Pension Plan SMSP
2010 2009 2010 2009
(thousands of dollars)
$506,744 $464,416 $52,719 $48,393
17,671 16,514 1,541 1,610
29,119 27,865 3,004 2,854
35,909 16,193 5,186 3,156
(19,509)(18,244)(3,324)(3,294)
569,934 506,744 59,126 52,719
313,474 295,324
43,038 36,394
Page 123.24
Change in benefit obligation:
Beneft obligation at Januar 1
Serce cost
Interest cost
Actuaral loss
Benefits paid
Benefit obligation at December 31
Change in plan assets:
Fair value at Januar I
Actal retrn on plan assets
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Employer contrbutions 60,000
Benefits paid (19,509)(18,244)
Fair value at December 3 i 397,003 313,474
Funded status at end of year $(172,931)$(193,270)$(59,126)$(52,719)
Amounts recognized in the statement of
financial position consist of:
Other current liabilities $$$(3,289)$(3,244)
Noncurrent liabilties (1)(172,931)(193,270)(55,837)(49,475)
Net amount recognized $(172,931)(193,270)$(59,126)$(52,719)
Amounts recognized in accumulated other
comprehensive income consist of:
Net loss $161,855 $150,196 $18,840 $14,585
Prior serice cost 1,855 2,505 1,744 1,977
Subtotal 163,710 152,701 20,584 16,562
Less amount recorded as regulatoiy asset (163,710)(152,701)
Net amount recognized in accumulated
other comprehensive income $$$20,584 $16,562
Accumulated beneft obligation $482,448 $425,744 $54,213 $48,563
(I) Noncurrent liabilities are contained in Idao Power's Balance Sheets under and "Oter defered credits."
The followig table shows the components of net periodic benefit cost for these plans:
Pension Plan SMSP
2010 2009 2010 2009
Serce cost $17,671 $16,514 $1,541 $1,610
Interest cost 29,119 27,865 3,004 2,854
Expected retrn on assets (26,463)(23,965)
Amortzation of net loss 7,675 8,857 931 232
Amortization of prior serce cost 650 650 233 659
Net perodic pension cost 28,652 29,921 5,709 5,355
Costs not recognized due to the
efects of regulation (i)(24,104)(28,669)
Net perodic benefit cost
recognized for financial
reporting (2)$4,548 $1,252 $5,709 $5,355
(I) Under IPUC order, income statement recognition of pension plan costs has been defered until costs
are recovered though rates. See Note 3 for informtion on Idao Power's 20 I 0 pension rate filig.
(2) Net perodic benefit costs for the penion plan are recognized for the Oregon jursdiction and
non-regulated subsidiares, and begiing in June 20 I 0, for the Idao and FERC jursdctions.
In 2011, Idaho Power expects to recognze as components of net periodic benefit cost $10.6 millon from amorting amounts recorded
in accumulated other comprehensive income (or as a regulatory asset for the pension plan) as of December 31, 2010, relatig to the
pension and SMSP plans. This amount consists of $8.4 million of amortzation of net loss and $0.7 milion of amortation of prior
service cost for the pension plan, and $1.3 million of amortization of net loss and $0.2 millon of amortzation of prior servce cost for
theSMSP.
IFERC FORM NO.1 (ED. 12-88) Page 123.25
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
The followig table sunarizes the expected futue benefit payments of these plans:
2011 2012 2013 2014
(thousands of dollars)
24,748 $ 26,554 $
3,695 $ 3,869 $
2015 2016-2020
Pension Plan
SMSP
$
$
21,229 $
3,371 $
22,791 $
3,491 $
28,656 $
4,016 $
180,364
21,816
Pension Protection Act: In accordace with the Pension Protection Act of 2006 (PP A), and the relief provisions of the Worker,
Retiree, and Employer Recovery Act of 2008 (WRRA), which was signed into law on December 23, 2008, companes are required to
meet minium fuding levels in order to avoid benefit restrctions. The WRRA also provides for asset smoothg, which allows the
use of asset averaging, including expected retus (subject to certin limtations), for a 24-month period in the determation of the
fudig requirements. Idaho Power has elected to use asset smoothg.
On March 31, 2009, the U.S. Departent of the Treasur (Treasur) provided guidance on the selection of the corporate bond yield
cure for determng plan liabilities and allows companes to choose from a range of months in selectig a yield cure, rather than
requirg the use of prescribed rates. The Treasur's announcement specifically referenced 2009, but also indicated that techncal
guidance wil be fortcomig to address futue years. The revisions in the PP A, WRRA, Treasur guidance, and IRS gudance
resulted in Idaho Power revising the funded status as of Januar 1, 2009, effectively reducing or delayig the required contrbutions
from Idao Power from what would otherwse be required, and what was previously disclosed. At January 1, 2009, Idaho Power's
pension plan was above the mium required fuding levels as revised by the PP A, WRRA, Treasur guidance and IRS guidance,
but below the mium required fuding levels at Janua 1, 2010, and is projected to stay below the mium requied fuding levels
though 2015. As Idaho Power's pension plan was below the mium required funding levels at Januar 1, 20 I 0, futu mium
contrbutions are required. Based on the provisions and methodologies allowed under the PP A, WRRA, Treasur guidance, and IRS
guidance, Idaho Power was not required to contrbute to their pension plan in 2009. Unless Idaho Power elects an alternative
amortization schedule under the new legislation discussed below, mium required contrbutions to the defied benefit penion plan
are estimated to be approximately $3 million in 2011, $46 millon in 2012, $36 millon in 2013, $32 millon in 2014, and $31 million
in 2015. Idaho Power may elect to make contrbutions earlier tha the required dates.
The IRS and Treasur have issued final reguations effective October 15,2009 tht apply to plan year beging on or after Januar 1,
2010. These regulations reflect provisions added by the PPA, as amended by the WRRA. These regulations affect sponsors,
admstrators, parcipants, and beneficiares of single employer defmed benefit pension plan. The regulations provide guidace
regarding the determation of the value of plan assets and benefit liabilities for puroses of the fuding requiements, regardig the
use of certin fuding balances maintained for those plan, and regarding benefit restrctions for certin underfded defied benefit
pension plans. These fial regulations did not materially change existing estiates relating to pension plan contrbutions.
In June 2010, the Preservation of Access to Care for Medicare Beneficiaries and Pension Relief Act of2010 was signed into law,
which permts employers to choose between two alternative fuding options for defied benefit pension plans for any two plan years
between 2008 and 201 I, either (i) amortizing the fuding shortfall for the applicable years over 15 years or (ü) payig interest only on
the applicable plan years' fuding shortfall for two plan year followed by amortation of the actul shortfall for 7 years. If an
alternate fuding option is elected for plan year 2011, the only remaing plan year for which the company could mae an election, it
would reduce near-term required contrbutions to the plan by spreading them over a longer time period. The legislation does not
eliate Idaho Power's obligation to fully fud the pension plan. In addition, the legislation outlines penalties in the form of
increased pension contrbutions from an employer tht elects one of the fuding relief options at the same time that employer (or
entities with its ERISA-controlled group) awards "excess employee compensation" (generally compensation over $1 millon per year
paid to an employee), grants "excessive" dividends, or effects specified stock redemptions. Idaho Power will evaluate the legislation
and its alternatives fuer prior to electig an alternative, if any. See Note 3 for a discussion of Idaho Power's recovery of pension
plan contrbutions though the ratemakg process.
Additional legislative or regulatory measures, as well as fluctuations in fiancial market conditions, may impact fuding requiements.
Idaho Power will continue to monitor the legislative and regulatory envionments for additional changes, evaluatig them for their
I FERC FORM NO.1 (ED. 12-88)Page 123.26
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Daf Yr)
Idaho Power Company (2)A Resubmission 04/15/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
potential impact on funding requiements and strategies.
Postretirement Benefits
Idaho Power maintain a defined benefit postretirement benefit plan (consistig of health care and death benefits) that covers all
employees who were enrolled in the active group plan at the tie of retirement as well as their spouses and qualifyg dependents.
Retirees hied on or after January 1, 1999 have access to the stadard medical option at full cost, with no contrbution by Idaho Power.
Benefits for employees who retire after December 31, 2002, are limted to a fied amount, which will limt the growt of Idaho
Power's future obligations under ths plan.
2010
The followig table summarzes the changes in benefit obligation and plan assets (in thousands of dollars):
2009
Change in accumulated benefit obligation:
Benefit obligation at January 1
Servce cost
Interest cost
Actuaral loss
Benefits paid( 1 )
Plan amendments
Benefit obligation at December 31
$62,647 $
1,276
3,578
3,291
(3,373)
629
68,048
59,648
1,221
3,565
2,128
(3,915)
62,647
Change in plan assets:
Fair value of plan assets at January 1
Actul retu on plan assets
Employer contrbutions
Benefits paid(l)
Fair value of plan assets at December 31
Funded status at end of year (included in noncurent liabilities)(2)
30,892 25,283
3,381 5,609
2,276 3,915
(3,373)(3,915)
33,176 30,892
$(34,872)$(31,755)
(1) Benefits paid are net of $2,791 and $2,731 of plan paricipant contrbution, and $415 and $385 of Medcare Par D subsidy
receipts for 2010 and 2009, respectively.
(2) Noncurt liabilties are contained in "Other defered credits."
Amounts recogned in accumulated other comprehensive income consist of (in thousands of dollars):
Net loss
Prior servce credit
Transition obligation
Subtotal
Less amount recognzed in regulatory assets
Less amount included in deferred ta assets
Net amount recogned in accumulated other comprehensive income
2010
$ 15,963 $
(426)
4,080
19,617
(19,032)
(585)$ $
2009
14,112
(1,537)
6,120
18,695
(15,235)
(3,460)
The net periodic postretirement benefit cost was as follows (in thousands of dollars):
I FERC FORM NO.1 (ED. 12-88)Page 123.27
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da. Yr)
Idaho Power Company (2)A Resubmission 04/15/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
2010 2009
Servce cost $1,276 $1,221
Interest cost 3,578 3,565
Expected retu on plan assets (2,503)(2,146)
Amortization of net loss 562 842
Amortization of prior servce cost (482)(535)
Amortization of unecogned tranition obligation 2,040 2,040
Net periodic postretirement benefit cost $4,471 $4,987
In 2011, Idaho Power expects to recogne as components of net periodic benefit cost $2.3 millon from amorting amounts recorded
in accumulated other comprehensive income as of December 31, 2010 relatig to the postretiement benefit plan. This amount consists
of ($0.4) millon of prior servce cost, $0.7 million of net loss, and $2.0 millon of transition obligation.
Medicare Act: The Medicare Prescription Drug, Improvement and Moderation Act of2003 was signed into law in December
2003 and established a prescription drg benefit, as well as a federal subsidy to sponsors of retiee health care benefit plan that
provide a prescription drg benefit that is at least actuarally equivalent to Medicare's prescription drg coverage.
The Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act were enacted in March 20 i o.
One provision of ths legislation elimates the deductibilty of employer health care costs for retiee prescription drg expenses that
are covered by federal subsidy payments equivalent to Medicare Part D. Whle ths provision is not effective unti 2013, relevant
income tax accountig guidance requies recogntion of the futue effects of new law in the period of enactment. Due to the regulatory
treatment of postretiement benefit costs, the increase in certin postretiement costs relating to the legislation is deferred as a
regulatory asset. See Note 2 for the tax impacts recorded as a result of ths legislation.
The followig table summarizes the expected futue benefit payments of the postretirement benefit plan and expected Medicare Part D
subsidy receipts (in thousands of dollars):
2011 2012 2013 2014 2015 2016-2020
Expected benefit payments $
Expected Medicare Par D
subsidy receipts $
4,300 $ 4,400 $ 4,600 $ 4,800 $ 4,900 $ 25,600
500 $ 500 $ 600 $ 600 $ 700 $ 4,400
The assumed health care cost trend rate used to measure the expected cost of health benefits covered by the plan was 7.5 percent and
8.0 percent in 2010 and 2009, respectively. The assumed health care cost trend rate for 2010 is assumed to decrease grdually to 4.9
percent by 2070. The assumed dental cost trend rate used to measure the expected cost of dental benefits covered by the plan was 5
percent in both 2010 and 2009. A one percentage point change in the assumed health care cost trend rate would have the followig
effects at December 31,2010 (in thousands of dollars):
One-Percentage-Point
Increase Decrease
Effect on total of cost components
Effect on accumulated postretirement benefit obligation
$
$
309
2,842
$
$
(233)
(2,233)
IFERCFORM NO.1 (ED. 12-88) Page 123.28
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) 2Ç An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Plan Assumptions:
The followig table sets fort the weighted-average assumptions used at the end of each year to determe benefit obligations for all
Idao Power-sponsored pension and postretirement benefits plans:
Pension Postretiement
Benefits Benefits
2010 2009 2010 2009
Discount rllte 5.4%5.9%5.4%5.9%
Rate of compensation increase 4.5%4.5%
Medical trend rate 7.5%8.0%
Dental trend rate 5.0%5.0%
Measurement date 12/31/10 12/31/09 12/31/10 12/31/09
The followig table sets fort the weighted-average assumptions used to determe net periodic benefit cost for all Idaho
Power-sponsored pension and postretirement benefit plan:
Discount rate
Expected long-term rate of retu on assets
Rate of compensation increase
Medical trend rate
Dental trend rate
Plan Assets:
Idaho Power's pension plan and postrtiement benefit plan assets at December 31, by asset category, are as follows:
Pension Postretirement
Plan Benefits
Asset Category 2010 2009 2010 2009
Cash and cash equivalents $16,837 $4,512 $$
Short-term bonds 30,241 30,774
Core bonds 43,156 41,165
Equity securties 230,666 184,562
Real estate 22,069 20,783
Private market investments 29,932 20,202
Commodities 24,102 11,476
OtherCl)33,176 30,892
Total $397,003 $313,474 $33,176 $30,892
(1) The postretrement beefits assets are priarly life insurance contrcts.
IFERC FORM NO.1 (ED. 12-88)Page 123.29
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Pension Asset Alocation Policy: The target allocation and actual allocations at December 31, 2010 for the portfolio by asset class
are as follows:
Target
Alocation
Actual
Alocation
December 31, 2010
Large-cap growt stocks
Large-cap value stocks
Mid-cap growt stocks
Mid-cap value stocks
Small-cap growt stocks
Small-cap value stocks
Micro-cap stocks
Interntional growt stocks
International value stocks
Interntional small-cap stocks
Emerging markets stocks
Commodities
Private market investments
Short-term bonds
Core bonds
Cash and cash equivalents
Real estate
Total
6%
6%
4%
4%
4%
4%
4%
6%
6%
5%
5%
6%
8%
10%
14%
2%
6%
100%
7.5%
7.2%
4.2%
3.9%
3.9%
5.0%
4.4%
6.0%
5.9%
5.0%
5.1%
6.1%
7.5%
7.6%
10.9%
4.2%
5.6%
100%
Assets are rebalanced as necessar to keep the portfolio close to target allocations.
The plan's principal investment objective is to maximze total retu (defined as the sum of realized interest and dividend income and
realized and unealized gain or loss in market price) consistent with prudent parameters of risk and the liability profile of the portfolio.
Emphasis is placed on preservation and growt of capital along with adequacy of cash flow suffcient to fud curent and futue
payments to pensioners.
The thee major goals in Idao Power's asset allocation process are, as follows:
· determe if the investments have the potential to earn the rate of retu assumed in the actuaral liability calculations;
· match the cash flow needs of the plan. Idaho Power sets bond allocations suffcient to cover at least five years of benefit
payments and cash allocations suffcient to cover the curent year benefit payments. Idaho Power then utilizes growth
intrents (equities, real estate, ventue capital) to fund the longer-term liabilities of the plan; and
· maintain a prudent risk profile consistent with ERISA fiduciary stadads.
Allowable plan investments include stocks and stock fuds, investment-grade bonds and bond fuds, core real estate fuds, private
equity fuds, and cash and cash equivalents. With the exception of real estate holdings and private equity, investments must be readily
marketable so that an entie holdig can be disposed of quickly with only a mior effect upon market price.
Rate-of-retu projections for plan assets are based on historical risk/return relationships among asset classes. The priar measure is
the historical risk premium each asset class has delivered versus the retu on 10-year u.S. Treasur Notes. This historical risk
premium is then added to the curent yield on 10-year u.S. Treasur Notes, and the result provides a reasonable prediction of futue
IFERC FORM NO.1 (ED. 12-88) Page 123.30
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) 2Ç An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
investment pedormance. Additional analysis is pedormed to measure the expected range of retu, as well as worst-case and
best-case scenarios. Based on the curent low interest rate environment, curent rate-of-retu expectations are lower th the nomial
retu generated over the past 20 years when interest rates were generally much higher.
Idaho Power's asset modelig process also utilizes historical market retus to measure the portfolio's exposure to a "worst-case"
market scenaro, to determe how much pedormance could vary from the expected "average" pedormance over varous time periods.
This "worst-case" modeling, in addition to cash flow matchig and diversification by asset class and investment style, provides the
basis for maging the risk associated with investing portolio assets.
Fair Value of Plan Assets: Idaho Power classifies its pension plan and postretirement benefit plan investments using the followig
hierarchy:
. Level 1, which refers to securties valued using quoted prices from active makets for identical assets;
. Level 2, which refers to securties not traded on an active market but for which observable maket inputs are readily available;
and
. Level 3, which refers to securties valued based on signficant unobservable inputs.
If the inputs used to measure the securties fall with different levels of the hierarchy, the categorization is based on the lowest level
input (Level 3 being the lowest) that is signficant to the fair value measurement of the securty. The followig table sets fort by level
withn the fair value hierarchy a sunry of the plans' investments measured at fair value on a recurrg basis at December 31,2010:
Quoted Prices in
Active Markets
for Identical
Assets (Levell)
Significant
Unobservable
Inputs
(Level 3)
Signficant
Other
Observable
Inputs (Level 2)Total
Assets at December 31, 2010
Pension assets:
Cash and cash equivalents $16,837 $- $-$
Short-term bonds 30,241
Core bonds 43,156
Equity securities 164,290 66,376
Real estate 22,069
Private market investments 29,932
Commodities 3,406 20,696
Total pension assets $257,930 $87,072 $52,001 $
Postretirement assets $-$33,176 $-$
Assets at December 31, 2009
Pension assets:
Cash and cash equivalents $4,512 $- $-$
Short-term bonds 30,774
Core bonds 41,165
Equity securties 126,049 58,513
Real estate 20,783
Private maket investments 20,202
Commodities 11,476
Total pension assets $202,500 $69,989 $40,985 $
Postretirement assets $-$30,892 $-$
I FERC FORM NO.1 (ED. 12-88)Page 123.31
16,837
30,241
43,156
230,666
22,069
29,932
24,102
397,003
33,176
4,512
30,774
41,165
184,562
20,783
20,202
11,476
313,474
30,892
Name of Respondent This Report is:Date of Report Year/Period of Report
( 1 ) 2S An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
The followig table presents a reconcilation of the beging and ending balances of the fair value measurements using signficant
unobservable inputs (Level 3):
Private Real
Equity Estate Total
Beging balance - Janua 1, 2009 $17,863 $37,418 $55,281
Realized losses (1,040)(671)(1,711)
Unrealized gain (losses)3,103 (14,912)(11,809)
Purchases, issuances, and settlements, net 276 (1,052)(776)
Ending balance - December 31, 2009 20,202 20,783 40,985
Realized losses (47)(47)
Unrealized gains 1,284 2,211 3,495
Purchases, issuances, and settlements, net 8,446 (878)7,568
Ending balance - December 31, 2010 $29,932 $22,069 $52,001
Employee Savigs Plan
Idaho Power has an Employee Savigs Plan that complies with Section 401 (k) of the Internal Revenue Code and covers substatially
all employees. Idaho Power matches specified percentages of employee contrbutions to the plan. Matchig anual contrbutions were
$5 million in each of2010 and 2009.
Post-employment Benefits
Idaho Power provides certin benefits to former or inactive employees, their beneficiares, and covered dependents after employment
but before retiement. These benefits include salary contiuation, health care and life inurance for those employees found to be
disabled under Idaho Power's disability plans, and health care for survig 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, 2010 and 2009 are $4.5 millon and $5.2 million, respectively.
11. PROPERTY, PLANT AND EQUIPMENT AND JOINTLY-OWNED PROJECTS:
The followig table presents the major classifications ofIdao Power's utility plant in servce, anual depreciation provisions as a
percent of average depreciable balance, and accumulated provision for depreciation for the years 2010 and 2009 (in thousands of
dollars):
2010 2009
Balance AvgRate Balance AvgRate
Production $1,792,305 2.23%$1,758,813 2.23%
Transmission 855,202 2.03 768,260 2.07
Distrbution 1,377,239 3.13 1,331,065 2.89
General and Oter 307,308 7.41 302,040 7.88
Total in servce 4,332,054 2.84%4,160,178 2.81%
Accumulated provision for depreciation (1,771,655)(1,713,943)
In servce - net $2,560,399 $2,446,235
I FERC FORM NO.1 (ED. 12-88)Page 123.32
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
In 20 I 0, Idaho Power sold $ i 9 million of transmission-related assets to PacifiCorp at book value.
Idaho Power has interests in thee jointly-owned generating facilities included in the table above. Under the joint operatig
agreements, each partcipating utility is responsible for fiancing its share of constrction, 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 Idao Power's paricipation, were as follows at December 31, 2010 (in thousands of dollars):
Utilty Construction Accumulated
Plant In Work in Provision for Ownership
Name of Plant Location Service Progress Depreciation %MW(I)
Jim Bridger Units 1-4 Rock Sprigs, WY $530,617 $8,472 $273,823 33 771
Boardman Boardman OR 72,176 1,267 52,364 10 64
Valmy Units i and 2 Winemucca, NV 334,821 4,932 201,372 50 284
(i) Idaho Power's share of nameplate capacity
IERCo, Idaho Power's wholly-owned subsidiary, is a joint ventuer in Bridger Coal Company. Idaho Power's coal purchases from the
joint ventue were $76 millon and $66 million in 2010 and 2009, respectively.
Idaho Power has contrcts to purchase the energy from four PUR A qualified facilities that are 50 percent owned by Ida-West. Idaho
Power's power purchases from these facilities were $8 milion and $9 millon in 2010 and 2009, respectively.
12. ASSET RETIRMENT OBLIGATIONS (ARO):
The guidance relating to accounting for AROs requires that legal obligations associated with the retiement of propert, plant and
equipment be recognzed as a liability at fair value when incured and when a reasonable estimate of the fair value of the liability can
be made. Under the guidance, when a liability is intially recorded, the entity increases the carrg amount of the related long-lived
asset to reflect the futue 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 recogned. As a rate-regulated entity, Idao Power records regulatory assets or liabilities
instead of accretion, depreciation and gain or losses. The reguatory assets recorded under ths order do not eam a retu on
investment.
Idaho Power's recorded AROs relate to the removal of polychloriated biphenyls-contaated equipment at its distrbution facilities
and the reclamation and removal costs at its jointly owned coal-fied generation facilities. In 2010, changes in estiates at the
coal-fied generation facilities resulted in a net increase of$0.9 million in the recorded ARO.
Idaho Power also has AROs associated with its transmission system and hydroelectrc facilities; however, due to the indetermate
removal date, the fair value of the associated liabilities curently cannot be estiated and no amounts are recognzed in the .
consolidated ficial statements. The regulated operations ofIdaho Power also collect removal costs in rates for certin assets tht do
not have associated AROs.
The followig table presents the changes in the carg amount of AROs (in thousands of dollars):
2010 2009
$16,240 $12,415
819 697
929 3,684
139
(1,036)(695)
Page 123.33
Balance at begig of year
Accretion expense
Revisions in estiated cash flows
Liability incured
Liability settled
I FERC FORM NO.1 (ED. 12-88)
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) lÇ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Balance at end of year $16,952 $16,240
13. INVESTMENTS:
The followig table sunarzes Idaho Power's investments as of December 31 (in thousands of dollar):
2010 2009
90,495 $83,969
24,561 18,842
4,746 5,217
3 267
119,805 $108,295
Idao Power investments:
Equity method investment $
Available-for-sale equity securities
Executive deferred compensation plan
Other investments
Total Idaho Power investments $
Equity Method Investments
Idaho Power, through its subsidiary IERCo, is a 33 percent owner of Bridger Coal Company, which supplies coal to the Jim Bridger
generatig plant. The followig table presents Idaho Power's eargs (loss) of unconsolidated equity-method investments (in
thousands of dollars):
Bridger Coal Company - lERCO $
2010
11,281 $
2009
8,256
Investments in Debt and Equity Securities
Investments in debt and equity securties classified as available-for-sale securties are reported at fair value, using either specific
identification or average cost to determe the cost for computing gains or losses. Any unealized gain or losses on available-for-sale
securties are included in other comprehensive income. The followig table sunaries investments in debt and equity securties (in
thousands of dollars):
2010 2009
Gross Gross Gross Gross
Unrealied Unrealed Fair Unrealied Unrealied Fair
Gain Loss Value Gain Loss Value
Available- for-sale
securties $4,876 $- $24,561 $2,989 $- $18,842
The followig table sunaries sales of available-for-sale securties (in thousands of dollars):
2010 2009
Proceeds from sales
Gross realized gains from sales
Gross realized losses from sales
$$9,006
11
35
These investments are evaluated as of the end of each reportg period to determe whether they have experienced a decline in market
I FERC FORM NO.1 (ED. 12-88) Page 123.34 I
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
value tht is other-than-temporary. At December 31,2010 and 2009, Idaho Power did not have any securties that were in a loss
position.
14. DERN ATIV FINANCIAL INSTRUMENTS
Commodity Price Risk
Idao Power is exposed to market risk relating to electrcity, natual gas, and other fuel commodity prices, all of which are heavily
inuenced by supply and demand. Market risk may also be influenced by market participants' nonpedormance of their contractul
obligations and commtments, which affects the supply of or demand for the commodity. Idaho Power uses derivative intrents,
such as physical and fiancial forward contracts, for both electricity and fuel to manage the risks relatig to these commodity price
exposures. The objective ofIdaho Power's energy purchase and sale activity is to meet the demand of retail electrc customers,
maintain appropriate physical reserves to ensure reliability, and make economic use of temporary surluses that may develop.
All commodity-related derivative intrents not meeting the normal purchases and normal sales exception to derivative accounting
are recorded at fair value on the balance sheet. With the exception of forward contracts for the purchase of natual gas for use at Idaho
Power's natural gas generation facilities, Idao Power's physical forward contracts, including renewable energy certficates, qualify for
the normal purchases and normal sales exception. Because ofIdaho Power's power cost adjustment mechanisms, unealized gain and
losses associated with the changes in fair value of these derivative intrents are recorded as reguatory assets or liabilities.
Derivative Commodity Contracts
As of December 3 i, 2010, Idao Power had the followig outstanding derivative commodity forward contracts that were entered into
for the purpose of economically hedgig forecasted purchases and sales:
Commodity
Electrcity purchases
Electrcity sales
Natul gas purchases
Diesel
Number of Units
347,400 MWh
338,200 MW
647,900 MMtu
1,061,969 gallons
The followig table presents the fair values and locations of derivative instrents recorded in the balance sheet at December 31, 2010
and 2009 (in thousands of dollars):
Asset Derivatives Liabilty Derivatives
Balance Sheet Fair Balance Sheet Fair
Location Value Location Value
December 31,2010
Curent:
Financial swaps Other curent assets $930 Other curent assets $356
Financial swaps Other curent liabilities 2,440 Other curent liabilities 4,172
Forward contracts Oter curent liabilities 508
Long-term:
Financial swaps Other liabilities 100 Other liabilities 138
Total $3,470 $5,174
December 31,2009
Curent:
Financial swaps Other current assets $2,931 Other curent assets $2,087
I FERC FORM NO.1 (ED. 12-88)Page 123.35
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Fincial swaps Other curent liabilities 9 Other curent liabilities 610
Forward contracts Other current liabilities 354 Other curent liabilities
Long-term:
Financial swaps Other assets 442 Other assets 229
Total $3,736 $2,926
The following table presents gains and losses on derivatives for the years ended December 31,2010 and 2009 (in thousands of
dollars):
Commodity derivatives
Year ended December 31, 2010:
Financial swaps
Financial swaps
Financial swaps
Forward contracts
Year ended December 31, 2009:
Financial swaps
Financiál swaps
Financial swaps
Forward contracts
Location of Gain(Loss)
Recognied in Income on
Derivative
Amount of Gai(Loss)
Recognied in Income on
Derivative(l)
Off-system sales
Purchased power
Fuel expense
Fuel expense
$4,499
(12,240)
(101)
(721)
Off-system sales
Purchased power
Fuel expense
Fuel expense
$3,245
(3,966)
(5,794)
(986)
(l)Excludes changes in fa value of dervatives, which are recorded on the balace shee as regulatory assets or liabilties.
Settlement gain and losses on electrcity swap contrcts are recorded on the income statement in off-system sales or purchased power
depnding on the forecasted position being economically hedged by the derivative contract. Settlement gain and losses on both
fiancial and physical contracts for natual gas are reflected in fuel expense. Settlement gains and losses on diesel derivatives, which
are recorded in fuel inventory on the balance sheet, were imaterial for all thee years. See Note 15 for additional inormtion
concerng the determation of the fair value of Idaho Power's assets and liabilities from price risk maagement activities.
Credit Risk
At December 31, 2010, Idaho Power did not have material credit exposure from fiancial intrents, includig derivatives. Idaho
Power monitors credit risk exposure thugh reviews of counterpar credit quality, corporate-wide counterpar credit exposure, and
corporate-wide counterpar concentration levels. Idaho Power manages these risks by establishig appropriate credit and
concentration lits on transactions with counterpartes and requirg contractul guantees, cash deposits, or letters of credit from
counterparties or their affliates, as deemed necessary. The majority ofIdaho Power's contracts are under the form of the Western
Systems Power Pool agreement that provides for adequate assurances if a counterpart has debt that is downgrded to below
investment grade by at least one rating agency. Idaho Power also requires Nort American Energy Standards Board contrcts as
necessar for physical gas tranactions, and International Swaps and Derivatives Association, Inc. contracts as needed for fiancial
tranactions.
Credit-Contigent Features
Certin ofIdaho Power's derivative intrents contain provisions that require Idao Power's unecured debt to maintain an
investment grade credit rating from Moody's Investor Servces and Standard & Poor's Ratings Servces. IfIdao Power's unecured
debt were to fall below investment grde, it would be in violation of these provisions, and the counterparties to the derivative
intrents could request imediate payment or demand imediate and ongoing full overnght collateralization on derivative
intrents in net liability positions. The aggregate fair value of all derivative intrents with credit-risk-related contigent featues
IFERC FORM NO.1 (ED. 12-88) Page 123.36
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2) A Resubmission 04/15/2011 2010/04
NOTES TO FINANCIAL STATEMENTS (Continued)
that are in a liability position on December 31,2010, is $5.2 million. Idaho Power has posted $4.6 million of collateral related to ths
amount. If the credit-risk-related contigent featues underlyig these agreements were trggered on December 31, 2010, Idaho Power
could have been required to post $0.5 million of cash collateral to its counterparties.
15. FAI VALUE MEASURMENTS:
Idao Power has categorized their financial intrments into a thee-level fair value hierarchy, based on the priority of the inputs to the
valuation technque. 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 fiancial intrments fall
within different levels of the hierarchy, the categoriation is based on the lowest level input that is signficant to the fair value
measurement of the instrment.
Financial assets and liabilties recorded on the consolidated balance sheets are categoried based on the inputs to the valuation
technques as follows:
. Levell: Financial assets and liabilities whose values are based on undjusted quoted prices for identical assets or liabilties
in an active market that Idao Power has the ability to access.
· Level 2: Financial assets and liabilities whose values are based on the followig:
a) Quoted prices for simlar assets or liabilities in active markets;
b) Quoted prices for identical or simlar assets or liabilties in non-active markets;
c) Pricing models whose inputs are observable for substantially the full term of the asset or liabilty; and
d) Pricing models whose inputs are derived pricipally from or corroborated by observable market data though
correlation or other means for substatially the full term of the asset or liability.
Idaho Power Level 2 inputs are based on quoted market prices adjusted for location using corroborated, observable market
data.
. Level 3: Financial assets and liabilities whose values are based on prices or valuation technques that require inputs that are
both unobservable and signficant to the overall fair value measurement. These inputs reflect mangement'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. Electrcity swaps are valued on
the Intercontiental Exchange with quoted prices in an active market. Natual gas and diesel derivative valuations are pedormed using
New York Mercantile Exchange (NYEX) pricing, adjusted for basis location, which are also quoted under NYEX. Trading
securities consist of employee-directed investments held in a Rabbi Trut and are related to an executive deferred compensation plan.
Available-for-sale securties are related to the SMSP and are held in a Rabbi Trust and are actively traded money market and equity
fuds with quoted prices in active markets.
The table below presents inormation about Idaho Power's assets and liabilities measured at fair value on a recurg basis as of
December 31, 2010 and 2009 (in thousands of dollars). Idaho Power's assessment of the signficance ofa paricular input to the fair
value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement with the fair
value hierarchy. There were no tranfers between levels for the periods presented. See Note 10 for fair value informtion regarding
Idao Power's benefit plans.
Quoted Pnces in
Active Markets
for Identical
Assets (Levell)
Signifcant
Other
Observable
Inputs (Level 2)
Signifcant
Unobservable
Inputs
(Level 3)Total
2010
Assets:Dervatives $
Money market funds
Trading secunties
I FERC FORM NO.1 (ED. 12-88)
573 $ - $
151,173
4,746
- $573
151,173
4,746
Page 123.37
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Available-for-sale equity securities
Liabilties:
Dervatives
24,561 24,561
508 508
2009
Assets:Dervatives $
Money market funds
Trading securities
Availaòle-for-sale equity securities
Liabilties:
Dervatives
1,056 $354 $-$1,410
19,364 19,364
5,217 5,217
18,842 18,842
601 601
The followig tables present the carrg value and estimated fair value of fmancial instrents that are not reported at fair value,
using available market inormation and appropriate valuation methodologies. The use of different market assumptions and/or
estimation methodologies may have a material effect on the estiated 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 carng
value as these are a reasonable estiate of their fair value. The estimated fair values for notes receivable and long-term debt are based
upon quoted maket prices of the same or simlar issues or discounted cash flow analyses as appropriate.
December 31, 2010 December 31, 2009
Carryg Estimated Carryg Estimated
Amount Fair Value Amount Fair Value
(thousands of dollars)
Liabilties:
Long-ter debt $ 1,612,790 $ 1,621,425 $1,413,854 $ 1,398,681
16. RELATED PARTY TRSACTIONS:
IDACORP
Idaho Power pedorm corporate fuctions such as fiancial, legal, and management services for IDACORP and its subsidiaries. Idao
Power charges IDACORP for the costs of these servces based on service agreements and other specifically identified costs. For these
services Idaho Power biled IDACORP $0.8 millon and $0.9 million in 2010 and 2009, respectively.
Ida-West
Idaho Power purchases all of the power generated by four ofIda- West's hydroelectrc projects located in Idaho. Ida-West is a
wholly-owned subsidiary ofIDACORP, Inc. Idaho Power paid $8 millon and $9 million to Ida-West in 2010 and 2009, respectively.
I FERC FORM NO.1 (ED. 12-88)Page 123.38
IS ~o s:(1) ~An Original
(2) A Resubmission
SUMMA Y OF UTILITY PLANT AND ACCUM LATED PROVISIONS
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Report in Column (c) the amount for electric function, in column (d) the amount for gas functon, in column (e), (f), and (g) report other (specify) and in
column (h) common function.
End of
(a)
Total Company for the
Current YearlQuarter Ended
(b)
Electric
(c)
Line
No.
Classification
1 Utilty Plant
2 In Service
3 Plant in Service (Classified)
4 Propert Under Capital Leases
5 Plant Purchased or Sold
6 Completed Constrction not Classified
7 Experimental Plant Unclassified
8 Total (3 thru 7)
9 Leased to Others
10 Held for Future Use
11 Construction Work in Progress
12 Acquisition Adjustments
13 Total Utilty Plant (8 thru 12)
14 Accm Prov for Depr, Amort, & Depl
15 Net Utility Plant (13 less 14)
16 Detail of Accum Prov for Depr, Amort & Depl
17 In Service:
18 Depreciation
19 Amort & Depl of Producing Nat Gas Land/Land Right
20 Amort of Underground Storae Land/Land Rights
21 Amort of Oter Utility Plant
22 Total In Service (18 thru 21)
23 Leased to Others
24 Depreciation
25 Amortzation and Depletion
26 Total Leased to Others (24 & 25)
27 Held for Future Use
28 Depreciation
29 Amortization
30 Total Held for Future Use (28 & 29)
31 Abandonment of Leases (Natural Gas)
32 Amort of Plant Acquisition Adj
33 Total Accum Prov (equals 14) (22,26,30,31,32)
-~~-~---- --~------ ---
4,332,508,702 4,332.508,702
4,332,508,702 4,332.508,702
7,076,146
416,949,593
-454,450
4,756,079,991
1,771,654,529
2,984,425,462
7,076,146
416,949,593
-454,450
4,756,079.991
1 ,771,654,529
2,984,425,462~-----~~~--
-~-~ -~-- ---~~
r~~~---i
-418,471
1 ,771,654,529
-418,471
1,771,654,529
FERC FORM NO.1 (ED. 12-89)Page 200
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2010/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2011
ELECTRIC PLANT IN SERVICE (Accunt 101,102,103 and 106)
1. Report below the original cost of electric plant in service accrding to the prescrbed accunts.
2. In addition to Accunt 101, Electric Plant in Service (Classified), this page and the next indude Accunt 102, Electric Plant Purchased or Sold;
Accunt 103, Experimental Electric Plant Undassified; and Accunt 106, Completed Construction Not Classified-Electric.
3. Indude 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, induded by primary plant accunt, increases in column (c) additions and
reductions in column (e) adjustments.
5. Endose in parentheses credit adjustments of plant accunts to indicate the negative effect of such accunts.
6. Classify Acunt 106 accrding to prescrbed accunts, on an estimated basis if necessary, and indude the entries in column (c). Also to be induded
in column (c) are entries for reversals of tentative distributions of prior year reported in column (b). Likewise, if the respondent has a significant amount
of plant retirements which have not been dassified to primary accunts at the end of the year, include in column (d) a tentative distrbution of such
retirements, on an estimated basis, with appropriate contra entry to the accunt for accmulated depreciation provision. Include also in column (d)Line ccunt Balance AdditionsNo Beginning of Year. W ~
1 1. INTANGIBLE PLANT
2 (301) Organization
3 (302) Franchises and Consents
4 (303) Miscellaneous Intangible Plant
5 TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4)
6 2. PRODUCTION PLANT
7 A. Steam Production Plant
8 (310) Land and Land Rights
9 (311) Structures and Improvements
10 (312) Boiler Plant Equipment
11 (313) Engines and Engine-Driven Generators
12 (314) Turbogenerator Units
13 (315) Accssory Electric Equipment
14 (316 Misc. Power Plant Equipment
15 (317) Asset Retirement Costs for Steam Production
16 TOTAL Steam Production Plant (Enter Total of lines 8 thru 15)
17 B. Nudear Production Plant
18 (320) Land and Land Rights
19 (321) Structures and Improvements
20 (322) Reactor Plant Equipment
21 (323) Turbo enerator Units
22 (324) Accssory Electric Equipment
23 (325) Misc. Power Plant Equipment
24 (326) Asset Retirement Costs for Nudear Production
25 TOTAL Nudear Prouction Plant (Enter Total of lines 18 thru 24)
26 C. H draulic Production Plant
27 (330) Land and Land Rights
28 (331) Structures and Improvements
29 (332) Reservoirs, Dams, and Waterways
30 (333) Water Wheels, Turbines, and Generators
31 (334) Accssry Electic Equipment
32 (335) Misc. Power PLant Equipment
33 (336) Roads, Railroads, and Bridges
34 (337) Aset Retirement Costs for Hydraulic Production
35 TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34)
36 D. Other Production Plant
37 (340) Land and Land Rights
38 (341 Structures and Improvements
39 (342) Fuel Holders, Proucts, and Accssories
40 (343) Prime Movers
41 (344) Generators
42 (345) Accssory Electrc Equipment
43 346) Misc. Power Plant Equipment
44 (347) Aset Retirement Costs for Other Production
45 TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44)
46 TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45)
-46,004
21,620,769
34,760,040
56,334,805
51,707
1,544,768
4,760,093
6,356,568r~--- ------- ~---
I
1,370,320
138,632,198
535,996,056
225,421
2,342,621
27,087,429
r~-~----------~i
134,758,504
62,010,255
15,184,798
3,585,511
891,537,642
17,657,531
604,886
957,711
-69,524
48,806,075
¡ - ~--~-~- ----- - --~-~
!
30,823,031
153,562,171
250,236,942
192,732,014
42,752,897
17,959,833
7,492,685
-709,228
1,942,473
564,264
1,706,402
1,252,068
867,976
29,108
695,559,573 5,653,063r------------- ----- ------
I
402,746
7,169,595
4,445,866
92,651,571
39,093,026
24,899,230
3,054,175
2,196,949
8,150,065
-7,411,126
128,368
64,469
171,716,209
1,758,813,424
3,128,725
57,587,863
FERC FORM NO.1 (REV. 12-05)Page 204
Name of Respondent
Idaho Power Company
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2011
ELECTRIC PLANT IN SERVICE (Accunt 101,102,103 and 106) (Continued)
distributions of these tentative classifications in columns (c) and (d), including the reversals of the prior years tentative accunt distrbutions of these
amounts. Careful observance of the above instructions and the texts of Accunts 101 and 106 wil avoid serious omissions of the reported amount of
respondent's plant actually in service at end of year.
7. Show in column (f) reclassifications or transfers within utility plant accunts. Include also in column (f) the additions or reductions of primary accunt
classifications arising from distribution of amounts initially recorded in Accunt 102, include in column (e) the amounts with respect to accumulated
provision for depreciation, acquisition adjustments, etc., and show in column (f) only the offset to the debits or credits distributed in column (f) to primary
accunt classifications.
8. For Accunt 399, state the nature and use of plant included in this accunt and if substantial in amount submit a supplementary statement showing
subaccunt classification of such plant conforming to the requirement of these pages.
9. For each amount comprising the reported balance and changes in Accunt 102, state the propert purchased or sold, name of vendor or purchase,
and date of transaction. If proposed journal entries have been filed with the Commission as required by the Uniform System of Accunts, give also dateRetirements Adjustments Transfers Balance at LineEnd lg)Year No.
Year/Period of Report
End of 2010/Q4
6,536,552
6,536,552
5,703
23,165,537
32,983,581
56,154,821-~~-~~---~~------~~~- -- - ~ T - "i - ~ -" ~ "~,,
-8,291
1,809,612
14,017,871
1,604,032
139,165,207
549,065,614
3,616,146
2,728,385
655,960
148,799,889
59,886,756
15,486,549
3,515,987
917,524,03422,819,683~~-~-~-----~~~------~---~--
~-~~-~~~~-----~----~~----
3,834
79,259
50,328
161,151
242,880
739,125
30,109,969
155,425,385
250,750,878
194,277,265
43,762,085
18,088,684
7,521,793
1,276,577 699,936,059----~------~~~-
2,599,695
7,169,595
4,445,866
100,801,636
31,681,900
25,027,598
3,118,644
24,096,260
174,844,934
1,792,305,027
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO.1 (REV. 12-05)205Page
Name of Respondent
Idaho Power Company
47 3. TRANSMISSION PLANT
48 (350) Land and Land Rights
49 (352) Structures and Improvements
50 (353) Station Equipment
51 (354) Towers and Fixtures
52 (355) Poles and Fixtures
53 (356) Overhead Conductors and Devices
54 (357) Under round Conduit
55 358) Underground Conductors and Devices
56 (359) Roads and Trails
57 (359.1) Asset Retirement Costs for Transmission Plant
58 TOTAL Transmission Plant (Enter Total of lines 48 thru 57)
59 4. DISTRIBUTION PLANT
60 (360) Land and Land Rights
61 (361 Strctures and Improvements
62 (362) Station Equipment
63 (363) Storage Battery Equipment
64 (364) Poles, Towers, and Fixtures
65 (365) Overhead Conductors and Devices
66 366) Underground Conduit
67 (367) Under round Conductors and Devices
68 (368) Line Transformers
69 (369) Service
70 (370) Meters
71 (371) Installations on Customer Premises
72 (372) Leased Property on Customer Premises
73 (373) Street Lighting and Signal Systems
74 (374) Asset Retirement Costs for Distribution Plant
75. TOTAL Distribution Plant (Enter Total of lines 60 thru 74)
76 5. REGIONAL TRANSMISSION AND MARKET OPERATION PLAT
77 (380) Land and Land Rights
78 (381) Structures and Improvements
79 (382) Computer Hardware
80 (383) Computer Softare
81 (384) Communication Equipment
82 (385) Miscellaneous Regional Transmission and Market Operation Plant
83 (386) Asset Retirement Costs for Regional Transmission and Market Oper
84 TOTAL Transmission and Market Operation Plant (Total lines 77 thru 83)
85 6. GENERA PLANT
86 (389) Land and Land Rights
87 (390) Structures and Improvements
88 (391) Offce Furniture and Equipment
89 (392) Transportation Equipment
90 (393) Stores Equipment
91 (394) Tools, Shop and Garage Equipment
92 (395) Laboratory Equipment
93 (396) Power Operated Equipment
94 (397) Communication Equipment
95 (398 Miscellaneous Equipment
96 SUBTOTAL (Enter Total of lines 86 thru 95)
97 (399) Other Tangible Propert
98 (399.1) Aset Retirement Costs for General Plant
99 TOTAL General Plant (Enter Total of lines 96, 97 and 98)
100 TOTAL (Accunts 101 and 106)
101 (102) Electric Plant Purchased (See Instr. 8)
102 (Less) (102) Electc Plant Sold (See Instr. 8)
103 (103) Experimental Plant Unclassified
104 TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103)
Line
No.
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04115/2011
ELECTRIC PLANT IN SERVICE (Accunt 101,102,103 and 106) (Continued)Accunt a anceBeginning of YearW ~
Year/Period of Report
End of 2010/Q4
31,028,848
43,115,497
304,153,598
139,305,363
95,225,302
155,113,007
3,227,413
12,772,297
53,454,147
5,418,177
6,886,404
14,576,603
318,351
768,259,966 96,335,041r--~-------- - -------
i
4,720,970
26,949,318
181,364,474
24,219
2,684,247
3,711,194
217,058,551
121,129,198
48,299,409
186,973,846
401,884,459
56,506,757
79,041,84
2,655,578
9,432,943
514,695
-19,750
5,201,635
17,736,409
1,094,460
18,781,574
193,840
4,247,818
232,370
1,331,064,592
169,561
355,610
59,880,637rc~-~-------~--------
i
~-------~~-~----I
10,761,268
76,656,381
40,825,812
58,924,843
1,330,794
5,250,205
11,551,486
9,240,588
27,393,124
4,225,136
246,159,637
418,905
1,281,788
3,669,556
3,743,616
171,621
386,103
826,418
687,555
2,587,431
637,268
14,410,261
246,159,637
4,160,632,424
14,410,261
234,570,370
4,160,632,424 234,570,370
FERC FORM NO.1 (REV. 12-05)206Page
Retirements
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2011
ELECTRIC PLANT IN SERVICE (Accunt 101,102,103 and 106) (Continued)Adjustments Transfers Balance at
End lJtear
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2010/Q4
2,323
220,357
8,156,354
34,253,938
55,667,437
349,451,391
144,723,540
101,621,493
169,165,595
490,213
524,015
318,351
9,393,262 855,201,745~~~~~-----~--- -------- --~~-~~-----~
4,745,189
147,703 29,485,862
2,481,706 182,593,962
1,431,589 225,059,905
1,508,292 120,135,601
63,945 48,215,714
681,268 191,494,213
4,838,735 414,782,133
281,308 57,319,909
2,125,893 95,697,525
98,519 2,750,899
46,865 4,370,514
587,980
13,705,823 1,377,239,406~---~----~~~----------~ ---~~---~-
-~-----~~---~--
56,411
659,555
5,119,827
1,711,154
43,075
68,786
431,209
5,961
766,410
99,807
8,962,195
11,123,762
77,278,614
39,375,541
60,957,305
1,459,340
5,567,522
11,946,695
9,922,182
29,214,145
4,762,597
251,607,703
8,962,195
62,694,092
251,607,703
4,332,508,702
62,694,092 4,332,508,702
Line
No.
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
81
82
83
84
85
86
87
88
89
90
91
92
93
94
95
96
97
98
99
100
101
102
103
104
FERC FORM NO, 1 (REV. 12-05)207Page
This ~ort Is: Date of Report(1) ~An Onginal (Mo, Da, Yr)
(2) A Resubmission 04/15/2011
ELECTRIC PLANT HELD FOR FUTURE USE (Accunt 105)
1. Report separately each propert held for future use at end of the year having an original cost of $250,000 or more. Group other items of propert held
for future use.
2. For propert having an original cost of $250,000 or more previously used in utilty operations, now held for future use, give in column (a), in addition to
other required information, the date that utilty use of such propert was discontinued, and the date the onginal cost was transferred to Accunt 105.
Line escrption and Location ate ngina y n u ed ate xpected to e use alance atNo Of Prolert in This Accunt in Utility Service End of Year. (a (b) (c) (d)
Name of Respondent
Idaho Power Company
Year/Penod of Report
End of 2010/04
1 Land and Rights:
2 Boise Operations Center
3 Production
4 Transmission Stations
5 Transmission Lines
6 Distrbution Stations
7 Beacon Light Substation
8 Homedale Substation
9 North River Operations Center
10 Line #854500 Kv
11 Boise Operations Center
12 Transmission Stations
13 Distnbution Stations
14 Homedale Substation
15 Beacon Light Substation
16
17
18
19 Column B if no date listed it is vanous
20
21 Other Propert:
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
12/31/82 762,521
112,704
429,822
68,619
1,074,920
465,662
109,453
2,630,412
308,066
72,785
199,069
72,016
215,719
554,378
12/30/02
2129108
1/31/08
3/31/09
12/31/82
12/31/81
2129/08
12130/02
~~--~------ ~- --~
47 Total 7,076,146
FERC FORM NO.1 (ED. 12-96)Page 214
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) Fi A Resubmission 04115/2011
CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Accunt 107)
1. Report below descriptions and balances at end of year of projects in process of construction (107)
2. Show items relating to "research, development, and demonstrtion" projects last, under a caption Research, Development, and Demonstrating (see
Accunt 107 of the Uniform System of Accunts)
3. Minor projects (5% of the Balance End of the Year for Accunt 107 or $1,000,000, whichever is less) may be grouped.
Line Description of Project Construction work in progress -
No.Electric (Accunt 107)
(a)(b)
1 LANGLEY GULCH POWER PLANT CONS 193,642,197
2 ROLLUP RELIC COST BROWNLEE 46,774,350
3 ROLLUP RELIC COST HELLS CANYON 32,030,925
4 ROLLUP RELIC COST OXBOW 14,704,586
5 GATEWAY WEST 500KV LINE 14,313,770
6 BOARDMAN - HEMINGWAY 500 KV LI 13,576,716
7 HELLS CANYON RELICENSING OUTSI 11,939,746
8 CIAC LIABILITY RECLASS 5,991,287
9 WQ - ONGOING HELLS CANYON RELI 5,073,688
10 BRIDGER 2007C207 U3 S02 EM IS C 4,064,825
11 RIVER ENG.-HELLS CANYON CONTIN 3,165,288
12 HCC RELICENSING FISH2004 FEASI 2,165,327
13 LANGLEY GULCH SWITCHYARD 2,125,776
14 REL-HELLS CANYON COMPLEX FY200 2,103,067
15 HCC RELICENSING, FISH2004 INST 2,101,401
16 CIAC LIABILITY RECLASS-PROJECT 2,069,855
17 MPSN0802 INCREASE CAPACITY OF 2,050,510
18 HCC RELICENSING, FISH2004 REDB 2,045,023
19 LANGLEY GULCH 230 KV DOUBLE CI 1,935,273
20 HCC RELICENSING, FISH2004 ANAD 1,707,975
21 LANGLEY GULCH PP CONST: WATER 1,688,355
22 VTRY ADD 2ND 138 LINE BAY 1,642,830
23 PAYROLL & IBNR ACCRUAL 1,566,781
24 CJ STRIKE #3 TURBINE RUNNER RE 1,488,366
25 AERATION FOR UNIT #5 TO IMPROV 1,294,073
26 BKFT1001 - REPLACE METALCLAD S 1,278,390
27 ROLLUP RELIC COST SWAN FALLS 1,260,525
28 REL-HCC OREGON REAUTHORIZATION 1,236,182
29 LEGAL DEPT. LABOR FOR RELICENS 1,235,515
30 SWAN FALLS RELICENSING 1,230,436
31 VALMY 98238682 REPL EVAP POND 1,217,269
32 BRIDGER 2008C132 U3 TURBINE UP 1,119,403
33 CUSTOMER SERVICE CALL MANAGEME 1,105,913
34 OTHER MINOR PROJECTS UNDER $1,000,000 36,003,970
35
36
37
38
39
40
41
42
43 TOTAL 416,949,593
FERC FORM NO.1 (ED. 12-87)Page 216
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2010/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2011
ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT (Accunt 108)
1. Explain in a footnote any important adjustments during year.
2. Explain in a footnote any difference between the amount for book cost of plant retired, Line 11, column (c), and that reported for
electric plant in service, pages 204-207, column 9d), excluding retirements of non-depreciable propert.
3. The provisions of Account 108 in the Uniform System of accounts require that retirements of depreciable plant be recorded when
such plant is removed from service. If the respondent has a significant amount of plant retired at year end which has not been recorded
and/or classified to the various reserve functional classifications, make preliminary closing entries to tentatively functionalize the book
cost of the plant retired. In addition, include all costs included in retirement work in progress at year end in the appropriate functional
classifications.
4. Show separately interest credits under a sinking fund or similar method of depreciation accounting.
ine
No.
em
(a)
Balance Beginning of Year
2 Depreciation Provisions for Year, Charged to
3 (403) Depreciation Expense
4 (403.1) Depreciation Expense for Asset
Retirement Costs
1,693,322,507 1,693,322,507
5 (413) Exp. of Elec. PIt. Leas. to Others
6 Transportation Expenses-Clearing
7 Other Clearing Accunts
8 Other Accunts (Specify, details in footnote):
9 Fuel Stock
10 TOTAL Deprec. Prov for Year (Enter Total of
lines 3 thru 9)
11 Net Charges for Plant Retired:
12 Book Cost of Plant Retired
13 Cost of Removal
14 Salvage (Credit)
15 TOTAL Net Chrgs. for Plant Ret. (Enter Total
of lines 12 thru 14)
16 Other Debit or Cr. Items (Descrbe, details in
footnote):
108,272
112,064,172
108,272
112,064,172
48,656,596
8,150,930
2,024,882
54,782,644
131,911
17
18 Book Cost or Asset Retirement Costs Retired
19 Balance End of Year (Enter Totals of lines 1,
10, 15, 16, and 18)
1,750,735,946 1,750,735,946
Section B. Balances at End of Year According to Functional Classification
20 Steam Production 522,242,776 522,242,776
21 Nuclear Production
22 Hydraulic Prouction-Conventional 337,974,005 337,974,005
23 Hydraulic Production-Pumped Storage
24 Other Producton 28,158,063 28,158,063
25 Transmission 264,169,778 264,169,77
26 Distrbution 497,188,284 497,188,284
27 Regional Transmission and Market Operation
28 General 101,003,040 101,003,04
29 TOTAL (Enter Total of lines 20 thru 28)1,750,735,946 1,750,735,946
FERC FORM NO.1 (REV. 12-05)Page 219
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2S An Original (Mo, Da, Yr)
Idaho Power Company 1(2)A Resubmission 04/15/2011 2010/Q4
FOOTNOTE DATA
¡Schedule Page: 219 Line No.: 14 Column: b
Relocation reimbursements, Up and down costs and damage and insurance claims $ 182,401
fsciiPige;-219---UneNi::Ciii:E-----.---
Accumulated Provision for Depreciation on Asset Retirement Obligation $131,911
IFERC FORM NO.1 (ED. 12-87) Page 450.1
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) 0 A Resubmission 04/15/2011
INVESTMENTS IN SUBSIDIARY COMPANIES (Accunt 123.1)
1.Report below investments in Acunts 123.1, investments in Subsidiary Companies.
2. Provide a subheading for each company and List there under the information called for below. Sub - TOTAL by company and give a TOTAL in
columns (e),(f),(g) and (h)
(a) Investment in Securities - List and descrbe each security owned. For bonds give also principal amount, date of issue, maturity and interest rate.
(b) Investment Advances - Report separately the amounts of loans or investment advances which are subject to repayment, but which are not subject to
current settlement. With respect to each advance show whether the advance is a note or open accunt. List each note giving date of issuance, maturity
date, and specifying whether note is a renewaL.
3. Report separately the equity in undistributed subsidiary eamings since acquisition. The TOTAL in column (e) should equal the amount entered for
Accunt 418.1.
Line Descrption of Investment Date Acquired Date Of Amount ot Investment at
No.Ma(~rity Beginning of Year
(a)(b)(d)
1 Idaho Energy Resources Company
2 Common Stock 02/01/74 500
3 Capital contributions 2,462,594
4 Equity in earnings 62,552,347
5
6 Subtotal Idaho Energy Resources Company 65,015,441
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31 .
32
33
34
35
36
37
38
39
40
41
42 Total Cost of Accunt 123.1 $2,463,0941 TOTAL 65,015,441
FERC FORM NO.1 (ED. 12-89)Page 224
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) Fi A Resubmission 04/15/2011
INVESTMENTS IN SUBSIDIARY COMPANIES (Accunt 123.1) (Continued)
4. For any securities, notes, or accunts that were pledged designate such securities, notes, or accunts in a footnote, and state the name of pledgee
and purpose of the pledge.
5. If Commission approval was required for any advance made or security acquired, designate such fact in a footnote and give name of Commission,
date of authorization, and case or docket number.
6. Report column (t) interest and dividend revenues form investments, including such revenues form securities disposed of during the year.
7. In column (h) report for each investment disposed of during the year, the gain or loss represented by the difference between cost of the inveStment (or
the other amount at which carried in the books of accunt if difference from cost) and the sellng price thereof, not including interest adjustment includible
in column (t).
8. Report on Line 42, column (a) the TOTAL cost of Accunt 123.1
equity in ::uOsidiary Revenues for Year Amount of Investment at Gain or Loss from Investment LineEarnin~s of Year End tYear DiSPf~fd of No.e)(t)g)
1
500 2
2,462,594 3
7,546,332 70,098,680 4
5
7,546,332 72,561,774 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
7,546,332 72,561,774 42
FERC FORM NO.1 (ED. 12-89)Page 225
THIS PAGE INTENTIONALLY LEFT BLANK
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)2010/Q4
(2) 0 A Resubmission 04/15/2011 End of
MATERIALS AND SUPPLIES
1. For Accunt 154, report the amount of plant materials and operating supplies under the primary functonal classifications as indicated in column (a);
estimates of amounts by function are accptable. In column (d), designate the departent or departments which use the class of materiaL.
2. Give an explanation of important inventory adjustments during the year (in a footnote) showing general classes of material and supplies and the
various accunts (operating expenses, clearing accunts, plant, etc.) affected debited or credited. Show separately debit or credits to stores expense
clearing, if applicable.
Line Accunt Balance Balance Department or
No.Beginning of Year End of Year Departments which
Use Material
(a)(b)(c)(d)
1 Fuel Stock (Accunt 151)25,633,645 27,546,983 Electc
2 Fuel Stock Expenses Undistributed (Accunt 152)
3 Residuals and Extracted Products (Accunt 153)
4 Plant Materials and Operating Supplies (Accunt 154)
5 Assigned to - Construction (Estimated)
6 Asigned to - Operations and Maintenance
7 Production Plant (Estimated)14,273,494 14,416,312
8 Transmission Plant (Estimated)13,295,452 13,365,654
9 Distribution Plant (Estimated)15,059,387 13,541,576
10 Regional Transmission and Market Operation Plant
(Estimated)
11 Assigned to - Other (provide details in footnote)713,727 897,634
12 TOTAL Accunt 154 (Enter Total of lines 5 thru 11)43,342,060 42,221,176 Electc
13 Merchandise (Accunt 155)
14 Other Materials and Supplies (Accunt 156)
15 Nuclear Materials Held for Sale (Accunt 157) (Not
applic to Gas Uti!)
16 Stores Expense Undistributed (Accunt 163)4,711,966 3,379,745 Electric
17
18
19
20 TOTAL Materials and Supplies (Per Balance Sheet)73,687,671 73,147,904
FERC FORM NO.1 (REV. 12-05)Page 227
Name of Respondent This wort Is:Date of Report Year/Penod of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) 0 A Resubmission 04/15/2011
OTHER REGULATORY ASSETS (Accunt 182.3)
1. Report below the particulars (details) called for concerning other regulatory assets, including rate order docket number, if applicable.
2. Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $100,000 which ever is less), may be
grouped by classes.
3. For Regulatory Assets being amortized, show period of amortization.
Line Description and Purpose of Balance at Debits CREDITS Balance at end of
No.Other Regulatory Assets Beginning of Wñtn olf Dunng Wnllen olf Dunng Currnt QuartrNear
Current the QuarterNear the Period
QuarterNear Account Charged Amount
(a)(b)(c)(d)(e)(f)
1 Asset Retirement Obligations- IPUC 14,749,123 1,251,626 Various 628,96 15,371,785
2 Ordei# 29414-DPUC Ordei# 04-585
3
4 SFAS 133 Mark to Market 280,459 12,958,490 244 10,999,255 2,239,694
5
6 Regulatoiy Unfunded Accu Def Inc Tax Noncurrnt 391,835,998 207,26,065 282 10,501,413 588,594,650
7
8 PCA Deferrl- IPUC order 32,m,040 47,277,755 Various 49,273,716 30,281,079
9 #27660 (amort period 6/05 thru 5/07)
10
11 PCA Prior Year Deferrl - IPUC Order 39,134,552 12,751,188 Various 64,607,616 -12,721,876
12 #27660 (amort period 06/09 thru 05/10)
13
14 Fixed Cost Adjusment (FCA) Order #30267 6,581,45 9,489,666 1823/401 6,596,995 9,474,129
15 (amort period 06/09 thru 05/10)
16
17 Prior Year FCA Order #30267 1,254,247 6,602,763 400 4,99,495 2,866,515
18
19 Idaho - Demand Side Management - IPUC order 1,621,331 270,217 401 1,891,54
20 #27660 (amort period 7/98 thru 6/10)
21
22 Excess Power Deferrl 06/07 - IPUC Order #07-555 1,542,629 46,703 Various 1,978,94 29,386
23 (amort period 10/09 thru 02112)
24
25 IPUC Grid West loans -IPUC order #30157 372,871 15,536 1823/401 201,973 186,434
26 (amort period 1/07 -12/11)
27
28 FERC Grid West Expense - ER08-629-000 279,321 6,983 401 90,779 195,525
29 (amort period 05/08 thru 04/13)
30
31 SFAS 106/158 Past Retirement Benefits 15,324,165 5,917,008 2283 2,209,430 19,031,743
32 IPUC order #30256
33
34 SFAS 87/158 Pension Accumulated ( 1.925,704)2,888,556 282 160,100,880 -159,138,028
35 IPUC order #30256
36
37 Pension Deferred FERC Porton 715,538 645,878 1823/2283 1,211,025 150,391
38
39 Pension Deferred Oreon Order UE-213 572,286 416,002 2283/4073 48,398 939,890
40
41 FAS 87 Deferrd Pension-I PUC order #30333 37,963,279 33,407,805 Various 62,821,496 8,549,588
42
43 FIN 48 Adjustment-Interest Payable-Order #30256 152,701,210 20,256,28 2283 9,247,401 163,710,092
44 TOTAL 715,831,853 501,942,326 456,348,295 761,425,884
FERC FORM NO. 1/3-Q (REV. 02-04)Page 232
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) 0 A Resubmission 04/15/2011
OTHER REGULATORY ASSETS (Accunt 182.3)
1, Report below the particulars (details) called for concerning other regulatory assets, including rate order docket number, if applicable.
2. Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $100,000 which ever is less), may be
grouped by classes.
3. For Regulatory Assets being amortized, show period of amorization.
Line Descrption and Purpose of Balance at Debits CREDITS Balance at end of
No.Other Regulatory Assets Beginning of Wñten off Dunng Wntten off Dunng Currnt QuartrlY ear
Currnt the QuartrlY ear the Period
QuarterlY ear Accunt Charged Amount
(a)(b)(c)(d)(e)(f)
1
2 ID DSM Rider Reclass- 29026 9,718,518 50,188,794 254 42,314,374 17,592,938
3
4 PCAM Oreon 2008 Order #08-238 5,485,419 1,119,455 1823/254 64,201 5,956,673
5
6 PCAM Interest Reserve 2008 Order #08-238 390,563 Various 669,237 -278,674
7
8 Exce Power Deferrl 2007 6,193,112 1,408,245 1823/4210 636,666 6,964,691
9 IPUC order #09-189
10
11 2007 EPC Interest Reserve Order #09-189 612,48 1823/4210 1,06,243 -452,759
12
13 Oregon DSM Rider Reclass. Advice #05-03 866,772 5,337,393 254 4,330,490 1,873,675
14
15 2009 Reorg order #30914 1,145,203 27,296 401 249,877 922,622
16 (amort period 01/10 thru 12/14)
17
18 OA IT Revenue Deferred Reserve Order #30940 4,686,838 2,941,239 186/4210 2,952,895 4,675,182
19 (amort perid 01/11 thru 12/13)
20
21 Idaho Pension Cash PUC Order #31 091 ~1823/401 9,489,405 53,169,373
22 (amort period 06/10 - 05/11)
23
24 FERC Pension Cash --1823/401 182,957 1,024,067
25 (amort period 06/10 -05/11)
26
27 Regulatory Unfunded Accu Def Inc Tax Currnt (7,774,317)7,774,317
28
29 Minor items (17)230,505 6,395,214 Various 6,408,620 217,099
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44 TOTAL 715,831,853 501,942,326 456,348,295 761,425,884
FERC FORM NO.1/3-Q (REV. 02-04)Page 232.1
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 0411512011 2010/Q4
FOOTNOTE DATA
iSclletlJlf! Page: 232.1 Line No.: 23 . Column: cIdaho Public Service CommissIon has authorized-iimoriTzation ü:fS-Š. 4 million over 12
months.
SchedulePiiiiii- 232.1-Une No.: 26 Column:c-----------------------------
FERC-h-as authori-zed amortization fo $10r th-oiisand over 12 months-:--
I FERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) DA Resubmission 04/15/2011
MISCELLANEOUS DEFFERED DEBITS (Accunt 186)
1.Report below the particulars (details) called for concerning miscellaneous deferred debits.
2.For any deferred debit being amortized, show period of amortization in column (a)
3. Minor item (1% of the Balance at End of Year for Account 186 or amounts less than $100,000, whichever is less) may be grouped by
classes.
Line Description of Miscellaneous Balance at Debits CREDITS Balance at
No.Deferred Debits Beginning of Year ~çcum.Amount End of Year
CharRed
(a)(b)(c)(d (e)(f)
1 Rents - Rights of way 270,368 579,928 401 76,711 773,585
2
3 2008 Poll Control Bond Refin 4,347,901 18,810 181/232 4,354,700 12,011
4
5 Advance prepaid coal royalties 1,507,205 3,006 Various 76,992 1,433,219
6
7 Security plan 20,866,261 701,574 165 520,406 21,047,429
8
9 American Falls bond refinance 220,709 401 14,552 206,157
10 (amort period 4/00 thru 7/26)
11
12 Prepaid Credit Facility 253,368 431 193,068 60,300
13
14 Company owned Life Insurance 5,787,403 1,596,192 Various 1,759,192 5,624,403
15
16 American Falls water rights 15,716,965 401 1,042,009 14,674,956
17 (amort period 1/06 thru 12/25)
18
19 Milner bond guarantee 8,509,091 253 1,063,636 7,445,455
20 (amort period 2/07 - 2/17)
21
22 American Falls - bond refinance 727,987 401 47,999 679,988
23 (35 year amortzation)
24
25 Shelf Registrtion - 2008 974,055 262,043 181/232 1,236,098
26
27 Shelf Registration - 2010 3,646,728 Various 1,262,834 2,383,894
28
29 Transmission Deposit-PacifiCorp 661,875 177,741 Various 151,875 687,741
30
31 Prepaid PeoplesoftPassport 109,596 486,424 186/401 287,718 308,302
32
33 Long Term Workers Compensation 1,328,786 1,328,786 Various 1,350,669 1,306,903
34
35 OATI Revenue Deferred Reserve -2,925,724 3,250,420 1823/431 2,935,409 -2,610,713
36 order #30940
37 (amort period 3 years start
38 date not yet determined)
39
40 Long-Term Firm Trans Deposits 941,654 Various 22,591 919,063
41
42 Minor Items & Job Orders (9)137,028 9,387,080 Various 9,345,329 178,779
43
44
45
46
47 Misc. Work in Progress
48 ueterreO Kegulatory Comm.
Expenses (See pages 350 - 351)
49 TOTAL 58,492,874 55,131,472
FERC FORM NO.1 (ED. 12-94)Page 233
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2010/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2011
ACCUMULATED DEFERRED INCOME TAXES (Accunt 190)
1. Report the information called for below concerning the respondents accounting for deferred income taxes.
2. At Other (Specify), include deferrals relating to other income and deductions.
Line
No.
escrption and Location
(a)
Electric
-847,076
8,334,734
21,611,994
-509,154
7,061,283
6,072,776
8 TOTAL Electric (Enter Total of lines 2 thru 7)
9 Gas
10
11
12
13
14
15 Other
16 TOTAL Gas (Enter Total of lines 10 thru 15
18,203,912
170,110,978
18,090,657
157,346,772
Notes
FERC FORM NO.1 (ED. 12-88)Page 234
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2011 2010/Q4
FOOTNOTE DATA
Schedule Page:-2~ Liii-ii No.:S--Column:a- -- ---- - --=~_-====~~=-_=~-~ ----
(Note 1):
Post Retiree Benefis-VEBA
AFUDC Hells Canyon Relicensing
Rate Case Disallowance
Stock Based Com pensation
Other Employee's Long Term Deferred Compensation
Post Retirement Benefis
Deferred Idaho ITC
Non-VEBA Pension and Benefits
Oregon-Pension Expense
FERC Credit OFA
IRS Interest Expense
Pension Expense (acct 228)
Deferred GBC
Bonus Deferral
Delivery Accruals
Total Other Electric
¡Schedule Page: 234 Line No.: 7 Column: a
(Note 2):
Pension
Regulatory Liability for Income Taxes
Postretirement Plan
Minimum Pension Liability
Total Other
'Schedule Page: 234 Line No.: 17 Column: a
Senior Management Security Plan
SMSP-Market Change of Rabbi Investments
Micron-CIAC
Meridian Gold Contributions
Bridger Sierra Reserve-Legal Fee's
Unrealized Loss on Investments
Total Non Electric
Beginning Balance
5,583,994
3,868,089
2,881,031
2,235,008
2,039,678
1,765,736
1,656,363
573,602
471,584
424,728
113,033
o
12,000
(2,577)
(10,275)
Ending Balance
5,658,260
8,292,259
2,765,193
2,496,071
1,855,362
1,504,637
4,183,991
414,231
817,276
182,024
93,084
(22,197,832)
24,000
(514)
(15,266)
21,611,994 6,072,776
59,698,538
47,183,294
9,450,830
6,474,752
122,807,414
64,358,800
46,199,137
8,025,874
8,047,399
126,631,210
13,718,388
2,669,975
1,526,244
130,567
97,738
61,000
18,203,912
15,067,824
1,626,015
1,288,363
108,455
18,090,657
I FERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) DA Resubmission 04/15/2011
CAPITAL STOCKS (Accunt 201 and 204)
1. Report below the particulars (details) called for concerning common and preferred stock at end of year, distinguishing separate
series of any general class. Show separate totals for common and preferred stock. If information to meet the stock exchange reporting
requirement outlined in column (a) is available from the SEC 10-K Report Form filing, a specific reference to report form (Le., year and
company title) may be reported in column (a) provided the fiscal years for both the 10-K report and this report are compatible.
2. Entries in column (b) should represent the number of shares authorized by the articles of incorporation as amended to end of year.
Line Class and Series of Stock and Number of shares Par or Stated Call Price at
No.Name of Stock Series Authorized by Charter Value per share End of Year
(a)(b)(c)(d)
1 Accunt 201
2 Common Stock registered on New York 50,000,000 2.50
3 and Pacific Stock Exchange
4 Total Common Stock 50,000,000 2.50
5
6 Accunt 204 - None
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
.
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
FERC FORM NO.1 (ED. 12-91)Page 250
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) FiA Resubmission 04/15/2011
CAPITAL STOCKS (Accunt 201 and 204) (Continued)
3. Give particulars (details) concerning shares of any class and series of stock authorized to be issued by a regulatory commission
which have not yet been issued.
4. The identification of each class of preferred stock should show the dividend rate and whether the dividends are cumulative or
non-cumulative.
5. State in a footnote if any capital stock which has been nominally issued is nominally outstanding at end of year.
Give particulars (details) in column (a) of any nominally issued capital stock, reacquired stock, or stock in sinking and other funds which
is pledged, stating name of pledgee and purposes of pledge.
OUTSTANDING PER BALANCE SHEET HELD BY RESPONDENT Line
(Total amount outstanding without reduction AS REACQUIRED STOCK (Accunt 217)IN SINKING AND OTHER FUNDS No.for amounts held by respondent)
Sl1ares Amount Shares ~pst Sh¡:res Amount
(e)(f)(g)(h)(i)0)
1
39,150,812 97,877,030 2
3
39,150,812 97,877,030 4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
FERC FORM NO.1 (ED. 12-88)Page 251
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) Fi A Resubmission 04/15/2011
OTHER PAID-IN CAPITAL (Accunts 208-211, inc.)
Report below the balance at the end of the year and the information specified below for the respective other paid-in capital accunts. Provide a
subheading for each accunt and show a total for the accunt, as well as total of all accunts for reconciliation with balance sheet, Page 112. Add more
columns for any accunt if deemed necessary. Explain changes made in any accunt during the year and give the accúnting entres efectng such
change.
(a) Donations Received from Stockholders (Accunt 208)-State amount and give brief explanation of the origin and purpose of each donation.
(b) Reducton in Par or Stated value of Capital Stock (Accunt 209): State amount and give brief explanation of the capital change which gave rise to
amounts reported under this caption including identification with the class and series of stock to which related.
(c) Gain on Resale or Cancellation of Reacquired Capital Stock (Accunt 210): Report balance at beginning of year, credits, debits, and balance at end
of year with a designation of the nature of each credit and debit identified by the class and series of stock to which related.
(d) Miscellaneous Paid-in Capital (Accunt 211 )-Classify amounts included in this accunt accrding to captions which, together with brief explanations,
disclose the general nature of the transactions which gave rise to the reported amounts.
i~e 'f:)"~glnto.
1 Accunt 208 - Donations received from stockholders - None
2
3 Accunt 209 - Reduction in par or stated value of Capital Stock - None
4
5 Accunt 210 - Gain on reacquired Capital Stock - None
6
7
8 Accunt 211 - Miscellaneous paid-in Capital - None
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40 TOTAL .
FERC FORM NO.1 (ED. 12-87)Page 253
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) Fi A Resubmission 04/15/2011
CAPITAL STOCK EXPENSE (Accunt 214)
1.Report the balance at end of the year of discount on capital stock for each class and series of capital stock.
2. If any change occurred during the year in the balance in respect to any class or series of stock, attch a statement giving particulars
(details) of the change. State the reason for any charge-off of capital stock expense and specify the account charged.
Line Class and Series of Stock Balance at End of Year
No.(a)(b)
1 Common Stock 2,096,925
2
3
4
5
6
7
8
9
10 Explanation of Changes during the year:
11
12
13
14
15
16
17
18
19
20
21
22 TOTAL 2,096,925
FERC FORM NO.1 (ED. 12-87)Page 254b
Name of Respondent This ~ort Is:Date of Report Year/Penod of Report
Idaho Power Company (1) An Onginal (Mo, Oa, Yr)End of 2010/Q4
(2) Fi A Resubmission 04/15/2011
LONG-TERM DEBT (Accunt 221, 222, 223 and 224)
1. Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221, Bonds, 222,
Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt.
2. In column (a), for new issues, give Commission authonzation numbers and dates.
3. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a descnption of the bonds.
4. For advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate
demand notes as such. Include in column (a) names of associated companies from which advances were received.
5. For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were
issued.
6. In column (b) show the pnncipal amount of bonds or other long-term debt onginally issued.
7. In column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt onginally issued.
8. For column (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount.
Indicate the premium or discount with a notation, such as (P) or (D). The expenses, premium or discount should not be netted.
9. Furnish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with
issues redeemed dunng the year. Also, give in a footnote the date of the Commission's authonzation of treatment other than as
specified by the Uniform System of Accounts.
Line Class and Senes of Obligation, Coupon Rate Pnncipal Amount Total expense,
No.(For new issue, give commission Authonzation numbers and dates)Of Debt issued Premium or Discunt
(a)(b)(c)
1 Accunt 221:
2 First Mortgage Bonds:
3 4.50% Senes due 2020 130,000,000 1,190,698
4 234,601 0
5
6 5.50% Senes due 2033 70,000,000 728,701
7 36,400 0
8
9 6.15% Senes Due 2019 100,000,000 1,034,909
10 184,949 0
11
12 3.40% Senes due 2020 OPUC UF42631PUC IPC-E-10-10 WPSC 20005-32-ES-10 100,000,000 498,864 0
13
14 5.30% Senes Due 2035 60,000,000 408,411 0
15 3,802,019
16
17 6.60% Senes due 2011 120,000,000 860,502
18
19 4.25%Senes due 2013 70,000,000 641,201
20 372,696 0
21
22 4.75% Senes due 2012 100,000,000 944,356
23 1,047,617 0
24
25 6.00% Senes due 2032 100,000,000 1,191,216
26 543,244 0
27
28 5.875% Series due 2034 55,000,000 -585,759
29 746,961 0
30
31 5.50% Senes due 2034 50,000,000 524,419
32 383,322 0
33 TOTAL 1,617,04,000 24,685,286
FERC FORM NO.1 (ED. 12-96)Page 256
Name of Respondent This Report Is:Date of Report Year/Penod of Report
Idaho Power Company (1) (!An Original (Mo, Da, Yr)End of 2010/Q4
(2) riA Resubmission 04/15/2011
LONG-TERM DEBT (Accunt 221, 222, 223 and 224) (Continued)
10.Identify separate undisposed amounts applicable to issues which were redeemed in prior years.
11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, Premium
on Debt - Credit.
12. In a footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to long-term
advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid
during year. Give Commission authorization numbers and dates.
13. If the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee
and purpose of the pledge.
14. If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end of
year, describe such securities in a footnote.
15. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest
expense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427, interest on
Long-Term Debt and Account 430, Interest on Debt to Associated Companies.
16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.
AMORTIZATION PERIOD uLltstanç:in~Une
Nominal Date Date of (Total amount outstan ing without Interest for Year No.
of Issue Matunty Date From Date To reduction for amounts held by Amount
(d)(e)(f)(g)
resllMent)
(i)
1
2
11/20/09 311/20 11120/09 311/20 130,000,000 5,850,000 3
4
5
05/01/03 04/01/33 05/01/03 03/31/33 70,000,000 3,850,000 6
7
8
4/1/09 4/1/19 4/1/09 4/1/19 100,000,000 6,150,000 9
10
11
11/1/10 51112020 1111/10 511120 100,000,000 1,142,778 12
13
08/26/05 08/26/35 08/26/05 08/26/35 60,000,000 3,180,000 14
15
16
03/02/01 03/02/11 03/02/01 03/02/11 120,000,000 7,920,000 17
18
05/01/03 10/01/13 05/01/03 09/29/13 70,000,000 2,975,000 19
20
21
11/15/02 11/15112 11/15/02 11/15/12 100,000,000 4,750,000 22
23
24
11/15/02 11/15/32 11/15/02 11/15/32 100,000,000 6,000,000 25
26
27
08/16/04 08/16/34 08/16/04 08/16/34 55,000,000 3,231,250 28
29
30
03/26/04 03/15/34 03/26/04 03/15/34 50,000,000 2,750,000 31
32
1,612,790,455 80,490,049 33
FERC FORM NO.1 (ED. 12-96)Page 257
Name of Respondent This wort Is:Date of Report Year/Penod of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) FiA Resubmission 04/15/2011
LONG-TERM DEBT (Accunt 221,222,223 and 224)
1. Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221, Bonds, 222,
Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt.
2. In column (a), for new issues, give Commission authorization numbers and dates.
3. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds.
4. For advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate
demand notes as such. Include in column (a) names of associated companies from which advances were received.
5. For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were
issued.
6. In column (b) show the principal amount of bonds or other long-term debt originally issued.
7. In column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued.
8. For column (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount.
Indicate the premium or discount with a notation, such as (P) or (D). The expenses, premium or discount should not be netted.
9. Furnish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with
issues redeemed during the year. Also, give in a footnote the date of the Commission's authorization of treatment other than as
specified by the Uniform System of Accounts.
Line Class and Senes of Obligation, Coupon Rate Pnncipal Amount Total expense,
No.(For new issue, give commission Authonzation numbers and dates)Of Debt issued Premium or Discount
(a)(b)(c)
1
2 4.85% Senes Due 2040 OPUC UF4263 IPUC IPC-E-10-10 WPSC 20005-32-ES-10 100,000,000 169,984 D
3
4 6.30% Senes due 2037 140,000,000 1,495,799
5 278,367 D
6
7 6.25% Series due 2037 100,000,000 1,141,489
8 267,677 D
9
10 Port of Morrow Variable due 2027 4,360,000 188,545
11
12 Humboldt Vanable due 2024 49,800,000 1,697,856
13
14 Sweetwater Vanable due 2026 116,300,000 3,026,122
15
16
17 6.025 % Senes Due 2018 120,000,000 1,630,120
18
19 Subtotal Accunt 221 1 ,585,460,000 24,685,286
20
21 Accunt 222 - Reaquired Bonds
22
23 Accunt 223: Advances for Associated Companies
24
25 Accunt 224:
26 Bond Guarantee - American Falls 19,885,000
27 Note Guarantee - Milner Dam 11,700,000
28 Subtotal Accunt 224 31,585,000
29
30
31
32
33 TOTAL 1,617,045,000 24,68,286
FERC FORM NO.1 (ED. 12-96)Page 256.1
.
Name of Respondent This Report Is:Date of Report Year/Period of Report
Idaho Power Company (1) (!An Original (Mo, Da, Yr)End of 2010/Q4
(2) DA Resubmission 04/15/2011
LONG-TERM DEBT (Accunt 221,222,223 and 224) (Continued)
10.Identify separate undisposed amounts applicable to issues which were redeemed in prior years.
11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, Premium
on Debt - Credit.
12. In a footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to long-term
advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid
during year. Give Commission authorization numbers and dates.
13. .If the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee
and purpose of the pledge.
14. If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end of
year, describe such securities in a footnote.
15. If interest expense was incIJrred during the year on any obligations retired or reacquired before end of year, include such interest
expense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427, interest on
Long-Term Debt and Account 430, Interest on Debt to Associated Companies.
16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.
AMORTIZATION PERIOD ul!tstan!JJnS LineNominal Date Date of (Total amount outstan ing without Interest for Year No.of Issue Maturity Date From Date To reduction for amounts held by Amount
(d)(e)(f)(g)
resPYh)dent)
(i)
1
2/15/10 8/15/40 2/15110 8/15/40 100,000,000 1,630,139 2
3
6/22/07 6/15/2037 6/22/07 6/15/2037 140,000,000 8,820,000 4
5
6
10/18/07 10/15/2037 10/18/07 10/15/2037 100,000,000 6,250,000 7
8
9
05/1700 02/01/27 05/17/00 02101/27 4,360,000 90,432 10
11
10/22103 12101/24 11/01/03 12/01/24 49,800,000 2,564,700 12
13
10/3/06 7/15/26 10/3/06 7/15/2026 116,300,000 6,105,750 14
15
16
7/0108 7/15/18 7/10/08 7/15/08 120,000,000 7,230,000 17
18
1,585,460,000 80,490,049 19
20
21
22
23
24
25
04/26/00 2/1/25 19,885,000 26
02/10/92 7,445,455 27
27,330,455 28
29
30
31
32
1,612,790,455 80,490,049 33
FERC FORM NO.1 (ED. 12-96)Page 257.1
THIS PAGE INTENTIONALLY LEFT BLANK
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) FiA Resubmission 04/15/2011
RECONCILIATION OF REPORTED NET INCOME WITH TAXBLE INCOME FOR FEDERAL INCOME TAXES
1. Report the reconciliation of reported net income for the year with taxable income used in computing Federal income tax accuals and show
computation of such tax accruals. Include in the reconciliation, as far as practicable, the same detail as furnished on Schedule M-1 of the tax return for
the year. Submit a reconciliation even though there is no taxable income for the year. Indicate clearly the nature of each 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
separate return were to be field, indicating, however, intercompany amounts to be eliminated in such a consolidated return. State names of group
member, tax assigned to each group member, and basis of allocation, assignment, or sharing of the consolidated tax among the group members.
3. A substitute page, designed to meet a particular need of a company, may be used as Long as the data is consistent and meets the requirements of
the above instructions. For electronic reporting purposes complete Line 27 and provide the substitute Page in the context of a footnote.
Line Partculars (Details)Amount
No.(a)(b)
1 Net Income for the Year (Page 117)140,634,223
2
3
4 Taxable Income Not Reported on Books
5
6
7
8
9 Deductions Recorded on Books Not Deducted for Return
10
11
12
13
14 Income Recorded on Books Not Included in Return
15
16
17 .
18
19 Deductions on Return Not Charged Against Book Income
20
21
22
23
24
25
26
27 Federal Tax Net Income -3,475,271
28 Show Computation of Tax:
29 Tenative Federal Tax (g 35%-1,216,345
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
FERC FORM NO.1 (ED. 12-96)Page 261
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2S An Original (Mo, Da, Yr)
Idaho Power Company I (2) A Resubmission 04/15/2011 2010/Q4
FOOTNOTE DATA
Schedilijje:-iiftIii-iio::-S----Coliimn:b--------------..-----~-------------;004003-CONSTRUCTION ADV-252 $ (3,638,428)004005-AVOIDED COST INT CAP 10,496,226
00401 O-EMISSION ALLOWANCE-254.409-411 2,022,525
004013-CIAC AS TAXBLE INC IN ACCT 107 (3,796,723)004021-ENGINEERING FEES-IN ACCT 107 -FED ONLY 23,493004022-FERC CREDIT OFA-254.307 (620,808)004506-CIAC-MERIDIAN GOLD (56,560)004507-CIAC-MICRON-DRAM (608,470)Total $ 3,821,255
'Schedu/e Page: 261 Line No.: 10 Column: b
Total Federal and State taxes deducted on books.
005001-BAD DEBT EXPENSE
005010-SFAS 112-POST -EMPL Y BEN 182/253
005014-0VERACCRUED VACATION-ACCT 242
005017 -INJURIES & DAMAGES
005019-DIRECTORS FEES DEF
005022-CAPITALIZED OVERHEADS
005024-MEALS (50% NON-DEDUCTIBLE) CHRGD TO R.E.
005025-MILNER FALLING WATER - REV ACCRL
005027-AMORTIZATION OF ACCOUNT 114
005028-0REGON OPER PROPERTY TAX ADJ
005023-PENSION EXPENSE-Acct 228
005033-NONVEBA PEN&BEN-Acct 228
005035-PCA EXPENSE DEFERRAL
005043-AMERICAN FALLS - FALLING WATER CONTRACT-FT
005047-0THER EMPLOYEE'S L T DEFERRED COMP-228
005052-AMORTIZATION OF ACCOUNT 181
005053-STOCK BASED COMPENSATION
005054-IPUC GRID WEST LOANS-ACCT 182
005055-0PUC GRID WEST LOANS-ACCT 182
005056-FERC GRID WEST EXP-ACCT 182
005057 -INTERVENER FUNDING ORDERS-ACCT 182
005058-FIXED COST ADJUSTMENT (FCA)-ACCT 182
005059-PS & I COSTS-COAL & CHP PLANTS-WRITE OFF
005060-0REGON-PCAM (POWER COST ADJ MECHANISM)
005061-PENSION EXPENSE-OREGON
005501-SEC PLAN-NET INS COSTS
005503-128-EDC-UNRLZD GN/LS FRM RABBI TRUST
005504-NONDEDUCTIBLE POLITICAL EXP-426.4
005505-SEC PLAN-BENEFIT ACCR
005510-FINES & PENALTIES-OPERATING
005531-RATE CASE DISALLOWANCES-REVERSE AMORT
005532-DELIVERY ACCRUALS-253.550
005537-BRIDGER SIERRA RESERVE-LEGAL FEES-Acct 228.4
005540-UNREALIZED LOSS ON INVESTMENTS-Acct 124
Total
$ 6,833,881
(349,041)
(667,857)
287,966
(81,597)
281,628
(10,000,000)
600,000
(429,332)
(22,723)
(86,638)
(56,779,214)
(407,649)
53,361,395
219,181
(471,456)
211,660
103,433
186,435
10,624
83,796
(32,055)
(4,504,939)
71,720
(192,580)
884,236
(201,936)
(407,115)
823,695
2,383,660
(203,479)
(296,299)
(107,585)
(250,000)
(156,030)
$ (9,304,215)
_......_- ----- -~~---------_...._...~--~-~._.
'Schedule Page: 261 Line No.: 15 Column: b
007010-AFUDC HC RELICENSING-ACCT 229
IFERC FORM NO.1 (EO. 12-87)
$ (11,316,461)
Page 450.1
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company 1(2)A Resubmission 04/15/2011 2010/Q4
FOOTNOTE DATA
007011-0ATI REVENUE DEFICIENCY
007501-REVERSE EQUITY EARNINGS OF SUBSIDIARIES
007502-ALLOWANCE FOR OFUDC
007503-ALLOWANCE FOR BFUDC
007504-RECLASS TAX EXEMPT INTEREST-FED ONLY
Total
303,355
7,546,333
16,551,145
10,675,095
5,796 _
23,765,263$
'Schedule Page: 261 Line No.: 20 Column: b
008001-VEBA-POST RET BNFTS-TRUST-ACCT 228
008009-DEPR FOR TAX GT OR L T BOOK
008016-VEBA-POST RET BNFTS-TRUST-MEDICARE PART D
008020-CONSERVATION PROGRAMS
008025-MANUFACTURING DEDUCTION
008027-NEVADA OPERATING PROPERTY TAX ADJ
008034-REMOVAL COSTS
008038-0REGON EXCESS PWR SUPPLY COSTS
008039-ST TAX-NOT DEDUCTED ON PRIOR RETURN
008041-AM FALLS - UNAMORTIZED DEBT EXP
008042-GAIN/LOSS ON REACQUIRED DEBT-FT
008057 -REORGANIZATION COSTS
008072-INTANGIBLE ASSET-LABOR DEDUCT-107-FED ONLY
008073-REPAIRS DEDUCTION
008071-PP INS & OTR EXP (1 YR OR LESS)-165
008501-COLl-TAX ADJ FROM BOOKS
008504-0REGON NONOP PROPERTY TAX ADJUST
008703-IPCO -162 (M) $1m THRESHOLD
IRS INTEREST EXPENSE
STATE INCOME TAX DEDUCTED ON FEDERAL RETURN
Total
$ (249,151)
66,918,590
(1,972,951 )
7,259,992
(229,000)34,869
8,144,207
(1,195,682)
813,266
(47,999)
(915,215)
(222,581)
1,561,500
30,000,000
(140,840)
169,988
72
(578,245)
51,028
5,459,423 _
$ 114,861,271
IFERC FORM NO.1 (ED. 12-87) Page 450.2
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) Fi A Resubmission 04/15/2011
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
1. Give partculars (details) of the combined prepaid and accued tax accunts and show the total taxes charged to operations and other accunts during
the year. Do not include gasoline and other sales taxes which have been charged to the accunts to which the taxed material was charged. If the
actual, or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts.
2. Include on this page, taxes paid during the year and charged direct to final accunts, (not charged to prepaid or acced taxes.)
Enter the amounts in both columns (d) and (e). The balancing of this page is not affeced by the inclusion of these taxes.
3. Include in column (d) taxes charged during the year, taxes charged to operations and other accunts through (a) accals credited to taxes accued,
(b)amounts credited to proportons of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accunts other
than acced and prepaid tax accunts.
4. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertined.
ine Kind of Tax BALANCE AT BEGINNING OF YEAR c1~~~~T~:ff Adjust-
No.(See instruction 5)Taxes Accrer:Prepaid Taxes ~nng ~~~g ments
(Accunt 236)(Include in Accunt 165)ear
(a)(b)(c)(d)(e)(f)
1 Federal:
2 Income -5,203,080 -62,281,493 -46,400,085
3 Social Security - (FOAB)2,124 12,457,819 12,459,015
4 Unemployment 120,285 120,285
5 Subtotal Federal -5,200,956 -49,703,389 -33,820,785
6
7 State of Idaho:
8 Propert 5,673,820 225 14,934,613 14,373,248
9 Non-Operating 21,866 17,978 28,188
10 Income -4,578,526 -5,372,288 -11,007,839
11 KWH 119,182 1,645,778 1,667,811
12 Unemployment -3 1,071,470 1,071,471 -3
13 Regulatory Commission 1,837,184 1,837,184
14 Business License - Sho Ban 150 300 150
15 Subtotal Idaho 1,236,339 375 14,135,035 7,970,213 -3
16
17 State of Oregon
18 Propert 1,090,708 2,228,127 2,397,398
19 Non-Operating Propert 766 1,605 1,676
20 Income -261,555 -118,383 -327,364
21 Regulatory Commission 21,300 92,603 113,903
22 Unemployment 7 36,776 36,776 7
23 Franchise 160,894 713,129 667,258 28,447
24 Subtotal Oregon -79,354 1,091,474 2,953,857 2,889,647 28,454
25
26 State of Montana:
27 Propert 119,148 210,443 224,454
28 Subtotal Montana 119,148 210,443 224,454
29
30 State of Nevada:
31 Propert 533,334 1,108,774 1,143,643
32 Business Tax
33 Subtotal Nevada 533,334 1,108,774 1,143,643
34
35 State of Wyoming
36 Corporate License 3,950 3,950
37 Propert 564,102 1,271,134 1,199,669
38 Subtotal Wyoming 564,102 1,275,084 1,203,619
39 Other States Income 106,794 -129,661 -32,802
40 Payroll Adjustment -13,686,351
41 TOTAL -3,253,927 1,625,183 -43,836,208 -20,422,011 28,451
FERC FORM NO.1 (ED. 12-96)Page 262
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) riA Resubmission 04/15/2011
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued)
5. If any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year,
identifying the year in column (a).
6. Enter all adjustments of the accrued and prepaid tax accunts in column (f) and explain each adjustment in a foot- note. Designate debit adjustments
by parentheses.
7. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductons or otherwise pending
transmittal of such taxes to the taxing authority.
8. Report in columns (i) through (i) how the taxes were distributed. Report in column (I) only the amounts charged to Accunts 408.1 and 409.1
pertining to electric operations. Report in column (I) the amounts charged to Accunts 408.1 and 109.1 pertining to other utility departents and
amounts charged to Accunts 408.2 and 409.2. Also shown in column (I) the taxes charged to utilty plant or other balance sheet accunts.
9. For any tax apportioned to more than one utility departent or accunt, state in a footnote the basis (neceity) of apportioning such tax.
BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED Une
(Taxes accued P,epald T.,as ~ .""""n"." ,-,Adjustments to Ret.Other No.
ACC~m236)(Incl. in Accunt 165) (Accunt 408.1,409.1) (Accunt 409.3)Earnings (Accunt 439)(h) (i) 0)(k)(I)
1
-21,084,488 -59,254,526 ~
927 12,457,819 3
120,285 4
-21,083,561 -46,676,422 -3,026,967 5
6
7
6,798,477 14,934,613 8
11,656 ~1,057,025 -4,800,681
97,149 1,645,778 11
-1 1,071,470 12
1,837,184 13
300 14
7,964,306 14,688,664 -553,629 15
16
17
1,177,346 2,228,127 18
838 ~-52,574 -91,673 20
92,603 21
36,776 22
178,317 713,129 23
125,743 1,178,184 2,978,962 -25,105 24
25
26
105,137 210,443 27
105,137 210,443 28
29
30
568,203 1,108,774 31
32
568,203 1,108,774 33
34
35
3,950 36
635,567 1,271,134 37
635,567 1,275,084 38
9,936 -126,949 ~
-13,686,351 40
-12,242,872 1,746,387 -40,227,795 -3,608,413 41
FERC FORM NO.1 (ED. 12-96)Page 263
THIS PAGE INTENTIONALLY LEFT BLANK
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ó An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2011 2010/Q4
FOOTNOTE DATA
Schedule Page: 262 Line No.: 1 Column: i
This footnote is for the total of Column I on page 263. The total of column I and the
amounts associated with accounts 408.1 & 409.1 in column I should total back to the sum of
lines 14, 15 & 16 on page 114. For the year 2010 this cross-check will not work as the
total of lines 14-16 on page 114 is $ 73,298,449 additional expense than line 41 page 263.
This difference represents an amount booked for the accounting of FIN #48. When FIN #48
was booked it does use account 409.1, however the other side of the entry is not
assocaited with account 236 or 165. Therefore FIN #48 will show up on page 114 but will
not be on pages 262 & 263.
'Schedule Page: 262Account 409.2
234
Line No.: 2 Column: i
$ (2,812,996)
(213,971)
Total $ (3,026,967)
¡Schedule Page: 262 Line No.: 9 Column: i
Account 409.2 $ 17,978
¡Schedule Page: 262 Line No.: 10 Column: iAccount 409.2 $ (533,113)234 (38,494)
Total $ (571,607)
-----
¡Schedule Page: 262Account 409.2
Schedule Page: 262Account 409.2
234
Line No.: 19 Column: i
$ 1,605
Line No.: 20 Column: i
$ (24,753)
(1,957)
Total $ (26,710)
¡Schedule Page: 262 Line No.: 39 Column: iAccount 409.2 $ (2,059)234 (653)
$ (2,712)
IFERC FORM NO.1 (ED. 12-87) Page 450.1
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) nA Resubmission 04/15/2011
ACCUMULA ED DEFERRED INVESTMENT TAX RED ITS (Accunt 255)
Report below information applicable to Account 255. Where appropriate, segregate the balances and transactions by utilty and
nonutility operations. Explain by footnote any correction adjustments to the account balance shown in column (g).Include in column (i)
the average period over which the tax credits are amortized.
ine Accunt
No.Subdi~~sions of Year Deferred for Year Current Yeats Income Adjustments(b) Accur:t No. Arount Accurit NO. AAouri ( )(c) (d) (e) (f) g
1 Electric Utiity
23%
34%825,558 88,71~
47%
510%27,102,330 1,589,64€
6 1,293,701 26,72~
7 44,283,936 411.4 1,844,480 411.4 1,672,587
8 TOTAL 73,505,525 1,844,480 3,371,67C
9 Other (List separately
and show 3%, 4%, 7%,
10% and TOTAL)
10 Line 6 Col A 11%
11
12 State of Idaho 44,283,936 411.4 1,844,481 411.4 1,672,581
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
30
31
32
33
34 ,
35
36
37
38
39
40
41
42
43
44
45
46
47
48
FERC FORM NO.1 (ED. 12-89)Page 266
ACCUMULATED D
This ~ort Is:
(1) ~An Original
(2) A Resubmission
FERRED INVESTMENT TAX CREDI
Date of Report
(Mo, Da, Yr)
04/15/2011
S Accunt 255) (continued)
Year/Period of Report
End of 2010/Q4
Name of Respondent
Idaho Power Company
ADJUSTMENT EXPLANATION Line
No.
736,844 9.31
1
2
3
4
5
6
7
8
9
25,512,684
1,266,978
44,455,829
71,972,335
17.05
48.41
26.48-~---~-~-~--~
10
11
12
13
14.
15
16
17
18
19
20
21
22
23
24
25
26
27
28
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
44,455,830
FERC FORM NO.1 (ED. 12-89)Page 267
THIS PAGE INTENTIONALLY LEFT BLANK
Name of Respondent This 7!0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) Fi A Resubmission 04/15/2011
OTHER DEFFERED CREDITS (Accunt 253)
1.Report below the particulars (details) called for concerning other deferred credits.
2.For any deferred credit being amortized, show the period of amortzation.
3.Minor items (5% of the Balance End of Year for Accunt 253 or amounts less than $100,000, whichever is greater) may be grouped by classes.
Line Descrption and Other Balance at DEBITS Balance at
No.Deferred Credits Beginning of Year Contra Amount Credits End of Year
(b)
Accunt
(f)(a)(c)(d)(e)
1 Smart Grid various 52,765,478 62,803,733 10,038,255
2
3 Point to Point Transmission Study 1,741,105 various 1,671,495 723,676 793,286
4
5 FTV 4,866,666 400 400,000 4,466,666
6
7 Sho Ban Trans ROW 378,150 242 115,650 262,500
8
9 Delivery Accuals 97,063 107/401 622,605 544,592 19,050
10
11 Milner Fallng Water 1,861,890 186 1,063,636 634,305 1,432,559
12
13 Postretirement Benefits 4,516,526 401 667,857 3,848,669
14
15 Directors Deferred Compensation 4,329,923 131 340,677 622,304 4,611,550
16
17 IBM Mainframe Softare Licenses 1,514,798 232 393,486 1,121,312
18 (amort period 2010 - 2015)
19
20 Minor Items (2)57,150 various 338,774 356,046 74,422
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 TOTAL 19,363,271 58,379,658 65,684,656 26,668,269
FERC FORM NO.1 (ED. 12-94)Page 269
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2010/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2011
ACCUMULATED DEFFERED INCOME TAXES - OTHER PROPERTY (Accunt 282)
1. Report the information called for below concerning the respondent's accounting for deferred income taxes rating to propert not
subject to accelerated amortzation
2. For other (Specify),include deferrals relating to other income and deductions.
CHANGES DURING YEAR
Line
No.
Accunt Balance at
Beginning of Year Amounts Debited
to Accunt 410.1
(c)
Amounts Credited
to Accunt 411.1
(d)(a)(b)
1 Accunt 282
2 Electric
3 Gas
4 Other
5 TOTAL (Enter Total of lines 2 thru 4)
6 Non-Operating Propert
7 Other - Regulatory Asset for I
8
9 TOTAL Accunt 282 (Enter Total of lines 5 thru
10 Classification of TOTAL
11 Federal Income Tax
12 State Income Tax
13 Local Income Tax
282,033,763 40,025,883 37,265,774
382,135,977
664,169,740 40,025,883 37,265,774------~~-~--------~ -~ -~---
558,484,600
105,685,140
39,880,644
145,239
36,776,391
489,383
NOTES
FERC FORM NO.1 (ED. 12-96)Page 274
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2010/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2011
ACCUMULATED DEFERRED INCOME TAXES - OTHER PROPERTY (Accunt 282) (Continued)
3. Use footnotes as required.
CHANGES DURING YEAR
Amounts Debited Amounts Credited
to Accunt 410.2 to Accunt 411.2
ADJUSTMENTS
Amount
Balance at
End of Year
Line
No.Debits
182 157,212,32
197,291,82
7
8
9
o
601,940,14 11
105,069,20 12
13
---~--~------- ------- ~-~~--- -~---~- ~--- ~ ---~157,212,32
131,878,19
25,334,12
172,229,48
25,062,33
NOTES (Continued)
FERC FORM NO.1 (ED. 12-96)Page 275
THIS PAGE INTENTIONALLY LEFT BLANK
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2) A Resubmission 04/15/2011 2010/Q4
FOOTNOTE DATA
!Schedule Page: 274 Line No.: 2 Column: b
2,010 Changes during Year Ad Dr AdiCr 2,010
Beginning DR to CRto DR to CRto Acc.Acc.Ending
Accunt Balance 410.1 411.1 410.2 411.2 cr Amt dr Amt Balance
(a)b c d e f g h i i k
Acclerated Depreciation 269,668,778 38,734,246 36,916,284 271,486,739
Intangible Asset-Labor Oed 13,029,653 230,969 13,260,623
Valmy Capitalized Items 504,266 76,500 427,766
Engineering Fees in Acc 107 (133,441)13,210 21,433 (141,663)
Misc Softare Develop Costs 365,323 (281,396)83,927
Taxable CIAC in CWIP Bal.(1,400,817)1,328,853 251,557 (323,520\
TOTAL Line 2 282,033,763 40,025,883 37,265,774 0 0 0 0 284,793,872
IFERC FORM NO.1 (ED. 12-87) Page 450.1
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2010/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2011
ACCUMULATED DEFFERED INCOME TAXES - OTHER (Account 283)
1. Report the information called for below concerning the respondent's accounting for deferred income taxes relating to amounts
recorded in Account 283.
2. For other (Specify),include deferrals relating to other income and deductions.
1 Accunt 283
2 Electric
3 Other Electric -- See Note
4
5
6
7
(a)
Balance at
Beginning of Year
(b)
Line
No.
Accunt
8 Other -- See Note
9 TOTAL Electrc (Total of lines 3 thru 8)
10 Gas
11
12
13
14
15
16
17 TOTAL Gas (Total of lines 11 thru 16)
18 Other - See Note
19 TOTAL (Acc 283)(EnterTotal of lines 9, 17 and 18)
20 Classification of TOTAL
21 Federal Income Tax
22 State Income Tax
23 Local Income Tax
91,781,031
17,631,332
12,664,760
2,432,932
26,789,995
5,146,424
NOTES
FERC FORM NO.1 (ED. 12-96)Page 276
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2010/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2011
ACCUMULATED DEFERRED INCOME TAXES - OTHER (Accunt 283) (Continued)
3. Provide in the space below explanations for Page 276 and 277. Include amounts relating to insignificant items listed under Other.
4. Use footnotes as required.
CHANGES DURING YEAR
Amounts Debited Amounts Credited
to Accunt 410.2 to Accunt 411.2
ADJUSTMENTS
Balance at
End of Year
(k)
Line
No.
232,171
44,601
59,376
11,407
5,744,099
1,103,436
25,656,008 3
4
5
6
7
73,705,667 8
99,361,675 9
o
11
12
13
14
15
16
17
265,485 18
99,627,160 19
o
83,572,690 21
16,054,470 22
23
6,847,535
6,847,535~~--~--~----~----------~-~-------
~~~--------- ---~------~----------
276,772
276,772
70,783
70,783 6,847,535
NOTES (Continued)
FERC FORM NO.1 (ED. 12-96)Page 277
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2) A Resubmission 04/15/2011 2010/Q4
FOOTNOTE DATA
'Schedule Page: 276 Line No.: 3 Column: b
2010 Changes durin Year AdDr Adicr 2010
Beginning DR to CRto DR to CRto Acc.Acc Ending
Accunt Balance 410.1 411.1 410.2 411.2 cr Amt dr Amt Balance
(a)b c d e f a h i i k
PCA Expense Deferral
27,918,362 8,843,833 29,705,470 7,056,724
Conservation Programs
4,772,178 4,116,522 1,278,228 7,610,472
Oregon Excess Power Costs
3,114,987 558,151 2,556,836
Oregon PCAM
2,144,525 240,6~7 165,328 2,219,814
IPUC Grid West Loans
145,774 72,887 72,887
OA TT Revenue Deficiency
688,508 122,588 3,991 807,104
Reorganization Costs
447,717 87,018 360,699
FERC Grid West Expense
109,201 32,760 76,440
OPUC Grid West Loans
27,269 10 4,163 23,116
Intervenor Funding Orders
34,808 12,915 384 47,340
Fixed Cost Adjustment
3,063,369 1,761,206 4,824,575
PS & i Costs-Coal & CHP Plants
28,039 28,039 (0)
TOTAL
42,494,736 15,097,692 31,936,419 ----25,656,008
'Schedule Page: 276 Line No.: 8 Column: b
Pension 59,698,538 190 4,660,262 64,358,800
Postretirement Plan
5,990,982 190 1,449,478 7,440,460
Unrealized gains on Mkt Secu
1,168,611 219 737,796 1,906,407
TOTAL
66,858,132 -----6,847,535 73,705,667
Schedule Page: 276 Line No.: 18 Column: b
Advance Coal Royalties 246,755 66,347 19,548 293,554
Oregon Non-Op Prop Tax Adj
299 28 328
Unrealized GIL From Rabbi Tst
(187,558)210,397 51,236 (28,397)
TOTAL
59,496 --276,772 70,783 --265,485
IFERC FORM NO.1 (ED. 12-87) Page 450.1
Name of Rèspondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) nA Resubmission 04/15/2011
OTHER REGULATORY LIABILITIES (Accunt 254)
1. Report below the particulars (details) called for conceming other regulatory liabilties, including rate order docket number, if
applicable.
2. Minor items (5% of the Balance in Account 254 at end of period, or amounts less than $100,000 which ever is less),may be grouped
by classes.
3. For Regulatory Liabilties being amortized, show period of amortization.
Balance at Begining DEBITS Balance at End
Line Descrption and Purpose of of Current of Current
No.Other Regulatory Liabilties QuarterlYear Accunt Amount Credits QuarterlYearCredited
(a)(b)(e)(d)(e)(f)
1 Market to Market Short Term -IPUC Order#28661 502,669 175 1,027,997 1,09,554 573,226
2
3 Oreon Solar Pilot -Advice # 10-11 Varius 223,745 421,370 197,625
4
5 FAS 133 - Market to Market-IPUC Order # 28661 212,580 175 470,50 257,920
6
7 Oreon Gren Tags 182 28,227 223,492 195,265
8
9 Emission Sales IEEP- Order #30529 479,101 Varius 175,477 67,587 371,211
10
11 Unfunded Accumulate Deferr Income Tax 47,183,294 190 4,336,426 3,352,270 46,199,138
12
13 FERC Credit for OFA -IPUC Order #30754 1,086,401 401 672,542 51,734 465,593
14 (amort period 09/06 - 09/11)
15
16 Regulatory unfunded Accum Deferrd Income Tax Various 533,17 7,774,317 7,241,146
17
18 Minor Items (4)14,034 Various 389,04 411,712 36,698
19
20
21
22
23
24
25
26 .
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41 TOTAL 49,478,079 7,857,133 13,658,956 55,279,902
FERC FORM NO. 1/3-Q (REV 02-04)Page 278
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2010/Q4
This Report Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2011
ELECTRIC OPERATING REVENUES (Accunt 400)
1. The following instructions generally apply to the annual version of these pages. Do not report quarterly data in columns (c), (e), (f), and (g). Unbiled revenues and MWH
related to unbiled revenues need not be reported separately as required in the annual version of these pages.
2. Report below operating revenues for each prescribed accunt, 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 accunts; except that where separate meter readings are added
for billing purposes, one customer should be counted for each group of meters added. The -average number of customers means the average of twelve figures at the close of
each month.
4. If increases or decreases frm previous period (columns (c),(e), and (g)), are not derived from previously reported figures, explain any inconsistencies in a fotnote.
5. Disclose amounts of $250,000 or greater in a footnote for accunts 451, 456, and 457.2.
(a)
Operating Revenues Year
to Date Quarterly/Annual
(b)
Operating Revenues
Previous year (no Quartrl)
(c)
Line
No.
Title of Accunt
Sales of Electricity
2 (440) Residential Sales
3 (442) Commercial and Industrial Sales
4 Small (or Comm.) (See Instr. 4)
5 Large (or Ind.) (See Instr. 4)
6 (444) Public Street and Highway Lighting
7 (445) Other Sales to Public Authorities
8 (446) Sales to Railroads and Railways
9 (448) Interdepartmental Sales
1 0 TOTAL Sales to Ultimate Consumers
11 (447) Sales for Resale
12 TOTAL Sales of Electricity
13 (Less) (449.1) Provision for Rate Refunds
14 TOTAL Revenues Net of Provo for Refunds
15 Other Operating Revenues
16 (450) Forfeited Discounts
17 (451) Miscellaneous Service Revenues
18 (453) Sales of Water and Water Power
19 (454) Rent from Electc Propert
20 (455) Interdepartmental Rents
21 (456) Other Electrc Revenues
22 (456.1) Revenues from Transmission of Electricity of Others
23 (457.1) Regional Control Service Revenues
24 (457.2) Miscellaneous Revenues
25
26 TOTAL Other Operating Revenues
27 TOTAL Electrc Operating Revenues
338,716,361
138,394,166
3,278,628
339,240,028
141,529,986
3,230,165
880,995,785
78,133,502
959,129,287
10,667,522
948,461,765
893,479,498
94,373,321
987,852,819
-2,551,647
990,404,466
3,532,831 3,811,350
21,141,127 18,272,233
44,517,995
15,398,402
32,457,459
1,050,873
84,590,355
1,033,052,120
55,591,915
1,045,996,381
FERC FORM NO. 1/3-Q (REV. 12-05)Page 300
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2010/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da. Yr)
(2) A Resubmission 04115/2011
ELECTRIC OPERATING REVENUES (Accunt 400)
6. Commercial and industnal Sales, Accunt 442. may be classified accrding to the basis of classification (Small or Commercial, and Large or Industrial) regularly used by th
respondent if such basis of classification is not generally greater than 1000 Kw of demand. (See Accunt 442 of the Uniform System of Accunts. Explain basis of classification
in a footnte.)
7. See pages 108-109, Importnt Changes During Period, for importnt new terrtory added and importnt rate increase or decreases.
8. For Unes 2,4.5.and 6. see Page 304 for amounts relating to unbiled revenue by accunt.
9. Include unmetered sales. Provide details of such Sales in a footnote.
MEGAWATT HOURS SOLD
Year to Date Quartrly/Annual Amount Previous year (no Quarterl)~) 00 AVG.NO. CUSTOMERS PER MONTH Line
Current Year (no Quarterly) Previous Year (no Quarterly) No.(ij (g)
5,439,730 5,476,690 81,571 81,532
3,075,379 3.140,209 124 127 5
30,016 30,938 1,459 1,372 6
7
8
9
13,512,504 13,948,280 490,705 488.175 10
1,981,936 2,836,028 11
15,494,440 16,784.308 490.705 488,175 12
13
15,494,440 16,784,308 490,705 488,175 14
Line 12. column (b) indudes $
Line 12, column (d) indudes
-3,346,469
-25,409
of unbiled revenues.
MWH relating to unbiled revenues
FERC FORM NO.1/3-Q (REV. 12-05)Page 301
THIS PAGE INTENTIONALLY LEFT BLANK
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) riA Resubmission 04/15/2011
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescrbed operating revenue accunt in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue accunt, List the rate schedule and sales data under each
applicable revenue accunt subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue accunt classification (such as a general residential
schedule and an off peak water heating schedule), the entres in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bils rendered during the year divided by the number of biling periods during the year (12
if all billngs are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue biled pursuant thereto.
6. Report amount of unbiled revenue as of end of year for each applicable revenue accunt subheading.
..ine Numoer ano I ite or Kate sCheOule MWh ::010 Revenue Average Numoer I'vvnßrSares ty~'S'trcrr
No.(a)(b)(c)of c~~~omers Per ?~stomer
(f)
1 440 - Residential Sales:
2 01 - Residential 4,973,73~396,218,848 407,409 12,208 0.0797
3 03 - Residential Master Meter 4,957 377,729 22 225,318 0.0762
4 04 - Residential - EW 713 56,211 44 16,205 0.0788
5 05 - Residential - TOO 1,128 88,884 76 14,842 0.0788
6 15 - Dusk to dawn lighting 2,886 528,937 0.1833
7 Unbiled Revenues -16,053 -1,074,454 0.0669
8 Other Revenues 4,411,323
9 Total440 4,967,370 400,607,478 407,551 12,188 0.0806
10
11 442-Commercial & Industrial Sales
12 07 - General service 163,316 16,033,397 31,260 5,224 0.0982
13 09 - General service 409,534 23,044,182 181 2,262,619 0.0563
14 09 - General service 3,137,839 187,745,653 30,345 103,405 0.0598
15 09 - General service 5,321 299,881 3 1,773,667 0.0564
16 15 - Dusk to Dawn Light 4,159 691,087 0.1662
17 19 - Uniform rate contracts 2,109,565 98,195,956 116 18,185,905 0.0465
18 19 - Uniform rate contracts 7,166 368,986 1 7,166,000 0.0515
19 19 - Uniform rate contract 114,540 5,282,385 4 28,635,000 0.0461
20 24 - Irrgation Pumping 1,706,632 110,511,488 18,609 91,710 0.0648
21 40 - General service 13,154 921,212 1,173 11,214 0.0700
22 Commercial & Industrial & Unbil 843,892 33,681,230 4 210,973,000 0.0399
23 Other Revenues 334,222
24 Total 442 8,515,118 477,109,679 81,696 104,229 0.0560
25
26 444 - Public Street Lighting:
27 40 - General service 2,772 194,297 806 3,439 0.0701
28 41 - Street lighting 23,797 2,901,820 304 78,280 0.1219
2~42 - Traffc control lighting 3,379 173,468 349 9,682 0.0513
30 Other Revenues 68 9,043 0.1330
31 Total 444 30,016 3,278,628 1,459 20,573 0.1092
32
33
34
35
36
37
38
3~
40
41 TOTAL Biled 13,537,91 884,342,253 490,7Ó€27,58~0.0653
42 Total Unbiled Rev.(See Instr. 6)-25,40~-3,346,469 C C 0.1317
43 TOTAL 13,512,50A 880,995,784 490,70€27,531 0.0652
FERC FORM NO.1 (ED. 12-95)Page 304
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/04
(2) n A Resubmission 04/15/2011
SALES FOR RESALE (Accunt 447)
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the suppliets service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrpted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition Of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availabilty and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Averaie Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly iIing Avera~e Ave~
cation Tariff Number Demand (MW)Monthly NC Deman Monthly C emand
(a)--(c)(d)(e)(f)
1 Raft River Rural Electric V6-44 8.804 8.804 7.612
2 Raft River Rural Electric V6-44 n/a n/a n/a
3 .
4 Arizona Public Service Co.~WSpp n/a n/a n/a
5 Avista Corp.WSPP n/a n/a n/a
6 Avista Corp.SF WSPP n/a n/a n/a
7 Barclays Bank PLC .WSPP n/a n/a n/a
8 Black Hils Power Inc.WSPP n/a n/a n/a
9 Black Hils Power Inc.WSPP n/a n/a n/a
10 Black Hils Power Inc.SF WSPP n/a n/a n/a
11 Bonnevile Power Administration SF WSPP n/a n/a n/a
12 BP Energy Company SF WSPP n/a n/a n/a
13 Calpine Energy Services, L.P.SF WSPP n/a n/a n/a
14 Cargil Power Markets LLC WSPP n/a n/a n/a
Subtotal RO 0 0 0
Subtotal non-RO 0 0 0
Total 0 0 0
FERC FORM NO.1 (ED. 12-90)Page 310
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) n A Resubmission 04/15/2011
SALES FOR RESALE (Accunt 447) (Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups. for service provided in prior reportng
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter .Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariff under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billng demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the suppliets system reaches its monthly peak. Demand reported in columns (e) and (t) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bils rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bils rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401 ,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)ü)(k)
53,012 720,684 1,874,031 6,000 2,600,715 1
283,995 283,995 2
3
241,500 7,866,860 7,866,860 4
25 500 500 5
2,166 82,625 82,625 6
30,800 1,348,696 1,348,696 7
2,239 2,239 8
10,819 432,266 432,266 9
6,261 190,686 190,686 10
96,800 3,628,220 3,628,220 11
85,200 3,826,100 3,826,100 12
40,800 1,412,936 1,412,936 13
584,839 584,839 14
53,012 720,684 1,874,031 289,995 2,884,710
1,928,924 0 74,030,994 1,217,798 75,248,792
1,981,936 720,684 75,905,025 1,507,793 78,133,502
FERC FORM NO.1 (ED. 12-90)Page 311
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Onginal (Mo, Da, Yr)End of 2010/Q4
(2)DA Resubmission 04/15/2011
SALES FOR RESALE (Accunt 447)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( Le., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projected load for this service in its system resource planning). In addition, the reliabilty of requirements service must
be the same as, or second only to, the suppliets service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availabilty and reliability of
service, aside from transmission constraints, must match the availabilty and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Avera~e Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly iIing Avera~e Aver~
cation Tanff Number Demand (MW)Monthly NC Demani Monthly C emand
(a)(b)(c)(d)(e)(f)
1 Cargil Power Markets LLC WSPP n/a nla n/a
2 Cargil Power Markets LLC SF WSPP n/a nla n/a
3 Chelan Co PUD SF WSPP n/a n/a n/a
4 Citigroup Energy Inc.SF WSPP n/a n/a n/a
5 Conoco Phillps Company SF WSPP n/a n/a n/a
6 DB Energy Trading LLC SF WSPP n/a n/a n/a
7 EDF Trading North Amenca, LLC SF WSPP n/a n/a n/a
8 Endure Energy, LLC SF WSPP n/a n/a n/a
9 Eugene Electnc Board SF WSPP n/a n/a n/a
10 Grant CO Public Utility District #2 --SF WSPP n/a n/a n/a
11 IBERDROLA RENEWABLES, Inc.WSPP n/a n/a n/a
12 IBERDROLA RENEWABLES, Inc.SF WSPP n/a n/a n/a
13 JPMorgan Chase Bank, N.A.-n/a n/a n/a
14 J.P. Morgan Ventures Energy Corporation SF WSPP n/a n/a n/a
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORM NO.1 lED. 12-90\Paae 310.1
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) r=A Resubmission 04/15/2011
SALES FOR RESALE (Accunt 447) (Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billng demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly NCP demand is the maximum
metered hourly (60-minuteintegration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bils rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQJNon-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)ü)(k)
624 17,862 17,862 1
331,911 12,991,788 12,991,788 2
415 15,170 15,170 3
75,325 2,393,411 2,393,411 4
3,400 116,500 116,500 5
2,400 79,696 79,696 6
10,800 426,600 426,600 7
800 400 400 8
9,600 254,700 254,700 9
2,200 80,732 80,732 10
2,104 2,104 11
76,208 2,989,230 2,989,230 12
164,828 164,828 13
2,000 86,064 86,064 14
53,012 720,684 1,874,031 289,995 2,884,710
1,928,924 0 74,030,994 1,217,798 75,248,792
1,981,936 720,684 75,905,025 1,507,793 78,133,502
FERC FORM NO.1 (ED. 12-90)Page 311.1
Name of Respondent This ~ort Is:Date of Report Year/Penod of Report
Idaho Power Company (1) X An Onginal (Mo, Da, Yr)End of 2010/04
(2) nA Resubmission 04115/2011
SALES FOR RESALE (Accunt 447)
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions ofthe service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the suppliets service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrpted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Avera~e Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly iIing Avera~e Aver~
cation Tanff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 Macquane Energy LLC WSPP n/a n/a n/a
2 Macquane Energy LLC SF WSPP n/a n/a n/a
3 Morgan Stanley Capital Group Inc.-n/a n/a n/a
4 Morgan Stanley Capital Group Inc.V6-62 n/a n/a n/a
5 Morgan Stanley Capital Group Inc.SF V6-62 n/a n/a n/a
6 Morgan Stanley Capital Group Inc.WSPP n/a n/a n/a
7 Morgan Stanley Capital Group Inc.SF WSPP n/a n/a n/a
8 Nortern California Power Agency WSPP n/a n/a n/a
9 NortWestern Energy WSpp n/a n/a n/a
10 PacifiCorp Inc.SF T-7 n/a n/a n/a
11 PacifiCorp Inc.WSPP n/a n/a n/a
12 PacifiCorp Inc.SF WSPP n/a n/a n/a
13 Portland General Electric Company WSPP n/a n/a n/a
14 Portland General Electnc Company WSPP n/a n/a n/a
Subtotal RO 0 0 0
Subtotal non-RO 0 0 0
Total 0 0 0
FERC FORM NO.1 (ED. 12-90)Page 310.2
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) X An Original .(Mo, Da, Yr)End of 2010/Q4
(2) 0 A Resubmission 04/15/2011
SALES FOR RESALE (Accunt 447) (Continued)
OS - for other service. use this category only for thöse services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RO sales together and report them starting at line number one. After listing all RO sales, enter "Subtotal - RO"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RO" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RO sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly biling demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bils rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bils rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RO/Non-RO grouping (see instrction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RO" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RO" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401 ,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)(j (k)
1,371 1,371 1
73,575 3,329,198 3,329,198 2
271,134 271,134 3
150 2,300 2,300 4
144,413 4,496,237 4,496,237 5
67,560 67,560 6
400 16,808 16,808 7
15 715 715 8
1,469 1,469 9
101 3,316 3,316 10
1,211 1,211 11
1,800 66,180 66,180 12
294 294 13
5,986 150,850 150,850 14
53,012 720,684 1,874,031 289,995 2,884,710
1,928,924 0 74,030,994 1,217,798 75,248,792
1,981,936 720,684 75,905,025 1,507,793 78,133,502
FERC FORM NO.1 (ED. 12-90)Page 311.2
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/04
(2) DA Resubmission 04/15/2011
SALES FOR RESALE (Accunt 447)
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projected load for this service in its system resource planning). In addition, the reliabilty of requirements service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that serice cannot be interrpted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliabilty of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Avera~e Actual Demand (MW)
No.(Footnote Affliations)Classif-Schedule or Monthly iIing -A\tera~e Ave~
cation Tariff Number Demand (MW)Monthly NC Deman Monthly C em and
(a)(b)(c)(d)(e)(f)
1 Portland General Electric Company SF WSPP n/a n/a n/a
2 Powerex Corp.WSPP n/a n/a n/a
3 Powerex Corp.WSPP n/a n/a n/a
"
4 Powerex Corp.SF WSPP n/a n/a n/a
5 PPL EnergyPlus, LLC WSPP n/a n/a n/a
6 PPL EnergyPlus, LLC SF WSPP n/a n/a n/a
7 Prudential Bache Commodities, LLC -n/a n/a n/a
8 Public Service Company of Colorado SF WSPP n/a n/a n/a
9 Puget Sound Energy, Inc.WSPP n/a n/a n/a
10 Puget Sound Energy, Inc.SF WSPP n/a n/a n/a
11 Rainbow Energy Marketing Corporation WSPP n/a n/a n/a
12 Rainbow Energy Marketing Corporation WSPP n/a nla n/a
13 Rainbow Energy Marketing Corporation SF WSPP n/a n/a n/a
14 Seattle City Light WSPP n/a n/a n/a
Subtotal RO 0 0 0
Subtotal non-RO 0 0 0
Total 0 0 0
FERC FORM NO.1 (ED. 12-90)Page 310.3
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) n A Resubmission 04/15/2011
SALES FOR RESALE (Accunt 447) (Continued)
as - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariff under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly biling demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bils rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j. Explain in a footnote all components of the amount shown in column (j. Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401 ,¡ine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)0)(k)
7,750 282,606 282,606 1
268,597 268,597 2
47,875 1,055,388 1,055,388 3
55,691 1,780,720 1,780,720 4
43,723 43,723 5
24,316 614,759 614,759 6
3,748,887 3,748,88 7
3,121 118,470 118,470 8
6,545 170,350 170,350 9
10,837 357,055 357,055 10
80,709 80,709 11
200 4,500 4,500 12
285,082 9,900,637 9,900,637 13
2,426 74,408 74,408 14
53,012 720,684 1,874,031 289,995 2,884,710
1,928,924 0 74,030,994 1,217,798 75,248,792
1,981,936 720,68 75,905,025 1,507,793 78,133,502
FERC FORM NO.1 (ED. 12-90)Page 311.3
Name of Respondent This Report Is:Date of Report Year/Period of Report
Idaho Power Company (1 )(g An Original (Mo, Da, Yr)End of 2010/Q4
(2)D A Resubmission 04/15/2011
SALES FOR RESALE (Accunt 447)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( Le., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions ofthe service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the suppliets service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrpted for economic
reasons and is intended.to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliabilty of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Averaße Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly illng Avera~e Ave~
cation Tariff Number Demand (MW)Monthly NC Deman Monthly C emand
(a)(b)(c)(d)(e)(f)
1 Seattle City Light SF WSPP n/a n/a n/a
2 Sempra Energy Trading LLC -n/a n/a n/a
3 Sempra Energy Trading LLC WSPP n/a n/a n/a
4 Sempra Energy Trading LLC SF WSPP n/a n/a n/a
5 Shell Energy Nort America (US), L.P.WSPP n/a n/a n/a
6 Shell Energy Nort America (US), L.P.WSPP n/a n/a nla
7 Shell Energy Nort America (US), L.P.WSPP n/a n/a n/a
8 Shell Energy North America (US), L.P.SF WSPP n/a n/a n/a
9 Sierra Pacific Power Co., dba NV Energy SF T-7 n/a n/a n/a
10 Sierra Pacific Power Co., dba NV Energy WSPP n/a n/a n/a
11 Sierra Pacific Power Co., dba NV Energy WSPP n/a n/a n/a
12 Southem California Edison WSPP n/a n/a n/a
13 TransAita Energy Marketing (U.S.) Inc.WSPP n/a n/a n/a
14 TransAita Energy Marketing (U.S.) Inc.SF WSPP n/a n/a n/a
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORM NO.1 (ED. 12-90)Page 310.4
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) nA Resubmission 04/15/2011
SALES FOR RESALE (Accunt 447) (Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line ofthe schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly biling demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the averagemonthly coincident peak (CP) .
demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line ofthe schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401 ,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)ü)(k)
6,240 215,360 215,360 1
751,140 751,140 2
2,605 2,605 3
11,000 484,840 48,840 4
242,496 242,496 5
27,499 27,499 6
40,593 999,994 999,994 7
147,101 5,737,778 5,737,778 8
46 1,762 1,762 9
128,305 128,305 10
7 199 199 11
23 23 12
5,244 5,244 13
23,600 720,590 720,590 14
53,012 720,684 1,874,031 289,995 2,884,710
1,928,924 0 74,030,994 1,217,798 75,248,792
1,981,936 720,684 75,905,025 1,507,793 78,133,502
FERC FORM NO.1 (ED. 12-90)Page 311.4
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2)o A Resubmission 04/15/2011
SALES FOR RESALE (Accunt 447)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( Le., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions ofthe service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrpted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU ~ for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Avera~e Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly illng .Avera~e Aver~
cation Tariff Number Demand (MW)Monthly NC Deman Monthly C emand
(a)(b)(c)(d)(e)(f)
1 United Materials of Great Falls 61 nla nla nla
2
3
4 LESS BAD DEBT WRITE-OFF
5
6
7
8
9
10
11
12
13
14
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORM NO.1 (ED. 12-90)Page 310.5
Name of Respondent This 780rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) ñA Resubmission 04/15/2011
SALES FOR RESALE (Accunt 447) (Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis,. enter the
average monthly billng demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the suppliets system reaches its monthly peak. Demand reported in columns (e) and (t) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j. Explain in a footnote all components of the amount shown in column (j. Report in column (k)
the total charge shown on bils rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line ofthe schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401 ,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)0)(k)
26,447 26,447 1
2
3
4
5
6
7
8
9
10
11
12
13
14
53,012 720,684 1,874,031 289,995 2,884,710
1,928,924 0 74,030,994 1,217.798 75,248,792
1,981,936 720,684 75,905,025 1,507,793 78,133,502
FERC FORM NO.1 (ED. 12-90)Page 311.5
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ó An Original (Mo. Da, Yr)
Idaho Power Company ì2) A Resubmission 04/15/2011 2010/Q4
FOOTNOTE DATA
--~----'----_.----------------'----"--'~'-
¡Schedule Page: 310 Line No.: 1 Column: b
Customer Charge ~.__~~ _ __~_____~~__~_~___~_.__
¡Schedule Page: 310 Line No.: 2 Column: b
Network Transmission Charges
lSchedule Page: 310 Line No.: 5 Column: bNon-firm Sales ----,--"----.__.' -
¡Schedule Page: 310 Line No.: 8 Column: b
Financial Transmission Losses
lSchedule Page: 310 Line No.: 9 Column: b
Non-firm Sales
lSchedu/e Page: 310 Line No.: 14 Column: b
Financial Transmission Losses
¡Schedule Page: 310.1 Line No.: 1 Column: b
Non-firm Sales --'~-'--"-'-'.._--'--'_.'-'---¡Schedule Page: 310.1 Line No.: 11 Column: b
Financial Transmission Losses
¡Schedule Page: 310.1 Line NO.:-13--Column:b
ISDA Master Agreement with JP Morgan Chase Bank dated November 4, 2005
ISchedule Page: 310.2 Line No.: 1 Column: b
Financial Transmission Losses - -- --_.._..__._'"¡Schedule Page: 310.2 Line No.: 3 Column: b
ISDA Master Agreement with Morgan Stanley dated~~.arch .1-,. 2000
SChedUiPaiie:31.2 Line No.: 4 Column: bNon-firm Sales,.-----------Schedule Page: 310.2 Line No.: 6 Column: b
Financial Transmission Losses
!Schedule Page: 310.2 ~~L¡ne No.: 8 Column: bNon-firm Sales
!Schedule Page: 310.2 Line No.: 9 Column: b
Financial Transmission Losses
¡Schedule Page: 310.2 Line NO--11-COmnb-.-----~--------~-~---
Financial Transmission Losses
~edUiePage: 310.2 Line No.: 13 Column: b
Financial Transmission Losses-- _.,--~_._--_..._._.,-~_.,_._----------_._-- - ------------_._-- .._---'...-------_..._------_._--_.'._-_.,-'Schedule Page: 310.2 Line No.: 14 Column: bNon-firm Sales
¡Schedule Page: 310.3 Line No.: 2 Column: b
Financial Transmission Losses~1i¡¡31--JiNo-:3--.-Cofumn:ii~-----. .-------.---~Non-firm Sales
rsdule Page: 310.3 Line No.: 5 Column: b
Financial Transmission Losses
~eilii¡eP¡iiiii:30:-L¡neNO~-COin:b-~~--~-~~~.-
Prudential Bache Commodities, LLC Futures Account Document, . dated September 4-,~Q08____
¡Schedule Page: 310.3 Line No.: 9 Column: b
Non-firm Sales----------_._._._-,----~._----_._-~----------_.- ~-_._-----¡Schedule Page: 310.3 Line No.: 11 Column: b
Financial Transmission Losses
¡Schedule Page: 310.3. ~~Iliie No.: 12 Column: b
Non-firm Sales
¡SChi,¡iiaiie:31-i.eNO~:-f4....-Co¡¡Îmn: b~-~-~--Non-firm Sales _.._._._--------_._._'_._.
¡Schedule Page: 310.4 Line No.: 2 Column: b
IFERC FORM NO.1 (ED. 12-87)
--
:
Page 450.1
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company I (2) A Resubmission 04/15/2011 2010/Q4
FOOTNOTE DATA
ISDA Master Agreement Ý'?:_h Sempra dated FE;eE1J_ary ~ 21..~Q~__
Schedule Page: 310.4 Line No.: 3 Column: b
Financial Transmission Losses -~~--------_._._---_._---~~.....-¡Schedule Page: 310.4 Line No.: 5 Column: b
ISDA Master Agreement with Shell Energy North America dated November 1f 2009
~chedule Page:310--~f~-~Line No.: 6 Co¡Îimii:~b ~
Financial Transmission Losses----------¡Schedule Page: 310.4 Line No.: 7 Column: b
Non-firm Sales
'Schedule Page: 310.4 Line No.: 10 Column: b
Financial Transmission Losses
¡Schedule Page: 310.4 Line No.: 11 Column: bNon-firm Sales
¡Schedule Page: 310.4 Line No.: 12 Column: b
Financial Transmission Losses¡Sciieiiiige:310.4 Line No.: 13 Column:b---~-----~~
Financial Transmission Losses
¡Schedule Page: 310.5 Line~No.: 1 Column: b
Contract Expiration Date 5/31/2013
--------~-~-------------~-l
"--I
IFERC FORM NO.1 (ED. 12-87) Page 450.2
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2010/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2011
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnote.Line Accunt Amount forNo ~~. (a) (b)
1 1. POWER PRODUCTION EXPENSES
2 A. Steam Power Generation
3 Operation
4 (500) Operation Supervision and Engineering
5 (501) Fuel
6 (502 Steam Expenses
7 (503) Steam from Other Sources
8 (Less) (504) Steam Transferred-Cr.
9 (505) Electric Expenses
10 (506) Miscellaneous Steam Power Expenses
11 (507) Rents
12 (509) Allowances
13 TOTAL Operation (Enter Total of Lines 4 thru 12)
14 Maintenance
15 (510) Maintenance Supervision and Engineering
16 (511) Maintenance of Structures
17 (512) Maintenance of Boiler Plant
18 (513) Maintenance of Electrc Plant
19 (514) Maintenance of Miscellaneous Steam Plant
20 TOTAL Maintenance (Enter Total of Lines 15 thru 19)
21 TOTAL Power Production Expenses-Steam Power (Entr Tot lines 13 & 20)
22 B. Nuclear Power Generation
23 Operation
24 (517) Operation Supervision and Engineering
25 (518) Fuel
26 (519) Coolants and Water
27 (520) Steam Expenses
28 (521) Steam from Other Sources
29 (Less) (522) Steam Transferred-Cr.
30 (523) ElectriC Expenses
31 (524) Miscellaneous Nuclear Power Expenses
32 (525) Rents
33 TOTAL Operation (Enter Total of lines 24 thru 32)
34 Maintenance
35 (528) Maintenance Supervision and Engineering
36 (529) Maintenance of Structures
37 (530) Maintenance of Reactor Plant Equipment
38 (531) Maintenance of Electric Plant
39 (532) Maintenance of Miscellaneous Nuclear Plant
40 TOTAL Maintenance (Enter Total of lines 35 thru 39)
41 TOTAL Power Producton Expenses-Nuc. Power (Entr tot lines 33 & 40)
42 C. Hydraulic Power Generation
43 Operation
44 (535) Operation Supervision and Engineering
45 (536) Water for Power
46 (537) Hydraulic Expenses
47 (538) Electric Expenses
48 (539) Miscellaneous Hydraulic Power Generation Expenses
49 (540) Rents
50 TOTAL Operation (Enter Total of Lines 44 thru 49)
51 C. Hydraulic Power Generation (Continued)
52 Maintenance
53 (541) Mainentance Supervision and Engineering
54 (542) Maintenance of Structures
55 (543) Maintenance of Reservoirs, Dams, and Waterways
56 (544) Maintenance of Electrc Plant
57 (545) Maintenance of Miscellaneous Hydraulic Plant
58 TOTAL Maintenance (Enter Total of lines 53 thru 57)
59 TOTAL Power Production Expenses-Hydraulic Power (tot of lines 50 & 58)
Amount forPrevious Year
(c)
1,888,571
146,926,801
7,337,561
1,814,867
130,234,531
7,434,710
2,140,193
9,797,755
229,315
2,568,382
8,111,562
514,732
~-~-~- - -~--- ----~-168,320,196 150,678,784
~~~-~--~-~--~---~-
2,292,767
309,374
16,067,832
3,915,291
3,753,015
26,338,279
194,658,475
2,072,391
487,528
13,675,892
3,595,301
4,639,081
24,470,193
175,148,977
--~--~ ~~------~-- ~
~----~-------~- ---- ---
5,362,099
7,322,751
10,671,807
1,565,842
2,895,723
406,432
28,224,654
5,242,496
7,174,597
10,093,906
1,470,715
2,686,753
376,849
27,045,316~-~-----~
1,967,876
1,155,653
1,368,190
3,177,811
3,029,473
10,699,003
38,923,657
2,072,103
1,396,815
1,132,574
2,962,850
2,971,583
10,535,925
37,581,241
FERC FORM NO.1 (ED. 12-93)Page 320
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2010/Q4
This Report Is: Date of Report
(1) ~An Original (Mo, Da,Yr)
(2) A Resubmission 04/15/2011
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.Line Accunt Amount forNo ~~. ~) ~
60 D. Other Power Generation
61 Operation
62 (546) Operation Supervision and Engineering
63 (547) Fuel
64 (548) Generation Expenses
65 (549) Miscellaneous Other Power Generation Expenses
66 (550) Rents
67 TOTAL Operation (Enter Total of lines 62 thru 66)
68 Maintenance
69 (551) Maintenance Supervision and Engineering
70 (552) Maintenance of Strctures
71 (553) Maintenance of Generating and Electric Plant
72 (554) Maintenance of Miscellaneous Other Power Generation Plant
73 TOTAL Maintenance (Enter Total of lines 69 thru 72)
74 TOTAL Power Production Expenses-Other Power (Enter Tot of 67 & 73)
75 E. Other Power Supply Expenses
76 (555) Purchased Power
77 (556) System Control and Load Dispatching
78 (557) Other Expenses
79 TOTAL Other Power Supply Exp (Enter Total of lines 76 thru 78)
80 TOTAL Power Production Expenses (Total of lines 21, 41, 59, 74 & 79)
81 2. TRANSMISSION EXPENSES
82 Operation
83 (560) Operation Supervision and Engineering
84 (561) Load Dispatching
85 (561.1) Load Dispatch-Reliabilty
86 (561.2) Load Dispatch-Monitor and Operate Transmission System
87 (561.3) Load Dispatch-Transmission Service and Schedulin
88 (561.4) Scheduling, System Control and Dispatch Services
89 (561.5) Reliabilty, Planning and Standards Development
90 (561.6) Transmission Service Studies
91 (561.7) Generation Interconnection Studies
92 (561.8) Reliabilty, Planning and Standards Development Services
93 (562) Station Expenses
94 (563) Overhead Lines Expenses
95 (564) Underground Lines Expenses
96 (565) Transmission of Electricity by Others
97 (566) Miscellaneous Transmission Expenses
98 (567) Rents
99 TOTAL Operation (Enter Total of lines 83 thru 98)
100 Maintenance
101 (568) Maintenance Supervision and Engineering
102 (569) Maintenance of Structures
103 (569.1) Maintenance of Computer Hardware
104 (569.2) Maintenance of Computer Softare
105 (569.3) Maintenance of Communication Equipment
106 (569.4) Maintenance of Miscellaneous Regional Transmission Plant
107 (570) Maintenance of Station Equipment
108 (571) Maintenance of Overhead Lines
109 (572) Maintenance of Underground Lines
110 (573) Maintenance of Miscellaneous Transmission Plant
111 TOTAL Maintenance (Total of lines 101 thru 110)
112 TOTAL Transmission Expenses (Total of lines 99 and 111)
AmountJprPrevious Year
(c)
328,417
12,745,952
448,744
450,180
347,933
19,331,689
405,013
320,014
-~--~---~-- --~-- -13,973,293 20,404,649
-~--~-~----
43
182,03
118,533
1,077,264
1,377,883
15,351,176
194,110
524,579
1,710,504
2,429,193
22,833,842
~-~~~~-
137,850,336
160
53,795,016
191,645,512
440,578,820
160,569,065
13,142
69,383,801
229,966,008
465,530,068
2,992,955
273,869
2,534,092
169,190
1,254,735
1,316,482
1,348,929
994,682
I --~----~-~-~
108,008 101,790
1,987,214 1,946,068
660,035 907,200
5,918,507 6,628,695
336,835 386,603
1,569,168 1,564,349
16,417,808 16,581,598
540,340 590,179
195
66,482 82,703
324,033 268,304
28,510 32,141
3,447,662 2,999,666
2,781,256 2,936,203
-40 38
7,188,438 6,909,234
23,606,246 23,490,832
FERC FORM NO.1 (ED. 12-93)Page 321
Name of Respondent
Idaho Power Company
Year/Penod of Report
End of 2010/Q4
This ~ort Is: Date of Report(1) ~An Onginal (Mo, Da, Yr)
(2) A Resubmission 04/15/2011
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.Line Accunt Amount forNo ~~. (a) (b)
113 3. REGIONAL MARKET EXPENSES
114 Operation
115 (575.1) Operation Supervision
116 (575.2) Day-Ahead and Real-Time Market Facilitation
117 (575.3) Transmission Rights Market Facilitation
118 575.4) Capacity Market Facilitation
119 (575.5) Ancillary Services Market Facilitation
120 (575.6) Market Monitonn and Compliance
121 (575.7) Market Facilitation, Monitonng and Compliance Services
122 (575.8) Rents
123 Total Operation (Lines 115 thru 122)
124 Maintenance
125 (576.1) Maintenance of Structures and Improvements
126 (576.2) Maintenance of Computer Hardware
127 (576.3) Maintenance of Computer Softare
128 (576.4) Maintenance of Communication Equipment
129 (576.5) Maintenance of Miscellaneous Market Operation Plant
130 Total Maintenance (Lines 125 thru 129)
131 TOTAL Regional Transmission and Market Op Expns (Total 123 and 130)
132 4. DISTRIBUTION EXPENSES
133 Operation
134 (580) Operation Supervision and Engineenng
135 (581) Load Dispatching
136 (582) Station Expenses
137 (583) Overhead Line Expenses
138 (584) Underground Line Expenses
139 (585) Street Lighting and Signal System Expenses
140 (586) Meter Expenses
141 (587) Customer Installations Expenses
142 (588) Miscellaneous Expenses
143 (589) Rents
144 TOTAL Operation (Enter Total of lines 134 thru 143)
145 Maintenance
146 (590) Maintenance Supervision and Engineenng
147 (591) Maintenance of Structures
148 (592) Maintenance of Station Equipment
149 (593) Maintenance of Overhead Lines
150 (594) Maintenance of Underground Lines
151 (595) Maintenance of Line Transformers
152 (596) Maintenance of Street Lighting and Signal Systems
153 (597) Maintenance of Meters
154 (598) Maintenance of Miscellaneous Distribution Plant
155 TOTAL Maintenance (Total of lines 146 thru 154)
156 TOTAL Distnbution Expenses (Total of lines 144 and 155)
157 5. CUSTOMER ACCOUNTS EXPENSES
158 Operation
159 (901) Supervision
160 (902) Meter Reading Expenses
161 (903) Customer Records and Collecton Expenses
162 (904) Uncollectible Accunts
163 (905) Miscellaneous Customer Accunts Expenses
164 TOTAL Customer Accunts Expenses (Total of lines 159 thru 163)
Amount forPrevious Year
(c)
r-~-~-- - ~-~~-- --------~
--~~---~---~----~
- -- --~---------~--~
3,713,391
3,419,960
1,277,818
3,029,340
1,792,342
79,537
4,219,270
1,521,427
5,004,179
440,788
24,498,052
3,357,224
3,186,033
1,136,350
3,446,690
1,915,974
134,828
4,473,033
1,331,636
5,003,459
308,806
24,294,033
-----~---- ~------ -----~
371,979
-11,385
3,774,723
14,297,636
1,003,405
448,157
587,953
700,080
137,583
21,310,131
45,808,183
310,403
25,089
3,354,447
14,503,170
1,083,316
410,917
501,683
711,387
267,231
21,167,643
45,461,676
410,702
4,026,937
12,988,731
4,638,855
342
22,065,567
373,734
5,399,410
13,096,476
5,268,902
556
24,139,078
FERC FORM NO.1 (ED. 12-93)Page 322
Name of Respondent
Idaho Power Company
Year/Penod of Report
End of 2010/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2011
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.Line Accunt Amount forN Current Year~ 00 00
165 6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
166 Operation
167 (907) Supervision
168 (908) Customer Asistance Expenses
169 (909) Informational and Instructional Expenses
170 (910) Miscellaneous Customer Service and Informational Expenses
171 TOTAL Customer Service and Information Expenses (Total 167 thru 170)
172 7. SALES EXPENSES
173 Operation
174 (911) Supervision
175 (912) Demonstrating and Sellng Expenses
176 (913) Advertising Expenses
177 (916) Miscellaneous Sales Expenses
178 TOTAL Sales Expenses (Enter Total of lines 174 thru 177)
179 8. ADMINISTRATIVE AND GENERAL EXPENSES
180 Operation
181 (920) Administrative and General Salaries
182 (921) Offce Supplies and Expenses
183 (Less) (922) Administrative Expenses Transferred-Credit
184 (923) Outside Servces Employed
185 (924) Propert Insurance
186 (925) Injunes and Damages
187 (926) Employee Pensions and Benefits
188 (927) Franchise Requirements
189 (928) Regulatory Commission Expenses
190 (929) (Less) Duplicate Charges-Cr.
191 (930.1) General Advertising Expenses
192 (930.2) Miscellaneous General Expenses
193 (931) Rents
194 TOTAL Operation (Enter Total of lines 181 thru 193)
195 Maintenance
196 (935) Maintenance of General Plant
197 TOTAL Administrative & General Expenses (Total of lines 194 and 196)
198 TOTAL Elec Op and Maint Expns (Total 80,112,131,156,164,171,178,197)
Amount forPrevious Year
(c)
-----~-~~--
352,779
51,959,849
31,517
864,003
53,208,148
258,454
40,754,937
16,116
840,420
41,869,927
-~-- - ~~--~~
63,660,597
13,613,991
27,799,634
7,210,630
3,329,577
5,668,380
30,031,098
2,549
3,797,836
61,677,661
12,455,430
27,866,621
7,562,948
3,262,112
6,804,103
31,049,314
3,196
5,298,808
-~-------~---~
417,950
3,826,102
12,600
103,771,676
158,199
3,561,160
1,090
103,967,400
4,182,610
107,954,286
693,221,250
3,946,638
107,914,038
708,405,619
FERC FORM NO.1 (ED. 12-93)Page 323
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) 0 A Resubmission 04115/2011
PU~CHAJlED POWER J,ACCUW 555)(nclu ing power ex anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliabilty of requirement service must
be the same as, or second only to, the suppliets service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrpted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third partes to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contrct.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly Billng Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Wills and Bett Deveny/Shinglecreek LU -N/A N/A N/A
2 James B. Howell 1 CHI Elkcreek LU -N/A N/A N/A~LU -4.942Mw
4 Owyhee Irrigation District
5 Mitchell Butte LU -N/A N/A N/A
6 Owyhee Dam LU -N/A N/A N/A
7 Tunnel #1 LU -N/A N/A N/A
8 Reynolds Irrigation District LU -N/A N/A N/A
9 Clifton E. Jenson/Birchcreek LU .05Mw ~-
10 Snake River Pottery LU -N/A N/A N/A
11 White Water Ranch LU -N/A N/A N/A
12 John R LeMoyne LU -N/A N/A N/A
13 David R Snedigar LU -N/A N/A N/A
14 Mud Creek White Hydro, Inc LU -N/A N/A N/A
Total
FERC FORM NO.1 (ED. 12-90)Page 326
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2)o A Resubmission 04/15/2011
,-ccu~t asa.UQ ntinued)
(Including power exc anges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average biling demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (50-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (50-minute integration) in which the suppliets system reaches its monthly peak. Demand reported in columns (e) and (t)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
5. Report in column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components ofthe amount shown in column (I). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (i)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.
Received Delivered ~l \i~
($)of Settement ($)
(g)(h)(i)(I)(m)
94e 65,88S 65,888 1
3,45~244,15E 244,156 2
33,34f 1,576,498 1,257,OOC 2,833,498 3
4
5,38E 123,771 123,771 5
17,67E 332,66S 332,668 6
6,47~642,682 642,682 7
1,18.1 86,901 86,901 8
341 17,500 9,63~27,139 9
39f 26,66.1 26,663 10
692 46,402 46,402 11
64A 35,619 35,619 12
1,571 108,951 108,951 13
41"28,001 28,007 14
2,377,686 438,656 535,420 2,815,124 120,642,221 14,392,991 137,850,336
FERC FORM NO.1 (ED. 12-90)Page 327
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) n A Resubmission 04/15/2011
PU~CHA~ED POWER chAccu~t 555)
(nclu ing power ex anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliabilty of requirement service must
be the same as, or second only to, the suppliets service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availabilty and reliability of
service, aside from transmission constraints, must match the availabilty and reliabilty of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly Billng Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Rim View Trout Company ~N/A N/A N/A
2 Curr Cattle Company LU -.084Mw --
3 BranchflowerlTrout Company LU -N/A N/A N/A
4 Big Wood Canal Company
5 Black Canyon LU -N/A N/A N/A
6 Jim Knight LU -N/A N/A N/A
7 Sagebrush LU -N/A N/A N/A
8 Fisheries Development -N/A N/A N/A
9 Shorock Hydro Inc.
10 Shoshone Cspp LU -N/A N/A N/A
11 Shoshone #2 LU -N/A N/A N/A
12 Rock Creek #1 Joint Venture LU -1.732Mw ~
13 Richard Kaster
14 Box Canyon LU -N/A N/A N/A
Total
FERC FORM NO.1 (ED. 12-90)Page 326.1
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) n A Resubmission 04/15/2011
ccunt 55!lUO ntlnued(Including poWer exchanges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average biling demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (i). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line ofthe schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total Ü+k+l)No.
Received Delivered ~l ~~~
($)of Settlement ($)
(g)(h)(i)(i)(m)
1,16 26,17A 26,174 1
58~26,796 16,47~43,275 2
82~57,47E 57,475 3
4
29~20,28.1 20,284 5
76~52,12.1 52,124 6
1,07~75,8Of 75,805 7
1,021 24,54C 24,540 8
9
1,791 141,78~141,782 10
2,24f 150,92ì 150,927 11
8,47~552,508 239,7Oì 792,215 12
13
1,97~129,70~129,702 14
2,371,686 438,656 535,420 2,815,124 120,642,221 14,392,991 137,850,33t
FERC FORM NO.1 (ED. 12-90)Page 327.1
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2)D A Resubmission 04115/2011
PU~CHA~ED POWERJ,Accußt 555)(nclu ing power ex anges
1. Report all power purchases made during the year. Also report exchanges of electrcity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the suppliets service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrpted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availabilty and reliability of
service, aside from transmission constraints, must match the availability and reliabilty of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)
Classifi-Schedule or Monthly Biling Average Average
cation Tariff Number Demand (MW)Monthly NCP DemancI Monthly CP Demand
(a)(b)(c)(d)(e)I (f)
1 Briggs Creek LU -N/A N/A N/A
2 David McCollum/Canyon Springs LU -N/A N/A N/A
3 H.K. Hydro Mud Creek S & S LU -N/A N/A N/A
4 Allan RavenscroWMalad River LU -.488Mw
5 Wiliam Arkoosh/Littewood LU -N/A N/A N/A
6 Clear Springs Food Inc.LU -N/A N/A N/A
7 Koyle Hydro Inc.LU -N/A N/A N/A
8 Kasel & Witherspoon LU -N/A N/A N/A
9 Lateral 10 Ventures LU -N/A N/A N/A
10 Crystal Springs Hydro LU -N/A N/A N/A
11 Pigeon Cove Power LU -1.389
12 Consolidated Hydro Inc. / Enel -
13 Barber Dam LU N/A N/A N/A
14 GeoBon#2 LU -N/A N/A N/A
Total
FERC FORM NO.1 (ED. 12-90)Page 326.2
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2)o A Resubmission 04/15/2011
v ccunt.~~?l \ t (,ontinued)
'ì1ncludlng power exchanges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups. for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average biling demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (i). Explain in a footnote all components of the amount shown in column (i). Report in column (m)
the total charge shown on bils received as settement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total Ü+k+l)No.
Recived Delivered ~l m ~fl
of Settlement ($)
(g)(h)(i)(m)
3,32f 225,841 225,841 1
85£20,23"20,233 2
1,47f 107,011 107,017 3
2,49f 155,672 70,65£226,328 4
3,82.281,61~281,612 5
3,41 287,691 287,697 6
3,28£268,031 268,031 7
3,80:291,661 291,667 8
8,72~571,411 571,411 9
10,19 694,88 694,883 10
8,48£486,150 208,75 694,907 11
12
11,010 565,62~565,629 13
3,458 253,598 253,598 14
2,377,686 438,656 535,420 2,815,124 120,642,221 14,392,991 137,850,336
FERC FORM NO.1 (ED. 12-90)Page 327.2
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) nA Resubmission 04/15/2011
PU~CHAJlED POWER JiACCUßt 555)nclu ing power ex anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name ofthe seller or other part in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions ofthe service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the suppliets service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrpted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availabilty and reliabilty of
service, aside from transmission constraints, must match the availability and reliabilty of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than oné year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly Billng Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Rock Creek #2 LU -N/A N/A N/A
2 Dietrich Drop LU -N/A N/A N/A
3 Lowline#2 LU -N/A N/A N/A
4 Little Mac Power Co.lCedar Draw LU -N/A N/A N/A~LU -N/A N/A N/A
6 Little Wood River Irrigation Dismct LU -N/A N/A N/A
7 Marco Rancher's Irngation Inc.LU -N/A N/A N/A
8 Faulkner Brothers Hydro Inc.LU -N/A N/A N/A
9 Magic Reservoir Hydro LU -N/A N/A N/A
10 Bypass Limited LU -N/A N/A N/A
11 SE Hazelton A LP LU -N/A N/A N/A
12 Lemhi Hydro Power Co.lSchaffer LU -N/A N/A N/A
13 J R Simplot Co.LU -N/A N/A N/A
14 Blind Canyon Hydro LU -N/A N/A N/A
Total
FERC FORM NO.1 (ED. 12-90)Page 326.3
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) ¡=A Resubmission 04115/2011
ccunt.~~~uu ntinueó)(Includíng power exChanges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average biling demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the suppliets system reaches its monthly peak. Demand reported in columns (e) and (t)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COSTISETILEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.
Received Delivered ($)m \~l
of Settement ($)
(g)(h)(i)(j (m)
7,50!387,61:-387,612 1
13,981 766,85~766,859 2
9,85!522,921 522,921 3
5,80(372,40'372,404 4
27,45'1,967,031 1,967,031 5
5,371 397,8n 397,873 6
3,12(207,5De 207,505 7
3,56!267,60~267,609 8
15,56~857,911 857,911 9
26,217 1,408,36~1,408,365 10
23,21E 1,190,42~1,190,424 11
1,39!105,83(105,830 12
79,34~4,439,681 4,439,681 13
4,43~395,44-395,444 14
2,371,686 438,656 535,420 2,815,124 120,642,221 14,392,991 137,850,33E
FERC FORM NO.1 (ED. 12-90)Page 327.3
Name of Respondent This ~ort Is:Date of Report Year/Penod of Report
Idaho Power Company (1) X An Onginal (Mo, Da, Yr)End of 2010/Q4
(2) n A Resubmission 04/15/2011
PU~CHA~ED POWER J,ACCUßt 555)
(nclu ing power ex anges
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the suppliets service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrpted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authonty Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly Billng -Average Average
cation Tariff Number Demand(MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 City of Hailey LU -N/A N/A N/A
2 City of Pocatello LU -N/A N/A N/A_LU -N/A N/A N/A4 W -N/A N1A N/A5 W -N/A N/A N/A
6 Pristine Springs Inc. #1 LU -N/A N/A N/A
7 Vaagen Brothers Lumber Inc.LU -N/A N/A N/A
8 Horseshoe Bend Hydro LU -N/A N/A N/A
9 Contractors Power Group Inc.lMile 28 LU -N/A N/A N/A
10 Rupert Cogeneration Partners/Magic Val LU -N/A N/A N/A
11 Glenns Ferry Cogeneration Parters/Mag LU -N/A N/A N/A
12 Tasco - Nampa ~N/A N/A N/A
13 Pnstine Spnngs Inc # 3 LU -N/A N/A N/A
14 Ted S. SorensonfTber Dam LU N/A N/A N/A
Total
FERC FORM NO.1 (ED. 12-90)Page 326.4
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) tl A Resubmission 04/15/2011
r cc~t ~~~ucontinued)(Including power ex anges)
AD - for out-of-penod adjustment. Use this code for any accounting adjustments or Rtrue-ups" for service provided in pnor reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC junsdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tanffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billng demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
dunng the hour (50-minute integration) in which the suppliets system reaches its monthly peak. Demand reported in columns (e) and (t)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. Ifthe settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line ofthe schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entnes as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.
Received Delivered ~l \~~\~l
of Settlement ($)
(g)(h)(i)(m)
39 2,70~2,705 1
1,29::92,531 92,531 2
41,414 2,670,43€2,670,436 3
25,964 1,807,88~1,807,885 4
22,231;1,548,494 1,548,494 5
831;46,50€46,508 6
7
38,154 2,598,301 2,598,307 8
4,50€305,86~305,862 9
78,99"5,069,99€5,069,998 10
11
26"4,479 4,479 12
1,284 66,70€66,708 13
28,821 1,438,662 1,438,662 14
2,377,686 438,656 535,420 2,815,124 120,642,221 14,392,991 137,850,336
FERC FORM NO.1 (ED. 12-90)Page 327.4
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da. Yr)End of 2010/Q4
(2) 0 A Resubmission 04/15/2011
PU~CHA~ED POWER J,Accußt 555)
(nclu ing power ex anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions ofthe service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the suppliets service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrpted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availabilit and reliability of
service, aside from transmission constraints, must match the availability and reliabilty of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly Billng Average Average
cation Tariff Number Demand(MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Fossil Gulch Wind LU -N/A N/A N/A
2 G2 Energy Hidden Hollow LU N/A N/A N/A
3 Horseshoe Bend Wind/United Materials LU N/A N/A N/A
4 Horseshoe Bend Wind/United Materials --N/A N/A NlA
5 Riverside Hydro Mora Drop LU N/A N/A N/A
6 J.M. Miler/Sahko Hydro LU N/A N/A N/A
7 D.R. Johnson Lumber/Co Gen Co SF N/A N/A N/A
8 Twin Falls Energy/Lowline Midway Hydro LU N/A N/A N/A
9 Bennett Creek Wind Farm LU N/A N/A N/A
10 Bettencourt DryCreek Biofactory LU N/A N/A N/A
11 Big Sky Dairy Digester LU N/A N/A N/A
12 Hot Springs Wind Farm LU N/A N/A N/A
13 Tuana Springs Expansion LU N/A N/A N/A
14 Cassia Wind Farm LU N/A N/A N/A
Total
FERC FORM NO.1 (ED. 12-90)Page 326.5
Name of Respondent This~rtIS:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2)D A Resubmission 04/15/2011
r ""..cc~t.~~iiucontinued)'Tlncluding power ex anges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average biling demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the suppliets system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (i). Explain in a footnote all components ofthe amount shown in column (i). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (i)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line ofthe schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETILEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total u+k+l)No.
Received Delivered ($)~i~~~l
of Settement ($)
(g)(h)(i)ü)(m)
28,33.1,374,14€1,374,146 1
23,081 1,265,41~1,265,412 2
12,71'657,91~657,912 3
-4
4,81 264,65(264,650 5
1,231 23,161 23,161 6
18,90 996,931 996,937 7
8,791 540,23€540,236 8
29,89~1,709,391 1,709,391 9
12,72€749,161 749,161 10
9,894 616,37~616,37~11
30,98,1,765,37.1,765,372 12
54,76/3,422,511 3,422,518 13
26,081 1,246,881 1,246,885 14
2,377,686 438,656 535,420 2,815,124 120,642,221 14,392,991 137,850,33€
FERC FORM NO.1 (ED. 12-90)Page 327.5
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) DA Resubmission 04/15/2011
PU~CHA~ED POWER J,Accußt 555)
(nclu ing power ex anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliabilty of requirement service must
be the same as, or second only to, the suppliets service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrpted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availabilty and reliabilit of
service, aside from transmission constraints, must match the availability and reliabilty of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly Biling Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Riverside InvestmentsArena Drop LU N/A N/A N/A
2 Cargil Inc.I6 Anaerobic Digester LU N/A N/A N/A
3 Cassia Gulch Wind Park LU N/A N/A N/A
4 New Wind Projects Scheduled Energy -N/A N/A N/A
5 Other Purchased Power
6 Arzona Public Service Co.SF WSPP N/A N/A N/A
7 Avista Corp.SF T-12 N/A N/A N/A
8 Avista Corp.SF WSPP N/A N/A N1A
9 Avista Corp._iwspp N/A N/A N/A
10 Barclays Bank PLC SF WSPP N/A N/A N/A
11 Black Hils Power Inc.
:I;=wspp
N/A N/A N/A
12 Black Hils Power Inc.N/A N/A N/A
13 Black Hils Power Inc.N/A N/A N/A
14 Bonnevile Power Administration ~N/A N/A N/A
Total
FERC FORM NO.1 (ED. 12-90)Page 326.6
Name of Respondent This Report Is:Date of Report Year/Period of Report
Idaho Power Company (1) IK An Onginal (Mo, Da, Yr)End of 2010/Q4
(2) t1 A Resubmission 04/15/2011
r" "'"ccunt 5~~.UCt ntinued)'(Including power exchanges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j, energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (i). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total G+k+l)No.
Received Delivered ($)~i~\~l
of Settlement ($)
(g)(h)(i)G)(m)
50~21,081 21,08€1
1,69~33,77 33,772 2
16,97~739,55!739,555 3
1,271 4
5
28,41-1 ,010,20~1,010,208 6
13C 4,39~4,392 7
7,58C 276,40C 276,400 8
246,160 246,160 9
21,60C 798,25€798,256 10
1,31€44,B4C 44,840 11
54(16,35C 16,350 12
98,33,80'33,804 13
538,370 538,370 14
2,377,686 438,656 535,420 2,815,124 120,642,221 14,392,991 137,850,331
FERC FORM NO.1 (ED. 12-90)Page 327.6
Name of Respondent This 00rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2)DA Resubmission 04/15/2011
PU~CHAdTED POWER hACCUßt 555)(nclu ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions ofthe service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliabilty of requirement service must
be the same as, or second only to, the suppliets service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrpted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date ofthe contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly Billng Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Bonnevile Powèr Administration SF WSPP N/A N/A N/A
2 BP Energy Company SF WSPP N/A N/A N1A
3 California ISO ~N/A N/A N/A
4 Calpine Energy Services, L.P.SF WSPP N/A N/A N/A
5 Cargil Power Markets LLC SF WSPP N/A N/A N/A
6 Chelan Co PUD SF WSPP N/A N/A N/A
7 Citigroup Energy Inc.SF WSPP N/A N/A N/A
8 Clatskanie PUD _WSPP N/A N/A N/A
9 Clatskanie PUD SF WSPP N/A N/A N/A
10 Conoco Philips Company SF WSPP N/A N/A N/A
11 Constellation Energy Commodities Group SF WSPP N/A N/A N/A
12 DB Energy Trading LLC SF WSPP N/A N/A N/A
13 Douglas County PUD SF WSPP N/A N/A N/A
14 EDF Trading North America, LLC SF WSPP N/A N/A N/A
Total
FERC FORM NO.1 (ED. 12-90)Page 326.7
Name of Respondent This ~ort Is:Date of Report Year/Penod of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) nA Resubmission 04/15/2011
ccunt 5~~u(,ontinUed)'llncluding poWer exChanges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average biling demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (i). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported às Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COSTISETILEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.
Received Delivered ($)m \~l
of Settement ($)
(g)(h)(i)0)(m)
71,78'2,798,00!2,798,009 1
33,00.1,736,67(1,736,670 2
1,72'3
4,00.158,86t 158,866 4
144,48(6,598,41~6,598,419 5
741 29,761 29,761 6
19,631 718,40~718,402 7
1(8
38f 14,97~14,973 9
1,20(36,10C 36,100 10
80'26,53€26,538 11
28,60 723,5BA 723,584 12
41'4,891 4,891 13
11,75(372,10!372,10¿14
2,371,686 438,656 535,420 2,815,124 120,642,221 14,392,991 137,850,33t
FERC FORM NO.1 (ED. 12-90)Page 327.7
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2)DA Resubmission 04/15/2011
PU~CHA~ED POWER J,ACCUW 555)
(nclu ing power ex anges
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part in an exchange transaction in column (a). Do not abbreviate or trncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3, In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliabilty of requirement service must
be the same as, or second only to, the suppliets service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availabilty and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly Biling Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman l Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Endure Energy, LLC SF WSPP N/A N/A N/A
2 Eugene Water & Electric Board SF WSPP N/A N/A N/A
3 Grant CO Public Utilty District #2 --SF WSPP N/A N/A N/A
4 IBERDROLA RENEWABLES, Inc.J_WSPp N/A N/A N/A
5 IBERDROLA RENEWABLES, Inc.SF WSPP N/A N/A N/A
6 J.P. Morgan Ventures Energy Corporatio ~wspp N/A N/A N/A
7 JPMorgan Chase Bank, NA N/A N/A N/A
8 Macquarie Cook Power Inc.SF WSPP N/A N/A N/A
9 Morgan Stanley Capital Group Inc.JJ N/A N/A N/A
10 Morgan Stanley Capital Group Inc.SF WSPP N/A N/A N/A
11 NextEra Energy Power Marketing, LLC SF WSPP N/A N/A N/A
12 NorthPoint Energy Solutions Inc.SF WSPP N/A N/A N/A
13 NorthWestern Energy SF T-7 N/A N/A N/A
14 NorthWestern Energy SF WSPP N/A N/A N/A
Total
FERC FORM NO.1 (ED. 12-90)Page 326.8
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2)o A Resubmission 04/15/2011
~ccu~t ~~~Uu ntinued)'(1ncluding poWer exc anges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (t). For all other types of service, enterNA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (i). Explain in a footnote all components of the amount shown in column (i). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certin credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.
Received Delivered ($)~t~
($)of Settement ($)
(g)(h)(i)0)(I)(m)
80C 33,00(33,000 1
38,57!814,201 814,201 2
5,62.147,78C 147,780 3
2 -27C -270 4
55,37!1,302,47:1,302,472 5
3,60C 132,99:132,992 6
229,972 229,972 7
57,48 2,197,24 2,197,247 8
912,802 912,802 9
9,51 341,40e 341,406 10
48C 20,271 20,271 11
62!19,00C 19,000 12
14.4,83~4,839 13
29(8,07!8,075 14
2,371,686 438,656 535,420 2,815,124 120,642,221 14,392,991 137,850,33E
FERC FORM NO.1 (ED. 12-90)Page 327.8
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) 0 A Resubmission 04/15/2011
PU~CHA~ED POWER J,Accu0t 555)
(nclu In9 power ex anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrpted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availabilty and reliabilty of
service, aside from transmission constraints, must match the availability and reliabilty of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly Biling Average Average
cation Tariff Number Demand(MW)Monthly NCP Deman Monthly CP Demand
~a)(b)(c)(d)(e)(f)
1 Pacific Northwest Generating Cooperati SF WSPP N/A N/A N/A
2 PacifiCorp Inc.SF T-13 NlA N/A N/A
3 PacifiCorp Inc.SF WSPP N/A N/A N/A
4 PacifiCorp Inc.~WSPP N/A N/A N/A
5 Portand General Electric Company SF T-14 N/A N/A N/A
6 Portand General Electric Company SF WSPP N/A N/A N/A
7 Powerex Corp.SF WSPP N/A N/A N/A
8 PPL EnergyPlus, LLC IF WSPP N/A N/A N/A
9 PPL EnergyPlus, LLC SF WSPP N/A N/A N/A
10 Prudential Bache Commodities, LLC
~WS
N/A N/A N/A
11 Prudential Bache Commodities, LLC N/A N/A N/A
12 Public Service Company of Colorado N/A N/A N/A
13 Public Servce Company of New Mexico SF WSPP N/A N/A N/A
14 Puget Sound Energy, Inc.~~WSPP N/A N/A N/A
"i
Total
FERC FORM NO.1 (ED. 12-90)Page 326.9
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) n A Resubmission 04115/2011
,cc~t.~~~U(. ntinueCl)
"(Including power ex anges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service,as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billng demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (i). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certin credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.
Recived Delivered ($)
~~~~fl
of Settement ($)
(g)(h)(i)0)(m)
40(4,20l 4,200 1
71'24,01 24,013 2
11,551 425,781 425,780 3
221,600 221,600 4
22€7,571 7,576 5
30,07€1,111,02l 1,111,020 6
50,52.2,936,591 2,936,591 7
103,f1 9,555,62A 9,555,624 8
85,79.2,546,931 2,546,937 9
8,907,322 8,907,322 10
5,904 5,90 11
5,60(195,20C 195,200 12-
1,35~49,06'49,064 13
10(50l 500 14
2,377,686 438,656 535,420 2,815,124 120,642,221 14,392,991 137,850,331
FERC FORM NO.1 (ED. 12-90)Page 327.9
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) nAResubmission 04/15/2011
PU~CHA~ED POWER chAccußt 555)(nclu ing power ex anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the suppliets service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrpted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that nintermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)
Classifi-Schedule or Monthly Billng Average Average
cation Tariff Number Demand(MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Puget Sound Energy, Inc.SF T-9 N/A N/A N/A
2 Puget Sound Energy, Inc.SF WSPP N/A N/A N/A
3 Rainbow Energy Marketing Corporation SF WSPP N/A N/A N/A
4 Sacramento Municipal Utiity District SF WSPP N/A N/A N/A
5 Salt River Project SF WSPP N/A N/A N/A
6 Seatte City Light SF WSPP N/A N/A N/A
7 Sempra Energy Solutions SF WSPP N/A N/A N/A
8 Sempra Energy Trading LLC N/A N/A .N/A
9 Sempra Energy Trading LLC SF WSPP N/A N/A N/A
10 Shell Energy Nort America (US), L.P.WSPP N/A N/A N/A
11 Shell Energy North America (US), L.P.N/A N/A N/A
12 Shell Energy North America (US), L.P.SF WSPP N/A N/A N/A
13 Sierr Pacific Power Co., dba NV Energ SF T-55 N/A N/A N/A
14 Sierra Pacific Power Co., dba NV Energ SF WSPP N/A N/A N/A
Total
FERC FORM NO.1 (ED. 12-90)Page 326.10
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) t1 A Resubmission 04/15/2011
r.. 'VI ccun~~~!?.ucontinued)'(1ncludlng power exchanges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billng demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (i). Explain in a footnote all components ofthe amount shown in column (I). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line ofthe schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must b~ reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total Q+k+l)No.
Received Delivered ~l \i~\fl
of Settement ($)
(g)(h)(i)(m)
22~7,76.7,763 1
60,43C 2,377,761 2,377,768 2
12,13f 313,24.313,243 3
40C 12,70(12,700 4
21C 10,30!10,305 5
16,17:;624,10.624,102 6
2,85C 82,24.82,243 7
1,967,180 1,967,180 8
85,00 5,036,02 5,036,027 9
10C 2,70(2,700 10
435,552 435,552 11
28,761 992,62t 992,626 12
13~4,57.4,573 13
1,53~56,57!56,575 14
2,377,686 438,656 535,420 2,815,124 120,642,221 14,392,991 137,850,33€
FERC FORM NO.1 (ED. 12-90)Page 327.10
Name of Respondent This ~ort Is:Date of Report Year/Penod of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) n A Resubmission 04/15/2011
PU~CHAdTED POWER chAccußt 555)(nclu ing power ex anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliabilty of requirement service must
be the same as, or second only to, the suppliets service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrpted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availabilty and reliability of
service, aside from transmission constraints, must match the availability and reliabilty of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authonty Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly Billng Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Sierra Pacific Power Co., dba NV Energ _WSPP N/A N/A N/A
2 Snohomish County PUD SF WSPP N/A N/A N/A
3 Southern California Edison SF WSPP N/A N/A N/A
4 Southwestern Public Service Company SF WSPP N/A N/A N/A
5 Tacoma Power SF WSPP N/A N/A N/A
6 The Energy Authonty, Inc.SF WSPP N/A N/A N/A
7 TransAlta Energy Marketing (U.S.) Inc.SF WSPP N/A N/A N/A
8 Turlock Irngation Distrct SF WSPP N/A N/A N/A
9 Western Area Power Partners LLC SF WSPP N/A N/A N/A
10 Raft River Energy I LLC gPOA N/A N/A N/A
11 Telocaset Wind Power Partners LLC N/A N/A N/A
12 Net Metering Customers N/A N/A N/A
13 Oregon Solar Customers N/A N/A N/A
14 Power Exchanges
Total
FERC FORM NO. 1 (ED. 12-90)Page 326.11
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/04
(2) DA Resubmission 04/15/2011
i cc~t 5!?!?ucontinued)(Including power ex anges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billng demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the suppliets system reaches its monthly peak. Demand reported in columns (e) and (t)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components ofthe amount shown in column (I). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line ofthe schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETILEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.
Received Delivered ($)
~~~\fl
of Settement ($)
(g)(h)(i)0)(m)
408 408 1
16,89.:591,27C 591,270 2
2,02e 82,36~82,364 3
41 4
3,45.:130,831 130,837 5
1,33;:12,73~12,733 6
2,28.:62,OU 62,018 7
52 2,05C 2,050 8
e 15~154 9
71,84€4,141,482 4,141,482 10
313,25€16,618,09~16,618,093 11
54€43,50e 43,505 12
7 13
14
2,371,686 438,656 535,420 2,815,124 120,642,221 14,392,991 137,850,336
FERC FORM NO.1 (ED. 12-90)Page 327.11
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) r=A Resubmission 04/15/2011
PU~CHA~ED POWER ciACCUßt 555)(nclu ing power ex anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliabilty of requirement service must
be the same as, or second only to, the suppliets service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrpted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF. provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliabilty of
service, aside from transmission constraints, must match the availability and reliabilty of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly Biling Average Average
cation Tariff Number Demand(MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Bonnevile Power Administration
2 NorthWestern Energy
3 PacifiCorp Inc.-
4 Puget Sound Energy, Inc.-
5 Sierra Pacific Power Co., dba NV Energ
6 Utah Associated Municipal Power System Ii:tff
7 Clatskanie PUD EX 153
8 Sierra Pacific Power Co., dba NV Ende EX WSPP
9 NorthWestern Energy EX WSPP
10 Other Transactions
11 Acc Valuation-Clatskanie PUD Exchange
12
13
14
Total
FERC FORM NO.1 (ED. 12-90)Page 326.12
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) nA Resubmission 04/15/2011
ccunt.~~~uo ntinuoo).(Including power exchanges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (50-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (50-minute integration) in which the suppliets system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
5. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settement amount (i)
include credits or charges other than incremental generation expenses, or (2) excludes certin credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total U+k+l)No.
Received Delivered ($)
~~~\fl
of Settlement ($)
(g)(h)(i)ü)(m)
59,996 2,165 1
5,733 2
109,457 272,150 3
645 4
9,935 5
108 6
77,685 54,672 7
190,764 190,764 8
1 1 9
10
927,721 927,721 11
12
13
14
2,377,686 438,656 535,420 2,815,124 120,642,221 14,392,991 137,850,33t
FERC FORM NO.1 (ED. 12-90)Page 327.12
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company . (2) A Resubmission 04/15/2011 2010/Q4
FOOTNOTE DATA
¡Schedule Page: 326 Line No.: 3 Column: a
The Tamarack Energy Partnership demand readings are taken from an electronic demand
recorder provided by Idaho Power Co. The actual demand is not used in determining the cost
of energy.
!$iilePage:-326 Line NO':3-Coiiiiiri:e-----------Unavailable
Schedule Page: 326---TiiieNo-:3---Column: f ------------Unavailable
Schedule Page: 326 Line No.: 9 Column: eUnavailable
¡Schedule Page: 326I.Ti-¡'o-:--ohimii:-'--- ----------------------
Unavailable~.___.___~____..__._____.__._m_Schedule Page: 326.1 Line No.: 1 Column: b
Non Firm Purchases
¡Schedule Page: 326:1-rreNO::i--Oiiimn:e---~----..----------~----
Unavailable
~iiediiïe Page: 326.1 Line No.: 2 ---Coiiili:'-- --------
Unavailable
¡Schedule Page: 326.1 Line No.: 8 Coiiimn:¡------Non Firm Purchases~-~-------_...
¡Schedule Page: 326.1 Line No.: 12 Column: eUnavailable
¡Schedule Page: 326.1 Line No.: 12 Column: fUnavailable,---_.._-~_._---_._----~--------~~-----~-_._._-_._- --------_..._----_.,-~_.-Schedule Page: 326.2 Line No.: 4 Column: eUnavailable
Schedule Page: 326.2 Line No.: 4 Column: fUnavailable-_.._--_._------~-~.
Schedule Page: 326.2 Line No.: 11 Column: eUnavailable-------,--_._-_._-_.__._-"---~---_.. _._--~-------_._------_...Schedule Page: 326.2 Line No.: 11 Column: fUnavailable_. -_.,'--.._,------,.'.- - ~---_._--_._.~---_._------ _.----_._.__._------~---~-_.._..-Schedule Page: 326.3 Line No.: 5 Column: aIda West, a sUl:.'t.ct~ry _of_Idaho PoweECompany,_~sp~J:!:L~l__ownership of these projects.
¡Schedule Page: 326.4 Line No.: 3 Column: a
!.9~_1j~_~~_~E3?bsidiary_~ Idaho Power Company,J1~:"-2artial _?wn~rshii:_ of these proj (ócts.!Schedule Page: 326.4 Line No.: 4 Column: a
ida West, a subsidiary of Idaho Power Company, has partial ownership of these projects.
~CheiiPage:-326.4 Line No::S-COhmn:a-------
Ida West, a subsidiary of Idaho Power Company, has partial o",nership of these projects.
'SChediile Page: 326.4 Line No.: 12 Column: b -----
Non Firm Purchases,.---_._- . --------~ .__..._----~----,--------- _.._-~-~-_.._...__._----_._-----¡Schedule Page: 326.5 Line No.: 4 Column: b
Energy difference betwe~i: mountain and pac:L:tl~ time sc.liedui~s
¡Schedule Page: 326.6 Line No.: 4 Column: b
Ene:rS!Z-"~hedul_~d _ in. Dece~~~~OL.booked in.:",i:1.~ry 2011___
¡Schedule Page: 326.6 Line No.: 9 Column: b
Financial Transmission Losses
Schedi-Page:.326:Lielili;:-n-.coiiimn:¡;--..-----.... ..-------------------
Non Firm Purchases
¡Sèliedule Page:32ff1f-Lie.Nii~cOium-ii:b--------.~-------..-.
Short Term Unit Contingent
iSediiPage:326~6--Ti¡:o~:14CO¡umn: b
IFERC FORM NO.1 (ED. 12-87)
-~~~--
j
..------.1
-_..--
Page 450.1
Name of Respondent This Report is:Datè of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company I (2) A Resubmission 04/15/2011 2010104
FOOTNOTE DATA
Financial Transmission Losses~~- ""-- ._.._~--_._--_._---_..,_.-'Schedule Page: 326.7 Line No.: 3 Column: b
WECC Inadvertant Settlement ~---'--"-'------'-¡Schedule Page: 326.7 Line No.: 8 Column: bShort Term Uni t Conttngen~_~_________ ______
:Schedule Page: 326.8 Line No.: 4 Column: 'b
Non Firm Purchases ----_.__._._-~~-_._---_._.._----'_..-
¡Schedule Page: 326.8 Line No.: 7 Column: b
ISDA Masterl:gr-Eò~me~t:_"'gÈ__9"P Morgan Cha~E:_~an~j.ated November 4, 2005.
Schedule Page: 326.8 Line No.: 9 Column: b
_ISDA Master. Agreement with Morgan Stanley dated 03/01/2000
'Schedule Page: 326.9 Line No.: 4 Column: b
Financial Transmission Losses
---------
..__.._----~---i
Schedule Page: 326.9 Line No.: 10
Prudential Bache Commodities,
¡Schedule Page: 326.9 Line No.: 11
2009 Correction
¡Schedule Page: 326.9 Line No.: 14 Column: b
Non Firm Purchases
¡Schedule Page: 326.10 Line No.: 8 Column: b
ISDA Master Agreem~nt wit~_§_empE?__E~il_e_rgx_':£ading: ~ate? Febni_ary _~_~~Qo.§-._~__
:Schedule Page: 326.10 Line No.: 10 Column: b
Non Firm Purchases .._--_..-~----~---_._---¡Schedule Page: 326.10 Line No.: 11 Column: b
ISDA Ma~te:r~_:ire":rrE3Il_t:_ with Shell EnergYÌ\()_:rt:J:_~Am_~J-ca d~!ed N~~embe:r__~_Q~___~___~¡Schedule Page: 326.11 Line No.: 1 Column: b i
Financial Transmission Losses!Schedule Page: 326.11 Line No.: 10 Column: b
Unavailable.~------_._-~---------_.__._-'--~---'Schedule Page: 326.11 Line No.: 12 Column: b
Schedule 84 Net Met~ring______________________
'Schedule Page: 326.11 Line No.: 13 Column: b
§ch!:duJ:E3_§ß_°-.~g~~~olar ___~__~___________~______________ .._.___________~_______~
Schedule Page: 326.12 Line No.: 1 Column: b
Scheduled losses not removed with loss transactions..-~----'-----"'------- --- --~--- ------ - --- --------~---Schedule Page: 326.12 Line No.: 2 Column: b
Scheduled losses not removed with loss transactions.-_.__._._.....~-_.._-,---_.,...._._----.._---------------------- --- - -- ~ - - ---- -- ---~ - - ----- "--------,-Schedule Page: 326.12 Line No.: 3 Column: b
Scheduled losses not removed with loss transactions.
¡Schedule Page: 326.12 Line No.: 4 Column: b
Scheduled losses not removed with loss transactions.------~-_.~--Schedule Page: 326.12 Line No.: 5 Column: b
Scheduled losses not removed with loss transactions.-- -¡Schedule Page: 326.12 Line No.: 6 Column: b
Scheduled losses not removed with loss transactions.
Column: b
LLC Futures Account Document, dated September 4, 2008.
Column: b
--,
---~---------
!
IFERC FORM NO.1 (ED. 12-87) Page 450.2
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo. Da, Yr)End of 2010/Q4
(2) DA Resubmission 04/15/2011
~~..~' , ,,'", i=ni: i '"" ,~.~Accunt 456.1)
(Including trnsactons referred to as 'wheeling')
1. Report all transmission of electricity, Le., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilties, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, lFP - "long-Term Firm Point to Point
Transmission Service, OlF - Other long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line Payment By Energy Received From Energy Delivered To Statistical
No.(Company of Public Authority)(Company of Public Authority)(Company of Public Authority)Classifi-
(Footnote Affliation)(Footnote Affliation)(Footnote Affliation)cation
(a)(b)(c)(d)
1 Bonnevile Power Administration - OTEC Bonneville Power Administrtion Oregon Trails Electric Co-op FNO
2 Bonnevile Power Administration - OTEC AD
3 Bonnevile Power Administration - USBR Bonnevile Power Administration United States Bureau of Reclamati FNO
4 Bonnevile Power Administration - USBR AD
5 Bonnevile Power Administration - Raft Bonnevile Power Administration Raft River Electric Co-op FNO
6 Bonnevile Power Administration - Raft AD
7 Bonnevile Power Administration - PF Bonnevile Power Administration Priority Firm Customers FNO
8 Bonnevile Power Administration - PF AD
9 Milner Irrigation District United States Bureau of Reclamati Milner Irrgation District OlF
10 Cargil Seatte City Light Bonnevile Power Administration OS
11 PacifiCorp PacifiCorp West PacifiCorp West FNO
12 PacifiCorp AD
13 United States Bureau of Indian Affirs Bonnevile Power Administrtion United States Bureau of Indian Af OS
14 Black Hils Power PacifiCorp West Bonnevile Power Administrtion NF
15 Black Hils Power Bonneville Power Administration PacifiCorp West NF
16 Black Hils Power .AD
17 Black Hils Power AD
18 BPA Power Administration Bonnevile Power Administrtion Bonnevile Power Administration NF
19 BPA Power Administration Bonnevile Power Administration Sierra Pacific Power NF
20 BPA Power Administrtion Bonnevile Power Administration Sierr Pacific Power SFP
21 BPA Power Administration Avista Bonnevile Power Administrtion NF
22 BPA Power Administration Avista Bonneville Power Administration SFP
23 BPA Power Administration Avista Sierra Pacific Power NF
24 BPA Power Administration Avista Sierra Pacific Power SFP
25 BPA Power Administration AD
26 BPA Power Administration AD
27 Cargil Power Markets PacifiCorp East NortWestem/PacifiCorp East NF
28 Cargil Power Markets PacifiCorp East NorthWestern/PacifiCorp East SFP
29 Cargil Power Markets PacifiCorp East PacifiCorp West NF
30 Cargil Power Markets PacifiCorp East NorthWestem/PacifiCorp East SFP
31 Cargil Power Markets PacifiCorp East Bonnevile Power Administration NF
32 Cargil Power Markets PacifiCorp East Bonnevile Power Administrtion SFP
33 Cargil Power Markets PacifiCorp East Avista NF
34 Cargil Power Markets PacifiCorp East Sierra Pacific Power NF
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328
This ~ort Is:
(1) ~An Onginal
(2) A ResubmissionI I ccunt
(Including transactions reffered to as 'wtìeeling')
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (t), report the
designation for the substation, or other appropriate identification for where energy was received as specifed in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billng demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and m the total megawatthours received and delivered.
Year/Penod of Report
End of 2010/Q4
Name of Respondent
Idaho Power Company
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo. Da, Yr)End of 2010/Q4
(2) ri A Resubmission 04/15/2011
I.OF ELE.'- , n.'v.' , Y t ~~~ccunt 456.1 )
(Including transactions referred to as 'wheeling')
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, lFP - "long-Term Firm Point to Point
Transmission Service, OlF - Other long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups. for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line Payment By Energy Received From Energy Delivered To Statistical
No.(Company of Public Authority)(Company of Public Authority)(Company of Public Authority)Classifi-
(Footnote Affliation)(Footnote Affliation)(Footnote Affliation)cation
(a)(b)(c)(d)
1 Cargil Power Markets PacifiCorp East Sierr Pacific Power SFP
2 Cargil Power Markets PacifiCorp East NorthWestern/PacifiCorp East SFP
3 Cargil Power Markets NortWestern/PacifiCorp East PacifiCorp East NF
4 Cargil Power Markets NortWestern/PacifiCorp East PacifiCorp East SFP
5 Cargill Power Markets NortWestern/PacifiCorp East Avista NF
6 Cargil Power Markets NortWestern/PacifiCorp East Sierra Pacific Power NF
7 Cargil Power Markets NorthWestern/PacifiCorp East Sierra Pacific Power SFP
8 Cargil Power Markets PacifiCorp East PacifiCorp East NF
9 Cargil Power Markets PacifiCorp East PacifiCorp East SFP
10 Cargil Power Markets PacifiCorp East Bonneville Power Administration NF
11 Cargill Power Markets PacifiCorp East Bonneville Power Administrtion SFP
12 Cargill Power Markets PacifiCorp East Avista NF
13 Cargil Power Markets PacifiCorp East Sierra Pacific Power NF
14 Cargil Power Markets PacifiCorp East Sierr Pacific Power SFP
15 Cargil Power Markets PacifiCorp West PacifiCorp East NF
16 Cargil Power Markets PacifiCorp West PacifiCorp East SFP
17 Cargill Power Markets PacifiCorp West PacifiCorp West NF
18 Cargil Power Markets PacifiCorp West Sierr Pacific Power NF
19 Cargil Power Markets PacifiCorp West PacifiCorp East NF
20 Cargil Power Markets PacifiCorp West PacifiCorp East SFP
21 Cargil Power Markets PacifiCorp West NorthWestern/PacifiCorp East NF
22 Cargil Power Markets PacifiCorp West NorthWestem/PacifiCorp East SFP
23 Cargil Power Markets PacifiCorp West PacifiCorp West NF
24 Cargil Power Markets PacifiCorp West Bonnevile Power Administrtion NF
25 Cargil Power Markets PacifiCorp West Bonnevile Power Administration SFP
26 Cargil Power Markets PacifiCorp West Avist NF
27 Cargil Power Markets PacifiCorp West Sierr Pacific Power NF
28 Cargill Power Markets PacifiCorp West Sierr Pacific Power SFP
29 Cargil Power Markets PacifiCorp West NorthWesternlPacifiCorp East SFP
30 Cargil Power Markets NortWestem/PacifiCorp East PacifiCorp East NF
31 Cargil Power Markets NortWestern/PacifiCorp East PacifiCorp East SFP
32 Cargil Power Markets NorthWestem/PacifiCorp East Bonnevile Power Administrtion NF
33 Cargil Power Markets NorthWestern/PacifiCorp East Sierra Pacific Power NF
34 Cargil Power Markets NorthWestem/PacifiCorp East Sierra Pacific Power SFP
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.1
Name of Respondent This 780rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) n A Resubmission 04/15/2011
i ~ . ELt:G I N;11,.ATYFgR a! ccunt 45ö)(Gontinued)
(Including trnsactions reffered to as 'wlìeeling')
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation. or other appropriate identification for where. energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of biling demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and U) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Billng TRANSFER OF ENERGY Line
Schedule of (Subsatation or Other (Substation or Other Demand MegaWatt Hours Megawatt Hours No.
Tariff Number Designation)Designation)(MW)Received Delivered
(e)(f)(g)(h)(i)0)
5 BORA M345 3,203 3,20 1
5 BORA AVAT.NWMT 400 40C 2
5 BPAT.NWMT BORA 651 651 3
5 BPAT.NWMT BORA 5,540 5,54C 4
5 BPAT.NWMT LOLO 56 51 5
5 BPAT.NWMT M345 3,233 3,23;6
5 BPAT.NWMT M345 16,518 16,511 7
5 BRDY BORA 2,548 2,541 8
5 BRDY BORA 400 40(9
5 BRDY LAGRANDE 253 25~10
5 BRDY LAGRANDE 1,699 1,69~11
5 BRDY LOLO 409 4m 12
5 BRDY M345 551 551 13
5 BRDY M345 1,968 1,96~14
5 ENPR BORA 18,253 18,25~15
5 ENPR BORA 1,616 1,611 16
5 ENPR JBSN 800 80(17
5 ENPR M345 10,990 10,99(18
5 JBSN BORA 416 411 19
5 JBSN BORA 317 31 ¡20
5 JBSN BPAT.NWMT 330 33(21
5 JBSN BPAT.NWMT 91 91 22
5 JBSN ENPR 625 62~23
5 JBSN LAGRANDE 2,575 2,57~24
5 JBSN LAGRANDE 892 89~25
5 JBSN LOLO 312 31~26
5 JBSN M345 1,208 1,2Of 27
5 JBSN M345 208 20f 28
5 JBSN AVAT.NWMT 32 3,29
5 JEFF BORA 32 3:30
5 JEFF BORA 400 40(31
5 JEFF LAGRANDE 79 7~32
5 JEFF M345 2,855 2,85'33
5 JEFF M345 258 251 34
0 4,527,870 4,527,871
FERC FORM NO.1 (ED. 12-90)Page 329.1
Name of Respondent This wort Is:Date of Report Year/Penod of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) DA Resubmission 04/15/2011
I Ur T '. ~l~ccunt 456.1)
(Including transactions referred to as .'wheeling')
1. Report all transmission of electricity, Le., wheeling, provided for other electric utilties, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type oftransmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and. conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, as - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line Payment By Energy Received From Energy Delivered To Statistical
No.(Company of Public Authonty)(Company of Public Authority)(Company of Public Authonty)Classifi-
(Footnote Affliation)(Footnote Affliation)(Footnote Affliation)cation
(a)(b)(c)(d)
1 Cargil Power Markets Bonnevile Power Administration PacifiCorp East NF
2 Cargil Power Markets Bonnevile Power Administration PacifiCorp East NF
3 Cargil Power Markets Bonnevile Power Administration PacifiCorp West NF
4 Cargil Power Markets Bonnevile Power Administration Avista NF
5 Cargil Power Markets Bonnevile Power Administration Sierr Pacific Power NF
6 Cargil Power Markets Bonneville Power Administration Sierra Pacific Power SFP
7 Cargil Power Markets Avista PacifiCorp East NF
8 Cargill Power Markets Avista PacifiCorp East SFP
9 Cargil Power Markets Avista Sierr Pacific Power NF
10 Cargil Power Markets Avista Sierr Pacific Power SFP
11 Cargil Power Markets Sierra Pacific Power PacifiCorp East NF
12 Cargil Power Markets Sierra Pacific Power PacifiCorp East SFP
13 Cargil Power Markets Sierra Pacific Power NorthWestern/PacifiCorp East NF
14 Cargil Power Markets Sierra Pacific Power NortWestern/PacifiCorp East SFP
15 Cargil Power Markets Sierra Pacific Power Idaho Power Company NF
16 Cargil Power Markets Sierra Pacific Power Bonnevile Power Administration NF
17 Cargil Power Markets Sierra Pacific Power Bonnevile Power Administration SFP
18 Cargil Power Markets Sierra Pacific Power Avista NF
19 Cargil Power Markets Sierra Pacific Power Sierr Pacific Power NF
20 Cargil Power Markets Sierra Pacific Power Sierra Pacific Power SFP
21 Cargil Power Markets Sierra Pacific Power PacifiCorp East NF
22 Cargil Power Markets Sierra Pacific Power PacifiCorp East SFP
23 Cargil Power Markets Sierra Pacific Power Idaho Power Company NF
24 Cargil Power Markets Sierra Pacific Power Bonnevile Power Administration NF
25 cargil Power Markets Sierra Pacific Power Avista NF
26 Cargil Power Markets Idaho Power Company Bonnevile Power Administration SFP
27 Cargil Power Markets Idaho Power Company Sierra Pacific Power NF
28 Cargil Power Markets AD
29 Cargil Power Markets AD
30 Constellation Energy AD
31 Constellation Energy AD
32 Eagle Energy NF
33 Endure Energy AD
34 Endure Energy AD
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.2
Name of Respondent ThiswrtlS:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2)D A Resubmission 04/15/2011
i ¡!~~ QF ELECTRIGITY FQR (.l nE:l"~ lAccunt 456)(Continued)
(Including transactons reffered to as 'wlieeling')
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billng demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and 0) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Billng TRANSFER OF ENERGY Line
Schedule of (Subsatation or Other (Substation or Other Demand MegaWatt Hours Megawatt Hours No.
Tariff Number Designation)Designation)(MW)Received Delivered
(e)(f)(g)(h)(i)G)
5 LAGRANDE BORA 1,269 1,26~1
5 LAGRANDE BRDY 34 3A 2
5 LAGRANDE JBSN 120 12(3
5 LAG RAN DE LOLO 65 6~4
5 LAGRANDE M345 14,567 14,56 5
5 LAGRANDE M345 3,484 3,48'6
5 LOLO BORA 18,886 18,881 7
5 LOLO BORA 2,808 2,801 8
5 LOLO M345 11,357 11,35 9
5 LOLO M345 1,166 1,16€10
5 LYPK BORA 3,861 3,861 11
5 LYPK BORA 16,193 16, 19~12
5 LYPK BPAT.NWMT 355 35~13
5 LYPK BPAT.NWMT 132 13~14
5 LYPK IPCO 48 4f 15
5 LYPK LAGRANDE 47,965 47,96~16
5 LYPK LAGRANDE 15,151 15,151 17
5 LYPK LOLO 188 181 18
5 LYPK M345 18,038 18,031 19
5 LYPK M345 179,321 179,321 20
5 M345 BORA 768 761 21
5 M345 BORA 32 3~22
5 M345 IPCO 25 2~23
5 M345 LAGRANDE 3,546 3,54€24
5 M345 LOLO 144 14A 25
5 OBBLPR LAGRANDE 400 40(26
5 OBBLPR M345 238 23f 27
5 28
5 29
5 ~30
5 31
5 .32
5 33
5 34
0 4,527,870 4,527,871
FERC FORM NO.1 (ED. 12-90)Page 329.2
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) n A Resubmission 04/15/2011
, i:OR "J '~i~~ceunt 4òö.1)
(Including transactions referred to as 'wheelin ')
1. Report all transmission of electricity, Le., wheeling, provided for other electric utilties, cooperatives, other public authorities,
qualifying facilities, non-traditional utilty suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type oftransmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line Payment By Energy Received From Energy Delivered To Statistical
No.(Company of Public Authority)(Company of Public Authority)(Company of Public Authority)Classifi-
(Footnote Affliation)(Footnote Affliation)(Footnote Affliation)cation
(a)(b)(c)(d)
1 Iberdrola Renewables PacifiCorp East Bonnevile Power Administrtion NF
2 Iberdrola Renewables Bonnevile Power Administrtion PacifiCorp East NF
3 Iberdrola Renewables AD
4 Iberdrola Renewables AD
5 Integrys Energy AD
6 Macquarie Cook Power NortWestern/PacifiCorp East Sierr Pacific Power NF
7 Macquarie Cook Power Bonneville Power Administration PacifiCorp East NF
8 Macquarie Cook Power Bonnevile Power Administrtion PacifiCorp East NF
9 Macquarie Cook Power Bonnevile Power Administration Sierra Pacific Power NF
10 Macquarie Cook Power AD
11 Morgan Stanley Capital Group PacifiCorp East NortWestern/PacifiCorp East NF
12 Morgan Stanley Capital Group PacifiCorp East Sierra Pacific Power NF
13 Morgan Stanley Capital Group PacifiCorp East Sierra Pacific Power SFP
14 Morgan Stanley Capital Group NorthWestern/PacifiCorp East PacifiCorp East NF
15 Morgan Stanley Capital Group NortWestern/PacifiCorp East Bonnevile Power Administration NF
16 Morgan Stanley Capital Group PacifiCorp East NortWestern/PacifiCorp East NF
17 Morgan Stanley Capital Group PacifiCorp East NortWestern/PacifiCorp East NF
18 Morgan Stanley Capital Group PacifiCorp East Bonnevile Power Administration NF
19 Morgan Stanley Capital Group PacifiCorp East Bonnevile Power Administration SFP
20 Morgan Stanley Capital Group PacifiCorp East Avista NF
21 Morgan Stanley Capital Group PacifiCorp East Sierr Pacific Power NF
22 Morgan Stanley Capital Group PacifiCorp East NortWestern/PacifiCorp East NF
23 Morgan Stanley Capital Group PacifiCorp West PacifiCorp East NF
24 Morgan Stanley Capital Group PacifiCorp West Sierr Pacific Power NF
25 Morgan Stanley Capital Group PacifiCorp West NorthWestern/PacifiCorp East NF
26 Morgan Stanley Capital Group PacifiCorp West Bonnevile Power Administrtion NF
27 Morgan Stanley Capital Group Idaho Power Company Bonnevile Power Administration NF
28 Morgan Stanley Capital Group NorthWestern/PacifiCorp East Bonnevile Power Administration NF
29 Morgan Stanley Capital Group NortWestern/PacifiCorp East Avista NF
30 Morgan Stanley Capital Group NorthWestern/PacifiCorp East Sierra Pacific Power NF
31 Morgan Stanley Capital Group NortWestern/PacifiCorp East NortWestern/PacifiCorp East NF
32 Morgan Stanley Capital Group Bonnevile Power Administration PacifiCorp East NF
33 Morgan Stanley Capital Group Bonnevile Power Administrtion PacifiCorp East NF
34 Morgan Stanley Capital Group Bonnevile Power Administration Sierr Pacific Power NF
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.3
Name of Respondent This Report Is:Date of Report Year/Period of Report
Idaho Power Company (1) IKAn Original (Mo, Da, Yr)End of 2010/Q4
(2) nA Resubmission 04/15/2011
i 'FQR ~ i Ht:K!S,lI:ccunt 456)(Continued)
(IncludinQ transactions reffered to as 'wtìeeling')
5. In column (e), identify the FERC Rate Schedule or Tanff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropnate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropnate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of biling demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and U) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Billng TRANSFER OF ENERGY Line
Schedule of (Subsatation or Other (Substation or Other Demand MegaWatt Hours Megawatt HOUrs No.
Tariff Number Designation)Designation)(MW)Received Delivered
(e)(f)(g)(h)(i)G)
5 BORA LAGRANDE 957 95 1
5 LAGRANDE BORA 386 38€2
5 3
5 4
5 5
5 BPAT.NWMT M345 75 7!6
5 LAGRANDE BORA 946 94E 7
5 LAGRADE BRDY 53 5.8
5 LAGRANDE M345 241 241 9
5 .10
5 BORA BPAT.NWMT 80 8(11
5 BORA M345 1,617 1,61 12
5 BORA M345 623 62:13
5 BPAT.NWMT BRDY 45 4~14
5 BPAT.NWMT LAGRANDE 806 80€15
5 BRDY BPAT.NWMT 44 4A 16
5 BRDY JEFF 45 4!17
5 BRDY LAGRANDE 30,482 30,48~18
5 BRDY LAGRANDE 215 2H 19
5 BRDY LOLO 2,571 2,571 20
5 BRDY M345 352 35~21
5 BRDY AVAT.NWMT 18 1!22
5 ENPR BRDY 2,687 2,68 23
5 ENPR M345 315 31'24
5 JBSN BPAT.NWMT 10 1(25
5 JBSN LAGRANDE 127 12 26
5 JBwr LAGRADE 445 44B 27
5 JEFF LAGRANDE 5,007 5,007 28
5 JEFF LOLO 360 36C 29
5 JEFF M345 52 5.30
5 JEFF GSHN 25 2!31
5 LAGRANDE BORA 314 31'32
5 LAGRANDE BRDY 4,411 4,411 33
5 LAGRANDE M345 2,667 2,661 34
0 4,527,870 4,527,87(
FERC FORM NO.1 (ED. 12-90)Page 329.3
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) ri A Resubmission 04/15/2011
I OF ELEC;I KIl.IT T i:':K U ccunt 456.1)
(Including transactons referred to as 'wheeling')
1. Report all transmission of electricity, i.e., wheeling, provided for other electrc utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, lFP - "long-Term Firm Point to Point
Transmission Service, OlF - Other long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, as - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line Payment By Energy Received From Energy Delivered To Statistical
No.(Company of Public Authority)(Company of Public Authority)(Company of Public Authority)Classifi-
(Footnote Affliation)(Footnote Affliation)(Footnote Affliation)cation
(a)(b)(c)(d)
1 Morgan Stanley Capital Group Avista PacifiCorp East NF
2 Morgan Stanley Capital Group Avista Bonneville Power Administrtion NF
3 Morgan Stanley Capital Group Avista Sierra Pacific Power NF
4 Morgan Stanley Capital Group Sierra Pacific Power PacifiCorp East NF
5 Morgan Stanley Capital Group Sierra Pacific Power PacifiCorp West NF
6 Morgan Stanley Capital Group Sierra Pacific Power NortWestem/PacifiCorp East NF
7 Morgan Stanley Capital Group Sierra Pacific Power Bonnevile Power Administrtion NF
8 Morgan Stanley Capital Group NorthWestern/PacifiCorp East PacifiCorp East NF
9 Morgan Stanley Capital Group NorthWestem/PacifiCorp East Bonnevile Power Administration NF
10 Morgan Stanley Capital Group AD
11 Morgan Stanley Capital Group AD
12 Nortwestern Energy PacifiCorp East Bonneville Power Administration NF
13 Northwestern Energy NorthWestem/PacifiCorp East Bonnevile Power Administration NF
14 Northwestern Energy AD
15 Pacificorp Power Marketing PacifiCorp East PacifiCorp West NF
16 Pacificorp Power Marketing PacifiCorp East Idaho Power Company NF
17 Pacificorp Power Marketing PacifiCorp East Bonneville Power Administration NF
18 Pacificorp Power Marketing PacifiCorp East Idaho Power Company NF
19 Pacificorp Power Marketing PacifiCorp East Idaho Power Company LFP
20 Pacificorp Power Marketing PacifiCorp East PacifiCorp East NF
21 Pacificorp Power Marketing PacifiCorp East PacifiCorp East SFP
22 Pacificorp Power Marketing PacifiCorp East Idaho Power Company NF
23 Pacificorp Power Marketing PacifiCorp West PacifiCorp East NF
24 Pacificorp Power Marketing PacifiCorp West PacifiCorp East NF
25 Pacificorp Power Marketing PacifiCorp West Idaho Power Company NF
26 Pacificorp Power Marketing PacifiCorp West Sierr Pacific Power NF
27 Pacificorp Power Marketing Idaho Power Company PacifiCorp East NF
28 Pacificorp Power Marketing Idaho Power Company PacifiCorp East LFP
29 Pacificorp Power Marketing Idaho Power Company PacifiCorp East NF
30 Pacificorp Power Marketing Idaho Power Company PacifiCorp West NF
31 Pacificorp Power Marketing Idaho Power Company Idaho Power Company NF
32 Pacificorp Power Marketing Idaho Power Company NorthWestem/PacifiCorp East NF
33 Pacificorp Power Marketing Idaho Power Company Bonneville Power Administrtion NF
34 Pacificorp Power Marketing Idaho Power Company PacifiCorp West NF
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.4
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2)D A Resubmission 04/15/2011
Ut T i-~K 4 ~' ,~, ';W ,(Accunt 456)(Contlnued)
(Including transactons reffered to as 'wlieeling')
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specifed in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Biling ,TRANSFER OF ENERGY LineSchedule of (Subsatation or Other (Substation or Other Demand MegaWatt Hours MegaWatt Hours No.Tariff Number Designation)Designation)(MW)Received Delivered
(e)(f)(g)(h)(i)G)
5 LOLO BRDY 414 41A 1
5 LOLO LAG RA DE 21 21 2
5 LOLO M345 799 79~3
5 M345 BRDY 35 3f 4
5 M345 JBSN 5 "5
5 M345 JEFF 180 18C 6
5 M345 LAGRANDE 130 13C 7
5 GSHN BRDY 40 4C 8
5 GSHN LAG RAN DE 235 23"9
5 -10
5 11
5 BRDY LAGRANDE 397 39 12
5 JEFF LAGRANDE --762 76 13
5 14
5 BORA ENPR 31,339 31,33~15
5 BORA IPCO 33 3 16
5 BORA LAGRANDE 13,680 13,68C 17
5 BORA KPRT 1,251 1,251 18
5 BORA KPRT 108,362 108,36:.19
5 BRDY BRDY 8,702 8,70:.20
5 BRDY BRDY 726 72€21
5 BRDY KPRT 16,320 16,320 22
5 ENPR BORA 73,303 73,303 23
5 ENPR BRDY 13,239 13,239 24
5 ENPR IPCO 9,562 9,56:.25
5 ENPR M345 1,050 1,050 26
5 JBM BORA 29,317 29,31 (27
5 JBM BORA 161,627 161,62(28
5 JBM BRDY 181,559 181,559 29
5 JBM ENPR 56,964 56,964 30
5 JBM IPCO 564 564 31
5 JBM JEFF 50 50 32
5 JBM LAG RAN DE 17,568 17,568 33
5 JBM M500 31,591 31,591 34
0 4,527,870 4,527,870
FERC FORM NO.1 (ED. 12-90)Page 329.4
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) ñ A Resubmission 04/15/2011
I !9N .OF ELE;(;T~Il.11 y t:u~ u ccunt 456.1)(Including transactions referred to as 'wheeling')
1. Report all transmission of electricity, Le., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utilty suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type oftransmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, lFP - "long-Term Firm Point to Point
Transmission Service, OlF - Other long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code \
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line Payment By Energy Received From Energy Delivered To Statistical
No.(Company of Public Authority)(Company of Public Authority)(Company of Public Authority)Classifi-
(Footnote Affliation)(Footnote Affliation)(Footnote Affliation)cation
(a)(b)(c)(d)
1 Pacificorp Power Marketing Idaho Power Company PacifiCorp West LFP
2 Pacificorp Power Marketing Bonnevile Power Administration PacifiCorp East NF
3 Pacificorp Power Marketing Bonneville Power Administration PacifiCorp East NF
4 Pacificorp Power Marketing Avista PacifiCorp West NF
5 Pacificorp Power Marketing AD
6 Pacificorp Power Marketing AD
7 Portand General Electric PacifiCorp East Bonnevile Power Administration NF
8 Portland General Electric NortWestem/PacifiCorp East Bonnevile Power Administration NF
9 Portland General Electric AD
10 Portland General Electric AD
11 Powerex Corporation PacifiCorp East NortWestem/PacifiCorp East NF
12 Powerex Corporation PacifiCorp East PacifiCorp East NF
13 Powerex Corporation PacifiCorp East PacifiCorp West NF
14 Powerex Corporation PacifiCorp East Bonnevile Power Administration NF
15 Powerex Corporation PacifiCorp East Avista NF
16 Powerex Corporation PacifiCorp East Sierr Pacific Power NF
17 Powerex Corporation NortWestem/PacifiCorp East PacifiCorp East NF
18 Powerex Corporation NorthWestem/PacifiCorp East Bonnevile Power Administration NF
19 Powerex Corporation NorthWestern/PacifiCorp East Sierr Pacific Power NF
20 Powerex Corporation PacifiCorp East NortWestern/PacifiCorp East NF
21 Powerex Corporation PacifiCorp East PacifiCorp West NF
22 Powerex Corporation PacifiCorp East Bonneville Power Administration NF
23 Powerex Corporation PacifiCorp East Bonnevile Power Administration SFP
24 Powerex Corporation PacifiCorp East Avista NF
25 Powerex Corporation PacifiCorp East Sierr Pacific Power NF
26 Powerex Corporation PacifiCorp West PacifiCorp East NF
27 Powerex Corporation PacifiCorp West PacifiCorp East NF
28 Powerex Corporation PacifiCorp West PacifiCorp East SFP
29 Powerex Corporation PacifiCorp West PacifiCorp West NF
30 Powerex Corporation PacifiCorp West Bonnevile Power Administration NF
31 Powerex Corporation PacifiCorp West Sierra Pacific Power NF
32 Powerex Corporation PacifiCorp West NorthWestern/PacifiCorp East NF
33 Powerex Corpration PacifiCorp West PacifiCorp East NF
34 Powerex Corporation PacifiCorp West PacifiCorp West NF
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.5
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) A Resubmission 04/15/2011
TRANSMISSION '-, "',,"''' I Kli.ii Y FOR u i i lL.."'" V ccunt 456)(Continuec
(Including transactions reffered to as 'wlieeling')
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of biling demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and ü) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Billng TRANSFER OF ENERGY LineSchedule of (Subsatation or Other (Substation or Other Demand lIegaWatt Hours Megawatt HOurs No.Tariff Number Designation)Designation)(MW)Received Delivered
(e)(f)(g)(h)(i)0)
5 JBWT M500 929,005 929,00e 1
5 LAGRANDE BORA 3,670 3,67C 2
5 LAGRANDE BRDY 320 32C 3
5 LOLO ENPR 1,624 1,62¿4
5 ~5
5 6
5 BRDY LAGRADE 2 ~7
5 JEFF LAGRANDE -200 20C 8
5 .9
5 10
5 BORA BPAT.NWMT 132 13~11
5 BORA BRDY 349 34~12
5 BORA ENPR 265 26e 13
5 BORA LAGRANDE 41,295 41,2ge 14
5 BORA LOLO 15 l'15
5 BORA M345 33 3 16
5 BPAT.NWMT BRDY 472 47,17
5 BPAT.NWMT LAGRANDE 1,157 1,15 18
5 BPAT.NWMT M345 399 391 19
5 BRDY BPAT.NWMT 59 51 20
5 BRDY ENPR 9.180 9,18(21
5 BRDY LAGRANDE 35,437 35,43 22
5 BRDY LAGRANDE 2,446 2,44E 23
5 BRDY LOLO 78 71 24
5 BRDY M345 642 64,25
5 ENPR BORA 3,570 3.57(26
5 ENPR BRDY 64,068 64,061 27
5 ENPR BRDY 13,839 13,831 28
5 ENPR JBSN 129 121 29
5 ENPR LAGRANDE 2,664 2.66¿30
5 ENPR M345 1,766 1,76E 31
5 JBSN BPAT.NWMT 333 33 32
5 JBSN BRDY 20 2(33
5 JBSN ENPR 54 .5¿34
0 4,527,870 4,527,87(
FERC FORM NO.1 (ED. 12-90)Page 329.5
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) ri A Resubmission 04/15/2011
i . i:Li:v "'~' I Y F:9R UI,I," ""'_ v: ccunt 456.1)
(Including transactions referred to as 'wheeling')
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilties, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions ofthe service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, lFP - "long-Term Firm Point to Point
Transmission Service, OlF - Other long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, as - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line Payment By Energy Received From Energy Delivered To Statistical
No.(Company of Public Authority)(Company of Public Authority)(Company of Public Authority)Classifi-
(Footnote Affliation)(Footnote Affliation)(Footnote Affliation)cation
(a)(b)(c)(d)
1 Powerex Corpration PacifiCorp West NortWestem/PacifiCorp East NF
2 Powerex Corporation PacifiCorp West Bonnevile Power Administrtion NF
3 Powerex Corporation PacifiCorp West Avista NF
4 Powerex Corporation Idaho Power Company PacifiCorp East NF
5 Powerex Corporation Idaho Power Company PacifiCorp West NF
6 Powerex Corporation Idaho Power Company Bonnevile Power Administrtion NF
7 Powerex Corporation Idaho Power Company Avista NF
8 Powerex Corporation NorthWestern/PacifiCorp East Bonnevile Power Administration NF
9 Powerex Corporation NorthWestern/PacifiCorp East Avista NF
10 Powerex Corpration NorthWestem/PacifiCorp East Sierra Pacific Power NF
11 Powerex Corporation Bonnevile Power Administration PacifiCorp East NF
12 Powerex Corporation Bonnevile Power Administration PacifiCorp East NF
13 Powerex Corporation Bonnevile Power Administration PacifiCorp East SFP
14 Powerex Corporation Bonnevile Power Administration PacifiCorp West NF
15 Powerex Corporation Bonnevile Power Administration Sierra Pacific Power NF
16 Powerex Corporation Avista PacifiCorp East NF
17 Powerex Corporation Avista PacifiCorp East NF
18 Powerex Corporation Avista Bonnevile Power Administration NF
19 Powerex Corporation Avista Sierr Pacific Power NF
20 Powerex Corporation Sierra Pacific Power NorthWestem/PacifiCorp East NF
21 Powerex Corporation Sierra Pacific Power PacifiCorp East NF
22 Powerex Corporation Sierr Pacific Power PacifiCorp West NF
23 Powerex Corporation Sierr Pacific Power NorthWestem/PacifiCorp East NF
24 Powerex Corporation Sierra Pacific Power Bonnevile Power Administration NF
25 Powerex Corporation NortWestern/PacifiCorp East PacifiCorp East NF
26 Powerex Corporation NorthWestem/PacifiCorp East PacifiCorp East NF
27 Powerex Corporation NortWestern/PacifiCorp East PacifiCorp West NF
28 Powerex Corporation NortWestern/PacifiCorp East PacifiCorp West NF
29 Powerex Corporation NorthWestern/PacifiCorp East Bonneville Power Administration NF
30 Powerex Corporation AD
31 Powerex Corporation AD
32 PPL EnergyPlus, LLC PacifiCorp East NorthWestem/PacifiCorp East NF
33 PPL EnergyPlus, LLC PacifiCorp East Bonneville Power Administration NF
34 PPL EnergyPlus, LLC PacifiCorp East Avista NF
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.6
Name of Respondent This~rtIS:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) nA Resubmission 04/15/2011
,qF i:1 T ,l,Iccunt 456)(Contlnued)(Including transactions reffered to as 'wfieeling')
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and ü) the total megawatthours received and delivered.
FERC Rate Point of Receipt .Point of Delivery Biling TRANSFER OF ENERGY LineSchedule of (Subsatation or Other (Substation or Other Demand MegaWatt Hours Megawatt Hours No.Tariff Number Designation)Designation)(MW)Received Delivered
(e)(f)(g)(h)(i)0)
5 JBSN JEFF 54 5-1 1
5 JBSN LAGRANDE 8,338 8,33€2
5 JBSN LOLO 23 2"3
5 JBWT BRDY 154 15-1 4
5 JBWT ENPR 10 1C 5
5 JBWT LAGRANDE 3,762 3,76.6
5 JBWT LOLa 150 15C 7
5 JEFF LAGRANDE 3,528 3,52€8
5 JEFF LOLa 11 11 9
5 JEFF M345 50 5C 10
5 LAGRANDE BORA 6,267 6,26 11
5 LAGRANDE BRDY 4,662 4,66~12
5 LAGRANDE BRDY 280 28C 13
5 LAGRANDE JBSN 1,258 1,25€14
5 LAGRANDE M345 6,262 6,26~15
5 LOLa BORA 248 24l 16
5 LOLa BRDY 1,892 1,89.17
5 LOLa LAGRANDE 1,600 1,60(18
5 LOLa M345 313 31 19
5 M345 BPAT.NWMT 10 1(20
5 M345 BRDY 155 15!21
5 M345 ENPR 150 15(22
5 M345 JEFF 37 3 23
5 M345 LAGRANDE 2,940 2,94(24
5 AVAT.NWMT BORA 129 12!25
5 GSHN BRDY 100 10(26
5 GSHN ENPR 132 13.27
5 GSHN JBSN 30 3(28
5 GSHN LAGRANDE 2,354 2,35'29
5 30
5 31
5 BRDY BPAT.NWMT 15 1!32
5 BRDY LAGRANDE 24,028 24,02f 33
5 BRDY LOLa 932 93~34
0 4,527,870 4,527,87(
FERC FORM NO.1 (ED. 12-90)Page 329.6
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) n A Resubmission 04/15/2011
iOFi:1 1 '.~ ~ ;(~ccunt456.1)
(Including transactions referred to as 'wheeling')
1. Report all transmission of electricity, Le., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions ofthe service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, as - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line Payment By Energy Received From Energy Delivered To Statistical
No.(Company of Public Authority)(Company of Public Authority)(Company of Public Authority)Classifi-
(Footnote Affliation)(Footnote Affliation)(Footnote Affliation)cation
(a)(b)(c)(d)
1 PPL EnergyPlus, LLC PacifiCorp East Avista SFP
2 PPL EnergyPlus. LLC NorthWestern/PacifiCorp East Bonnevile Power Administration NF
3 PPL EnergyPlus, LLC NorthWestern/PacifiCorp East Avista NF
4 PPL EnergyPlus. LLC Avista PacifiCorp East NF
5 PPL EnergyPlus, LLC Avista Sierra Pacific Power NF
6 PPL EnergyPlus, LLC PacifiCorp East Avista SFP
7 PPL EnergyPlus, LLC AD
8 PPL EnergyPlus, LLC AD
9 Puget Sound Energy PacifiCorp East Bonnevile Power Administration NF
10 Puget Sound Energy PacifiCorp East Avista .~NF
11 Puget Sound Energy NorthWestern/PacifiCorp East Bonnevile Power Administrtion NF
12 Puget Sound Energy Sierr Pacific Power Bonnevile Power Administration NF
13 Puget Sound Energy AD
14 Puget Sound Energy AD
15 Rainbow Energy Marketing Company PacifiCorp East Avista NF
16 Rainbow Energy Marketing Company PacifiCorp East Sierr Pacific Power NF
17 Rainbow Energy Marketing Company NorthWestern/PacifiCorp East Sierra Pacific Power NF
18 Rainbow Energy Marketing Company NorthWestern/PacifiCorp East Sierra Pacific Power SFP
19 Rainbow Energy Marketing Company PacifiCorp East Bonnevile Power Administrtion NF
20 Rainbow Energy Marketing Company PacifiCorp East Avista NF
21 Rainbow Energy Marketing Company PacifiCorp East Sierra Pacific Power NF
22 Rainbow Energy Marketing Company PacifiCorp East Sierra Pacific Power SFP
23 Rainbow Energy Marketing Company PacifiCorp West NortWestern/PacifiCorp East SFP
24 Rainbow Energy Marketing Company NortWestern/PacifiCorp East Sierr Pacific Power NF
25 Rainbow Energy Marketing Company NortWestern/PacifiCorp East Sierra Pacific Power SFP
26 Rainbow Energy Marketing Company Bonnevile Power Administration Sierr Pacific Power NF
27 Rainbow Energy Marketing Company Avista PacifiCorp East NF
28 Rainbow Energy Marketing Company Avista PacifiCorp East SFP
29 Rainbow Energy Marketing Company Avista Sierr Pacific Power NF
30 Rainbow Energy Marketing Company Avista Sierra Pacific Power SFP
31 Rainbow Energy Marketing Company Sierr Pacific Power Avista NF
32 Rainbow Energy Marketing Company NortWestern/PacifiCorp East PacifiCorp East SFP
33 Rainbow Energy Marketing Company NortWestern/PacifiCorp East Sierra Pacific Power NF
34 Rainbow Energy Marketing Company NorthWestern/PacifiCorp East Sierra Pacific Power SFP
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.7
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) DA Resubmission 04/15/2011
i-YK i. i . ,~, ':-x ccunt 456)(Continued)
(Including trnsactions reffered to as 'wtieeling;)'
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatt of billng demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and ü) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Biling TRANSFER OF ENERGY LineSchedule of (Subsatation or Other (Substation or Other Demand MegaWatt Hours Megawatt HOurs No.Tariff Number Designation)Designation)(MW)Received Delivered
(e)(f)(g)(h)(i)ü)
5 BRDY LOLO 1,080 1,08C 1
5 JEFF LAGRANDE 7,251 7,251 2
5 JEFF LOLO 1,271 1,271 3
5 LOLO BRDY 15 1~4
5 LOLO M345 1,136 1,13€5
5 MLCK LOLO 1,104 1,10'1 6
5 7
5 8,
5 BRDY LAGRANDE 17,782 17,78~9
5 BRDY LOLO 5 ~10
5 JEFF LAGRANDE 117 111 11
5 M345 LAGRANDE 180 18C 12
5 13
5 14
5 BORA LOLO 400 40C 15
5 BORA M345 400 40C 16
5 BPAT.NWMT M345 40 4C 17
5 BPAT.NWMT M345 720 72C 18
5 BRDY LAGRANDE 330 33C 19
5 BRDY LOLO 50 5C 20
5 BRDY M345 7,523 7,52~21
5 BRDY M345 29,800 29,80C 22
5 JBSN JEFF 768 76€23
5 JEFF M345 1,512 1,51~24
5 JEFF M345 800 80C 25
5 LAGRANDE M345 1,329 1,32~26
5 LOLO BORA 1,320 1,32C 27
5 LOLO BORA 12,384 12,38'28
5 LOLO M345 4,039 4,03~29
5 LOLO M345 2,995 2,99~30
5 M345 LOLO 6 €31
5 AVAT.NWMT BRDY 400 40C 32
5 AVAT.NWMT M345 600 60C 33
5 AVAT.NWMT M345 600 60C 34
0 4,527,870 4,527,870
FERC FORM NO.1 (ED. 12-90)Page 329.7
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) DA Resubmission 04/15/2011
T cL t:\,K ~ ':_ ,,..Ll;ccunt 456.1)
(Including transactions referred to as 'wheeling')
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilties, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line Payment By Energy Received From Energy Delivered To Statistical
No.(Company of Public Authority)(Company of Public Authority)(Company of Public Authority)Classifi-
(Footnote Affliation)(Footnote Affliation)(Footnote Affliation)cation
(a)(b)(c)(d)
1 Rainbow Energy Marketing Company AD
2 Rainbow Energy Marketing Company AD
3 Seattle City Light LFP
4 Seattle City Light AD
5 Sempra Energy AD
6 Sempra Energy AD
7 Shell Energy North America PacifiCorp East Bonneville Power Administration NF
8 Shell Energy Nort America PacifiCorp East Bonnevile Power Administration NF
9 Shell Energy Nort America PacifiCorp East Sierra Pacific Power NF
10 Shell Energy North America PacifiCorp West Bonnevile Power Administration NF
11 Shell Energy Nort America NorthWestem/PacifiCorp East Bonneville Power Administration NF
12 Shell Energy Nort America NortWestern/PacifiCorp East Avista NF
13 Shell Energy North America Bonneville Power Administration Sierra Pacific Power NF
14 Shell Energy North America Sierr Pacific Power Bonnevile Power Administration NF
15 Shell Energy North America Sierra Pacific Power NortWestern/PacifiCorp East NF
16 Shell Energy North America Sierra Pacific Power PacifiCorp East NF
17 Shell Energy North America Sierra Pacific Power Bonnevile Power Administration NF
18 Shell Energy North America Idaho Power Company Bonnevile Power Administration NF
19 Shell Energy North America Idaho Power Company Bonnevile Power Administration NF
20 Shell Energy Nort America AD
21 Shell Energy Nort America AD
22 Sierra Pacific Power NorthWestern/PacifiCorp East Sierr Pacific Power NF
23 Sierra Pacific Power PacifiCorp East Sierra Pacific Power NF
24 Sierra Pacific Power PacifiCorp East Sierr Pacific Power SFP
25 Sierra Pacific Power PacifiCorp West Sierr Pacific Power NF
26 Sierra Pacific Power NorthWestern/PacifiCorp East Sierra Pacific Power NF
27 Sierra Pacific Power Bonnevile Power Administration Sierra Pacific Power NF
28 Sierra Pacific Power Bonnevile Power Administration Sierra Pacific Power SFP
29 Sierra Pacific Power Avista Sierr Pacific Power NF
30 Sierra Pacific Power Avista Sierra Pacific Power SFP
31 Sierra Pacific Power Sierra Pacific Power PacifiCorp East NF
32 Sierra Pacific Power Sierr Pacific Power NorthWestem/PacifiCorp East NF
33 Sierra Pacific Power Sierra Pacific Power Bonnevile Power Administration NF
34 Sierra Pacific Power Sierra Pacific Power Avista NF
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.8
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2)o A Resubmission 04/15/2011
qF 1=1 . FgR '" ._. ';- lAccunt 45ö)(l,ontinuea)(Induding transactions reffered to as 'wtieeling').
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, .point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billng demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and ü) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Biling TRANSFER OF ENERGY LineSchedule of (Subsatation or Other (Substation or Other Demand Megawatt Hours Megawatt Hours No.Tariff Number Designation)Designation)(MW)Received Delivered
(e)(f)(g)(h)(i)0)
5 1
5 2
5 3
5 4
5 5
5 6
5 BORA LAGRADE 352 35.7
5 BRDY LAGRANDE 7,507 7,50 8
5 BRDY M345 784 78'9
5 JBSN LAGRADE 64 6l 10
5 JEFF LAG RA DE 1,262 1,26.11
5 JEFF LOLO 70 7(12
5 LAGRANDE M345 5,687 5,68 13
5 LYPK LAGRADE 633 63.:14
5 M345 BPAT.NWMT 25 2f 15
5 M345 BRDY 65 65 16
5 M345 LAGRANDE 5,937 5,93 17
5 MDSK LAGRANDE 88 8~18
5 OBBLPR LAGRANDE 155 15f 19
5 20
5 21
5 BPAT.NWMT M345 264 261 22
5 BRDY M345 14,496 14,49E 23
5 BRDY M345 11,215 11,21e 24
5 JBSN M345 146 14E 25
5 JEFF M345 713 71 26
5 LAGRANDE M345 27,772 27,77í.27
5 LAGRANDE M345 272 27.28
5 LOLO M345 28,510 28.51C 29
5 LOLO M345 14,071 14,071 30
5 M345 BRDY 55 5f 31
5 M345 JEFF 501 501 32
5 M345 LAGRANDE 8,261 8,261 33
5 M345 LOLO 200 20(34
0 4,527,870 4,527,87(
FERC FORM NO.1 (ED. 12-90)Page 329.8
Name of Respondent This wort Is:Date of Report Year/Penod of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2)D A Resubmission 04/15/2011
.OF ELEC-i KIL¿l I T r: I HI' :S_ lI;ccunt 456.1 )
(Including transactions referred to as 'wheeling')
1. Report all transmission of electncity, Le., wheeling, provided for other electnc utilities, cooperatives, other public authonties,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type oftransmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authonty that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authonty. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the onginal contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, lFP - "long-Term Firm Point to Point
Transmission Service, OlF - Other long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Penod Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting penods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line Payment By Energy Received From Energy Delivered To Statistical
No.(Company of Public Authonty)(Company of Public Authonty)(Company of Public Authonty)Classifi-
(Footnote Affliation)(Footnote Affliation)(Footnote Affliation)cation
(a)(b)(c)(d)
1 Sierra Pacific Power AD
2 Sierra Pacific Power AD
3 Southernn California Edison NorthWestern/PacifiCorp East Bonneville Power Administrtion NF
4 Transalta Energy Marketing PacifiCorp East Bonnevile Power Administration NF
5 Transalta Energy Marketing NortWestern/PacifiCorp East Sierra Pacific Power NF
6 Transalta Energy Marketing PacifiCorp East Bonnevile Power Administrtion NF
7 Transalta Energy Marketing PacifiCorp East Avista NF
8 Transalta Energy Marketing PacifiCorp West Bonneville Power Administrtion NF
9 Transalta Energy Marketing Bonnevile Power Administration PacifiCorp East NF
10 Transalta Energy Marketing Bonnevile Power Administration PacifiCorp East NF
11 Transalta Energy Marketing Bonnevile Power Administrtion Sierr Pacific Power NF
12 Transalta Energy Marketing Avista PacifiCorp East NF
13 Transalta Energy Marketing Avista Sierra Pacific Power NF
14 Transalta Energy Marketing Sierr Pacific Power Bonnevile Power Administration NF
15 Transalta Energy Marketing Sierra Pacific Power Avista NF
16 Transalta Energy Marketing AD
17 Transalta Energy Marketing AD
18 Utah Associated Municipal Power Systems PacifiCorp East Sierra Pacific Power NF
19 Utah Associated Municipal Power Systems AD
20 Utah Associated Municipal Power Systems AD
21
22
23
24
25
26
27
28
29
30
31
32
33
34
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.9
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) Õ A Resubmission 04/15/2011
~i- IT. lAccunt 45ö)(l.ontlnueo)
(Including transactions reffered to as 'wlieeling')
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (t), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billng demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and U) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Billing TRANSFER OF ENERGY LineSChedule of (Subsatation or Other (Substation or Other Demand MegaWatt Hours MegaWatt Hours No.Tariff Number Designation)Designation)(MW)Received Delivered
(e)(f)(g)(h)(i)ü)
5 1
5 2
5 GSHN LAGRANDE 20 ..20 3
5 BORA LAGRANDE 1,239 1,239 4
5 BPAT.NWMT M345 75 75 5
5 BRDY LAG RAN DE 280 280 6
5 BRDY LOLO 63 61 7
5 JBSN LAGRANDE 600 600 8
5 LAGRANDE BORA 474 474 9
5 LAGRANDE BRDY 60 60 10
5 LAGRANDE M345 712 71;¿11
5 LOLO BORA 1,528 1,52S 12
5 LOLO M345 25 25 13
5 M345 LAGRADE 477 471 14
5 M345 LOLO 10 10 15
5 16
5 17
5 BORA M345 3,074 3,074 18
5 19
5 20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
0 4,527,870 4,527,87C
FERC FORM NO.1 (ED. 12-90)Page 329.9
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) ri A Resubmission 04/15/2011
. o.f Ii y fQR ",' ...,,~v~ccunf456) (Continued)
(Including transactions reffered to as 'w eeling')
9. In column (k) through (n), report the revenue amounts as shown on bils or vouchers. In column (k), provide revenues from demand
charges related to the billng demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bils or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bils rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and U) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)Line
($)($)($)(k+l+m)No.
(k)(I)(m)(n)
1,241,026 2,602 1,243,628 1
-29,701 -29,701 2
1,055,121 145,316 1,200,437 3
-13,829 -13,829 4
585,362 -81,836 503,526 5
-14,459 -14,459 6
2,354,828 -454,037 1,900,791 7
-58,373 -58,373 8
13,581 13,581 9
203,368 203,368 10
6,464 1,466 7,930 11
-155 -155 12
54,639 54,639 13
2,870 2,870 14
1,990 1,990 15
-105 -105 16
-22 -22 17
4,361 4,361 18
2,843 2,843 19
3,446 3,446 20
7,264 7,264 21
39,130 39,130 22
2,110 2,110 23
3,075 3,075 24
-1,727 -1,727 25
-229 -229 .26
843 843 27
334 334 28
62 62 29
127 127 30
5,542 5,542 31
15,866 15,866 32
1,008 1,008 33
1,391 1,391 34
5,180,923 10,217,479 0 15,398,402
FERC FORM NO.1 (ED. 12-90)Page 330
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) ri A Resubmission 04/15/2011
i ......v I KIl,l I y' FQR L1IMt:K;:vf,~ccunt456HC(ntinued)
(Including transactions reffered to as 'w eeling')
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billng demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bils or vouchers rendered, including
out of penod adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bils rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and ü) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entnes and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)Line
($)($)($)(k+l+m)No.
(k)(I)(m)(n)
1,510 1,510 1
189 189 2
307 307 3
2,611 2,611 4
26 26 5
1,524 1,524 6
7,786 7,786 7
1,201 1,201 8
189 189 9
119 119 10
801 801 11
193 193 12
260 260 13
928 928 14
8,604 8,604 15
762 762 16
377 377 17
5,180 5,180 18
196 196 19
149 149 20
156 156 21
43 43 22
295 295 23
1,214 1,214 24
420 420 25
147 147 26
569 569 27
98 98 28
15 15 29
15 15 30
189 189 31
37 37 32
1,346 1,346 33
122 122 34
5,180,923 10,217,479 0 15,398,402
FERC FORM NO.1 (ED. 12-90)Page 330.1
Name of Respondent This Report Is:Date of Report Year/Period of Report
Idaho Power Company (1) ~An Original (Mo, Da, Yr)End of 2010/Q4
(2) n A Resubmission 04/15/2011
! qF Y i ~f,~ccunf4ContinUed)
(Including trnsactons reftered to as 'w eelina')
9. In column (k) through (n), report the revenue amounts as shown on bils or vouchers. In column (k), provide revenues from demand
charges related to the biling demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bils or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bils rendered to the entity Listed in column (a). If no monetary settement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and U) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)Line
($)($)($)(k+l+m)No.
(k)(I)(m)(n)
598 598 1
16 16 2
57 57 3
31 31 4
6,866 6,866 5
1,642 1,642 6
8,902 8,902 7
1,324 1,324 8
5,353 5,353 9
550 550 10
1,820 1,820 11
7,633 7,633 12
167 167 13
62 62 14
23 23 15
22,609 22,609 16
7,142 7,142 17
89 89 18
.8,503 8,503 19
84,526 84,526 20
362 362 21
15 15 22
12 12 23
1,671 1,671 24
68 68 25
189 189 26
112 112 27
-33,126 -33,126 28
-8,263 -8,263 29
-2,682 -2,682 30
-200 -200 31
45 45 32
-206 -206 33
-1,194 -1,194 34
5,180,923 10,217,479 0 15,398,402
FERC FORM NO.1 (ED. 12-90)Page 330.2
Name of Respondent This Report Is:Date of Report YeadPeriod of Report
Idaho Power Company (1) !KAn Original (Mo, Da, Yr)End of 2010/Q4
(2) DA Resubmission 04/15/2011
i lOf 1:1 T , ~ ~h~ccunt 456) (Continued)
(Including transactons reffered to as 'w eeling')
9. In column (k) through (n), report the revenue amounts as shown on bils or vouchers. In column (k), provide revenues from demand
charges related to the biling demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bils or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bils rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and ü) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)Line
($)($)($)(k+l+m)No.
(k)(I)(m)(n)
4,958 . 4,958 1
2,000 2,000 2
-530 -530 3
-16 -16 4
-6 -6 5
230 230 6
2,900 2,900 7
162 162 8
739 739 9
-4 -4 10
273 273 11
5,519 5,519 12
2,127 2,127 13
154 154 14
2,751 2,751 15
150 150 16
154 154 17
104,047 104,047 18
734 734 19
8,776 8,776 20
1,202 1,202 21
61 61 22
9,172 9,172 23
1,075 1,075 24
34 34 25
434 434 26
1,519 1,519 27
17,091 17,091 28
1,229 1,229 29
177 177 30
85 85 31
1,072 1,072 32
15,056 15,056 33
9,104 9,104 34
5,180,923 10,217,479 0 15,398,402
FERC FORM NO.1 (ED. 12-90)Page 330.3
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) Õ A Resubmission 04/15/2011
i-YK ~ i. ,~. ':- ccunt 456) (Continued)
(Including transactions reffered to as 'wlíeelinr:¡')
9. In column (k) through (n), report the revenue amounts as shown on bils or vouchers. In column (k), provide revenues from demand
charges related to the billng demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bils or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered tothe entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and ü) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)Line
($)($)($)(k+l+m)No.
(k)(I)(m)(n)
1,413 1,413 1
72 72 2
2,727 2,727 3
119 119 4
17 17 5
614 614 6
444 444 7
137 137 8
802 802 9
-2,161 -2,161 10
-215 -215 11
1,765 1,765 12
3,387 3,387 13
-13 -13 14
132,821 132,821 15
140 140 16
57,979 57,979 17
5,302 5,302 18
459,260 459,260 19
36,881 36,881 20
3,077 3,077 21
69,167 69,167 22
310,673 310,673 23
56,110 56,110 24
40,526 40,526 25
4,450 4,450 26
124,251 124,251 27
685,008 685,008 28
769,484 769,484 29
241,425 241,425 30
2,390 2,390 31
212 212 32
74,457 74,457 33
133,889 133,889 34
5,180,923 10,217,479 0 15,398,402
FERC FORM NO.1 (eo. 12-90)Page 330.4
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/04
(2) M A Resubmission 04/15/2011
I OF ELEGI KIL;l i Y i ~~ccunt 456)(ContinuEidY
(Including transactions reffered to as 'w eeling')
9. In column (k) through (n), report the revenue amounts as shown on bils or vouchers. In column (k), provide revenues from demand
charges related to the biling demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bils or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and m must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)¡Line
($)($)($)(k+l+m)No.
(k)(I)(m)(n)
3,937,311 3,937,311 1
15,554 15,554 2
1,356 1,356 3
6,883 6,883 4
-98,098 -98,098 5
-18,231 -18,231 6
17 17 7
1,679 1,679 8
-1,214 -1,214 9
-214 -214 10
437 437 11
1,155 1,155 12
877 877 13
136,631 136,631 14
50 50 15
109 109 16
1,562 1,562 17
3,828 3,828 18
1,320 1,320 19
195 195 20
30,373 30,373 21
117,249 117,249 22
.8,093 8,093 23
258 258 24
2,124 2,124 25
11,812 11,812 26
211,979 211,979 27
45,789 45,789 28
427 427 29
8,814 8,814 30
5,843 5,843 31
1,102 1,102 32
66 66 33
179 179 34
5,180,923 10,217,479 0 15,398,402
FERC FORM NO.1 (ED. 12-90)Page 330.5
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Onginal (Mo, Da, Yr)End of 2010/Q4
(2) 0 A Resubmission 04/15/2011
: Of. ELEC-i KI!:II T , ~h¿ccunt 456) (Olntinueå)
(Including transactions reffered to as 'w eeling')
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the biling demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total reVenues from all other charges on bils or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bils rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and ü) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)Line
($)($)($)(k+l+m)No.
(k)(I)(m)(n)
179 179 1
27,588 27,588 2
76 76 3
510 510 4
33 33 5
12,447 12,447 6
496 496 7
11,673 11,673 8
36 36 9
165 165 10
20,735 20,735 11
15,425 15,425 12
926 926 13
4,162 4,162 14
20,719 20,719 15
821 821 16
6,260 6,260 17
5,294 5,294 18
1,036 1,036 19
33 33 20
513 513 21
496 496 22
122 122 23
9,727 9,727 24
427 427 25
331 331 26
437 437 27
99 99 28
7,789 7,789 29
-60,353 -60,353 30
-9,282 -9,282 31
34 34 32
53,884 53,884 33
2,090 2,090 34
5,180,923 10,217,479 0 15,398,402
FERC FORM NO.1 (ED. 12-90)Page 330.6
Name of Respondent This (80rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) ri A Resubmission 04/15/2011
lO,': ELECTRIÇII y i-YK l. ccunt 45ö) ((,ontinuecl(Including transactions reffered to as 'wheeling')
9. In column (k) through (n), report the revenue amounts as shown 011 bils or vouchers. In column (k), provide revenues from demand
charges related to the biling demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bils or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature ofthe non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and ü) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS .
Demand Charges Energy Charges (Other Charges)Total Revenues ($)Line
($)($)($)(k+l+m)No.
(k)(I)(m)(n)
2,422 2,422 1
16,261 16,261 2
2,864 2,864 3
34 34 4
2,548 2,548 5
2,476 2,476 6
-1,705 -1,705 7
-233 -233 8
48,736 48,736 9
14 14 10
321 321 11
493 493 12
-1,996 -1,996 13
-84 -84 14
887 887 15
887 887 16
89 89 17
1,596 1,596 18
731 731 19
111 111 20
16,675 16,675 21
66,051 66,051 22
1,702 1,702 23
3,351 3,351 24
1,773 1,773 25
2,946 2,946 26
2,926 2,926 27
27,449 27,449 28
8,952 8,952 29
6,638 6,638 30
13 13 31
887 887 32
1,330 1,330 33
1,330 1,330 34
5,180,923 10,217,479 0 15,398,402
FERC FORM NO.1 (ED. 12-90)Page 330.7
Name of Respondent This Report Is:Date of Report Year/Period of Report
Idaho Power Company (1) !KAn Original (Mo, Da, Yr)End of 2010/Q4
(2) D A Resubmission 04/15/2011
rRANSMI t:Lt:~1 Klyll Y FQR l. I. ':- ccunt 'I ntinued)
(Including transactions reffered to as 'wheeling')
9. In column (k) through (n), report the revenue amounts as shown on bils or vouchers. In column (k), provide revenues from demand
charges related to the biling demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bils rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature ofthe non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and 0) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)Line
($)($)($)(k+l+m)No.
(k)(I)(m)(n)
-7,066 -7,066 1
-821 -821 2
1,687,225 1,687,225 3
-41,693 -41,693 4
-1,801 -1,801 5
-281 -281 6
931 931 7
19,855 19,855 8
2,074 2,074 9
169 169 10
3,338 3,338 11
185 185 12
15,041 15,041 13
1,674 1,674 14
66 66 15
172 172 16
15,703 15,703 17
233 233 18
410 410 19
-4,721 -4,721 20
-324 -324 21
650 650 22
35,691 35,691 23
27,613 27,613 24
359 359 25
1,756 1,756 26
68,379 68,379 27
670 670 28
70,196 70,196 29
34,645 34,645 30
135 135 31
1,234 1,234 32
20,342 20,342 33
492 492 34
5,180,923 10,217,479 0 15,398,402
FERC FORM NO.1 (ED. 12-90)Page 330.8
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) D A Resubmission 04/15/2011
.o.F 1=1 r , ~h~ccunt 456) (Continued)(Including transactons reffered to as 'w eeling')
9. In column (k) through (n), report the revenue amounts as shown on bils or vouchers. In column (k), provide revenues from demand
charges related to the billng demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bils or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bils rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and U) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)Line
($)($)($)(k+l+m)No.
(k)(i)(m)(n)
-28,422 -28,422 1
-3,558 -3,558 2
62 62 3
4,148 4,148 4
251 251 5
937 937 6
211 211 7
2,009 2,009 8
1,587 1,587 9
201 201 10
2,384 2,384 11
5,116 5,116 12
84 84 13
1,597 1,597 14
33 33 15
-287 -287 16
-90 -90 17
8,296 8,296 18
-276 -276 19
-25 -25 20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
5,180,923 10,217,479 0 15,398,402
FERC FORM NO.1 (ED. 12-90)Page 330.9
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ó An Original (Mo, Da, Yr)
Idaho Power Company (2) A Resubmission 04/15/2011 2010/Q4
FOOTNOTE DATA
Schedule Page: 328 Line No.: 1 Column: e
~L__()pen 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 Administration
for the Oregon Trail Electric Cooperative expires September 30, 2011. The billing demand
for network service is the customer's demand at the time of Idaho Power Company
transmission system peak and varies by month.
¡Schedule Page: 328 Line No~:-2 Column: h -
OATT rate refundl~r_yeriods 10/07 thru 12/09
¡Schedule Page: 328 Line No.: 3 Column: h
The network service agreement between Idaho Power and the Bonneville Power Administration
for the USBR expires December 31, 2014. The billing demand for network service is the
customer's demand at the time of Idaho Power Company transmission system peak and varies
by month.
¡Schedule Page: 328 Line No.: 4 Column: h
OATT_rate refund for per_~ods 10/07 thru 12/09
!Schedule Page: 328 Line No.: 5 Column: h
The network service agreement between Idaho Power and the Bonneville Power Administration
for Raft River expires September 30, 2011. The billing demand for network service is the
customer's demand at the time of Idaho Power Company transmission system peak and variesby month. ____________________________ _________
Schedule Page: 328 Line No.: 6 Column: h
OATT rate refund for periods 10/07 thru 12/09!SCUi-Pag:32S- Line No.: 7 Column: h --------~
The network service agreement between Idaho Power and the Bonneville Power Administration
for the Priority Firm Customers expires December 31, 2011. The billing demand for network
service is the customer's demand at the time of Idaho Power Company transmission system
peak and varies by month.
¡Schedule Page: 3u--LJiieNO:SCoiiimn:h-------
OATT rate refund for periods 10/07 thru 12/09
:Shedule Page: 328---Üne No.: 9 Column:-e-------
Legacy, contract prior to the Open Access Transmission Tariff
¡Schedule Page: 328 Line No.: 9 Column: h
The contract between Idaho Power and the Milner Irrigation District expires December 31,
2012.
¡Schedule Page: 328 Line No.: 10 Column: h
The agreement between Idaho Power and the City of Seattle expires December 31, 2017. City
of Seattle has sold this transmission service request to Cargill and Cargill is now
responsible for payment.
Schedule Page: 328 Line No.: 11 Column: h
The contract between Idaho Power and PacifiCorp - Imnaha expired on September 30, 2010 and
was extended thru 03/31/11.-_._-------Schedule Page: 328 Line No.: 12 Column: h
OATT rate refund for periods 10/07 thru__12/09 ~___
.Schedule Page: 328 Line No.: 13 Column: e
LegCicYL_contract prior to the Open Access Transmission Tariff
Schedule Page: 328 Line No.: 13 Column: h
The agreement between Idaho Power and the United States Department of the Interior, Bureau
of Indian Affairs is subject to termination upon 90 days written notice by the Bureau.
ISchediiie-Page:iLJ-No-:1i--cC;uiiii: h---
OATT rate refund for periods 10/07 thru 12/09
¡Schedule Page: 328 Line No.: 17 Column: h
Imbalance penalty disbtribution per OATT 7.5.1 for periods 07/07 thru 12/09
sCheiie-Page:32--Uiie-No-:25--COiiii:h------~--.-
IFERC FORM NO.1 (ED. 12-87) Page 450.1
-~--~-_._~~------
i
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company I (2) A Resubmission 04/1512011 2010/Q4
FOOTNOTE DATA
OATT rate refund for periods 10/07 thru 12/09
!Schedule Page: 328 Line No.: -26--ciiiih-~~---~-
~~~~ance penalty disbtribution per OATT 7.5.1 _for periods 07/07 thru 12/Q~_______
!Schedule Page: 328.2 Line No.: 28 Column: hOATT rate refund _tor periods 10/07 thru 12/09~____~__________~________"
Schedule Page: 328.2 Line No.: 29 Column: h
Imbalance penalty disbtribution per OATT 7.5.1 for periods 07/07 thru 12/09
!Schedule Page: 328.2 Line No.: 30 Column: h -.-
OATT rate refund for periods 10/07 thru 12/09
ISchedule Page: 328.2 Line No.: 31 Column: h
Imbalance penalty disbtribution per OATT 7.5.1 for periods 07/07 thru 12/09
¡Schedule Page: 328.2 Line No.: 33 Column: h
OATT rate refund for periods 10/07 thru 12/09
¡Schedule Page: 328.2 Line No.: 34 Coiiiiin;¡-~-------
Imbalance penalty disbtribution per OATT 7.5.1 for periods 07/07 thru 12/09
¡Schedule Page: 328.3 Line No.: 3 Column: h-...
OATT rate refund for periods 10/07 thru 12/09
!schedule Page: 328.3 Line No.: 4 Column: h
Imbalance penalty disbtribution per OATT 7. S. 1 for periods 07/07 thru 12/09
¡Schedule Page: 328.3 Line No.: 5 Column: h
OATT rate refund for periods 10/07thr~J:2/09___
¡Schedule Page: 328.3 Line No.: 10 Column: hOATT rat~ ret~nd for periods 10/07 thru 12/0~__~_______
¡Schedule Page: 328.4 Line No.: 10 Column: hOATT rate refund for periods 10/07 th£2 12/~______________
¡Schedule Page: 328.4 Line No.: 11 Column: h
Imbalance penalty disbtribution per OATT 7.5.1 fOE periods 07/07 thru 12/09
¡Schedule Page: 328.4 Line No.: 14 Column: h
OATT rate refund for periods 10/07 th:r.i12/09 ________
¡Schedule Page: 328.5 Line No.: 5 Column: h
OATT rate refund tor periods 10/07 thru 12/09
¡Schedule Page: 328.5 Line No.: 6 Column: hImbalance penalty disbtribution per OATT 7.5.1 for pe:r_~c:.c~ 07 /07 ~£u 12/09_____
!$ecule Page: 328.5 LineNo.:--g-ColU: hOATT rate refund:f~ periods 10/07 thru i~!'QL___________~___
¡Schedule Page: 328.5 Line No.: 10 Column: h
Imba.lance penalty disbtribution per OATT 7.5.1 for _"periods 07/07 _!.iJ:~__l_2/09
¡Schedule Page: 328.6 -line No.: 30 Column: h .-
OATT rate refund for periods 10/07 thru 12/09
:Schedule Page: 328.6 Line No.: 31 Column: h
Imbalance penalty disbtribution per OATT 7.5.1 for periods 07/07 thru 12/09
¡Schedule Page: 328.7- Line No.: 7 Column: h ----------
OATT ~ate..efund for periods 10/07 thru _1?/09
¡Schedule Page: 328.7 Line No.: 8 Column: hImbalance penalty disbtribution per OATT 7.5.1 for periods 07/07~thru _ 12lg~_
¡Schedule Page: 328.7 - Line No.: 13 Column: h -------
OATT rate refund for periods 10/07 thru 12/02___
¡Schedule Page: 328.7 Line No.: 14 Column: hImbalancep~nalty ?isbtribu~ion per OATT 7.5. 1 fO~.E~ric:?~07/07 _ thru_1_~lQ.~________
¡Schedule Page: 328.8 Line No.: 1 Column: h
OATT rate refund for periods 10l.Q7 thru 12/09
~chedule Page: 328.8 Line No.: 2 Column: h
Imbalance pe!laltY_.cisbt_riÈ.~!i:c:n per OATT 7.5.1 for periocls_ 07/07 thru 12/09
¡Schedule Page: 328.8 Line No.: 4 Column: h
IFERC FORM NO.1 (ED. 12-87) Page 450.2
THIS PAGE INTENTIONALLY LEFT BLANK
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company '2) A Resubmission 04/15/2011 2010/Q4
FOOTNOTE DATA
OATT rate refund for periods 10/07 thru 12/09
¡Schedule Page: 328.8 Line No.: 5 Column: h
OATT rate refund for periods 10/07 thru 12/09
¡Schedule Page: 328.8 Line No.: 6 Column: ¡,-Imbalance penalty disbtribution per OATT 7.5.1 for peri()~~_2LQL_thru 12L~_______~~
:Schedule Page: 328.8 Line No.: 20 Column: h
OATT rate refund for periods 10/07 thru 12/09
¡Schedule Page: 328.8 Line No.: 21 Column: h --~-- -
Imbalance penalty disbtribution per OATT 7.5.1 for periods 07/07 thru 12/09
¡Schedule Page: 328.9 Line No.: 1 Column: h--~-~
OATT rate refund for periods 10/07 thru 12/09
Schedule Page: 328.9 Line No.: 2 Column: h----~~----------~-- -----~--~
Imbalance penalty disbtribution per OATT 7.5.1 for periods 07/07 thru 12/09
¡Schedule Page: 328.9 Line No.: 16 Column: h .-------~---------~----~
OATT rate refund for periods 10/07 thru 12/09
¡Schedule Page: 328.9 Line No.: 17 Column: h .-~----~-----~-----------
Imbalance penalty disbtribution per OATT 7.5.1 for periods 07/07 thru 12/09
¡Schedule Page: 328.9 Line No~: 19 Column: h-----~---------------~-------~--
OATT rate refund for periods 10/07 thru 12/09
!schedule Page: 328.9 Line No.: 20 Column: h
Imbalancè penalty disbtribution per OATT 7.5.1 for periods 07/07 thru 12/09
IFERC FORM NO.1 (ED. 12-87)Page 450.3
Name of Respondent
Idaho Power Company
This ~ort Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2011
TRANSMISSION OF ELECTRICITY BY OTHERS (Accunt 565)
(Including transactions referred to as "wheeling")
1. Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public
authorities, qualifying facilities, and others for the quarter.
2. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3.ln column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, lFP - long-Term Firm Point-to-Point Transmission Reservations. OlF - Other
long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.
4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5. Report in column (e), (f) and (g) expenses as shown on bils or vouchers rendered to the respondent. In column (e) report the
demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all
other charges on bils or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all
components of the amount shown in column (g). Report in column (h) the total charge shown on bils rendered to the respondent. If no
monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement,
including the amount and type of energy or service rendered.
6. Enter "TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Year/Period of Report
End of 2010/Q4
Line
No. Name of Company or Public
Authority (Footnote Affliations)
(a)
1 Avista Corp-WWP Div
2
3
Statistical
Classification
(b)
NF
as
as
SFP
TOTAL
TRANSFER OF ENERG
Magawatt- agawa -tìours tìoursReceived Delivered(c) (d)
42,089 42,089
nergy er Total Cost ofCharlesCharresTransæssion($($
(f)(
230,634 230,634
-2,023 -2,023
-244 -244
1,000,490 1,000,490
1,195,395 1,195,395
53,856 53,856
18,863 18,863
-3,652 -3,652
2,698 2,698
199,600 199,600
22,581 22,581
-23,344 -23,344
796,867 796,867
759,375 759,375
164,804 164,804
-116 -116
198,623 198,623
428,401 428,401
3,505 3,505
623 623
9,292 9,292
4,937 4,937
139,746 139,746
76,431 76,431
30,440 30,440
1,348,861 1,448,851 4,505,995 -36,339 5,918,5071,348,861
FERC FORM NO. 1/3-Q (REV. 02-04)Page 332
Name of Respondent This~rtIS:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2010/04
(2) Fi A Resubmission 04/15/2011
TRANSMISSION OF ELECTRICITY BY OTHERS (Accunt 565)
(Including transactions referred to as .wheeling")
1. Report all transmission, Le. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public
authorities, qualifying facilities, and others for the quarter.
2. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.
4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5. Report in column (e), (f) and (g) expenses as shown on bils or vouchers rendered to the respondent. In column (e) report the
demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all
other charges on bils or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all
components of the amount shown in column (g). Report in column (h) the total charge shown on bils rendered to the respondent. If no
monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement,
including the amount and type of energy or service rendered.
6. Enter "TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Line TRANSFER OF ENERGY EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHER~
No.Name of Company or Public Statistical Magawatt-Magawatt-hl.emand ~nergy _umer Total Cost oftiourstioursCharresCharreschaWesTransæssionAuthority (Footnote Affliations) Classification Received Delivered ($($($(a) (b)(c)(d)(e)(f)(g)~OS -1,920 -1,920
2 PacifCorp Inc.SFP 65,389 65,389 708,750 708,750
3 PaTu Wind Fann, L1c SFP 20,600 20,600 46,552 46,552
4 Portand General Ele Co SFP 251,609 251,609 582,121 582,121~OS -5,040 -5,040
6 Puget Sound Energy, Inc SFP 16,394 16,394 21,745 21,745
7 Seatte City Light SFP 59,020 59,020 145,936 145,936
8 Sierr Pacific Power Co NF 370 370 2,879 2,879
9 Snohomish County PUD SFP 1,392 1,392 1,700 1,700
10
11
12
13
14
15
16
TOTAL 1,348,861 1,348,861 1,448,851 4,505,995 -36,339 5,918,507
FERC FORM NO. 1/3-0 (REV. 02-04)Page 332.1
THIS PAGE INTENTIONALLY LEFT BLANK
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2) A Resubmission 04/15/2011 2010/Q4
FOOTNOTE DATA
Schedule Page: 332 Line No.: 2 Column: a
Resale Transmission
¡SchiiePage:332--1iße-¡¡ii:-3 Column: a -~---~~~---Unreserved U~e Refund - Sharing Re::distriÌ)u_i:~ci_~~__
,Schedule Page: 332 Line No.: 5 Column: b
~~~!ract Expiration Q~te 9/30/2016
¡Schedule Page: 332 Line No.: 6 Column: b
Contract Ex~lr~tion Date 7/16/2011
Schedule Page: 332 Line No.: 8 Column: a
Reserves Provided
Schedule Page: 332 Line No.: 10 Column: bContract can~t~rminated at anytime, with 30 days prior notice.
¡Schedule Page: 332 Line No.: 12 Column: a
Resale Transmission_.~ --_.._-_.__.-¡Schedule Page: 332 Line No.: 14 Column: b
Contract Expiration Date 5/31/2014
¡Schedule Page: 332 Line No.: 16 Column: a
Unreserveci~~~e Refund - Sharing Re-distributed
¡Schedule Page: 332.1 Line No.: 1 Column: a
Resale Transmission~.~._---,_._..__._.~¡Schedule Page: 332.1 Line No.: 5 Column: a
Resale Transmission
-i
--i
-l
IFERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent This ~ort Is:Date of ReRort Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) n A Resubmission 04/15/2011
MISCELLANEOUS GENERAL EXPENSES (Accunt 930.2) (ELECTRIC)
Line Descr)tiOn Amount
No.(a (b)
1 Industry Asociation Dues 371,301
2 Nuclear Power Research Expenses
3 Other Experimental and General Research Expenses
4 Pub & Dist Info to Stkhldrs...expn servicing outstanding Securities 173,664
5 Oth Expn =-=5,000 show purpose, recipient, amount. Group if .c $5,000
6 Richard Dahl 81,166
7 Christine King 66,356
8 Jon Miler 48,700
9 Gary Michael 106,727
10 Richard Reiten 57,091
11 Joan Smith 76,841
12 Jan Packwood 56,116
13 Judith Johansen 74,332
14 Thomas Wilford 66,240
15 Robert Tintsman 72,960
16 Stephen Allred 60,128
17
18 Chambers of Commerce & Other Civic Organizations 99,881
19
20 Asciated Taxpayers of Idaho 21,252
21 Association of Idaho Cities 3,250
22 Boston College Center for Corporations 2,000
23 Corporate Executive Board 46,750
24 Idaho Assoc of Commerce & Industry 14,000
25 Idaho Association of Counties 1,500
26 National Assoc of Directors 5,500
27 Northwest Power Pool 80,083
28 Pacific NW Utilties 33,810
29 Western Electricity Coordinating Council 857,880
30 Western Energy Institute 46,073
31 Wyoming Taxpayers Assoc 1,590
32 Misc Memberhips 1,180
33
34 Misc General Management
35 Broadridge Financial Solutions 51,376
36 New York Stock Exchange 47,874
37 PR Newswire 13,685
38
39
40
41
42
43
44
45
46 TOTAL 3,826,102
FERC FORM NO.1 (ED. 12-94)Page 335
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
Idaho Power Company I (2) A Resubmission 04/15/2011 2010/Q4
FOOTNOTE DATA
Column:bPurpose
Mgmt Services
Stock Expense
Analyst Service
Transfer & Fees
Broker Fees
Analyst Services
Mgmt Services
Misc Expense
Misc
Schedule Page: 335 Line No.: 5Recipient
Laurel Hill Advisory Group
Stock Based Compensation
Thomson Financial
Wells Fargo S/O Service
Deutche Bank
Moody's Anaalytics
E Source Inc
Rate related Amort
other Purchased Service
$
Amount
55,781
475,200
99,267
139,384
35,000
27,597
22,480
230,656
101,431
Total $1,186,796
IFERC FORM NO.1 (ED. 12-87) Page 450.1
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) Fi A Resubmission 04/15/2011
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Accunt 403, 404, 405)
(Except amortzation of aquisition adjustments)
1. Report in section A for the year the amounts for: (b) Depreciation Expense (Account 403; (c) Depreciation Expense for Asset
Retirement Costs (Account 403.1; (d) Amortization of Limited-Term Electric Plant (Account 404); and (e) Amortization of Other Electric
Plant (Account 405).
2. Report in Section 8 the rates used to compute amortzation charges for electric plant (Accounts 404 and 405). State the basis used to
compute charges and whether any changes have been made in the basis or rates used frm the preceding report year.
3. Report all available information called for in Section C every fifth year beginning with report year 1971, reporting annually only changes
to columns (c) through (g) from the complete report of the preceding year.
Unless composite depreciation accounting for total depreciable plant is followed, list numerically in column (a) each plant subaccount,
account or functional classification, as appropriate, to which a rate is applied. Identify at the bottom of Section C the type of plant
included in any sub-account used.
In column (b) report all depreciable plant balances to which rates are applied showing subtotals by functional Classifications and showing
composite total. Indicate at the bottom of section C the manner in which column balances are obtained. If average balances, state the
method of averaging used.
For columns (c), (d), and (e) report available information for each plant subaccount, account or functional classification Listed in column
(a). If plant mortality studies are prepared to assist in estimating average service Lives, show in column (f) the type mortlity curve
selected as most appropriate for the account and in column (g), if available, the weighted average remaining life of surviving plant. If
composite depreciation accounting is used, report available information called for in columns (b) through (g) on this basis.
4. If provisions for depreciation were made during the year in addition to depreciation provided by application of reported rates, state at
the bottom of section C the amounts and nature of the provisions and the plant items to which related.
A.Summary of Depreciation and Amortzation Charges
Deprecation Amortzation of
Line D~reciation Expense for Asset Limited Term Amortzation of
No.Functional Classification xpense Retirement Costs Elecc Plant ,Other Electc Total
(Accunt 403)(Accunt 403.1 )(Accunt 404)Plant (Ace 405)
(a)(b)(c)(d)(e)(f)
1 Intangible Plant 6,857,301 6,857,301
2 Steam Production Plant 18,480,463 18,480,463
3 Nuclear Production Plant
4 Hydraulic Production Plant-Conventional 15,364,474 15,364,474
5 Hydraulic Producton Plant-Pumped Storage
6 Other Production Plant 4,940,258 4,940,258
7 Transmission Plant 16,395,129 16,395,129
8 Distribution Plant 42,238,509 42,238,509
9 Regional Transmission and Market Operation
10 General Plant 11,976,663 11,976,663
11 Common Plant-Electric -296,299 -296,299
12 TOTAL 109,099,197 6,857,301 115,956,498
B. Basis for Amortization Charges
Accunt 404 - Basis used to compute charges:
Balance to be Balance to be Remaining
Amortized 2010 Amortized months of
1/1/2010 Amortization 12131/2010 Amort 12131110
(1) 36,000 12,000 24,000 24
(2) 11,743,090 530,909 12,521,781 -
(3) 18,391,530 6,019,314 17,132,308 -
(4) 5,187,493 287,899 4,899,594 216
(5)7,179 227,990 -
Total 35,358,113 6,857,301 34,805,673
(1) Shoshone-Bannock Tribe License & Use Agreement(Termination date December 31, 2023).
(2) Middle Snake Relicesing Costs (Amortized over a 30 year license period).
(3) Computer Softare packages (Amortzed over a 60 month period frm date of purchase).
(4) Shoshone-Bannock Right of Way (Termination date December 31, 2028).
FERC FORM NO.1 (REV. 12-03)Page 336
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) r=A Resubmission 04/15/2011
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreCiaole Estimated Net Applied Mortlity Average
No.Accunt No.Plant Base Avg. Servce Salvage Depr. rates Curve Remaining
Ca)
(In Th?~fandS)7~r (Pergrnt)(PeJ~nt)Tr¡:e 7~r
12 310.20 522 75.00 1.05 R4.0 21.80
13 311.00 139,165 100.00 -10.00 1.54 S1.0 23.30
14 312.10 80,615 60.00 -7.00 1.68 R3.0 22.60
15 312.20 464,242 70.00 -5.00 2.17 R1.5 22.30
16 312.30 4,208 25.00 20.00 2.58 R3.0 12.20
17 314.00 148,800 50.00 -5.00 2.55 SO.5 20.30
18 315.00 59,887 65.00 -7.00 5.92 S1.5 22.20
19 316.00 13,876 50.00 -5.00 6.06 RO.5 20.80
20 316.10 59 10.00 25.00 9.52 L2.5 7.60
21 316.40 241 10.00 25.00 9.59 L2.5
22 316.50 83 10.00 25.00 5.94 L2.5 8.20
23 316.60 106 19.00 25.00 3.69 S2.0 12.00
24 316.70 80 19.00 25.00 3.88 S2.0 16.70
25 316.80 1,042 16.00 30.00 13.90 SO.O 9.30
26 317.000 3,516
27 Subtotal Steam 916,442
28 331.00 155,425 100.00 -25.00 2.70 R2.5 32.10
29 332.10 19,461 90.00 -20.00 2.27 S4.0 27.20
30 332.20 225,818 90.00 -20.00 2.22 S4.0 29.80
31 332.30 5,472 2.87 SQUARE 28.60
32 333.00 194,271 80.00 -5.00 1.91 R3.0 33.00
33 334.00 43,762 50.00 -5.00 2.93 R1.5 25.30
34 335.00 17,586 90.00 2.10 R2.0 30.50
35 335.10 25 15.00 1.93 SQUARE 12.30
36 335.20 364 20.00 3.65 SQUARE 10.70
37 335.30 114 5.00 22.92 SQUARE 2.00
38 336.00 7,522 75.00 1.90 R3.0 30.40
39 Subtotal Hydro 669,826
40 341.00 7,169 35.00 3.02 SQUARE 30.40
41 342.00 4,446 35.00 2.75 SQUARE 32.40
42 343.00 100,802 35.00 2.88 SQUARE 29.70
43 344.00 31,682 35.00 2.85 SQUARE 33.80
44 345.00 25,027 35.00 2.89 SQUARE 28.30
45 346.00 3,119 35.00 2.70 SQUARE 29.50
46 Subtotal Other 172,245
47 350.20 30,096 65.00 1.51 R3.0 54.20
48 352.00 55,668 60.00 -30.00 1.68 R3.0 47.30
49 353.00 349,451 45.00 -5.00 2.06 R1.0 35.40
50 354.00 144,723 65.00 -25.00 1.96 S3.0 48.60
FERC FORM NO.1 (REV. 12-03)Page 337
Name of Respondent This ~ort Is:Di¡te of Report Year/Period of Report
Idaho Power Company (1) An Original (ïo. Da, Yr)End of 2010/Q4
(2) n A Resubmission o /15/2011i
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLtNT (Continued)
iC. Factors Used in Estimating Depreciation Charges !
Line uepreClaole i:sumarea Net Appiiea Morraiiry lwerage
No.Accunt No.Plant Base Avg. Service Salvage D11~rates Curve Remaining
(a)(In Th?~fandS)~~l (pereInt)( e 'jnt)TrKe ~~lie
12 355.00 101,622 55.00 -60.00 I 2.81 R2.0 36.70
13 356.00 169,166 65.00 -30.00 i 1.92 R1.5 48.30
14 359.00 318 65.00 0.98 R3.0 23.80
15 Subtotal Transmission 851,044
16 361.00 29,486 65.00 -30.00 1.85 R2.5 52.60
17 362.00 182,594 50.00 -5.00 1.89 RO.5 42.10
18 364.00 225,060 44.00 -50.00 3.29 R1.5 31.50
19 365.00 120,135 47.00 -40.00 2.95 RO.5 35.10
20 366.00 48,216 60.00 -20.00 1.95 R2.0 51.20
21 367.00 191,494 50.00 -15.00 1.97 SO.5 41.10
22 368.00 414,782 37.00 5.00 1.67 R1.0 30.80
23 369.00 57,320 35.00 -40.00 3.09 R2.5 25.60
24 370.00 14,869 20.00 6.95 01.0 11.90
25 370.10 39,720 15.00 6.76 S3.0 14.40
26 370.20 2.00 19.38 Square
27 370.30 41,109 3.00 25.67 Square 1.50
28 371.10 40 10.00 -5.00 3.68 S4.0 1.40
29 371.20 2,711 15.00 -5.00 0.63 R2.0 13.90
30 373.20 4,370 25.00 -25.00 4.09 R1.5 13.90
31 374.00 588
32 Subtotal Distribution 1,372,494
33 390.11 26,532 100.00 -5.00 2.38 S1.5 33.60
34 390.12 40,796 50.00 -5.00 2.24 L2.0 36.30
35 390.20 9,950 30.00 2.58 S3.0 20.80
36 391.11 14,505 20.00 4.97 SQUARE 10.30
37 391.20 20,526 5.00 24.37 SQUARE 2.10
38 391.21 4,343 7.00 13.96 L4.0 3.90
39 392.10 708 10.00 25.00 6.23 L2.5 5.90
40 392.30 2,580 8.00 50.00 8.62 S2.5 4.30
41 392.40 19,074 10.00 25.00 3.58 L2.5 7.30
42 392.50 717 10.00 25.00 1.49 L2.5 8.60
43 392.60 29,431 19.00 25.00 3.69 S2.0 12.00
44 392.70 4,419 19.00 25.00 2.39 S2.0 11.90
45 392.90 4,028 30.00 25.00 1.99 S1.5 21.10
46 393.00 1,460 25.00 5.40 SQUARE 9.70
47 394.00 5,568 20.00 4.84 SQUARE 11.70
48 395.00 11,947 20.00 5.39 SQUARE 10.20
49 396.00 9,922 16.00 30.00 6.95 SO.O 7.00
50 397.10 6,158 15.00 6.16 SQUARE 7.70
FERC FORM NO.1 (REV. 12-03)Page 337.1
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) n A Resubmission 04/15/2011
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line ueprecaoie ~suma(eo Net AJpiiea Morially l\verage
No.Accunt No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
(a)(In Th(~rindS)~~)(Perdfnt)(per;fnt)Tr~e ~~l
12 397.20 17,437 15.00 6.99 SQUARE 9.60
13 397.30 3,221 15.00 8.36 SQUARE 6.60
14 397.40 2,399 10.00 8.20 SQUARE 5.60
15 398.00 4,763 15.00 9.57 SQUARE 6.90
16 Subtotal General 240,484
17 Total Plant 4,222,535
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 wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) nA Resubmission 04/15/2011
REGULATORY COMMISSION EXPENSES
1. Report particulars (details) of regulatory commission expenses incurred during the current year (or incurred in previous years, if
being amortized) relating to format cases before a regulatory body, or cases in which such a body was a part.
2. Report in columns (b) and (c), only the current yeats expenses that are not deferred and the current yeats amortization of amounts
deferred in previous years.
Line Description Assesse by Expenses Total . Dtlferrd
No.(Furnish name of regulatory commission or body the Regulatory of Expense for in Accunt
Commission Current Year 182.3 a/docket or case number and a descrption of the case)Utilty (b) + (c)Beginning 0 Year
(a)(b)(c)(d)(e)
1 Federal Energy Regulatory Commission:
2 Annual admin charges assessed by FERC 3,454,432 3,454,432
3
4 Generl Regulatory Expenses and
5 Various other Dockets -80,742 -80,742
6
7 Regulatory Commission Expenses - Idaho
8 Rate Case - Misc expenses 1,024 1,024
9
10 Other-IPUC
11 Amortization - rate related 5,731 5,731
12 Other 25,688 25,688
13
14 Oregon Hydro - Fees Amortization 158,506 158,506
15
16 Regulatory Commission Expenses - Oregon .
17 Rate Case - Misc expenses 6,532 6,532
18
19 Other- OPUC ,
20 AR- 538 45,710 45,710
21 UE - 214 73,823 73,823
22 UM - 1394 33,729 33,729
23 UM - 1355 20,127 20,127
24 UM -1461 19,975 19,975
25 Other matters less than $15,000 3,301 3,301
26
27 Intervenor Funding 30,000 30,000
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46 TOTAL 3,612,938 184,898 3,797,836
FERC FORM NO.1 (ED. 12-96)Page 350
Name of Respondent
Idaho Power Company
YearlPeriod of Report
End of 2010/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2011
REGULATORY COMMISSION EXPENSES (Continued)
3. Show in column (k) any expenses incurred in prior years which are being amortized. list in column (a) the period of amortization.
4. list in column (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.
AMORTIZED DURING YEAR
0)(k)
Deferred in Line
Accunt 182.3
End of Year No.
(I)(f)(h)
Deferred to
Accunt 182.3
(i)
Contra
Accunt Amount
Electric 928 -80,742
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
Electc 928 3,454,432
Electric 928 1,024
Electric 928 5,731
Electric 928 25,688
Electric 928 158,506
Electric 928 6,532
Electic 928 45,710
Electric 928 73,823
Electric 928 33,729
Electric 928 20,127
electric 928 19,975
Electric 928 3,301
Electrc 928 30,000
-~-~-~-~---
3,797,836 46
FERC FORM NO.1 (ED. 12-96)Page 351
THIS PAGE INTENTIONALLY LEFT BLANK
Name of Respondent This wort Is:Date of Report Year/Penod of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) nA Resubmission 04/15/2011
RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES
1. Descnbe and show below costs incurred and accunts charged dunng the year for technological research, development, and demonstration (R, D &
D) project initiated, continued or conCluded dunng the year. Report also support given to others dunng the year for jointly-sponsored projects.(ldentify
recipient regardless of affliation.) For any R, D & D work carned with others, show separately the respondent's cost for the year and cost chargeable to
others (See definition of research, development, and. demonstrtion in Uniform System of Accunts).
2. Indicate in column (a) the applicable Classification, as shown below:
Classifications:
A. Electic R, D & D Performed Internally:a. Overhead
(1) Generation b. Underground
a. hydroelectric (3) Distnbution
i. Recreation fish and wildlife (4) Regional Transmission and Market Operation
ii Other hydroelectnc (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. Electnc, R, D & D Performed Externally:
e. Unconventional generation (1) Research Support to the electrical Research Councilor the Electc
f. Siting and heat rejection Power Research Institute
(2) Transmission
Line Classification Descnption
No.(a)(b)
1 Approximately $3 milion of Idaho Powets 2010
2 energy effciency spending was related to
3 research and analysis, education, technology
4 evaluation and market transformation. Most of
5 this activity was done in conjuction with the
6 Northwest Energy Effciency Alliance (NEEA).
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30 .
31
32
33
34
35
36
37
FERC FORM NO.1 (ED. 12-87)Page 352
Name of Respondent
Idaho Power Company
Year/Penod of Report
End of 2010/04
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2011
DISTRIBUTION OF SALARIES AND WAGES
Report below the distribution of total salaries and wages for the year. Segregate amounts originally charged to clearing accounts to
Utilty Departments, Construction, Plant Removals, and Other Accounts, and enter such amounts in the appropriate lines and columns
provided. In determining this segregation of salaries and wages originally charged to clearing accounts, a method of approximation
giving substantially correct results may be used.
1 Electric
2 Operation
3 Production
4 Transmission
5 Regional Market
6 Distribution
7 Customer Accunts
8 Customer Service and Informational
9 Sales
10 Administrative and General
11 TOTAL Operation (Enter Total of lines 3 thru 10)
12 Maintenance
13 Producton
14 Transmission
15 Regional Market
16 Distnbution
17 Administrative and General
18 TOTAL Maintenance (Total of lines 13 thru 17)
19 Total Operation and Maintenance
20 Producton (Enter Total of lines 3 and 13)
21 Transmission (Enter Total of lines 4 and 14)
22 Regional Market (Enter Total of Lines 5 and 15)
23 Distnbution (Enter Total of lines 6 and 16)
24 Customer Accunts (Transcrbe from line 7)
25 Customer Service and Informational (Transcrbe from line 8)
26 Sales (Transcrbe from line 9)
27 Administrative and General (Enter Total of lines 10 and 17)
28 TOTAL Oper. and Maint. (Total of lines 20 thru 27)
29 Gas
30 Operation
31 Production-Manufactured Gas
32 Production-Nat. Gas (Including Expl. and Dev.)
33 Other Gas Supply
34 Storage, LNG Terminaling and Processing
35 Transmission
36 Distribution
37 Customer Accunts
38 Customer Service and Informational
39 Sales
40 Administrative and General
41 TOTAL Operation (Enter Total of lines 31 thru 40)
42 Maintenance
43 Production-Manufactured Gas
44 Production-Natural Gas (Including Exploration and Development)
45 Other Gas Supply
46 Storage, LNG Terminaling and Processing
47 Transmission
(a)
Direct PayrollDistnbution
(b)
TotalLine
No.
Classification
FERC FORM NO.1 (ED. 12-88)Page 354
Name of Respondent
Idaho Power Company
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2011
DISTRIBUTION OF SALARIES AND WAGES (Continued)
Year/Period of Report
End of 2010/Q4
(a)
Direc PayrollDistrbution
(b)
TotalLine
No.
Classification
48 Distribution
49 Administrative and General
50 TOTAL Maint. (Enter Total of lines 43 thru 49)
51 Total Operation and Maintenance
52 Production-Manufactured Gas (Enter Total of lines 31 and 43)
53 Production-Natural Gas (Including Expl. and Dev.) (Total lines 32,
54 Other Gas Supply (Enter Total of lines 33 and 45)
55 Storage, LNG Terminaling and Processing (Total of lines 31 thru
56 Transmission (Lines 35 and 47)
57 Distribution (Lines 36 and 48)
58 Customer Accunts (Line 37)
59 Customer Service and Informational (Line 38)
60 Sales (Line 39)
61 Administrative and General (Lines 40 and 49)
62 TOTAL Operation and Maint. (Total of lines 52 thru 61)
63 Other Utilty Departents
64 Operation and Maintenance
65 TOTAL All Utiity Dept. (Total of lines 28, 62, and 64)
66 Utility Plant
67 Construction (By Utilty Departments)
68 Electric Plant
69 Gas Plant
70 Other (provide details in footnote):
71 TOTAL Constructon (Total of lines 68 thru 70)
72 Plant Removal (By Utility Departments)
73 Electrc Plant
74 Gas Plant
75 Other (provide details in footnote):
76 TOTAL Plant Removal (Total of lines 73 thru 75)
77 Other Accunts (Specify, provide details in footnote):
78 Stores Expense
79 Other Clearing accunts
80 Other work in progress
81 Paid Absences
82 Preliminary Survey & Investigation
83 Other Accunts
84
85
86
87
88
89
90
91
92
93
94
95 TOTAL Other Accunts
96 TOTAL SALARIES AND WAGES
88,551,654 26,775,048 115,326,702~~~-~
i
r
36,304,765 10,583,832 46,888,597
36,304,765 10,583,832 46,888,597~----I
3,736,188 1,147,087 4,883,275
2,386,875 689,134 3,076,009
1,783,355 494,580 2,277,935
19,473,019 19,473,019
7,400 2,274 9,674
3,484,843 1,093,622 4,578,465
30,871,680
155,728,099
3,426,697
40,785,577
34,298,377
196,513,676
FERC FORM NO.1 (ED. 12-88)Page 355
Name of Respondent This 780rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) 0 A Resubmission 04/15/2011
MONTHLY TRANSMISSION SYSTEM PEAK LOAD
(1) Report the monthly peak load on the respondent's transmission system. If the respondent has two or more power systems which are not physically
integrated, furnish the required information for each non-integrated system.
(2) Report on Column (b) by month the transmission system's peak load.
(3) Report on Columns (c) and (d) the specified information for each monthly transmission - system peak load reported on Column (b).
(4) Report on Columns (e) through 0) by month the system' monthly maximum megawatt load by statistical classifications. See General Instrcton for
the definition of each statistical classification.
NAME OF SYSTEM:Idaho Power Company
Line Monthly Peak Day of Hour of Firm Network Firm Network Long-Term Firm Other Long- Short-Term Firm Oter
No.Month MW-Total Monthly Monthly Service for Self Service for Poinl-to-point Term Firm Point-to-point Service
Peak Peak Oters Reservations Service Reservation
(a)(b)(c)(d)(e)(f)(g)(h)(i)(j)
1 January 5,031 f 9 3,913 214 904
2 Februar 4,86"2~8 3,656 205 904 100
3 Mah 4,6g.11 8 3,627 152 90 11
4 Tota for Quartr 1 14,59 11,196 571 2,712 111
5 April 4,54(2~9 3,444 192 904
6 Ma 4,62~E 8 3,314 208 904 197
7 June 5,81~2f 19 4,511 304 874 125
8 Tota fo Quarter 2 14,97 11,269 704 2,682 322
9 July 5,75"21 17 4,578 303 874
10 August 5,74(A 18 4,562 285 874 19
11 September 5,04~A 18 3,918 250 874
12 Tota for Quarter 3 16,5~13,058 838 2,622 19
13 October 4,79E 1 18 3,532 206 874 184
14 Novembr 4,90~2~10 3,796 235 874
15 Deember 4,89~31 19 3,786 239 874
16 Total for Quartr 4 14,6~11,114 680 2,622 184
17 Tota Year to
DateJear 60,70~46,637 2,793 10,638 636
FERC FORM NO. 1/3-Q (NEW. 07-04)Page 400
Name of Respondent
Idaho Power Company
This ~ort Is:
(1) ~An Original
(2) A Resubmission
ELECTRIC ENERGY ACCOUNT
Report below the information called for concerning the disposition of electrc energy generated, purchased, exchanged and wheeled during the year.
Date of Report
(Mo, Da, Yr)
04/15/2011
YearlPeriod of Report
End of 2010/04
Line
No.
Item MegaWatt Hours
(a)
1 SOURCES OF ENERGY
2 Generation (Excluding Station Use):
3 Steam
4 Nuclear
5 Hydro-Conventional
6 Hydro-Pumped Storage
7 Oter
8 Less Energy for Pumping
9 Net Generation (Enter Total of lines 3
through 8)
10 Purchases
11 Power Exchanges:
12 Received
13 Delivered
14 Net Exchanges (Line 12 minus line 13)
15 Transmission For Other (Wheeling)
16 Received
17 Delivered
18 Net Transmission for Other (Line 16 minus
line 17)
19 Transmission By Others Losses
20 TOTAL (Enter Total of lines 9, 10, 14, 18
and 19)
MegaWatt Hours
(b)
Line
No.
Item
(b)
13,512,504
53,012
1,928,924
1,153,962
16,648,402
FERC FORM NO.1 (ED. 12-90)Page 401a
(a)
21 DISPOSITION OF ENERGY
22 Sales to Ultimate Consumers (Including
Interdepartmental Sales)
23 Requirements Sales for Resale (See
instruction 4, page 311.)
24 Non-Requirements Sales for Resale (See
instruction 4, page 311.)
25 Energy Furnished Without Charge
26 Energy Used by the Company (Electric
Dept Only, Excluding Station Use)
27 Total Energy Losses
28 TOTAL (Enter Total of Lines 22 Through
27) (MUST EOUAL LINE 20)
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) t: A Resubmission 04/15/2011
MONTHLY PEAKS AND OUTPUT
1. Report the monthly peak load and energy output. If the respondent has two or more power which are not physically integrated, furnish the required
information for each non- integrated system.
2. Report in column (b) by month the system's output in Megawatt hours for each month.
3. Report in column (c) by month the non-requirements sales for resale. Include in the monthly amounts any energy losses associated with the sales.
4. Report in column (d) by month the system's monthly maximum megawatt load (60 minute integration) associated with the system.
5. Report in column (e) and (f) the specified information for each monthly peak load reported in column (d).
NAME OF SYSTEM:Idaho Power Company
Line Monthly Non-Requirments MONTHLY PEAKSales for Resale &No.Month Total Monthly Energy Associated Losses Megawatts (See Instr. 4)Day of Month Hour
(a)(b)(c)(d)(e)(f)
29 January 1,477,843 238,101 2,215 8 8AM
30 February 1,351,435 288,679 2,049 22 8AM
31 March 1,313,559 223,940 1,894 11 8AM
32 April 1,145,768 118,247 1,807 9 8AM
33 May 1,413,424 281,198 1,906 17 5PM
34 June 1,458,768 189,213 2,930 28 7PM
35 July 1,745,903 64,438 2,914 17 7PM
36 August 1,588,027 66,197 2,874 4 6PM
37 September 1,328,266 92,700 2,342 3 7PM
38 October 1,153,195 96,971 2,006 1 6PM
39 November 1,232,934 95,720 2,149 24 9AM
40 December 1,439,280 173,520 2,102 30 7PM
41 TOTAL 16,648,402 1,928,924
FERC FORM NO.1 (ED. 12-90)Page 401b
Name of R~spondent This Report is:Date of Report Year/Period of Report
(1)~ An Original (Mo, Da, Yr)
Idaho Power Company I (2) A Resubmission 04/15/2011 2010/Q4
FOOTNOTE DATA
~chedule PJJJle¿401~l.ine JlQo_L!G___Çglii!!n: b _ __~ ___________ ~__________
Page 329 column I differs from Page 401 by 409 MWH, reported for Lucky Peak variation and
BPA Energy Imbalance schedules on page 401. The numbers that are shown on pages 328-330
are for account 456 wheeling only. However the numbers on page 401 have to be adjusted foraccount 447 transmission.
IFERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)2010/Q4
(2) 0 A Resubmission 04/15/2011 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Report data for plant in Servce only.2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in
this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants.3. Indicate by a footnote any plant leased or operated
as a joint facility.4. If net peak demand for 60 minutes is not available, give data which is available, specifying period.5. If any employees attend
more than one plant, report on line 11 the approximate average number of employees assignable to each plant.6. If gas is used and purchased on a
therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct.7. Quantities of fuel burned (Line 38) and average cost
per unit of fuel burned (Line 41) must be consistent with charges to expense accunts 501 and 547 (Line 42) as show on Line 20.8. If more than one
fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
Line Item Plant Plant
No.Name: Jim Bridger Name: Boardman
(a)(b)(c)
1 Kind of Plant (Internal Comb, Gas Turb, Nuclear Steam Steam
2 Type of Constr (Conventional, Outdoor, Boiler, etc)Semi-Outdoor Boiler Conventional
3 Year Originally Constructed
4 Year Last Unit was Installed 1979 1980
5 Total Installed Cap (Max Gen Name Plate Ratings-MW)
6 Net Peak Demand on Plant - MW (60 minutes)711 60
7 Plant Hours Connected to Load 8754 7538
8 Net Continuous Plant Capabilty (Megawatts)0 0
9 When Not Limited by Condenser Water
10 When Limited by Condenser Water 0 0
11 Average Number of Employees 0 0
12 Net Generation, Exclusive of Plant Use - KWh 499195000 416874000
13 Cost of Plant: Land and Land Rights 494358 106610
14 Structures and Improvements 66590599 13810712
15 Equipment Costs 448784017 57625476
16 Asset Retirement Costs 0 0
17 Total Cost 515868974 71542798
18 Cost per KWof Installed Capacity (line 17/5) Including 669.5250 1114.3738
19 Production Expenses: Oper, Supv, & Engr 154492 1129338
20 Fuel 101973965 7273624
21 Coolants and Water (Nuclear Plants Only)0 0
22 Steam Expenses 4771475 0
23 Steam From Other Sources 0 0
24 Steam Transferred (Cr)0 0
25 Electric Expenses 0 0
26 Mise Steam (or Nuclear) Power Expenses 7614528 273881
27 Rents 303752 0
28 Allowances 0 0
29 Maintenance Supervision and Engineering 47818 2144265
30 Maintenance of Structures -342 0
31 Maintenance of Boiler (or reactor) Plant 8061188 0
32 Maintenance of Electric Plant 2661023 0
33 Maintenance of Misc Steam (or Nuclear) Plant 3501782 9475
34 Total Producton Expenses 129089681 10830583
35 Expenses per Net KW 0.0258 0.0260
36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)Coal Oil Coal Oil
37 Unit (Coal-tons/Oil-barreIlGas-mcf/Nuclear-indicate)Tons Barrels Tons Barrels
38 Quantity (Units) of Fuel Burned 2768250 12605 0 248488 593 0
39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)9226 140000 0 8347 138800 0
40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 36.494 116.328 0.000 27.585 93.954 0.000
41 Average Cost of Fuel per Unit Burned 36.437 74.795 0.000 28.817 107.042 0.000
42 Average Cost of Fuel Burned per Millon BTU 1.961 12.720 0.000 1.739 18.367 0.000
43 Average Cost of Fuel Burned per KWh Net Gen 0.020 0.000 0.000 0.017 0.000 0.000
44 Average BTU per KWh Net Generation 10310.000 0.000 0.000 9884.000 0.000 0.000
FERC FORM NO.1 (REV. 12-03)Page 402
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)2010/Q4
(2) 0 A Resubmission 04/15/2011 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
9. Items under Cost of Plant are based on U. S. of A. Accunts. Production expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses.10. For IC and GT plants, report Operating Expenses, Accunt Nos.
547 and 549 on Line 25 "Electric Expenses," and Maintenance Accunt Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants
designed for peak load servce. Designate automatically operated plants.11. For a plant equipped with combinations of fossil fuel steam, nuclear
steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined
cycle operation with a conventional steam unit, include the gas-turbine with the steam plant.12. If a nuclear power generating plant, briefly explain by
footnote (a) accunting method for cost of power generated including any excess costs attbuted to research and development; (b) types of cost units
used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the
report period and other physical and operating characteristics of plant.
Plant Plant Plant Line
Name: Valmy Name:Danskin Name:Bennett Mountain No.
(d)(e)(f)
Steam Gas Turbine Gas Turbine 1
Outdoor Conventional Conventional 2
"2001 2005 3
1985 2001 2005 4
~.270.90 172.80 5
262 266 194 6
8653 733 278 7
0 261426 164159 8
0 0 9
0 0 0 10
0 8 5 11
1450896000 117685000 41827000 12
1003063 402745 0 13
58763895 5699334 1458303 14
266829313 103750812 60427533 15
0 0 0 16
326596271 109852891 61885836 17
1152.0151 405.5109 358.1356 18
604741 147952 27923 19
37679212 9591014 3140266 20
0 0 0 21
2566086 0 0 22
0 0 0 23
0 0 0 24
2140193 228650 212366 25
1909347 127600 99995 26
-74436 0 0 27
0 0 0 28
100684 0 0 29
309716 96881 74212 30
8006644 69883 9225 31
1254267 744376 279384 32
241757 0 0 33
54738211 11006356 3843371 34
0.0377 0.0935 0.0919 35
Coal Gas Gas 36
Tons MCF MCF 37
726212 0 0 1178898 0 0 438930 0 0 38
9711 0 0 1027 0 0 1027 0 0 39
50.798 0.000 0.000 8.136 0.000 0.000 7.154 0.000 0.000 40
50.508 0.000 0.000 8.136 0.000 0.000 7.154 0.000 0.000 41
2.600 0.000 0.000 7.922 0.000 0.000 6.966 0.000 0.000 42
0.026 0.000 0.000 0.081 0.000 0.000 0.075 0.000 0.000 43
9759.000 0.000 0.000 10288.000 0.000.0.000 10777.000 0.000 0.000 44
FERC FORM NO.1 (REV. 12-03)Page 403
THIS PAGE INTENTIONALLY LEFT BLANK
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company (2) A Resubmission 04/15/2011 2010/Q4
FOOTNOTE DATA
¡Schedule Page: 402 Line No.: 3 Column: b
This footnote applies to lines 3 and 4. The Jim Bridger Power
Plant consists of four equal units constructed jointly by Idaho
Power Company and Pacific Power and Light Company, with Idaho
owning 1/3 and PacifiCorp owning 2/3. Unit #1 was placed in
commercial operation November 30, 1974, Unit #2 December 1, 1975,
Unit #3 September 1, 1976, and Unit #4 November 29, 1979.
¡Schedule Page: 402 Line No.: 3 Column: c----~---
This footnote applies to lines 3 and 4. The Boardman plant
consists of one unit constructed jointly by Portland General
Electric Company, Idaho Power Company, and Pacific Northwest
Generating Company, with Idaho Power Company owning 10%. The
~~it was placed in commercial operation August 3, 1980.
¡Schedule Page: 402 Line No.: 3 Column: d
This footnote applies to lines 3 and 4. The Valmy plant consists
of two units constructed jointly by Sierra Pacific Power Company
and Idaho Power Company, with Sierra owning 1/2 and Idaho owning
1/2. Unit #1 was placed in commercial operation December 11, 1981
and Unit E_ May 21-,__l~e2_~___~_
¡Schedule Page: 402 Line No.: 5 Column: b
This footnote applies to line 5 and lines 12 through 43.
Information reflects Idaho Power Company's share as explained
in_~ote for line 3 page 40~__c:c:.iur~E::_____~~_~_____________~______________
rSchedule Page: 402 Line No.: 5 Column: c
This footnote applies to line 5 and lines 12 through 43.
Information reflects Idaho Power Company's share as explained
in note on line 3 page 402 column C
¡Schedule Page: 402 Line No.: 5 Column: d
This footnote applies to line 5 and lines 12 through 43.
Information reflects Idaho Power Company's share as explained
in note for line 3 page 403 column D.
'Schedule Page: 402 Line No.: 9 Column: b
This footnote applies to lines 9, 10, and 11. PacifiCorp
as operator of the plant will report thisinformation.
!Schedule Page: 402 Line No.: 9 Column: c
This footnote applies to lines 9, 10, and 11. Portland General
Elect:_~~_~()mpany, _~~_operator will report this information.
¡Schedule Page: 402 Line No.: 9 Column: d
This footnote applies to lines 9, 10, and 11. Sierra Pacific
Power, as operator of the plant, will report this information.
IFERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent
Idaho Power Company
Year/Period of ReportThis ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) DA Resubmission 04/15/2011
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. If any plant is leased, operated under a license frm the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in
a footnote. If licensed projec, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available specifyng period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
End of 2010/Q4
Line
No.
Item
(a)
FERC Licensed Project No. 2736
Plant Name: American Falls
(b)
FERC Licensed Project No. 1975
Plant Name: Bliss
(c)
1 Kind of Plant (Run-of-River or Storage)
2 Plant Construction type (Conventional or Outdoor)
3 Year Originally Constructed
4 Year Last Unit was Installed
5 Total installed cap (Gen name plate Rating in MW)
6 Net Peak Demand on Plant-Megawatts (60 minutes)
7 Plant Hours Connect to Load
8 Net Plant Capabilty (in megawatts)
9 (a) Under Most Favorable Oper Conditions
10 (b) Under the Most Adverse Oper Conditions
11 Average Number of Employees
12 Net Generation, Exclusive of Plant Use - Kwh
13 Cost of Plant
14 Land and Land Rights
15 Structures and Improvements
16 Reservoirs, Dams, and Waterways
17 Equipment Costs
18 Roads, Railroads, and Bridges
19 Asset Retirement Costs
20 TOTAL cost (Total of 14 thru 19)
21 Cost per KW of Installed Capacity (line 20 /5)
22 Production Expenses
23 Operation Supervision and Engineering
24 Water for Power
25 Hydraulic Expenses
26 Electic Expenses
27 Misc Hydraulic Power Generation Expenses
28 Rents
29 Maintenance Supervision and Engineering
30 Maintenance of Structures
31 Maintenance of Reservoirs, Dams, and Waterways
32 Maintenance of Electc Plant
33 Maintenance of Misc Hydraulic Plant
34 Total Production Expenses (total 23 thru 33)
35 Expenses per net KWh
Run-of-River
Outdoor
1949
1950
75.00
55
8,742
Outdoor
1978
1978
92.30
102
7,107 ----- -~-~~~-
110
o
4
318,627,000
76
1
5
336,360,000---~~-~---~--~ --
875,318
11,807,207
4,293,075
31,623,196
839,276
o
49,438,072
535.6237
768,358
1,039,561
8,426,020
7,275,185
486,477
o
17,995,601
239.9413.- ~-----~----~-- --~----
181,953
1,802,201
87,770
48,195
199,795
1,191
132,47
119,958
2,082
537,112
111,886
3,224,590
0.0101
767,875
605,976
701,681
47,683
236,503
24,639
108,083
63,687
194,224
246,929
133,441
3,130,721
0.0093
FERC FORM NO.1 (REV. 12-03)Page 406
Name of Respondent
Idaho Power Company
Year/Penod of ReportThis ~ort Is: Date of Report(1) ~An Onginal (Mo, Da, Yr)
(2) DA Resubmission 04/15/2011
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accunts or combinations of accunts prescribed by the Uniform System of Accunts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
End of 2010/Q4
FERC Licensed Project No. 1971
Plant Name: Brownlee
(d)
FERC Licensed Project No. 2848
Plant Name: Cascade
(e)
FERC Licensed Project No. 1971
Plant Name: Oxbow
Line
No.
1
Outdoor Outdoor 2
1983 1961 3
1984 1961 4
12.42 190.00 5
14 217 6
8,748 8,760 7
Storage
Outdoor
1958
1980
585.40
654
8,760-~-----~~----------~~--~---------~
747
220
7
2,247,125,000
15
1
2
35,781,000
221 9
202 10
7 11
975,054,000 12------~--~---~ -----~~-- --- ----~~----~~~--~-
17,382,696 82,142 1,210,187 14
31,430,623 7,364,154 9,959,405 15
67,073,285 3,145,630 30,375,714 16
55,537,342 12,720,572 15,821,605 17
518,444 122,668 565,842 18
0 0 0 19
171,942,390 23,435,166 57,932,753 20
293.7178 1,886.8894 304.9092 21~~~--------~----~~----~-
560,039 233,028 337,517 23
375,486 176,347 204,837 24
486,157 252,049 273,408 25
282,589 127,312 165,985 26
356,325 163,873 216,071 27
152,023 939 25,667 28
342,659 98,719 242,954 29
117,473 63,250 274,773 30
80,635 12,206 18,127 31
330,984 133,996 135,201 32
547,435 114,511 344,268 33
3,631,805 1,376,230 2,238,808 34
0.0016 0.0385 0.0023 35
FERC FORM NO.1 (REV. 12-03)Page 407
Name of Respondent
Idaho Power Company
YearlPeriod of Report
2010/Q4End of
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da. Yr)
(2) DA Resubmission 04/15/2011
HYDROELECTRIC GENERATING PLAT STATISTICS (Large Plants)
1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. If any plant is lease, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in
a footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available specifying period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
(a)
FERC Licensed Project No. 1971
Plant Name: Hells Canyon
(b
FERC Licensed Project No. 2726
Plant Name: Malad
(c)
Line
No.
Item
1 Kind of Plant (Run-of-River or Storage)
2 Plant Constructon type (Conventional or Outdoor)
3 Year Originally Constrcted
4 Year Last Unit was Installed
5 Total installed cap (Gen name plate Rating in MW)
6 Net Peak Demand on Plant-Megawatts (60 minutes)
7 Plant Hours Connect to Load
8 Net Plant Capabilty (in megawatts)
9 (a) Under Most Favorable Oper Conditions
10 (b) Under the Most Adverse Oper Conditions
11 Average Number of Employees
12 Net Generation. Exclusive of Plant Use - Kwh
13 Cost of Plant
14 Land and Land Rights
15 Structures and Improvements
16 Reservoirs. Dams, and Waterways
17 Equipment Costs
18 Roads, Railroads, and Bridges
19 Asset Retirement Costs
20 TOTAL cost (Total of 14 thru 19)
21 Cost per KWof Installed Capacity (line 20 1 5)
22 Production Expenses
23 Operation Supervision and Engineering
24 Water for Power
25 Hydraulic Expenses
26 Electric Expenses
27 Mise Hydraulic Power Generation Expenses
28 Rents
29 Maintenance Supervsion and Engineering
30 Maintenance of Strctures
31 Maintenance of Reservoirs, Dams, and Waterways
32 Maintenance of Electric Plant
33 Maintenance of Misc Hydraulic Plant
34 Total Production Expenses (total 23 thru 33)
35 Expenses per net KWh
Outdoor Outdoor
1967 1948
1967 1948
391.50 21.77
437 24
8,757 8,760r----~--~----~--~~--~
445
137
5
1,891,439,000
25
21
1
168,373,000- ------~ ~---~~----~------~
1,877,301
2,586,648
52,700,383
16,623,664
819,192
o
74,607,188
190.5675
205,376
2,764,626
6,199,398
4,026,866
304,683
o
13,500,949
620.1630,~-------~~~- -~----
470,231
291,454
445,316
222,194
267.685
42,439
350,627
66,739
312,624
208,451
568,289
3,246,049
0.0017
99,640
561,246
70,876
68,526
66,157
454
39,054
9,407
87,100
34,689
73,785
1,110,934
0.0066
FERC FORM NO.1 (REV. 12-03)Page 406.1
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2010/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) 0 A Resubmission 04115/2011
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accunts or combinations of accunts prescrbed by the Uniform System of Accunts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC Licensed Project No.2055 FERC Licensed Project No.503 FERC Licensed Project No.18 Line
Plant Name: C J Strke Plant Name: Swan Falls Plant Name: Twin Falls No.
(d)(e)
Run-of-River Run-of-River Run-of-River 1
Outdoor Conventional Conventional 2
1952 1910 1935 3
1952 1994 1995 4
82.80 25.00 52.74 5
86 23 46 6
8,760 8,760 8,744 7~-----~---- ------~---~---~-~----~-- ~---
91
84
5
423,822,000
24
14
3
124,623,000
53 9
50 10
5 11
115,370,000 12----~------~~--~--~--~- ------~-------~- --~~-
5,450,975 51,675 255,499 14
9,143,199 25,478,938 10,808,047 15
10,437,875 13,856,887 7,908,870 16
9,697,355 30,342,755 20,597,667 17
248,183 835,946 1,917,603 18
0 0 0 19
34,977,587 70,566,201 41,487,686 20
422.4346 2,822.6480 786.6455 21--------~------~-----~---~--~-~- ~-
1,027,331 254,735 213,710 23
753,948 180,782 167,496 24
971,545 166,121 132,309 25
50,321 40,466 42,866 26
382,733 116,381 168,313 27
104,526 26,232 7,801 28
204,871 85,180 40,387 29
79,707 66,145 35,430 30
124,754 40,504 4,952 31
639,809 161,351 92,946 32
335,250 220,455 104,233 33
4,674,795 1,358,352 1,010,443 34
0.0110 0.0109 0.0088 35
FERC FORM NO.1 (REV. 12-03)Page 407.1
Name of Respondent
Idaho Power Company
Year/Period of ReportThis ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) D A Resubmission 04/15/2011
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in
a footnote. If licensed project. give project number.
3. If net peak demand for 60 minutes is not available, give that which is available specifying period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
End of 2010/Q4
(a)
FERC Licensed Project No. 2777
Plant Name: Upper Salmon
(b)
FERC Licensed Project No. 2778
Plant Name: Shoshone Falls
(c)
Line
No.
Item
1 Kind of Plant (Run-of-River or Storage)
2 Plant Construction type (Conventional or Outdoor)
3 Year Originally Constructed
4 Year Last Unit was Installed
5 Total installed cap (Gen name plate Rating in MW)
6 Net Peak Demand on Plant-Megawatts (60 minutes)
7 Plant Hours Connect to Load
8 Net Plant Capabilty (in megawatts)
9 (a) Under Most Favorable Oper Conditions
10 (b) Under the Most Adverse Oper Conditions
11 Average Number of Employees
12 Net Generation, Exclusive of Plant Use - Kwh
13 Cost of Plant
14 Land and Land Rights
15 Structures and Improvements
16 Reservoirs, Dams, and Waterways
17 Equipment Costs
18 Roads, Railroads, and Bridges
19 Asset Retirement Costs
20 TOTAL cost (Total of 14 thru 19)
21 Cost per KW of Installed Capacity (line 20 / 5)
22 Production Expenses
23 Operation Supervision and Engineering
24 Water for Power
25 Hydraulic Expenses
26 Electrc Expenses
27 Misc Hydraulic Power Generation Expenses
28 Rents
29 Maintenance Supervision and Engineering
30 Maintenance of Structures
31 Maintenance of Reservoirs, Dams, and Waterways
32 Maintenance of Electric Plant
33 Maintenance of Misc Hydraulic Plant
34 Total Production Expenses (total 23 thru 33)
35 Expenses per net KWh
--~----~-~~--~
Run-of-River
Outdoor
1937
1947
34.50
37
8,760
Run-of-River
Conventional
1907
1921
12.50
14
8,760
~----~-----~~ ----~~---~~---
39
32
4
231,656,000
14
11
2
91,679,000
202,399
1,994,322
5,569,171
7,876,561
29,359
o
15,671,812
454.2554
313,328
1,207,557
512,402
4,503,350
51,383
o
6,588,020
527.0416~--~~-~
377,506
293,497
520,922
69,795
192,391
1,536
137,152
114,586
369,513
151,797
157,531
2,386,226
0.0103
242,269
171,034
188,087
30,619
111,877
1,094
26,133
11,296
10,858
37,622
50,272
881,161
0.0096
FERC FORM NO.1 (REV. 12-03)Page 406.2
Name of Respondent
Idaho Power Company
Year/Period of ReportThis ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) OA Resubmission 04/15/2011
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accunts or combinations of accunts prescrbed by the Uniform System of Accunts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
End of 2010/Q4
FERC Licensed Project No. 1971
Plant Name: Common Facilities
(d)
FERC Licensed Project No. 2061
Plant Name: Lower Salmon
(e)
FERC Licensed Project No. 2899
Plant Name: Milner
Line
No.
0.00
o
o
Run-of-River
Outdoor
1949
1949
60.00
43
8,760
Run-of-River 1
Conventional 2
1992 3
1992 4
59.45 5
42 6
8,760 7----~~------~-~---- ~~-------- -~----~-- -~-~
o
o
o
o
64
60
7
225,212,000
61 9
1 10
2 11
91,701,000 12-~~~------~---~-------------~-----~- -
114,367 424,428 138,100 14
26,156,672 2,805,900 10,340,105 15
13,556,785 6,831,204 17,179,601 16
1,190,964 7,907,638 27,676,057 17
99,051 88,693 501,877 18
0 0 0 19
41,117,839 18,057,863 55,835,740 20
0.0000 300.9644 939.2050 21--~-~.---~--- -----~------ ---
0 393,812 199,377 23
0 289,420 1,449,135 24
5,871,315 337,020 76,017 25
0 225,890 45,843 26
3,920 201,812 194,523 27
0 9,618 8,272 28
0 73,712 55,974 29
0 71,873 29,103 30
0 25,394 15,643 31
0 229,180 145,523 32
47,490 95,178 61,859 33
5,922,725 1,952,909 2,281,269 34
0.0000 0.0087 0.0249 35
FERC FORM NO.1 (REV. 12-03)Page 407.2
THIS PAGE INTENTIONALLY LEFT BLANK
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Idaho Power Company /2)A Resubmission 04/15/2011 2010/Q4
FOOTNOTE DATA
,,¡Schedule Page: 406 Line No.: 1 Column: b
American Falls generating capacity is dependent upon water releases controlled by the
United States Bureau of Reclamation.-----~--'Schedule Page: 406 Line No.: 1 Column: e
Cascade generating capacity is dependent upon water releases controlled by the United
States Bureau of Reclamation.--~-Schedule Page: 406 Line No.: 1 Column: f
Upstream storage in Brownlee Reservoir.
¡Schedule Page: 406.1 Line No.: 1 Column: b
Ups~~eam storage in Brownlee Reservoir
¡Schedule Page: 406.1 Line No.: 1 Column: c
Lower Malad maximum demand 15, 000 Kw, Upper Malad maximum demand 9, 000 Kw non-coincident.
--~i
IFERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) ñA Resubmission 04/15/2011
GENERATING PLANT STATISTICS (Small Plants)
1. Small generating plants are steam plants of, less than 25,000 Kw; internal combustion and gas turbine-plants, conventional hydro plants and pumped
storage plants of less than 10,000 Kw installed capacity (name plate rating).2. Designate any plant leased from others, operated under a license from
the Federal Energy Regulatory Commission, or operated as a joint facility, and give a concise statement of the facts in a footnote. If licensed project,
give project number in footnote.
Line Year Installed Gallcity Net Peak Net Generation
Name of Plant Orig.Name Plate atiñ!Demand Excluding Cost of Plant
No.Const.(In MW)(6~mvn.)Plant Use
(a)(b)(c)(e)(f)
1 Hydro:
2 Clear Lakes 1937 2.50 2.2 16,021 1,759,925
3 Thousand Springs 1912 8.80 6.5 51,590 5,023,460
4
5
6 Internal Combustion:
7 Salmon Diesel (1)1967 5.00 5.5 74 909,259
8
9
10
11 (1) Salmon units are classified as standby.
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30 ,
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO.1 (REV. 12-03)Page 410
Name of Respondent This ro0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) DA Resubmission 04/15/2011
GENERATING PLANT STATISTICS (Small Plants) (Continued)
3. List plants appropriately under subheadings for steam, hydro, nuclear, internal combustion and gas turbine plants. For nuclear, see instrcton 11,
Page 403. 4. If net peak demand for 60 minutes is not available, give the which is available, specifying period.5. If any plant is equipped with
combinations of steam, hydro internal combustion or gas turbine equipment, report each as a separate plant. However, if the exhaust heat frm the gas
turbine is utilzed in a steam turbine regenerative feed water cycle, or for preheated combustion air in a boiler, report as one plant.
Plant Cost (Incl Asset Operation Production Expenses Fuel Costs (in cents LineRetire. Costs) Per MW Exc'1. Fuel ruei Maintenance Kind of Fuel (per Millon Btu)No.
(g)(h)(i)G)(k)(I)
1
703,970 62,107 90,873 2
570,848 146,998 196,655 3
4
5
6
181,852 Diesel 7
8
9
10
11
12
13
14
15
16
17
18
19
20
"21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO.1 (REV. 12-03)Page 411
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo. Da, Yr)End of 2010/Q4
(2) Ei A Resubmission 04/15/2011
TRANSMISSION LINE STATISTICS
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accunts.Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Accunt 121, Nonutility Propert.
5. Indicate whether the type of supportng structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each tye of constrction
by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the
remainder of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on strctures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote. explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line DESIGNATION VI)I A(~~J~~Type of LE~~Ji~ ~~ie óliles)
No.(Indicate wtiere u ëlergrounllhnes Numberother than
60 cvcle, 30hase)Supporting report circuit miles)Of
From -On ~trl,cture u~.::rru?~res CircuitsToOperatingDesignedStructureof Line of.l0 erDesi(lated ine
(a)(b)(c)(d)(e)(g)(h)
1 Borah Midpoint 345.0C 500.00 STower 85.17 1
2 Boardman Slatt 500.0C 500.00 STower 1.79 1
3 Summer lake Hemingway 500.0C 500.00 STower 0.40 1
4 Hemingway Midpoint 500.0C 500.00 STower 0.37 1
5
6 Jim Bridger Goshen 345.0C 345.00 STower 226.14 1
7 State Line Midpoint 345.0C 345.00 STower 76.08 2
8 Kinport Borah 345.0C 345.00 STower 27.10 1
9 Midpoint Borah #1 345.0C 345.00 HWood 79.29 1
10 Midpoint Borah #2 345.0C 345.00 HWood 7758 2
11 Adelaide Tap Adelaide 345.0C 345.00 HWood 2.67 2
12
13 Quart LaGrande 230.0C 230.00 HWood 46.30 1
14 Midpoint Hunt 230.0C 230.00 STower 0.70 2
15 Brady Antelope 230.0C 230.00 HWood 56.29 1
16 Brady Treasureton 23O.0C 230.00 HWood 0.11 1
17 Brady #1 &#2 Kinport 230.0(230.00 STower 17.94 2
18 Jim Bridger Point of Rocks 230.0(230.00 HWood 1.40 1
19 Brownlee Ontario 230.0(230.00 STower 72.69 1
20 Mora Bowmont 138.0(230.00 SPWood 9.90 1
21 Mora Bowmont 138.0(230.00 HWood 8.82 1
22 Jim Bridger Point of Rocks 230.00 230.00 HWood 2.79 1
23 Caldwell 710 Locust 230.00 230.00 SP Steel 18.59 1
24 Boise Bench Caldwell 230.00 230.00 STower 7.58 1
25 Boise Bench Caldwell 230.00 230.00 HWood 33.68 1
26 Boise Bench Cloverdale 230.0C 230.00 S Tower 16.10 2
27 Boardman Dalreed Sub 230.00 230.00 HWood 1.68 1
28 Brownlee 714 Oxbow 230.00 230.00 SPSteel 11.10 2
29 Caldwell Ontario 230.00 230.00 HWood 27.10 1
30 Caldwell Ontario 230.00 230.00 S Tower 3.27 1
31 Bennett Mtn PP Rattlesnake TS 230.00 230.00 SPSteel 4.44 1
32 Borah Hunt 230.00 230.00 HSteel 68.17 1
33 Danskin Hubbard 230.00 230.00 H Steel 35.94 1
34 Danskin Hubbard 230.00 230.00 SP Steel 1.90 1
35 Danskin Hubbard 230.00 230.00 SPSteel 1.30 2
36 TOTAL 4,747.29 11.02 182
FERC FORM NO.1 (ED. 12-87)Page 422
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) n A Resubmission 04/15/2011
TRANSMISSION LINE STATISTICS (Continued)
7. Do not report the same trnsmission line strcture twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line strctures support lines of the same voltage, report the
pole miles of the primary strcture in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or porton thereof for which the respondent is not the sole owner. If such propert is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any trnsmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succnct statement explaining the
arrangement and giving partculars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accunted for, and accunts affected. Specify whether lessor, cowner, or
other part is an assciated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns 0) to (I) on the book cost at end of year.
CO::T OF LINE (Include in Column ü) Land,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material Land Construction and Total Cost Operation Maintenance Rents Total Line
Other Costs Expenses Expenses (0)Expenses No.(i)0)(k)(I)(m)(n)(p)
1272 ACSR 256,381 21,776,998 22,033,379 1
~X1780ACSR 446,708 446,708 2
1272 ACSR 802,274 802,274 3
1272 ACSR 4
5
1272 ACSR 483,30(16,540,614 17,023,923 6
1795 ACSR 571,97(11,046,840 11,618,819 7
1272 ACSR 344,22(6,034,618 6,378,838 8
1715.5 ACSR 283,14 5,832,249 6,115,392 9
i715.5ACSR 64,851 10,352,361 10,417,212 10
1715.5 ACSR 51,441 347,946 399,394 11
.12
i795ACSR 62,211 2,841,222 2,903,440 13
15.5 ACSR 9,14 998,42 1,007,597 14
1272 ACSR 108,301 2,502,500 2,610,801 15
1795 ACSR 6,186 6,186 16
715.5 ACSR 18,82~969,871 988,700 17
1272 ACSR 1,19(51,525 52,715 18
I2X954 ACSR 1,676,83f 20,418,606 22,095,444 19
15.5 ACSR 413,79 2,090,601 2,504,394 20
1715.5 ACSR 21
1272 ACSR 1,891 212,523 214,422 22
1590 ACSR 2,138,231 8,77,086 10,913,322 23
1272 ACSR 1,748,21'7,070,848 8,819,062 24
1715.5 ACSR 25
1272 ACSR 3,062,81 8,029,021 11,091,833 26
1795AAC 80,895 80,895 27
~54ACSR 34,17'16,026,470 16,060,644 28
I2X954 ACSR 197,65f 5,890,623 6,088,281 29
1272 ACSR 30
1272 ACSR 81,701 1,666,354 1,748,055 31
1590 ACSR 624,91 22,457,621 23,082,538 32
1590 ACSR 15,210,561 15,210,561 33
1590 ACSR 34
1590 ACSR 35
30,396,681 415,828,988 446,225,669 36
FERC FORM NO.1 (ED. 12-87)Page 423
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) n A Resubmission 04/15/2011
TRANSMISSION LINE STATISTICS
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accunts.Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Accunt 121, Nonutility Propert.
5. Indicate whether the tye 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 trnsmission line has more than one type of supporting structure, indicate the mileage of each type of constrction
by the use of brackets and extr lines. Minor portions of a transmission line of a different tye of construction need not be distinguished from the
remainder of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned strctures in column (g). In a footnote, explain the basis of such occpancy and state whether expenses with
respect to such strctures are included in the expenses reported for the line designated.
Line I luN \/01 TAr:~ (KV)LE~~J,~ ~ole óViles)
(Indicate wlìere Type of NumberNo.other than u dergrounSJhnes Of60 cvcle, 30hase)Supportng report circuit miles)
From
un ~trueture U~f~~i~res CircuitsToOperatingDesignedStructureof Line of .0 erDesiæatedme
(a)(b)(c)(d)(e)(g)(h)
1 Danskin Bennett Mtn 230.0(230.00 SP Steel 5.56 1
2 Hemingway Bowmont 230.0(230.00 SP Steel 13.02 1
3 Langley Gulch Tap 230.00
4 Boise Bench Midpoint #1 230.0(230.00 STower 0.86 1
5 Boise Bench Midpoint #1 230.0(230.00 HWoo 108.23 1
6 Brownlee Quart Jet 230.0(230.00 STower 1.52 1
7 Brownlee Quart Jct 230.0(230.00 HWood 41.69 1
8 Brownlee Boise Bench #1 & #2 230.0(230.00 STower 99.81 2
9 Oxbow Brownlee 230.0(230.00 STower 10.2 2
10 Boise Bench Midpoint #2 230.0 230.00 STower 3.42 1
11 Boise Bench Midpoint #2 230.0(230.00 HWoo 102.07 1
12 Oxbow Pallette Jet 230.00 230.00 STower 20.04 2
13 Pallette Jet Imnaha 230.00 230.00 HWoo 24.43 2
14 Hells Canyon Palette Jct 230.00 230.00 STower 8.24 2
15 Brownlee Boise Bench 230.00 230.00 STower 102.12 2
16 Boise Bench Midpoint #3 230.00 230.00 HWood 106.34 1
17 Palette Jct .Enterprise 230.0C 230.00 HWood 29.12 1
18 Borah Brady #2 230.0C 230.00 STower 0.41 1
19 Borah Brady #2 230.0C 230.00 HWood 3.56 1
20 Borah Brady #1 230.0C 230.00 HWood 3.88 1
21
22 Goshen State Line 161.0C 161.00 HWood 90.48 1
23 Don Goshen 161.0C 161.00 STower 2.39 2
24 Don Goshen 161.OC 161.00 HWoo 48.3 2
25
26 American Falls Power Plant Adelaide 138.0C 138.00 HWoo 10.99 2
27 American Falls Power Plant Adelaide 138.0C 138.00 SPWood 0.12 2
28 Minidoka Loop Adelaide 138.0C 138.00 STower 1.11 2
29 Nampa Caldwell 138.0C 138.00 SPWood 10.72 2
30 Upper Salmon Mountain Home Jct 138.0C 138.00 HWood 54.36 1
31 Upper Salmon Cliff 138.0C 138.00 HWood 30.90 1
32 Eastgate Russet 138.0C 138.00 SPWood 2.08 1
33 Brady Fremont 138.00 138.00 STower 0.98 2
34 Brady Fremont 138.00 138.00 HWood 24.32 2
35 Brady Fremont 138.00 138.00 SPWoo 24.33 2
36 TOTAL 4,747.29 11.02 182
FERC FORM NO.1 (ED. 12-87)Page 422.1
Name of Respondent This (!0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) FiA Resubmission 04/15/2011
TRANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such propert is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any trnsmission line other than a leased line, or porton thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succnct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accunted for, and accunts affected. Specify whether lessor, co-owner, or
other part is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns (j to (I) on the book cost at end of year.
COST OF LINE (Include in Column (j Land,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material Land Construction and Total Cost Operation Maintenance Rents Total LineOther Costs Expenses Expenses (0)
Expenses No.(i)(j (k)(I)(m)(n)(p)
1590 ACSR 3,528,033 3,528,033 1
1590 ACSR 1,854,991 9,197,975 11,052,971 2
430,88 430,883 3
15.5 ACSR 336,181 4,237,077 4,573,263 4
15.5 ACSR 5
95 ACSR 53,061 2,139,082 2,192,150 6
95 ACSR 7
VARIOUS 289,931 8,047,757 8,337,691 8
1272 ACSR 14,81(1,182,550 1,197,360 9
15.5 ACSR 227,82 6,115,266 6,343,091 10
VARIOUS 11
1272 ACSR 23,301 2,075,244 2,098,552 12
1272 ACSR 138,4 1,386,300 1,524,777 13
1272 ACSR 10,73 1,252,130 1,262,867 14
~54ACSR 184,81 5,624,726 5,809,543 15
15.5 ACSR 247,85 5,423,341 5,671,198 16
1272 ACSR 51,12.1,739,212 1,790,334 17
1272 ACSR 3,06~426,826 429,894 18
15.5 ACSR 19
1272 ACSR 10,06~311,349 321,413 20
21
50 COPPER 16,15'648,382 664,537 22
15.5 ACSR 76,041 1,652,914 1,728,955 23
97.5 ACSR 24
25
50 COPPER 26,501 2,396,233 2,422,740 26
50 COPPER 27
15.5 ACSR 21,32E 249,233 270,559 28
95AAC 587,391 1,753,582 2,340,979 29
95 ACSR 47,681 2,635,628 2,683,315 30
95 ACSR 43,56~788,709 832,277 31
95AAC 270,82 557,504 828,327 32
VARIOUS 564,93.3,719,546 4,284,478 33
VARIOUS 34
VARIOUS 35
30,396,681 415,828,988 446,225,669 36
FERC FORM NO.1 (ED. 12-87)Page 423.1
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo. Da, Yr)End of 2010/04
(2) 0 A Resubmission 04/15/2011
TRANSMISSION LINE STATISTICS
1. Report information conceming transmission lines, cost of lines. and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accunts.Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any trnsmission lines for which plant costs are included in Accunt 121, Nonutilty Propert.
5. Indicate whether the type of supportng structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood. or steel poles; (3) tower;
or (4) underground constrction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and exta lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the
remainder of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on strctures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or party owned structures in column (g). In a footnote, explain the basis of such occpancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
DESIGNATIONLine yu!-T Type of LE~GJr ~ole Wiles)Number(Indicate wtiere r.te SJONo.other than u dergroun lines Of60 cYcle, 3 phase)Supportng report circuit miles)
From I un ~tflcture U~v~mw¡es CircuitsToOperatingDesignedStructureof Line o ot erDesiæatedLine(a)(b)(c)(d)(e)(g)(h)
1 King Lower Malad 138.0C 138.00 HWood 84.73 2
2 Emmett Jct Payette 138.0C 138.00 HWood 66.45 2
3 Mountain Home AFB Tap 138.0C 138.00 HWood 6.20 1
4 Ontario Quart 138.0C 138.00 HWood 73.33 1
5 King American Falls PP 138.0C 138.00 STower 1.03 2
6 King American Falls PP 138.0C 138.00 HWood 148.96 1
7 King American Falls PP 138.0C 138.00 SPWood 3.71 1
8 Duffn Clawson 138.0C 138.00 HWood 6.22 1
9 American Falls Brady Tie 138.0C 138.00 HWood 0.30 1
10 Upper Salmon A-B King 138.0C 138.00 HWood 6.00 1
11 Upper Salmon B Wells 138.0C 138.00 HWood 126.40 1
12 King Wood River 138.0C 138.00 HWood 73.61 1
13 Boise Bench Grove 138.0C 138.00 SPWood 10.36 2
14 Quart John Day 138.0C 138.00 HWood 67.32 1
15 Sinker Creek Tap 138.0C 138.00 HWood 2.80 1
16 Mora Cloverdale 138.0(138.00 HWood 2.57 1
17 Mora Cloverdale 138.0C 138.00 SPWood 22.28 1
18 Mora Cloverdale 138.0C 138.00 SPSteel 0.96 2
19 Stoddard Jct Stoddard Sub 138.0(138.00 SPSteel 3.80 1
20 Fossil Gulch Tap 138.0(138.00 HWood 1.95 1
21 Wood River Midpoint 138.0C 138.00 HWood 53.05 2
22 Wood River Midpoint 138.0C 138.00 SPWood 16.69 2
23 Oxbow McCall 138.0C 138.00 HWood 37.33 1
24 Oxbow McCall 138.0C 138.00 SPWood 2.32 1
25 Lowell Jct Nampa 138.0C 138.00 S PWood 7.50 2
26 Hunt Milner 138.0C 138.00 SPWood 19.40 1
27 Strke Bruneau Bridge 138.0C 138.00 HWood 13.47 1
28 American Falls Kramer Sub 138.0C 138.00 SPWood 18.40 2
29 Pingree Haven 138.0C 138.00 SPWood 11.72 1
30 Midpoint Twin Falls 138.0C 138.00 SPWood 25.12 2
31 Twin Falls Russett 138.0C 138.00 SPWood 1.1 1
32 Blackfoot Aiken 46.0C 138.00 SPWoo 6.17 2
33 Petersn Tendoy 69.0C 138.00 HWood 57.19 1
34 Eastgate Tap Eastgate 138.0C 138.00 S PWood 7.28 1
35 Boise Bench Mora 138.0C 138.00 HWood 13.15 2
36 TOTAL 4,747.29 11.02 182
FERC FORM NO.1 (ED. 12-87)Page 422.2
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) riA Resubmission 04/15/2011
TRANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such propert is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any trnsmission line other than a leased line, or porton thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succnct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accunted for, and accunts affected. Specify whether lessor, co-owner, or
other part is an associated company.
9. Designate any trnsmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns U) to (I) on the book cost at end of year.
COST OF LINE (Include in Column U) Land,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material Land Constructon and Total Cost Operation Maintenance Rents Total LineOther Costs Expenses Expenses (0)
Expenses No.(i)U)(k)(I)(m)(n)(p)
ARIOUS 76,82 2,068,846 2,145,669 1
ARIOUS 30,91€2,508,77 2,539,395 2
97.5 ACSR 1,95~12,983 14,938 3
"ARIOUS 34,42E 1,929,353 1,963,781 4
15.5 ACSR 216,91~7,792,986 8,009,905 5
15.5 ACSR 6
15.5 ACSR 7
\0 4,191 310,154 314,345 8
54 ACSR 96,921 96,921 9
~50COPPER 2,741 93,073 95,814 10
!VARIOUS 28,90 2,151,842 2,180,332 11
¡VARIOUS 173,68 2,670,867 2,844,550 12
!VARIOUS 225,60i 1,652,72 1,878,374 13
ß97.5ACSR 92,17 2,362,416 2,454,589 14
!VARIOUS 20 77,199 77,219 15
1715.5 ACSR 3,115,486 7,904,710 11,020,196 16
!VARIOUS 17
1795AAC 18
1272 ACSR 19
1250 COPPER 45(154,349 154,799 20
1397.5 ACSR 349,561 6,983,609 7,333,176 21
1397.5 ACSR 22
~97.5ACSR 109,89¡2,306,969 2,416,868 23
1397.5 ACSR 24
1715.5 ACSR 211,131 1,448,294 1,659,425 25
1715.5 ACSR 3,32¿1,190,604 1,193,928 26
~97.5ACSR 14,921 587,404 602,331 27
1715.5 ACSR 13,7J.1,052,549 1,066,283 28
~97.5ACSR 18,22~1,276,855 1,295,078 29
!VARIOUS 54,84E 2,958,765 3,013,613 30
1715.5 ACSR 16,79(206,158 222,948 31
1715.5 ACSR 13,61(481,232 494,848 32
~97.5ACSR 395,691 3,449,949 3,845,645 33
1715.5 ACSR 343,95 1,058,897 1,402,852 34
15.5 ACSR 14,69 637,273 651,970 35
30,396,681 415,828,988 446,225,669 36
FERC FORM NO.1 (ED. 12-87)Page 423.2
Name of Respondent This ~ort Is:Date of Report Year/Penod of Report
Idaho Power Company (1) An Onginal (Mo, Da, Yr)End of 2010/Q4
(2) DA Resubmission 04/15/2011
TRANSMISSION LINE STATISTICS
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each trnsmission line having nominal voltage of 132
kilovolts or greater. Report trnsmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accunts.Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Accunt 121, Nonutility Propert.
5. Indicate whether the type of supportng structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a different tye of construction need not be distinguished frm the
remainder of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on strctures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occpancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line ATION YuL, i Al;t:.~~YJ Type of LE~GJiH ~oie Wiles)Number(Indicate wliere ~r.te ~oNo.other than u dergroun lines Of60 cvcle, 30hase)Supportng report circuit miles)
From To Operating Designed un ~l!\ctUre unf%uoi~res CircuitsStrctreof Line o Li~e er
(a)(b)(c)(d)(e)Desi(lated
(g)(h)
1 Bowmont-Caldwell SimplotSub 138.0(138.00 SPWood 0.51 1
2 Gary Lane Eagle 138.0(138.00 SPWood 6.53 1
3 Locust Grove Blackcat Sub 138.0(138.00 S P Steel 9.94 2.98 1
4 Boise Bench Butler 138.0(138.00 SPWood 0.24 4.02 1
5 Eagle Star 138.0(138.00 SPWood 6.35 1
6 Karcher Sub Zilog Tap 138.0(138.00 S P Steel 2.08 1
7 Cloverdale - 712 712 - Wye 138.0(138.00 S P Steel 0.21 4.02 1
8 Butler Wye 138.0(138.00 S P Steel 2.84 1
9 Horseflat Starkey 138.0(138.00 HWood 33.86 1
10 Starkey Mccll 138.0(138.00 S P Steel 2.08 2
11 Starkey Mccll 138.0(138.00 HWood 3.80 1
12 Starkey Mccll 138.0(138.00 S P Steel 1.50 1
13 Starkey Mccll 138.0(138.00 SPWood 17.61 1
14 Chestnut Happy Valley 138.0(138.00 S P Stel 2.79 1
15 Garnet Ward 138.00
16 McCall Lake Fork 138.0(138.00 SPWood 8.80 1
17 McCall Lake Fork 138.0(138.00 SSteel 2.90
18 Caldwell Wills 138.0(138.00 S P Stel 1.30 1
19 Caldwell Wills 138.0(138.00 SPSteel 1.59 1
20 Caldwell Wills 138.0(138.00 SPWoo 0.87 1
21 ValivueTap 138.0(138.00 S P Steel 0.80 2
22 Kinport Don #1 138.0(138.00 STower 1.24 2
23 Donn HOKU 138.0(138.00 SPStel 2.74 1
24 HOKU Alamed 138.0C 138.00 S PSteel 0.22 2
25 HOKU Alamed 138.0C 138.00 S P Steel 0.23 2
26 HOKU Alamed 138.0C 138.00 S P Steel 2.85 1
27 Twin Falls PP Tap 138.0(138.00 HWood 0.82 1
28 American Falls PP Amercian Falls Trans ST 138.0C 138.00 S P Steel 0.43 1
29 Lower Salmon King Tie 138.0C 138.00 HWood 0.19 1
30 C J Stnke Strike Jct 138.0C 138.00 STower 4.39 2
31 Strike Jct Mountain Home Jct 138.0C 138.00 HWood 23.46 1
32 Stnke Jct Bowmont 138.00 HWood 0.05 1
33 Stnke Jct Bowmont 138.0C 138.00 STower 0.36 1
34 Stnke Jct Bowmont 138.0C 138.00 HWood 68.24 1
35 Lucky Peak Lucky Peak Jct 138.0C 138.00 HWood 4.48 2
36 TOTAL 4,747.29 11.02 182
FERC FORM NO.1 (ED. 12-87)Page 422.3
Name of Respondent This wort Is:Date of Report Year/Penod of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) FiA Resubmission 04/15/2011
TRANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the pnmary strcture in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or porton thereof for which the respondent is not the sole owner. If such propert is leased frm another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a lease line, or porton thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succnct statement explaining the
arrngement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accunted for, and accunts affeced. Specify whether lessor, co-owner, or
other part is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns (j to (I) on the book cost at end of year.
COST OF LINE (Include in Column (j Land,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and cleanng nght-of-way)
Conductor
and Matenal Land Construction and Total Cost Operation Maintenance Rents Total Line
Other Costs Expenses Expenses (0)
Expenses No.(i)(j (k)(I)(m)(n)(p)
95AAC 49,642 49,642 1
95AAC 489,03 1,944,888 2,433,925 2
1272 ACSR 935,72!3,601,590 4,537,315 3
1272 ACSR 34,68 838,605 873,292 4
15.5 ACSR 179,81 2,909,434 3,089,251 5
95AAC 43,03'482,937 525,972 6
1272 ACSR 140,41.709,148 849,560 7
95 ACSR 134,471 1,405,436 1,539,907 8
15.5 ACSR 2,472,83 18,211,011 20,683,844 9
15.5 ACSR 10
15.5 ACSR 11
15.5 ACSR 12
15.5 ACSR 13
1272 ACSR 78,57~1,821,921 1,900,500 14
40,58(40,580 15
15.5 ACSR 331,53c 4,682,879 5,014,418 16
17
1272 ACSR 272,231 2,141,218 2,413,49 18
95 ACSR 19
95 ACSR 20
95 ACSR 351,497 351,497 21
15.5 ACSR 1,17'212,777 213,951 .22
1272 ACSR 19(398 588 23
1272 ACSR 24
95 ACSR 25
95 ACSR 26
50 COPPER 5f 53,889 53,947 27
15.5 ACSR 76,560 76,560 28
J97.5ACSR 4,406 4,406 29
15.5 ACSR 5,56E 385,744 391,310 30
J97.5ACSR 4,35'2,240,408 2,244,763 31
15.5 ACSR 86,651 1,866,338 1,952,989 32
15.5 ACSR 33
34
15.5 ACSR i 279,481 279,488 35
30,396,681 415,828,988 446,225,669 36
FERC FORM NO.1 (ED. 12-87)Page 423.3
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) . An Original (Mo, Da, Yr)End of 2010/Q4
(2) riA Resubmission 04/15/2011
TRANSMISSION LINE STATISTICS
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accunts.Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Accunt 121, Nonutility Propert.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frme wood, or steel poles; (3) tower;
or (4) underground constructon If a transmission line has more than one tye of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a different type of constructon need not be distinguished from the
remainder of the line.
6. Report in columns (f) and (g) the total pole miles of each trnsmission line. Show in column (f) the pole miles of line on strctures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or party owned structures in column (g). In a footnote, explain the basis of such occpancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line DESIGNATION )(OL TAGE IKVl Type of LENGJr ~oie Wiles)
No.(Indicate wlìere 1.10 e scf 0 Number
other than u ë1ergroun lines
60 cvcle, 30hase)Supportng report circuit miles)Of
From
un ~truetre un,~tr'&1Wres CircitsToOperatingDesignedStructureof Line ofAnot erDesimiatedLine
(a)(b)(c)(d)(e)(g)(h)
1 Bliss King 138.0C 138.00 HWood 10.60 1
2 Milner Deadend MiinerPP 138.DC 138.00 SPWood 1.37 1
3 Swan Falls Tap 138.0C 138.00 HWoo 1.02 1
4
5
6
7 Hines BPA (Harney)115.0C 115.00 HWoo 3.28 1
8
9
10 69 Kv Lines 69.0C 69.00 HWood 166.31 1
11 69 Kv Lines 69.DC 69.00 SPWoo 929.34 1
12
13
14 46 Kv Lines 46.0C 46.00 SPWood 409.26 1
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36 TOTAL 4,747.29 11.02 182
FERC FORM NO.1 (ED. 12-87)Page 422.4
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) nA Resubmission 04/15/2011
TRASMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such propert is teased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any trnsmission line other than a leased line, or porton thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succnct statement explaining the
arrngement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accunted for, and accunts affected. Specify whether lessor, co-owner, or
other part is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns u) to (I) on the book cost at end of year.
l;U:; I Uf LINE (Include in i;olumn û) Land,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material Land Construction and Total Cost Operation Maintenance Rents Total Line
Other Costs Expenses Expenses (0)
Expenses No.(i)u)(k)(I)(m)(n)(p)
15.5 ACSR 5,620 978,001 983,621 1
1715.5 ACSR 2,814 183,606 186,420 2
ß97.5ACSR 12,88~261,511 274,396 3
4
5
6
ß97.5ACSR 1,978 63,404 65,382 7
8
9
VARIOUS 1,482,63 46,699,103 48,181,740 10
VARIOUS 11
12
13
VARIOUS 308,67(12,379,478 12,688,148 14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
30,396,681 415,828,988 446,225,669 36
FERC FORM NO.1 (ED. 12-87)Page 423.4
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) Fi A Resubmission 04/15/2011
TRANSMISSION LINES ADDED DURING YEAR
1.Report below the information called for concerning Transmission lines added or altered during the year.It is not necessary to report
minor revisions of lines.
2. Provide separate subheadings for overhead and under- ground construction and show each transmission line separately. If actual
costs of competed construction are not readily available for reporting columns (I) to (0), it is permissible to report in these columns the
Line LINE DE:;IGNArlON Line lNG::TROCTOR~CIR RSTRUl,IUR
No.From To
Lerigth
Type Average Present UltimateinNumber perMilesMiles
(a)(b)(c)(d)(e)(f)(g)
1 Summer Lake Hemingway 0.40 S Tower 7.50 1 1
2 Hemingway Midpoint 0.37 S Tower 8.11 1 1
3
4 Langley Gulch Tap 2
5 "
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44 TOTAL 0.77 15.61 2 ~
FERC FORM NO.1 (REV. 12-03)Page 424
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
Idaho Power Company (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) Fi A Resubmission 04/15/2011
TRANSMISSION LINES ADDED DURING YEAR (Continued)
costs. Designate, however, if estimated amounts are reported. Include costs of Clearing Land and Rights-of-Way, and Roads and
Trails, in column (i) with appropriate footnote, and costs of Underground Conduit in column (m).
3. If design voltage differs from operating voltage, indicate such fact by footnote; also where line is other than 60 cycle, 3 phase,
indicate such other characteristic.
RS Voltage L1I"ST Line
Size Specification Conf~uration KV Land and Poles, Towers Conductors Asset Total No.
and pacing (Operating)Land Rights and Fixtures and Devices Retire. Costs
(h)(i)m (k)(I)(m)(n)(0)(p)
1272 ASCR TDC-DCTA 15'500 802,27~802,274 1
1272 ASCR TDC-DCTA 15'500 2
3
230 430,883 430,883 4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
/38
39
40
41
42
43
430,883 802,27~1,233,157 44
FERC FORM NO.1 (REV. 12-03)Page 425
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Onginal (Mo, Da, Yr)End of 2010/Q4
(2) n A Resubmission 04/15/2011
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (t).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Pnmary Secondary Tertiary
(a)(b)(c)(d)(e)
1 Adelaide transmission 345.00 138.00 13.80
2 Aiken distnbution 46.00 13.00
3 Alameda distribution 46.00 13.00
4 Alameda distnbution 138.00 13.09
5 Amencan Falls PP - attended transmission 138.00 13.80
6 Amencan Falls transmission 138.00 46.00 12.47
7 Artesian distnbution 46.00 13.00
8 Bannock Creek distnbution 46.00 13.00
9 Bennett Mountain Power Plant transmission 230.00 18.00
10 Bennett Mountain Power Plant distnbution 18.00 4.16
11 Bethel Court distnbution 138.00 13.00
12 Black Cat distnbution 138.00 13.09
13 Blackfoot distribution 46.00 13.00
14 Blackfoot transmission 161.00 46.00 12.47
15 Blackfoot distnbution 161.00 138.00 12.98
16 Bliss - attended transmission 138.00 13.80
17 Blue Gulch distnbution 138.00 35.00
18 Boise Bench - attended transmission 230.00 138.00 13.20
19 Boise Bench - attended distribution 138.00 35.00
20 Boise Bench - attended transmission 138.00 69.00 12.98
21 Boise Bench - attended transmission 230.00 138.00 13.80
22 Boise distribution 138.00 13.00
23 Borah transmission 345.00 230.00 13.80
24 Bowmont distnbution 69.00 46.00 6.90
25 Bowmont distribution 138.00 35.00
26 Bowmont transmission 138.00 69.00 12.98
27 Bowmont trnsmission 138.00 69.00 12.47
28 Bowmont transmission 230.00 138.00 13.80
29 Brady distribution 46.00 13.00
30 Brady trnsmission 230.00 138.00 13.80
31 Brady transmission 138.00 46.00 12.47
32 Brady distnbution 69.00 13.00
33 Brownlee - attended transmission 230.00 13.80
34 Bruneau Bridge distnbution 138.00 35.00
35 Buckhorn distribution 69.00 35.00
36 Bucyrus distribution 46.00 7.20
37 Buhl distribution 46.00 13.00
38 Burley Rural distribution 69.00 13.00
39 Butler distnbution 138.00 13.09
40 Caldwell distnbution 138.00 13.00
FERC FORM NO.1 (ED. 12-96)Page 426
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) 0 A Resubmission 04/15/2011
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifers, condensers, etc.and auxilary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co~owner or other part, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other part is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARTUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)
Transformers Spare Type of Equipment Total Capacity No.In Servce Transformers Number of Units
(In MVa)
(f)(g)(h)(i)(j (k)
300 2 1
20 2 2
15 1 3
18 1 4
72 1 5
25 1 6
10 1 7
10 1 8
135 1 9
5 1 10
15 1 11
24 1 12
30 2 13
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
300 3 30
1 31
1 32
734 5 1 33
30 2 34
20 1 35
6 1 4 36
20 2 37
12 1 38
48 2 39
39 2 1 40
FERC FORM NO.1 (ED. 12-96)Page 427
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2)D A Resubmission 04/15/2011
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (t).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 Caldwell transmission 138.00 69.00 12.47
2 Caldwell transmission 230.00 138.00 12.47
3 Caldwell distribution 13.00 4.16
4 Canyon Creek distnbution 138.00 35.00
5 Canyon Creek transmission 138.00 69.00 12.98
6 Cascade Power Plant - attended trnsmission 69.00 4.60
7 Cascade Distnbution 69.00 13.10
8 Chestnut distribution 138.00 13.00
9 Clear Lake - attended trnsmission 46.00 2.40
10 Cliff trnsmission 138.00 46.00 12.50
11 Cloverdale Distribution 138.00 13.00
12 Dale distnbution 46.00 13.00
13 Dale distribution 69.00 13.00
14 Dale distribution 138.00 36.20
15 Dale Transmission 138.00 46.00 12.47
16 Danskin Transmission 230.00 18.00
17 Danskin transmission 230.00 138.00 13.80
18 Danskin distnbution 18.00 4.16
19 Danskin transmission 138.00 12.00
20 Don distnbution 138.00 7.60
21 Don distnbution 138.00 13.20
22 Don distnbution 138.00 13.00
23 Don distribution 14.00
24 DRA distribution 138.00 13.09
25 DRAM transmission 230.00 138.00 13.80
26 DRAM distribution 138.00 12.47
27 Duffn distnbution 138.00 35.00
28 Eagle distnbution 138.00 13.09
29 Eastgate distnbution 138.00
30 Eastgate distnbution 138.00 13.00
31 Eckert distribution 138.00 36.20
32 Eden distribution 138.00 36.20
33 Eden transmission 138.00 46.00 12.98
34 Elkhorn distribution 138.00 12.47
35 Elkhorn distnbution 138.00 13.00
36 Elmore distribution 138.00 35.00
37 Elmore transmission 138.00 69.00 12.50
38 Emmett distribution 138.00
39 Emmett Transmission 138.00 69.00 12.47
40 Falls distribution 46.00 13.00
FERC FORM NO.1 (ED. 12-96)Page 426.1
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo. Da, Yr)End of 2010/Q4
(2) 0 A Resubmission 04/15/2011
SUBSTATIONS (Continued)
5. Show in columns (1),0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other part, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other part is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)Transformers Spare Total Capacity No.In Servce Transformers Type of Equipment Number of Units
(In MVa)
(f)(g)(h)(i)0)(k)
75 3 1
240 2 2
1 3
15 1 4
15 1 5
12 1 6
10 1 7
48 2 8
4 1 9
16 3 1 10
48 2 11
7 12
1 13
27 1 14
25 1 15
140 1 16
180 1 17
6 1 18
96 2 19
1 20
108 6 3 21
26 1 1 22
80 6 23
118 7 24
160 2 25
17 1 26
36 2 27
38 2 28
24 1 29
18 1 1 30
18 1 31
24 1 32
15 1 33
8 1 34
8 1 35
17 1 36
30 2 37
24 1 38
25 1 39
18 2 40
FERC FORM NO.1 (ED. 12-96)Page 427.1
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2)o A Resubmission 04/15/2011
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (t).
Une VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 Filer distribution 46.00 13.00
2 Flying H distrbution 69.00 2.40
3 Fort Hall distrbution 46.00 13.00
4 Fossil Gulch distrbution 138.00 35.00
5 Fremont transmission 138.00 46.00 12.50
6 Gary distrbution 138.00 13.00
7 Gem distrbution 69.00 13.00
8 Gem distrbution 69.00
9 Goodng Rural distribution 46.00 13.00
10 Golden Valley distrbution 69.00 13.00
11 Gowen Substation distrbution 138.00 35.00
12 Grindstone distribution 35.00
13 Grove distrbution 138.00 13.09
14 Hagerman distrbution 46.00 13.00
15 Hagerman distrbution 46.00 13.00 32.00
16 Hailey distrbution 138.00 13.00
17 Happey Valley distrbution 138.00 13.09
18 Haven distrbution 138.00 35.00
19 Haven transmission 138.00 46.00---20 transmission 500.00 230.00 34.50-
21 Hewlett Packard distribution 138.00 13.00
22 Hidden Springs distrbution 138.00 13.00
23 Highland distrbution 138.00 13.00
24 Hil distrbution 138.00 13.00
25 Hilsdale distrbution 138.00
26 Homedale distribution 69.00 13.00
27 Horse Flat transmission 230.00 138.00 13.80
28 Horse Flat distribution 69.00 13.00
29 Horseshoe Bend distrbution 35.00
30 Horseshoe Bend distribution 69.00 36.20
31 Horseshoe Bend distribution 69.00 25.00
32 Huston distribution 69.00 13.00
33 Hulen distribution 46.00 13.00
34 Hunt transmission 230.00 138.00 13.80
35 Hydra distribution 138.00 36.20
36 Island distrbution 69.00 13.00
37 Jerome distribution 138.00 13.00
38 Julion Clawson distribution 138.00 35.00
39 Joplin distribution 138.00 13.00
40 Joplin distrbution 138.00 35.00
FERC FORM NO.1 (ED. 12-96)Page 426.2
Name of Respondent This Report Is:Date of Report Year/Period of Report
Idaho Power Company (1) !KAn Original (Mo, Da, Yr)End of 2010/Q4
(2) n A Resubmission 04/15/2011
SUBSTATIONS (Continued)
5. Show in columns (i), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxilary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other part, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other part is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units
(In MVa)
(f)(g)(h)(i)(j (k)
10 1 1
15 2 2
10 1 1 3
15 1 4
50 3 1 5
37 2 6
8 1 7
10 1 8
15 2 9
10 1 1 10
24 1 11
5 2 12
72 3 13
10 1 14
5 1 15
20 1 16
18 1 17
12 1 18
25 1 19
600 3 1 20
20 1 21
8 1 22
18 1 23
39 2 1 24
24 1 25
22 2 26
100 1 27
1 28
5 1 29
12 1 30
5 1 31
10 1 32
10 1 33
300 3 34
48 2 35
12 1 36
40 2 37
30 2 38
15 1 39
18 1 40
FERC FORM NO.1 (ED. 12-96)Page 427.2
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Onginal (Mo, Da, Yr)End of 2010/Q4
(2)D A Resubmission 04/15/2011
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f.
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Pnmary Secondary Tertiary
(a)(b)(c)(d)(e)
1 Karcher distribution 138.00 13.00
2 Kenyon distribution 69.00 13.00
3 Ketchum distribution 138.00 13.00
4 Kinport transmission 161.00 46.00 13.20
5 Kinport transmission 230.00 138.00 12.47
6 Kinport transmission 230.00 138.00 13.80
7 Kinport transmission 345.00 230.00 13.80
8 Kramer distribution 138.00 35.00
9 Kramer distnbution 138.00 36.20
10 Kuna distribution 138.00 13.00
11 Lake Fork distnbution 138.00 36.20
12 Lake Fork transmission 138.00 69.00 12.50
13 Lamb distnbution 138.00 13.00
14 Lansing distnbution 69.00 13.00
15 Lincoln distnbution 138.00 13.09
16 Linden distribution 138.00 13.00
17 Locust distribution 138.00 36.20
18 Locust transmission 230.00 138.00 13.80
19 Lower Malad - attended transmission 138.00 7.20
20 Lower Salmon - attended transmission 138.00 13.80
21 Map Rock distribution 69.00 13.00
22 McCall distribution 13.00 13.09
23 McCall distribution 138.00 36.20
24 Mendian distnbution 138.00 13.00
25 Micron distnbution 138.00 13.09
26 Micron distnbution 138.00 13.00
27 Midpoint transmission 230.00 138.00 13.80
28 Midpoint transmission 345.00 230.00 13.80
29 Midpoint transmission 500.00 345.00
30 Midrose distribution 138.00 13.09
31 Milner transmission 138.00 69.00 12.47
32 Milner distnbution 69.00 46.00 6.90
33 Milner distnbution 138.00 35.00
34 Milner PP - attended transmission 138.00 13.80
35 Moonstone .distnbution 138.00 35.00
36 Mora distnbution 138.00 35.00
37 Mora distnbution 138.00 36.20
38 Moreland distnbution 35.00 13.00
39 Moreland distnbution 46.00 13.00
40 Moreland distnbution 46.00 35.00 12.47
FERC FORM NO.1 (ED. 12-96)Page 426.3
Name of Respondent This i80rt Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo. Da. Yr)End of 2010/Q4
(2) 0 A Resubmission 04/15/2011
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxilary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other part, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other part is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)Transformers Spare Total Capacity No.In Service Transformers Type of Equipment Number of Units
(In MVa)
(f)(g)(h)(i)0)(k)
12 1 1
20 2 2
42 2 3
7 4
180 1 5
180 1 6
600 3 1 7
12 1 8
18 1 9
15 1 10
18 1 11
15 1 12
18 1 13
12 1 14
10 1 15
33 2 16
48 2 17
360 2 18
16 1 19
70 4 20
10 1 21
12 1 22
18 1 23
36 2 24
24 2 25
24 2 26
120 1 27
720 2 28
750 3 1 29
24 1 30
100 4 31
8 3 1 32
17 1 33
36 1 34
12 1 35
15 1 36
24 .1 37
6 1 38
8 1 39
8 4 40
FERC FORM NO.1 (ED. 12-96)Page 427.3
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) 0 A Resubmission 04/15/2011
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Une VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 Mountain Home distribution 69.00 13.00
2 Mountain Home Air Force Base distribution 69.00 13.00
3 Mountain Home Air Force Base distribution 138.00 13.00
4 Nampa distrbution 230.00 138.00 13.80
5 Nampa distribution 138.00 13.00
6 New Meadows distribution 138.00 36.20
7 New Plymouth distrbution 69.00 13.00
8 Notch Butte distribution 13.00 13.09
9 Orchard distribution 69.00 36.20
10 Orchard distrbution 69.00 35.00 12.47
11 Parma distrbution 69.00 13.00
12 Parma distrbution 69.00 35.00
13 Paul distribution 138.00 35.00
14 Payette distribution 138.00 13.00
15 Pingree transmission 138.00 46.00 12.50
16 Pingree distribution 138.00 35.00
17 Pleasant Valley distrbution 138.00 35.00
18 Pocatello distribution 46.00 13.00
19 Poleline distribution 138.00 13.09
transmission 345.00
21 Porteuf distribution 138.00 35.00
22 Portneuf distribution 46.00 35.00
23 Rockford distribution 46.00 13.00
24 Russett distribution 138.00 13.00
25 Sailor Creek distrbution 138.00 2.40
26 Sailor Creek distribution 138.00 35.00
27 Salmon distrbution 69.00 13.00
28 Salmon distribution 69.00 34.50 12.50
29 Salmon trnsmission 13.00 2.40
30 Shoshone distribution 46.00 13.00
31 Shoshone distribution 46.00 7.20
32 Shoshone Falls - attended transmission 46.00 2.30
33 Shoshone Falls - attended transmission 46.00 6.60
34 Silver distrbution 138.00 35.00
35 Simplot distribution 138.00 13.00
36 Sinker Creek distribution 138.00 35.00
37 Siphon distribution 138.00 35.00
38 South Park distrbution 46.00 13.00
39 Star distribution 138.00 13.09
40 Starkey Transmission 138.00 69.00 12.50
FERC FORM NO.1 (ED. 12-96)Page 426.4
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) n A Resubmission 04/15/2011
SUBSTATIONS (Continued)
5. Show in columns (1),0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxilary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other part, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other part is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)Transformers Spare Total Capacity No.In Servce Transformers Type of Equipment Number of Units
(In MVa)
(f)(9)(h)(i)0)(k)
15 1 1
1 2
18 1 3
180 1 4
50 3 5
12 1 6
10 1 .7
10 1 8
6 1 9
10 3 10
10 1 11
12 1 12
36 2 13
23 3 14
50 3 15
22 2 16
42 2 17
18 1 18
18 1 19
20
18 1 21
1 22
14 2 23
18 1 24
15 2 25
15 1 26
10 1 4 27
10 3 1 28
5 2 29
10 1 30
2 3 31
3 1 32
10 1 33
12 1 34
15 1 35
12 1 36
33 2 37
10 1 38
18 1 39
18 1 40
FERC FORM NO.1 (ED. 12-96)Page 427.4
Name of Respondent This Report Is:Date of Report Year/Period of Report
Idaho Power Company (1) ~An Original (Mo, Da, Yr)End of 2010/Q4
(2) 0 A Resubmission 04/15/2011
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b). the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (t).
Une VOLTAGE (In MVa)
Name and Location of Substation Character of SubstationNo.Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 State distribution 69.00 13.00
2 Stoddard distribution 138.00 13.00
3 Strke Power Plant - attended transmission 138.00 13.80
4 Sugar distribution 138.00 35.00
5 Swan Falls - attended transmission 138.00 6.90
6 Taber distribution 46.00 13.00
7 Ten Mile distrbution 138.00 13.09
8 Terry distribution 138.00 13.09
9 Thousand Springs - attended transmission 46.00 7.20
10 Thousand Springs - attended trnsmission 7.00 2.40
11 Toponis distribution 138.00 33.00
12 Twin Falls distrbution 138.00 13.09
13 Twin Falls transmission 138.00 46.00 12.98
14 Twin Falls PP - attended transmission 138.00 7.20
15 Twin Falls PP - attended transmission 138.00 13.20
16 Upper Malad - attended transmission 45.00 7.20
17 Upper Salmon- attended trnsmission 138.00 7.20
18 Ustick distribution 138.00 13.00
19 Vallvue distribution 138.00 13.09
20 Victory distribution 138.00 13.00
21 Ware distrbution 69.00 13.00
22 Weiser distrbution 69.00 13.00
23 Weiser transmission 138.00 69.00 12.47
24 Wilder distribution 69.00 13.00
25 Wilis distribution 138.00 13.09
26 Wye distribution 138.00 13.00
27 Zilog distribution 138.00 13.09
28
29
30 The above are all State of Idaho
31
32 Montana:
33 Peterson transmission 230.00 69.00 13.20
34
35 Nevada:_""n""I",~,345.00 17.4037 ;ft;;ì:~ transmission 345.00 22.00
38 Wells transmission 138.00 69.00 13.00
39
40 Oregon:
FERC FORM NO.1 (ED. 12-96)Page 426.5
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) n A Resubmission 04/15/2011
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxilary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other part, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other part is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)Transformers Spare.Total Capacity No.In Service Transformers Type of Equipment Number of Units
(In MVa)
(f)(g)(h)(i)ü)(k)
33 2 1
15 1 2
83 3 3
20 2 4
18 1 5
5 1 6
24 1 7
42 3 8
8 1 9
3 1 10
18 1 11
44 2 12
33 2 13
9 1 14
72 1 15
8 1 16
36 4 17
44 2 18
18 1 19
24 1 1 20
12 1 1 21
20 2 22
25 1 23
10 1 24
18 1 25
56 3 26
24 1 27
28
29
30
31
32
30 3 1 33
34
35
315 1 36
300 1 1 37
20 3 1 38
39
40
FERC FORM NO.1 (ED. 12-96)Page 427.5
Name of Respondent This wort Is:Date of Report Year/Penod of Report
Idaho Power CompClny (1) X An Onginal (Mo, Da, Yr)End of 2010/Q4
(2) 0 A Resubmission 04/15/2011
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (t).
Une VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Pnmary Secondary Tertary
(a)(b)(c)(d)(e)_.."""'OS'O"500.00 24.002 transmission 230.00 7.203 transmission 24.00 7.204 Cairo distribution 69.00 13.00
5 Hells Canyon - attended transmission 230.00 13.80
6 Hells Canyon distnbution 69.00 0.50
7 Hines transmission 138.00 115.00 12.47
8 Malheur Butte distribution 69.00 34.50
9 Nyssa distribution 69.00 13.00
10 Ontano distnbution 138.00 13.00
11 Ontario transmission 138.00 69.00 12.47
12 Ontario transmission 230.00 138.00 13.80
13 Ontano transmission 138.00 69.00 12.98
14 Ontano transmission 138.00 69.00 13.09
15 Ore-Ida distnbution 69.00 13.00
16 Oxbow - attended trnsmission 138.00 69.00 13.00
17 Oxbow - attended transmission 230.00 13.80
18 Oxbow - attended transmission 230.00 138.00 13.80
19 Quart transmission 138.00 69.00 12.50
20 Quart transmission 230.00 138.00 13.00
21 Vale distnbution 69.00 13.00
22
23 Wyoming:_.."""'-"345.00 22.0025 transmission 345.00 230.00 34.50
26
27
28
29
30
31 Transformers-distnbution substations under 10,000
32 KVA 83 unattended.
33
34
35
36
37
38
39
40
FERC FORM NO.1 (ED. 12-96)Page 426.6
Name of Respondent This wort Is:Date of Report Year/Period of Report
Idaho Power Company (1) X An Original (Mo. Da, Yr)End of 2010/Q4
(2) nA Resubmission 04/15/2011
SUBSTATIONS (Continued)
5. Show in columns (I), U), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other part, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other part is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)Transformers Spare Total Capacity No.In Service Transformers Type of Equipment Number of Units
(In MVa)
(f)(g)(h)(i)ü)(k)
685 3 1
55 1 2
55 1 3
12 1 4
500 3 5
1 1 6
40 1 7
8 3 1 8
20 2 9
38 2 10
25 1 1 11
240 2 12
50 2 13
1 14
15 1 15
10 3 1 16
244 2 17
100 1 18
30 2 19
100 3 1 20
10 1 21
22
23
1122 2 24
1084 22 25
26
27
28
29
30
31
338 32
33
34
35
36
37
38
39
40
FERC FORM NO.1 (ED. 12-96)Page 427.6
Name of Respondent This Report is:Date of Report Year/Period of Repor
(1 ) ~ An Original (Mo, Da, Yr)Idaho Power Company (2)A Resubmission 04/15/2011 2010/Q4
FOOTNOTE DATA
Sc~erJ!!f!l'tlJl: 426.L_Line No.: 20~0Iußl-'lL~__________________
See note 5 Page 109.1.
SchediiJePage:426.4 - Line No.: 20--Column~---- --- - ~--------------~-- -----
S ee---Ñ at e- - 5~ on Pa-ge--I09--:----~-~-- -- ----------"-- ..~.- ... -----.----....-.-----.------.--~-~-~----
~(;heduli~J~_~iie: ~~§.I~=J.j!iiNo.:- 3~::Coiiijij¿~==:-=::-_: ------- -- - ---Jointly owned with Sierra Pacific Power Company, d/b/a NV Energy. Idaho Power has a 50%
share of ownership.
'SchediJ/fa:iage:-42ILiiNo.:37 Coiiiiim:. a---__--- ------- _.---------------------------------
Jointly owned with Sierra Pacific Power Compariy;---CfTSTal:'! Energy. Idaho Power has a 50%
share of ownership.
Schedule Page:426.6--Tliief.iiJ::1--Column: a ----------------:--:-~--------==___________
Jointlyowned with PortfandGeneraTElectric,--Power-Resources-coop-éJ:'-ati ve and BA Leasing
BCS, LLC. Idaho Power has a 10% share of the jointly owned capacity. 100% of the capacity~_r_ep~tE:_ci-"_____ ----------------~-------------------~-------------Schedule Page: 426.6 Line No.: 2 Column: a. . . . .. . '
Jointly -üwriedw:rEh Portland General Electr:-ic;-Power--Res-ources Cooperati ve and BA Leasing---
BCS, LLC. Idaho Power has a 10% share of the jointly owned capacity. 100% of the capacity
is reported.
Sc;hedii¡e~~e:~26.6_ Line No.: 3- -ciitiÎr¡a--=-=_:---------
Jointly owned with Portland General Electric, Power Resources Cooperative and BA Leasing
BCS, LLC. Idaho Power has a 10% share of the jointly owned capacity. 100% of the capacity
is reported.
iSchediiiêiiage: 426.6 Line No.-:24Cofiimn:-a-------
JOintly-owned with PacificCorp. Idaho Power--E21s-a 33.3% share of ownership.
~checliiiê'iiage:-426.6- Line No.: 25 Column:a----------
Jointly owned-wIth PacificCorp. Idaho Power- h21.5- a 33.3% share of ownership.
IFERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent
Idaho Power Company
Year/Period of Report
End of 2010/Q4
Line
No.
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2011
TRANSACTIONS WITH ASSOCIATED (AFFILIATED) COMPANIES
1. Report below the information called for concerning all non-power goods or services received from or provided to associated (affliated) companies.
2. The reporting threshold for reporting purposes is $250,000. The threshold applies to the annual amount biled to the respondent or biled to
an associated/affliated company for non-power goods and services. The good or service must be specific in nature. Respondents should not
attempt to include or aggregate amounts in a nonspecific category such as "general".
3. Where amounts biled to or received from the associated (affliated) company are based on an allocation process, explain in a footnote.
Name of Accunt
Assiciated/Affliated Charged orCompany Credited(b) (c)Descrption of the Non-Power Good or Service
(a)
1 Non-power Goods or Services Provided by Affliated
2
3
4
5
6
Amount
Charged or Credited
(d)---~~~~- ~-------~---~
7
8
9
10
11
12
13
14
15
16
17
18
19
20 Non-power Goods or Services Provided for Affilate
21 Managerial Expense
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
-~ ----~- --~---~~------ -~ - --~~--~
IDA 417420 467,652
FERC FORM NO.1 (New)
FERC FORM NO. 1.F (New)
Page 429
INDEX
December 31, ~
?ó'lï C.t/t4p;f i/~22
P¡y
~.~
ANNUAL REPORT
IDAHO SUPPLEMENT TO FERC FORM 1
MULTI-STATE ELECTRIC COMPANIES
Page
Number Title
1 Statement of Income for the Year
2 Taxes Allocated to Idaho
3 Notes and Accounts Receivable
3 Accumulated Provision for Uncollectible Accounts
4 Receivables from Associated Companies
5 Gain or loss on Disposition of Propert
6 Professional or Consultative Services
7-10 Electric Plant in Service
11 Electric Operating Revenues
12-15 Electric Operation and Maintenance Expenses
15 Number of Electric Department Employees
IDAHO SUPPLEMENT
THIS PAGE INTENTIONALLY LEFT BLANK
Idaho Power Company
STATE OF IDAHO. ALLOCATED
An Original
STATEMENT OF INCOME FOR THE YEAR
December 31,2010
1. Report amounts for accounts 412 and 413, Revenue and Expenses from Utility Plant Leased to Others, in another utility
column (i,k,m,o) in a similar manner to a utilty departent. Spread the amount(s) over lines 01 thru 24 as appropriate.
Include these amounts in columns (c) and (d) totals.
2. Report amounts in account 414, Other Utility Operating Income, in the same manner as accounts 412 and 413 above.
3. RepOrt data for lines 7, 9, and 10 for Natural Gas companies using accunts 404.1, 404.2, 404.3, 407.1, and 407.2.
4. Use page 122 for importnt notes regarding the state ment of income or any accunt thereof.
5. Give concise explanations concerning unsetted rate proceedings where a contingency exists such that refunds of a
material amount may need to be made to the utilty's customers or which may result in a material refund to the utilty
with respect to power or gas purchases. State for each year affected the gross revenues or costs to which the contingency
relates and the tax effects together with an explanation of retain such revenues or recover amounts paid with respect
to power and gas purchases.
6. Give concise explanations concerning significant amounts of any refunds made or received during the year.
Line
No.
Account
(a)
1 UTILITY OPERATING INCOME
2 Operating Revenues (400).......................................................................
3 Operating Expenses
4 Operation Expenses (401).....................................................................
5 Maintenance Expenses (402).................................................................
6 Depreciation Expense (403)...................................................................
7 Amort. & Depl. of Utilty Plant (404-405)................................................
8 Amort. of Utilty Plant Acq. Adj. (406).....................................................
9 Amort. of Propert Losses, Unrecovered Plant and
10 Regulatory Study Costs (407)..............................................................
11 Amort. of Conversion Expenses (407)...................................................
12 Regulatory Debits/Credits (407.3 & 407.4).............................................
13 Taxes Other Than Income Taxes (408.1)...............................................
14 Income Taxes - Federal (409.1).............................................................
15 - Other (409.1)..........................................................................
16 Provision for Deferred Income Taxes (410.1 & 411.1) Net. ...... ... ... ...
17 Investment Tax Credit Adj. - Net (411.4)............................................. ...
18 (Less) Gains from Disp. of Utilty Plant (411.6)......................................
19 Losses from Disp. of Utility Plant (411.7)...............................................
20 (Less) Gains from Disposition of Allowances (411.8).............................
21 Losses from Disposition of Allowances (411.9)......................................
22
23 TOTAL Utilty Operating Expenses (Enter Total of lines 4 thru 22).......
24
25 Net Utilty Operating Income (Enter Total of line 2 less 23)
26 (Carry forwrd to page 11, line 27)................................... ..................
(Ref.)
Page TOTAL
No.Current Year Previous Year
(b)(c)(d)
11 $978,237,919 $993,232,456
15 591,076,570 613,147,331
15 66,618,522 64,769,922
101,868,184 96,284,156
5,959,981 6,307,117
--
2 21,747,745 18,952,082
2 7,279,837 14,745,212
2 2,997,295 1,466,739
2 2,215,520 12,847,159
2 (1,423,437)223,185
798,340,218 828,742,902
$ 179,897,701 $ 164,489,555
IDAHO SUPPLEMENT Page 1
Idaho Power Company
STATE OF IDAHO. ALLOCATED
An Original December 31,2010
TAXES ALLOCATED TO IDAHO
Kind of Tax
Taxes Other Than Income Taxes:
Labor Related:
FiCA............................................................
FUTA...........................................................
State Unemployment.... ........ ........ ..............
Payroll Deduction & Loading......................
Total Labor Related.........................
Propert Taxes...............................................
Kilowatt-hour Tax...........................................
Licenses.........................................................
Regulatory Commission Fees. ... .......... ..........
Irrigation p~c..................................................
Total Taxes Other Than Income Taxes...........
Federal Income Taxes.....................................
State Income Taxes.........................................
Deferred Income Taxes...................................
Investment Tax Credit Adjustment - Net........
Total Taxes Allocated to Idaho........................
Taxes Charged
During Year
$ 11,743,213
113,385
1,044,675
(12,901 ,273)
o
18,331,150
1,34,580
4,053
1,837,184
230,778
21,747,745
7,279,837
2,997,295
2,215,520
(1 ,423,437)
$ 32,816,961
IDAHO SUPPLEMENT Page 2
STATE OF IDAHO - ALLOCATED
An OriginalIdaho Power Company December 31,2010
NOTES AND ACCOUNTS RECEIVABLE
Summary for Balance Sheet
Show separately by footnote the total amount of notes and accounts receivable
from directors, offcers, and employees included in Notes Receivable (Accunt
141) and Other Accounts Receivable (Accunt 143)
Line
Balance Balance
Beginning of End of
Year Year
(b)(c)
$636,667 $303,143
76,792,157 63,612,796
9,087,713 6,166,234
$86,516,536 $70,082,172
1,990,343 1,641,302
$84,526,193 $68,440,870
Accounts
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
(a)
Notes Receivable (Account 141 )..................... ................ ................. .............. ...............
Customer Accounts Receivable (Account 142)......... ... ........ ..... .......... .............. .............
Other Accounts Receivable (Account 143)....................................................................
(Disclose any capital stock subscription received)
Total........................................................................................................................
Less: Accumulated Provision for Uncollecble
Accounts-Cr. (Account 144).....................................................................................
Total, Less Accumulated Provision for
Uncollectible Accounts...........................................................................................
Notes Receivable - Accunt 141: (at 12-31-10)
Directors, offcers, and employees - ~ -
Other Accounts Receivable - Account 143: (at 12-31-10)
Directors, offcers, and employees - ~ -
ACCUMULATED PROVISION FOR UNCOLLECTIBLE ACCOUNTS - CR. (Accunt 144)
1. Report below the information called for concerning this accumulated provision.
2. Explain any importnt adjustments of subaccunts.
3. Entries with respect to offcers and employees shall not include items for utility services.
Mdse,Line Item Utilty Jobbing & Ofcers Other Total
Customers Contrct andNo. (a) Work Employees(b) (c) (d) (e) (f)
21
22 Bal. beginning of year $ 1,990,343 $
23 Provo for uncollectibles
24 for year.............................................
25 Accounts wrtten off............................
26 Coli. of accunts
27 wrtten off...................... ..... ............ ...
28 Adjustments (explain).........................
29
30
31
32 Balance end of year............................ $ 1,990,343 $
33
(349,041) $$$1,641,302
- $(349,041) $- $1,641,302
IDAHO SUPPLEMENT Page 3
STATE OF IDAHO. ALLOCATED
An OriginalIdaho Power Company December 31, 2010
RECEIVABLES FROM ASSOCIATED COMPANIES (Accunts 145, 146)
1. Report particulars of notes and accunts receivable frm associated companies at end of year.
2. Provide separate headings and totals for accunts 145, Notes Receivable frm Associated Companies, and 146,
Accunts Receivable from Associated Companies, in addition to a total for the combined accunts.
3. For notes receivable list each note separately and state purpose for which received. Show also in column
(a) date of note, date of maturity and interest rate.
4. If any note was received in satisfaction of an open accunt, state the period covered by such open accunt.
5. Include in column (f) interest recorded as income during the year, including interest on accounts and notes
held at any time during the year.
6. Give particulars of any notes pledged or discounted, also of any collateral held as guarantee of payment
of any note or accunt.
Line
Balance
Beginning
of Year
(b)
Interest
For Year
(f)
Partculars Totals for Year
Debits Credits
(c) (d)
Balance
End of Year
(e)No.(a)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
Accunt 145:
IERCO................................ $ 18,894,101 $ 37,465,907 $ 41,975,080 $ 14,384,928
Total Account 145.................18,894,101 37,465,907 41,975,080 14,384,928
Accunt 146:
IDACORP, Inc...................... $$124,133,570 $124,133,570 $
Total Account 146................... $- $124,133,570 $124,133,570 $
IDAHO SUPPLEMENT Page 4
STATE OF IDAHO. ALLOCATED
An OriginalIdaho Power Company December 31,2010
STATE OF IDAHO - TOTAL SYSTEM DATA
GAIN OR LOSS ON DISPOSITION OF PROPERTY (Accunt 421.1 and 421.2)
1. Give a brief description of propert creating the gain or loss. Include name of part acquiring the propert (when
acquired by another utilty or associated company) and the date transaction was completed. Identify propert
by type; Leased, Held for Future Use, or Nonutility.
2. Individual gains or losses relating to propert with an original cost of less than $50,000 may be grouped, with the
number of such trnsactions disclosed in column (a).
3. Give the date of Commission approval of journal entries in column (b), when approval is required. Where approval
is required but has not been received, give explanation following the item in column (a). (See account 102, Utilty
Plant Purchased or Sold.)
Line
Original Cost
of Related
Propert
(b)(e)
Date Journal
Entr Approved
(When Required)
(c)
Description of Propert Acct421.1 Acct421.2
No.(a)(d)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
Gain on disposition of
proper:
Cloverdale Substation
**Approval pending
$$122,7352,323
Total gain...................................................... $$122,7352,323
CJ Strke
** Approval pending
$$(3,155)3,834
Transmission Line #103
* Land purchased in 1942. Could not identify
original cost in asset records
(200)
Total loss............................................. .... . $$(3,355)3,834
IDAHO SUPPLEMENT Paqe 5
Idaho Power Company
STATE OF IDAHO. ALLOCATED
An Original December 31,2010
STATE OF IDAHO - TOTAL SYSTEM DATA
PROFESSIONAL OR CONSULTATIVE SERVICES -ITEMS $10,000 AND OVER
Line PAYEE SERVICE TYPE Amount
No.(a)(b)(c)
1 ACCENTIENT INC Computer Support Services $21,000
2 ADECCO ENGINEERING & TECHNICAL Staffng Servces 143,855
3 ADVERTISING CHECKING BUREAU IN Consulting Services 17,913
4 AERO-GRAPHICS Mapping Services 53,537
5 ALEKSANDER & ASSOCIATES PA Consulting Services 24,677
6 ANTHONY & ASSOCIATES, INC.Consulting Services 11,266
7 ATER, WYNNE LLP Legal Services 14,283
8 BARKER, ROSHOLT & SIMPSON LLP Legal Services 349,524
9 BERGLES LAW LLC Legal Service 61,526
10 BLANK & ASSOCIATES P.S.Legal Services 11,362
11 BLUE HERON CONSULTING, INC Consulting Services 87,432
12 BOISE STATE UNIVERSITY Environmental Services 15,850
13 BRASSEY, WETHRELL, & CRAWFORD,Legal Services 48,769
14 BRENNEMAN, JOHN Lobby Serices 73,319
15 BROWNSTEIN HYATT FARBER SCHREC Legal Services 535,047
16 CADMUS GROUP INC, THE Consulting Services 208,338
17 CASCADE ENERGY ENGINEERING INC Engineering Services 101,283
18 CH2M HILL Engineering Services 20,000
19 CLEAREDGE PARTNERS INC Computer Support Servces 119,250
20 COMSYS INFORMATION TECHNOLOGY Computer Support Servces 123,036
21 CSHQA Architect Services 26,049
22 DAVIS WRIGHT TREMAINE LLP Legal Services 414,306
23 DEAN & CARTER PLLC Legal Services 31,909
24 DELOITTE & TOUCHE LLP Accunting Sercices 511,015
25 DESERT RESEARCH INSTITUTE Environmental Services 42,657
26 DEWEY & LEBOEUF LLP Legal Services 2,711,407
27 DHIINC Environmental Services 22,274
28 EBERLE, BERLIN, KADING, TURNBO Legal Services 39,160
29 ECOANAL YSTS INC Environmental Services 22,160
30 ECOS IQ Consulting Services 93,522
31 ECOTOPE Architect Servce 20,524
32 ENGLAND CONSULTING Consulting Services 23,100
33 ERISA LAW GROUP PA Legal Services 20,997
34 ETALK CORPORATION Consulting Services 16,652
35 EUREKA SOFTWARE Computer Support Services 46,169
36 EVERGREEN CONSULTING GROUP, LL Consulting Services 23,340
37 FLUID MARKET STRATEGIES INC Marketing Services 17,262
38 GARTNER GROUP Computer Support Service 171,280
39 GIVENS PURSLEY LLP Legal Services 69,287
40 GJORDING & FOUSER, PLLC Legal Servce 17,120
41 GLAHE & ASSOCIATES INC Environmental Service 34,697
42 GLOBAL ENERGY PARTNERS LLC Environmental Service 73,685
43 HARDESTY, REBECCA Environmental Services 21,891
IDAHO SUPPLEMENT
Page 6
Idaho Power Company
STATE OF IDAHO - ALLOCATED
An Original December 31, 2010
STATE OF IDAHO - TOTAL SYSTEM DATA
PROFESSIONAL OR CONSUL TATIVE SERVICES - ITEMS $10,000 AND OVER
Line PAYEE SERVICE TYPE Amount
No.(a)(b)(c)
44 HERITAGE ENVIRONMENTAL CONSULT Environmental Services $59,281
45 HONEYWELL INTERNATIONAL INC Consulting Service 36,386
46 HYQUAL Environmental Servces 75,317
47 IBM BUSINESS CONTINUITY Computer Support Servces 23,424
48 IDAHO HELICOPTERS INC Transportation Services 15,553
49 INTER-FLUVE, INC.Environmental Services 17,811
50 IOWA INSTITUTE OF HYDRAULICS Engineering Services 96,950
51 JONES AND SWARTZ PLLC Legal Services 20,316
52 JUB ENGINEERS Engineering Services 29,489
53 KLARQUIST SPARKMAN LLP Legal Services 11,771
54 MAINLINE INFORMATION SYSTEMS Computer Support Services 93,965
55 MCCLURE ENGINEERING Engineering Services 12,000
56 MCDOWELL RACKNER & GIBSON PC Legal Services 698,509
57 MERRILL COMM.Consulting Services 52,000
58 MIRANDE, MICHAEL Legal Services 51,286
59 NIELSEN GROUP INC, THE Consulting Services 229,981
60 ORACLE CORPORATION Computer Support Services 69,176
61 PAINE HAMBLEN LLP Management Servces 316,320
62 PANTER, GREGORY W Legal Servce 18,000
63 PARR BROWN GEE & LOVELESS INC Legal Servces 45,796
64 PLANNEDSCAPE Consulting Services 34,485
65 PORTLAND ENERGY CONSERVATION Environmental Services 62,487
66 PROFESSIONAL TRAINING SYSTEMS Management Services 17,889
67 REYNOLDSON GROUP PLLC Legal Services 29,075
68 RIDDELL WILLIAMS P.S.Legal Services 24,979
69 S G S STATISTICAL SERVICES Consulting Servces 14,250
70 SALLADAY & DAVIS Legal Services 46,094
71 SCIENCE APPLICATIONS INTE Engineering Services 18,585
72 scon A WELLS, PHD, PE Engineering Servces 14,184
73 SHARP & SMITH INC.Engineering Services 124,266
74 SHOOK DORAN KOEHL LLP Legal Services 13,855
75 SOFTWARE AG INC Computer Support Services 117,000
76 SOS STAFFING SERVICES Staffng Services 11,703
77 SPATIAL NETWORK SOLUTIONS Admin Training Services 14,509
78 STAPLEY ENGINEERING, INC Engineering Services 49,157
79 STEPHAN, KVANVIG, STONE & TRAI Legal Servce 10,270
80 STEPTOE & JOHNSON LLP Legal Servces 485,177
81 STILLWATER SCIENCES Environmental Servces 45,996
82 STOEL RIVES LLP Legal Services 301,175
83 SULLIVAN & CROMWELL Manangement Sevices 160,260
84 TETRA TECH INC Environmental Servces 27,115
85 TROUT, JONES, GLEDHILL, FUHRMA Legal Services 11,630
Page6A
IDAHO SUPPLEMENT
Idaho Power Company
STATE OF IDAHO - ALLOCATED
An Original December 31,2010
STATE OF IDAHO - TOTAL SYSTEM DATA
PROFESSIONAL OR CONSULTATIVE SERVICES - ITEMS $10,000 AND OVER
Line PAYEE SERVICE TYPE Amount
No.(a)(b)(c)
86 UNIVERSITY OF IDAHO Environmental Services $415,832
87 UTAH STATE UNIVERSITY Environmental Services 32,500
88 WEATHER MODIFICATION INC Cloud Seeding Services 343,718
89 XTENSIBLE SOLUTIONS, INC Consulting Services 89,815
90 YTURRI& ROSE& BURNHAM& BENTZ Legal Servces 26,735
TOTAL 11,027,799
Page6B
IDAHO SUPPLEMENT
Idaho Power Company
STATE OF IDAHO. ALLOCATED
An Original December 31,2010
PROFESSIONAL OR CONSULTATIVE SERVICES
ITEMS $5,000 OR MORE BUT LESS THAN $10,000
Line PREDOMINANT
No.PAYEE NATURE OF SERVICE AMOUNT
1 ATREEHOUSE Computer/Pnnter Supplies $9,087
2 CGI TECHNOLOGIES AND SOLUTIONS Computer Support Servces 8,251
3 COLLEGE OF IDAHO Environmental Services 6,500
4 CONNOR CLAIMS SPECIALISTS Insurance Services 6,269
5 EVANS KEANE Legal Services 8,987
6 FALTER PHD, C. MICHAEL Environmental Services 6,400
7 FEHRN, BRIAN Meterologist Services 7,900
8 FIRE CAUSE ANALYSIS Consulting Services 7,396
9 GLOBAL ENERGY Consulting Servces 7,951
10 JIM GRAY CONSULTANTS LLC Consulting Services 7,731
11 LEVIN STRATEGIC RESOURCES LLC Lobbyist Servces 6,000
12 MONTANA STATE UNIVERSITY Environmental Servces 8,600
13 MOORE INFORMATION INC Consulting Servces 9,450
14 MUSGROVE ENGINEERING PA Engineenng Servces 7,040
15 NORTHWEST NATURAL RESOURCE GRO Environmental Services 5,975
16 OFFICE EQUIPTMENT COMPANY Offce Equipment Services 7,715
17 REGULUS INTEGRATED SOLUTIONS L Consulting Services 6,438
18 RIPLEY, LARRY D Legal Service 7,725
19 RIVERSIDE TECHNOLOGY INC Management Services 8,073
20 TREASURE VALLEY LEGAL SERVICES Legal Services 8,009
21 VAN WINKLE ENVIRONMENTAL CONSU Environmental Services 6,000
22 WALDNER LAW OFFICES LLC Legal Services 5,880
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
TOTAL 163,377
IDAHO SUPPLEMENT
Page 6C
Idaho Power Company
STATE OF IDAHO. ALLOCATED
An Original Decmber 31,2010
ELECTRIC PLANT IN SERVICE (Accounts 101,102,103 and 106)
1. Report below the original cost of electric plant in service accrding to the prescbe accunts.
2. In addition to Account 101, Electric Plant in Service (Classifed), this page and the next include Accunt 102, Electrc Plant
Purchased or Sold; Account 103, Experimental Electric Plant Unclassified; and Accunt 106, Completed Constrtion
Not Classifed - Electric.
3. Include in column (c) or (d), as appropriate, corrections of additons and retirements for the current or preceing year.
4. Enclose in parentheses credit adjustments of plant accunts to indicate the negative effect of such accounts.
5. Classify Account 106 according to prescribed accounts, on an estimated basis if necessry, and include the entries in
column (c) . Also to be included in column (c) are entries for reversals of tentative distributions of prior year reported in
column (b). Likewise, if the respondent has a significant amount of plant retirements the end of the year, include in
column (d) a tentative distribution of such retirements, on an estimated basis, with appropriate contra entry to the accunt
for accumulated depreciation provision. Include also in column (d) reversals of tentative distributions of prior year of un-
classified retirements. Attach supplemental statement showing the accunt distributions of these tentative classifications in
columns (c) and (d), including the reversals of the prior years tentative account distributions of these amounts. Careful ob-
servance of the above instructions and the texts of Accounts 101 and 106 will avoid serious omissions of the reported amount
of respondent's plant actually in service at end of year.
Line
AccountNo. (a)
1 1. Lt: PLAN I
2 (301) Organization................................................................... ................................
3 (302) Franchises and Consents............. ... .......... .......... ...... .......... ......... ... ....... .... ....
4 (303) Miscellaneous Intangible Plant.......................................................................
5 TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4)....,...................................6 2. PRODUCTION PLANT
7 A. Steam Production Plant
8 (310) Land and Land Rights....................................................................................
9 (311) Structures and Improvements........................................................................
10 (312) Boiler Plant Equipment.................................................................................
11 (313) Engines and Engine Driven Generators.........................................................
12 (314) Turbogenerator Units.....................................................................................
13 (315) Accssory Electric Equipment.......................................................................
14 (316) Misc. Power Plant Equipment.......................................................................
15 (317) Asset Retirement Costs for Steam Production............... ... ... ...... ...,..........
16 TOTAL Steam Production Plant (Enter Total of lines 8 thru 15)..............................17 B. Nuclear Production Plant
18 (320) Land and Land Rights............ ........ ....... ..... ............. ........ ............. ......... .........
19 (321) Structures and Improvements........................................................................
20 (322) Reactor Plant Equipment............................................. .......... ......................
21 (323) Turbogenerator Units..................... ...................... ..........................................
22 (324) Accssory Electric Equipment.......................................................................
23 (325) Misc. Power Plant Equipment.. ........ ........................... .......... ............. ...........
24 (326) Asset Retirement Costs for Nuclear Production... ... ................. .................
25 TOTAL Nuclear Production Plant (Enter Total of lines 17 thru 24)..........................26 C. Hydraulic Production Plant
27 (330) Land and Land Rights... ..... ............ ............ ....... ...... .............. ........... ... ...........
28
29 (332) Reservoirs, Dams, and Waterwys...................................... ..........................
30 (333) Water Wheels, Turbines, and Generators......................................................
31 (334) Accsory Electric Equipment......................................................................
32 (335) Misc. Power Plant Equipment.......................................... .............................
33 (336) Roads, Railroads, and Bridges.................................. ........... ..........................
34 (337) Asset Retirement Costs for Hydraulic Production......................................
35 TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34)........................36 D. Other Production Plant
37 (340) Land and Land Rights............. ..................... ........................... ...... .................
38 (341) Structures and Improvements................................. ..................... .... ..... ...... ...
39 (342) Fuel Holders, Proucts and Accessories........................................................
40 (343) Prime Movers..:..............................................................................................
41 (344) Generators.....................................................................................................
42 (345) Accessory Electrc Equipment.............. ... ........................ ......................... ......
43 (346) Misc Power Plant Equipment................................... .....................................
page 7
IDAHO SUPPLEMENT
ljalance at
Beginning of year
(b)
Additions
(c)
$ (42,600)
20,610,043
32,188,432
5":,(00,0("
3,639,403
6óU,ln1,óW
Idaho Power Company
STATE OF IDAHO - ALLOCATED
An Original December 31, 2010
ELECTRIC PLANT IN SERVICE (Accunts 101,102,103 and 106) (Continued)
Show in column (f) reclassifcations or transfers wihin utility plant accunts. Include also in column
(f) the additions or reductions of primary account classifcations ansing from distnbution of amounts
initially recorded in Account 102. In showing the clearance of Accunt 102, include in column (e) the
amounts with respect to accumulated provision for depreciation, acquisition adjustments, etc., and show
in column (f) only the offset to the debits or credits distnbuted in column (f) to pnmary accnt classifications.
For Account 399, state the nature and use of plant included in this account and if substantial in amount
submit a supplementary statement showing subaccount classifcation of such plant conforming to the
requirements of these pages.
For each amount compnsing the reported balance and changes in Accunt 102, state the propert purchased
or sold, name of vendor or purchaser, and date of transaction. If proposed joumal entnes have been fied
with the Commission as required by the Uniform System of Accunts, give also date of such fiing.
Ijaiance at Line
Retirements Adjustments Transfers End of Year
(d)(e)(f)(g)No.
1
$5,295 (301)2
22,09,463 (302)3
30,622,473 (303)4
ó2,f24,2JU 5
6
7
(310)8
(311)9
(312)10
(313)11
(314)12
(315)13
(316)14
3,914,571 (317)15
875,741,735 16
17
(320)18
(321)19
(322)20
(323)21
(324)22
(325)23
(326)24
25
26
(330)27
(331)28
(332)29
(333)30
(334)31
(335)32
(336)33
(337)34
oo7,6J4,4tJ 35
36
(340)37
(341)38
(342)39
(343)40
(344)41
(345)42
(345)43
pa e8g
IDAHO SUPPLEMENT
Idaho Powr Company
STATE OF IDAHO - ALLOCATED
An Original Decmber 31, 2010
Line
ELECTRIC PLANT IN SERVICE (Accunts 101, 102, 103 and 106) (Continued)
AccountNo. (a)
44 1(;:4tl) MISC. t-ower t-iant t:quipment........................................................................
45 TOTAL Other Production Plant (Enter Total of lines 37 thru 44)..... ......... ... ..........
46 TOTAL Production Plant (Enter Total of lines 16, 25, 35, and 45).........................47 3. TRANSMISSION PLANT
48 (350) Land and Land Rights.....................................................................................
49 (352) Structures and Improvements............................. ................. ...........................
50 (353) Station Equipment.............. .............................................................................
51 (354) Towers and Fixtures........................................................................................
52 (355) Poles and Fixtures........ ..... .......... .............. ... ........... ..... ..... ... ............... ... ..... ...
53 (356) Overhead Conductors and Devices....... .............. .................... ........ ................
54 (357) Underground Conduit. ........ .......... .......... ................................ ...... ............ .......
55 (358) Underground Conductors and Devices...... ............... ...... ..................... ............
56 (359) Roads and Trails....... ......................................................................................
57 (359.1) Ast Retirement Costs for Transmission Plant..... ... ......... ....................
58 TOTAL Transmission Plant (Enter Total of lines 48 thru 57).................................59 4. DISTRIBUTION PLANT
60 (360) Land and Land Rights..... ...... ... ......... .... ............ ............ ... ....... ..... ... ... ...... .......
61 (361) Structures and Improvements.........................................................................
62 (362) Station Equipment... ..... .... ......... .... ...... .... ............. ...... .......... .... ........ ........ .......
63 (363) Storage Battery Equipment. ....... ... .... ...... ... ........ ........... ... ........... ............ ......
64 (364) Poles, Towers, and Fixtures............................................................................
65 (365) Overhead Conductors and Devices....... ..... ...... ........... ........ .......... .......... ........
66 (366) Underground Conduit.... ........... ............... ..... ...... ........... ....... ...... .......... ........ ...
67 (367) Underground Conductors and Devices.... ....... ....... ...... .......... ...... ............. ... ....
68 (368) Line Transformers...........................................................................................
69 (369) Services.... ............. .... ...... ....... ............... ......... ........ ....... .... .... ... ............... .......
70 (370) Meters.... ................. ..... ......................... ........ ..... ...... .... ..... .... ..... .......... ....... ....
71 (371) Installations on Customer Premises................................................................
72 (372) Leased Propert on Customer Premises. ....... ....... .... ............ ........ ..... .............
73 (373) Street Lighting and Signal Systems...... ...... .......... ..... ......... ......... ......... ....... ....
74 (374) Asset Retirement Costs for Distribution Plant. ... ...................................
75 TOTAL Distribution Plant (Enter Total of lines 60 thru 74)....................................76 5. GENERAL PLANT
77 (389) Land and Land Rights..................,..................................................................
78 (390) Strctures and Improvements...... ... ...... ........ ...... ....... ....... .... ........ ....... ...........
79 (391) Ofce Furniture and Equipment.....................................................................
80 (392) Transporttion Equipment...............................................................................
81 (393) Stores Equipment..........................................................................................
82 (394) Tools, Shop, and Garage Equipment............................................................
83 (395) Laboratory Equipment....... ............ ... ... ....... .......... ............... .... ..... ..... ......... .....
84 (396) Power Operated Equipment...........................................................................
85 (397) Communication Equipment. ................... ............. ... ............ ........ ...... ... ....... ...
86 (398) Miscllaneous Equipment........................................................;......................
87 SUBTOTAL (Enter Total of lines 77 thru 86).........................................................
88 (399) Other Tangible Propert..................................................................................
89 (399.1) Asset Retirement Costs for General Plant.......... ...... .......................
90 TOTAL General Plant (Enter Total of lines 87, 88 and 89)...................................
91 TOTAL (Acunts 101 and 106).....................................................................
92 (102) Electric Plant Purchased ................................................................................
93 (Less) (102) Electric Plant Sold................................................................................
94 (103) Experimental Plant Unclassified......................................................................
95
96 TOTAL Electric Plant in Service...... .............. ........... .............. .......... ....................
I"age II
IDAHO SUPPLEMENT
tsaiance at
Beginning of year
(b)
Additions
(c)
:I 163,688,832.
1,67tl,lS14,UZtl
26,355,337
36,874,135
259,189,976
118,781,110
78,699,437
130,470,816
259,091
ö:lU,IUll,\ll
4,464,403
25,428,370
171,224,978
198,384,439
112,606,744
47,630,314
183,885,941
365,533,296
53,584,402
76,159,662
2,428,221
4,035,560
1,Z45,366,330
9,965,131
70,985,209
37,805,449
54,565,482
1,232,339
4,861,786
10,696,887
8,556,954
25,366,534
3,912,553
2Zf ,ll,;:Z;:
ZU,ll4lS,;:Z;:
3,853,514,454
:¡ ;:,lS;:,:l14,454
Idaho Power Company
STATE OF IDAHO. ALLOCATED
An Original Decmber 31,2010
ELECTRIC PLANT IN SERVICE (Accunts 101,102,103 and 106) (Continued)
tsaiance at Line
Retirements Adjustments Transfers End of Year
(d)(e)(f)(9)No.
(346)44
$ 166,775,956 45
1,f1U,152,1b4 46
47
29,203,182 (350)48
47,523,329 (352)49
300,05,738 (353)50
123,38,005 (354)51
86,608,519 (355)52
144,200,672 (356)53
(357)54
(358).55
271,410 (359)56
(359.1)57
7 58
59
4,552,220 (360)60
28,289,519 (361)61
175,260,257 (362)62
(363)63
208,275,965 (364)64
112,894,031 (365)65
47,510,380 (366)66
188,247,935 (367)67
377,055,642 (368)68
54,375,115 (369)69
92,208,012 (370)70
2,517,879 (371)71
(372)72
4,156,85 (373)73
(374)74
1,295,343,809 75
76
10,327,475 (389)77
71,746,675 (390)78
36,556,870 (391)79
56,593,719 (392)80
1,354,873 (393)81
5,168,975 (394)82
11,091,499 (395)83
9,211,910 (396)84
27,122,872 (397)85
4,421,669 (398)86
2;j;j,óll,óM 87
(399)88
(399.1)89
2;J;J,5l:,5;J7 90
:,586 91
(1U2)92
(102)93
(371)94
95
$ ,,586 96
Pa e 109
IDAHO SUPPLEMENT
Idaho Power Company
STATE OF IDAHO. ALLOCATED
An Original December 31, 2010
ELECTRIC OPERATING REVENUES (Accunt 400)
1. Report below operating revenues for each prescribed account, and manufactured gas revenues in total.
2. Report number of customers, columns (f) and (g), on the basis of meters, in addition to the number of flat rate
accunts; except that where separate meter readings are added for billng purposes, one customer should be counted
for each group of meters added. The average number of customers means the average of twelve figures at the close
of each month.
3. If previous year (columns (c), (e) and (g), are not derived from previously reported figures, explain any
inconsistencies in a footnote.
OPERATING REVENUES
Amount for Amount for
No.Current Year Previous Year
(a)(b)(c)
1 Sales of Electrcity
2 (440) Residential Sales........................................................$385,897,031 $396,249,589
3 (442) Commercial and Industral Sales
4 Small (or Commercial)(See Instr. 4) (1).............................325,261,915 326,270,298
5 Large (or Industrial)(See Instr. 4) (2)..................................126,530,113 130,739,702
6 (444) Public Street and Highway Lighting............................3,152,822 3,115,326
7 (445) Other Sales to Public Authorities................................
8 (446) Sales to Railroads and Railways.................................
9 (448) Interdepartmental Sales..............................................
10 TOTAL Sales to Ultimate Consumers.............................840,841,882 *856,374,915
11 (447) Sales for Resale - Opportunity....Non-Firm Only........71,503,889 86,951,072
12 TOTAL Sales of Electricity..............................................912,345,771 943,325,987
13 (449) Provision for Rate Refunds........................................(10,624,673)(2,333,063)
14 TOTAL Revenue Net of Provision for Refunds.......... ......901,721,098 940,992,924
15 Other Operating Revenues
16 (450) Forfeited Discounts.....................................................
17 (451) Miscellaneous Service Revenues...............................3,455,502 3,738,436
18 (453) Sales of Water and Water Power...............................
19 (454) Rent from Electric Propert.........................................18,807,627 16.297,224
20 (455) Interdepartental Rents.............................................
21 (456) Other Electric Revenues.............................................54,253,693 32,203,871
22
23
24
25 TOTAL Other Operating Revenues.................................76,516,821 52,239,531
26 TOTAL Electric Operating Revenues. ................ .......... ...$978,237,919 $993,232,456
(1) Commercial and Industral sales - Small - under 1,000 KW and includes all irrgation customers.
(2) Commercial and Industrial sales - Large - 1,000 KW and over.
Page 11
IDAHO SUPPLEMENT
Idaho Power Company
STATE OF IDAHO - ALLOCATED
An Original December 31,2010
ELECTRIC OPERATING REVENUES (Accunt 400) (Continued)
4. Commercial and Industral Sales, Accunt 442, may be classified according to the basis of classification
(Small or Commercial, and Large or Industrial) regularly used by the respondent if such basis of classification
is not generally greater than 1000 Kw of demand. (See Account 442 of the Uniform System of Accunts. Explain
5. See page 108, Important Changes Dunng Year, for importnt new terntory added and important rate increases or
decreases.
6. For lines 2, 4, 5, and 6, see page 304 for amounts relating to unbiled revenue by accunts.
7. Include unmetered sales. Provide details of such sales in a footnote.
KILOWATT HOURS SOLD AVERAGE NUMBER OF CUSTOMERS PER MONTH
Amount for
Current Year
(d) .
Amount for
Previous Year
Amount for
Current Year
Number for
Previous Year
(e)(f)(g)
Line
No.
4,777,821,745 394,132 391,7595,094,579,185
5,248,080,006
2,828,443,711
29,217,485
76,563
118
1,438
76,494
120
1,353
5,260,695,289
2,889,807,183
30,137,604
12,883,562,947 **
1,883,300,132
14,766,863,079
472,251 469,72613,275,219,261
2,689,972,558
15,965,191,819
N/A N/A
472,251 469,726
. Includes ($3,167,019) unbiled revenues.
.. Includes (25,129,713) KWH relating to unbiled revenues.
Lines 11 through 21 are on an "allocated" basis.
1
2
3
4
5
6
7
8
9
10
11
12
13
Page 11a
IDAHO SUPPLEMENT
Idaho Power Company
STATE OF IDAHO - ALLOCATED
An Original December 31,2010
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
It me amount tor previous year is not denved trom previousiy reported tigures, expiain in tootnotes.
ine 1\mOUmTOr AmoumTor
No.Account Current Year Previous Year
(a)(0)(C)
1 1. POWER PRODUCTION EXPENSES
¿1\. ;:,¡eam i- ower ~enera(lon
3 Operation
4 (500) Operation Supervision and Engineering........... ..............................................................$1,801,415 $1,730,026
5 (501) Fuel...............................................................................................................................139,614,702 123,530,408
6 (502) Steam Expenses.......................... ...................................................... ......... ...................6,972,393 . 7,051,991
7 (503) Steam from Other Sources............................................................................................
8 (Less) (504) Steam Transferred-Cr.........................................................................................
9 (505) Electric Expenses.................................. ........................................................................2,033,682 2,436,169
10 (506) Miscellaneous Steam Power Expenses..........................................................................9,345,596 7,732,363
11 (507) Rents.......................................................................................................... ...................218,733 490,668
12 (509) Allowances.....................................................................................................................
13 TOTAL Operation (Enter Total of lines 4 thru 12).. .... ... ............................ ... ..... ........... ......151:,l:l:,5Li 142,971,625
14 Maintenance
15 (510) Maintenance Supervision and Engineering....................................................................2,186,957 1,975,511
16 (511) Maintenance of Structures........................................................................... ...................295,097 464,737
17 (512) Maintenance of Boiler Plant...........................................................................................15,268,185 12,971,894
18 (513) Maintenance of Electric Plant.......................................................................................3,720,438 3,410,225
19 (514) Miscellaneous Steam Plant............................................................................................3,579,816 4,422,214
20 TOTAL Maintenance (Enter Total of Lines 15 thru 19). .............. ............. .... ....... ......... ......L5,u5u,41:;j 23,244,580
21 TOTAL Power Production Expenses-Steam Power (Enter Total of lines 13 and 20).........iö5,u;J( ,u1;J 166,216,205
22 B.Nuclear Power Generation
23 Operation
24 (517) Operation Supervision and Engineering.........................................................................
25 (518) FueL.............................................................................................................................
26 (519) Coolants and Water.......................................................................................................
27 (520) Steam Expenses......................................... ................................................ ...................
28 (521) Steam from Other Sources.......................................................................... ..................
29 (Less) (522) Steam Transferred-Cr.........................................................................................
30 (523) Electric Expenses..........................................................................................................
31 (524) Miscellaneous Nuclear Power Expenses........................................................................
32 (525) Rents.............................................................................................................................
33 TOTAL Operation (Enter Total of lines 24 thru 32)...........................................................
34 Maintenance
35 (528) Maintenance Supervision and Engineering.......................... ..... .................. ...................
36 (529) Maintenance of Structures........................................................ .....................................
37 (530) Maintenance of Reactor Plant Equipment....................................................................
38 (531) Maintenance of Electrc Plant..... ....................................................................................
39 (532) Maintenance of Miscellaneous Nuclear Plant...............................................................
40
41 TOTAL Power Production Expenses-Nuclear Power (Enter Total of lines 33 and 40)
42 C. Hydraulic Power Generation
43 Operation
44 (535) Operation Supervision and Engineering.............................. ...........................................5,113,329 4,996,334
45 (536) Water for Power............................................................................................................,6,98,811 6,839,199
46 (537) Hydraulic Expenses............................... ............................................... .........................10,179,310 9,622,038
47 (538) Electric Expenses..........................................................................................................1,492,017 1,400,051
48 (539) Miscellaneous Hydraulic Power Generation Expenses...................................................2,762,087 2,561,153
49 (540) Rents.............................................................................................................................387,675 359,232
50 TOTAL Operation (Enter Total of lines 44 thru 49)...........................................................26,919,229 25,778,007
Page 12
IDAHO SUPPLEMENT
Idaho Power Company
STATE OF IDAHO. ALLOCATED
An Original December 31, 2010
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
It the amount tor previous year IS not åeriveå trom previously reporteå tigures, expiain in tootnotes.
ii.ine
No.Accunt
(a)
l\moum TOr
Current Year
(0)
AIoum Tor
Previous Year
(C)
51 C. Hydraulic Powèr Generation (Continued)
52 Maintenance
53 (541) Maintenance Supervision and Engineering....................................................................
54 (542) Maintenance of Structures............................................................... ..............................
55 (543) Maintenance of Reservoirs, Dams, and Waterwys.......................................................
56 (544) Maintenance of Electric Plant.........................................................................................
57 (545) Maintenance of Miscellaneous Hydraulic Plant............................................................
58 TOTAL Maintenance (Enter Total of lines 53 thru 57).........................................................
59 TOTAL Power Production Expenses-Hydraulic Power (Enter Total of lines 50 and 58)
60 D. Other Power Generation
61 Operation
62 (546) Operation Supervision and Engineering.........................................................................
63 (547) Fuel............................................................................................................... ................
64 (548) Generation Expenses....................................................................................................
65 (549) Miscellaneous Other Power Generation Expenses.........................................................
66 (550) Rents.............................................................................................................................
67 TOTAL Operation (Enter Total of lines 62 thru 66).............................................................
68 Maintenance
69 (551) Maintenance Supervision and Engineering....................................................................
70 (552) Maintenance of Structures.............................................................................................
71 (553) Maintenance of Generating and Electric Plant.............................................................
72 (554) Maintenance of Miscellaneous Other Power Generation Plant.....................................
73 TOTAL Maintenance (Enter Total of lines 69 thru 72)........................................................
74 TOTAL Power Production Expenses-Other Power (Enter Total of lines 67 and 73)............
75 E. Other Power Supply Expenses
76 (555) Purchased Power...........................................................................................................
77 (556) System Control and Load Dispatching...........................................................................
78 (557) Other Expenses.............................................................................................................
79 TOTAL Other Powr Supply Expenses (Enter Total of lines 76 thru 78)... ... ...... ..... ............
80 TOTAL Power Production Expenses (Enter Total of lines 21, 41, 59, 74, and 79)..............
81 2. TRANSMISSION EXPENSES
82 Operation
83 (560) Operation Supervision and Engineering.........................................................................
84 (561) Load Dispatching...........................................................................................................
85 (562) Station Expenses........ ...................................................................................................
86 (563) Overhead Line Expenses...............................................................................................
87 (564) Underground Line Expenses..........................................................................................
88 (565) Transmission of Electricity by Others.............................................................................
89 (566) Miscellaneous Transmission Expenses..........................................................................
90 (567) Rents...... .......................................................................................................................
91 TOTAL Operation (Enter Total of lines 83 thru 90).................................................... .... .....
92 Maintenance
93 (568) Maintenance Supervision and Engineering....................................................................
94 (569) Maintenance of Structures.............................................................................................
95 (570) Maintenance of Station Equipment.................. ............................................................
96 (571) Maintenance of Overhead Lines....................................................................................
97 (572) Maintenance of Underground Lines.................................................................. .............
98 (573) Maintenance of Miscellaneous Transmission Plant............................. .........................
99 TOTAL Maintenance (Enter Total of lines 93 thru 98).......... ............ ........... ...... ..... .............
100 TOTAL Transmission Expenses (Enter Total of lines 91 and 99)........................................
101 3. DISTRIBUTION EXPENSES
102 Operation
103 (580) Operation Supervision and Engineering.........................................................................
$1,877,060 $1,975,236
1,102,320 1,331,517
1,305,050 1,079,628
3,026,857 2,819,107
2,889,665 2,832,668
10,038,157
37,1;¿u,1ö1 35,816,164
313,261 331,668
12,111,625 18,336,546
427,597 385,488
429,404 305,054
0 °
13,281,ö87 19,358,755
41 °
173,642 185,036
112,955 497,807
1,027,549 1,630,541
1,314,187 2,313,384
14,5l:0,U74 21,672,139
131,000,128 152,316,715
153 12,528
51,884,430 73,149,445
182,öö4,71u ,,
41l:,0~7,l:7ö 449,183,196
2,559,146 2,146,091
2,816,811 2,232,972
1,706,312 1,658,377
562,633 763,563
5,623,961 6,287,468
288,013 327,409
1,341,727 1,324,828
14,öl:ö,oU;¿14,740,708
462,021 499,815
357,888 327,684
2,96,318 2,556,220
2,370,823 2,471,315
(34)32
0,151,U1:i 5,855,065
21,049,617 20,595,774
3,494,071 3,141,623
Page 13
IDAHO SUPPLEMENT
Idaho Power Company
STATE OF IDAHO - ALLOCATED
An Original December 31, '2010
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
It tne amount tor previous year is not aenvea trom previousiy reportea tigures, expiain in tootnotes.
..ine l\mOUmTOr l\mOUm Tor
No.Account Currnt Year Preious Year
(aJ (DJ (cJ
104 3. DISTRIBUTION EXPENSES (Continued)
105 (581) Load Dispatching........................................................................... ................................$3,280,881 $3,014,735
106 (582) Station Expenses...........................................................................................................1,226,496 1,072,819
107 (583) Overhead Line Expenses...............................................................................................2,818,499 3,169,511
108 (584) Underground Line Expenses..........................................................................................1,762,795 1,885,378
109 (585) Street Lighting and Signal System Expenses.................................................................75,649 128,093
110 (586) Meter Expenses.............................................................................................................4,065,420 4,309,928
111 (587) Customer Installations Expenses...................................................................................1,392,551 1,217,628
112 (588) Miscellaneous Distribution Expenses.............................................................................4,708,623 4,682,137
113 (589) Rents.............................................................................................................................414,753 288,975
114 TOTAL Operation (Enter Total of lines 103 thru 113).................. ...... ....... ............. ..... .......,££,910,827
115 Maintenance
116 (590) Maintenance Supervision and Engineering....................................................................350,009 290,469
117 (591) Maintenance of Structures.............................................................................................(10,923)23,673
118 (592) Maintenance of Station Equipment................................................................................3,623,115 3,166,911
119 (593) Maintenance of Overhead Lines....................................................................................13,302,525 13,336,846
120 (594) Maintenance of Underground Lines...............................................................................986,863 1,066,017
121 (595) Maintenance of Line Transformers.................................................................................407,395 373,749
122 (596) Maintenance of Street Lighting and Signal Systems......................................................559,210 476,614
123 (597) Maintenance of Meters..................................................................................................674,552 685,447
124 (598) Maintenance of Miscellaneous Distribution Plant.........................................................125,929 244,352
125 TOTAL Maintenance (Enter Total of lines 116 thru 124). ..... .... .......... ........... ...... ........... .....20,018,674 7
126 TOTAL Distribution Expenses (Enter Total of lines 114 and 125).......................................43,258,412 4£,574,904
127 4. CUSTOMER ACCOUNTS EXPENSES
128 Operation
129 (901) Supervision................. ............... ... ............ ........ ............ ...... ..... ............... ............ .... .......392,236 357,284
130 (902) Meter Reading Expenses...............................................................................................3,753,549 5,092,915
131 (903) Customer Recrds and Collection Expenses.................................................................12,502,606 12,604,114
132 (904) Uncollectible Accounts...................................................................................................4,479,964 5,092,669
133 (905) Miscellaneous Customer Accunts Expenses................................................................327 533
134 TOTAL Customer Accunts Expenses (Enter Total of lines 129 thru 133)..........................21,128,682 23,147,511)
135 5. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
136 Operation
137 (907) Supervision.................................................................................................. ..................339,665 257,106
138 (908) Customer Assistance Expenses.... ........... ....................... ............. ......... .........................50,028.521 40,542,279
139 (909) Informational and Instructional Expenses.... ........ ............ ... .......... .......... ........................30,338 15,511
140 (910) Miscellaneous Customer Service and Informational Expenses......................................831,888 836,024
141 TOTAL Cust. Service and Informational Expenses (Enter Total of lines 137 thru 140)...... ...51,230,413 41,650,920
142 6. SALES EXPENSES
143 Operation
144 (911) Supervision.......................... ........................................ ..................................................
145 (912) Demonstrating and Sellng Expnses.............................................................................
146 (913) Advertising Expenses....................................................................................................
147 (916) Miscellaneous Sales Exenses......................................................................................
148 TOTAL Sales Exnses (Enter Total of lines 144 thru 147)................................................
149 7. ADMINISTRATIVE AND GENERAL EXPENSES
150 Operation
151 (920) Administrative and General Salaries............................. .................................................60,00,898 57,849,175
152 (921) Offce Supplies and Expenses.......................................................................................12,833,065 11,682,289
153 (Less) (922) Administrative Expenses Transferred-Credit......................................................(26,204,991 )(26,136,870)
Page 14
IDAHO SUPPLEMENT
Idaho Power Company
STATE OF IDAHO - ALLOCATED
An Original December 31,2010
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
It tne amount tor previous year is not oenvea trom previousiy reporteo tigures, expiain in tootnotes.
ine l\mouni TOr Amoumror
No.Accunt Current Year Previous Year
(a)(b)(C)
154 7. ADMINISTRATIVE AND GENERAL EXPENSES (Continued)
155 (923) Outside Services Employed...........................................................................................$6,797,014 $7,093,497
156 (924) Propert Insurance.........................................................................................................3,112,351 3,046,423
157 (925) Injuries and Damages....... .......................... ....... .... ................. ....... .... .... .................... ....5,343,230 6,381,755
158 (926) Employee Pensions and Benefits... ... ....... ............... ....... ........ ............. .............. ..... .... ....28,308,455 29,122,006
159 (927) Franchise Requirements................ ................................................................................2,549 3,196
160 (928) Regulatory Commission Expenses............ ........ .... ... ..... ......... ..... ........... ......... ...... ... ......3,293,914 4,579,316
161 (929) Duplicate Charges-Cr.....................................................................................................
162 (930.1) General Advertising Expenses. ........... ........ ................................................................393,976 148,379
163 (930.2) Miscellaneous General Expenses...............................................................................3,606,629 3,340,110
164 (931) Rents.............................................................................................................................11,698 1,009
165 TOTAL Operation (Enter Total of lines 151 thru 164).........................................................9/,:iUtl,/ö7 97,110,285
166 Maintenance
167 (935) Maintenance of General Plant......................................................................................3,883,202 3,654,659
168 TOTAL Admin and General Expenses (Enter Total of lines 165-167)............................1u1,389,989 100,764,944
169 TOTAL Elec Op and Maint Exp (Total of 80, 100, 126, 134,141,148,168)....................:I 65 i ,tlll:i,Ull¿ :I 677,917,253
IDAHO ONLY
NUMBER OF ELECTRIC DEPARTMENT EMPLOYEES
1.I ne oata on number Of empioyees snouio be reportea tor tne payroii penoo enoing nearest to Uctober ::1,
or any payroii penoo enoing öU oays betore or atter Uctober ::1.
;¿ It tne responoenrs payroii tor tne reporting penoo IncluOes any speciai construction personnei, incluoe
sucn empioyees on line ::, ano snow tne number ot sucn speciai construction empioyees in a footnote.
::.i ne number ot empioyees assignabie to tne electnc oepartment trom Joint tunctions ot combination utllities
may be oeterrinea by estimate, on tne basis 'ot empioyee equivaients.::now tne estimatea number ot equiv-
aient empioyees attnbuteO to tne electnc oepartment trom Joint tunctions.
1 Payroll Period Ended (Date)....................................................................................................December 31,2010 December 31, 2009
2 Total Regular Full-Time Employees........................................................................................1,928 1,979
3 Total Part-Time and Temporary Employees............................................................................50 24
4 Total Employees.....................................................................................................................1,978 2,003
Page 15
IDAHO SUPPLEMENT