2012Annual Report.pdf

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Deloitte,
101 South Capitol Blvd.
Suite 1700
Boise, ID 83702-7734
USA
Tel: [phone]
Fax [phone]
www.deloitte.com
INDEPENDENT AUDITORS' REPORT
Idaho Power Company
Boise, Idaho
We have audited the accompanying financial statements of Idaho Power Company (the "Company"),
which comprise the balance sheet - regulatory basis as of December 31, 2012, and the related statements
of income - regulatory basis, retained earnings - regulatory basis, and cash flows - regulatory basis
for the year then ended, included on pages 110 through 123 of the accompanying Federal Energy
Regulatory Commission Form 1, and the related notes to the financial statements.
Management's Responsibility for the Financial Statements
Management is responsible for the preparation and fair presentation of these financial statements in
accordance with the accounting requirements of the Federal Energy Regulatory Commission as set forth
in its applicable Uniform System of Accounts and published accounting releases; this includes the design,
implementation, and maintenance of internal control relevant to the preparation and fair presentation of
financial statements that are free from material misstatement, whether due to fraud or error.
Auditors' Responsibility
Our responsibility is to express an opinion on these financial statements based on our audit. We
conducted our audit in accordance with auditing standards generally accepted in the United States of
America. Those standards require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in
the financial statements. The procedures selected depend on the auditor's judgment, including the
assessment of the risks of material misstatement of the financial statements, whether due to fraud or error.
In making those risk assessments, the auditor considers internal control relevant to the Company's
preparation and fair presentation of the financial statements in order to design audit procedures that are
appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of
the Company's internal control. Accordingly, we express no such opinion. An audit also includes
evaluating the appropriateness of accounting policies used and the reasonableness of significant
accounting estimates made by management, as well as evaluating the overall presentation of the financial
statements.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for
our audit opinion.
Opinion
In our opinion, the regulatory-basis financial statements referred to above present fairly, in all material
respects, the assets, liabilities, and proprietary capital of Idaho Power Company, as of December 31,
Membrd
DetoitteToucheThhmatsu thnited
2012, and the results of its operations and its cash flows for the year then ended in accordance with the
accounting requirements of the Federal Energy Regulatory Commission as set forth in its applicable
Uniform System of Accounts and published accounting releases.
Basis of Accounting
As discussed in Note 1 to the financial statements, these financial statements were prepared in accordance
with the accounting requirements of the Federal Energy Regulatory Commission as set forth in its
applicable Uniform System of Accounts and published accounting releases, which is a basis of accounting
other than accounting principles generally accepted in the United States of America. Our opinion is not
modified with respect to this matter.
Restricted Use
This report is intended solely for the information and use of the board of directors and management of the
Company and for filing with the Federal Energy Regulatory Commission and is not intended to be and
should not be used by anyone other than these specified parties.
t.J41zQt. icz;: L.-ft
February 21, 2013
-2-
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FERC FORM NO. 113-Q:
REPORT OF MAJOR ELECTRIC UTILITIES LICENSEES AND OTHER
IDENTIFICATION
01 Exact Legal Name of Respondent I
02 Year/Period of Report
Idaho Power Company End of 2012/Q4
03 Previous Name and Date of Change (if name changed during year)
1/
04 Address of Principal Office at End of Period (Street, City, State, Zip Code)
1221 W Idaho St, P.O. Box 70 Boise, Id 83707-0070
05 Name of Contact Person 06 Title of Contact Person
Ken Petersen Corporate Controller and CAO
07 Address of Contact Person (Street, City, State, Zip Code)
1221 W Idaho St, P.O. Box 70 Boise, Id 83707-0070
08 Telephone of Contact Person,!nc/uding 09 This Report Is 10 Date of Report
Area Code (1)J An Original (2) 0 A Resubmission (Mo, Da, Yr)
[phone] 04/15/2013
ANNUAL CORPORATE OFFICER CERTIFICATION
The undersigned officer certifies that
I have examined this report and to the best of my knowledge, information, and belief all statements of fact contained in this report are correct statements
of the business affairs of the respondent and the financial statements, and other financial information contained in this report, conform in all material
respects to the Uniform System of Accounts.
01 Name 03 Signature 04 Date Signed
Ken Petersen (Mo, Da, Yr)
02 Title
Corporate Controller and CAO Ken Petersen 04/15/2013
Title 18, U.S.C. 1001 makes it a crime for any person to knowingly and willingly to make to any Agency or Department of the United States any
false, fictitious or fraudulent statements as to any matter within its jurisdiction.
FERC FORM No.113-Q (REV. 02-04) Page 1
Name of Respondent
Idaho Power Company
This Re ort Is:
(2) [:]A Resubmission
Date of Report
04/15/2013
Year/Period of Report
End of 2012/Q4
LIST OF SCHEDULES (Electric Utility)
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
Line
No.
-
Title of Schedule
(a)
Reference
Page No.
(b)
Remarks
(c)
I General Information 101
2 Control Over Respondent 102
3 Corporations Controlled by Respondent 103
4 Officers 104
5 Directors 105
6 Information on Formula Rates 106(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 Utility Plant & Accumulated Provisions for Dep, Amort & Dep 200-201
15 Nuclear Fuel Materials 202-203 N/A
16 Electric Plant in Service 204-207
17 Electric Plant Leased to Others 213 N/A
18 Electric Plant Held for Future Use 214
19 Construction Work in Progress-Electric 216
20 Accumulated Provision for Depreciation of Electric Utility Plant 219
21 Investment of Subsidiary Companies 224-225
22 Materials and Supplies 227
23 Allowances 228(ab)-229(ab) NIA
24 Extraordinary Property Losses 230 N/A
25 Unrecovered Plant and Regulatory Study Costs 230 N/A
26 Transmission Service and Generation Interconnection Study Costs 231
27 Other Regulatory Assets 232
28 Miscellaneous Deferred Debits 233
29 Accumulated Deferred Income Taxes 234
30 Capital Stock 250-251
31 Other Paid-in Capital 253
32 Capital Stock Expense 254
33 Long-Term Debt 256-257
34 Reconciliation of Reported Net Income with Taxable Inc for Fed Inc Tax 261
35 Taxes Accrued, Prepaid and Charged During the Year 262-263
36 Accumulated Deferred Investment Tax Credits 266-267
FERC FORM NO. I (ED. 12-96) Page 2
Name of Respondent
Idaho Power Company
This Re ort Is:
(2) []A Resubmission
Date of Report I
04/15/2013
Year/Period of Report
End of 2012/Q4
LIST OF SCHEDULES (Electric Utility) (continued)
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
Line
No.
-
Title of Schedule
(a)
Reference
Page No.
(b)
Remarks
(c)
37 Other Deferred Credits 269
38 Accumulated Deferred Income Taxes-Accelerated Amortization Property 272-273 N/A
39 Accumulated Deferred Income Taxes-Other Property 274-275
40 Accumulated Deferred Income Taxes-Other 276-277
41 Other Regulatory Liabilities 278
42 Electric Operating Revenues 300-301
43 j Regional Transmission Service Revenues (Account 457.1) 302 N/A
44 Sales of Electricity by Rate Schedules 304
45 Sales for Resale 310-311
46 Electric Operation and Maintenance Expenses 320-323
47 Purchased Power 326-327
48 Transmission of Electricity for Others 328-330
49 j Transmission of Electricity by ISOIRTOs 331 N/A
50 Transmission of Electricity by Others 332
51 Miscellaneous General Expenses-Electric 335
52 Depreciation and Amortization of Electric Plant 336-337
53 Regulatory Commission Expenses 350-351
54 Research, Development and Demonstration Activities 352-353
55 Distribution of Salaries and Wages 354-355
56 Common Utility Plant and Expenses 356 N/A
57 Amounts included in ISO/RTO Settlement Statements 397 N/A
58 Purchase and Sale of Ancillary Services 398 N/A
59 Monthly Transmission System Peak Load 400
60 Monthly ISO/RTO Transmission System Peak Load 400a N/A
61 Electric Energy Account 401
62 Monthly Peaks and Output 401
63 Steam Electric Generating Plant Statistics 402-403
64 Hydroelectric Generating Plant Statistics 406-407
65 Pumped Storage Generating Plant Statistics 408-409 N/A
66 Generating Plant Statistics Pages 410-411
FERC FORM NO. I (ED. 12-96) Page 3
Name of Respondent This Report Is: Date of Report Year/Period of Report
Idaho Power Company (1)JM Original (Mo, Da, Yr) E d f 2012/04 n
(2)fl A Resubmission 04/15/2013
LIST OF SCHEDULES (Electric Utility) (continued)
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
Line Title of Schedule Reference Remarks
No. Page No.
- (a) (b) (c)
67 Transmission Line Statistics Pages 422-423
68 Transmission Lines Added During the Year 424-425
69 Substations 426-427
70 Transactions with Associated (Affiliated) Companies 429
71 Footnote Data 450
- Stockholders' Reports Check appropriate box:
Two copies will be submitted
0 No annual report to stockholders is prepared
FERC FORM NO. I (ED. 12-96) Page 4
Name of Respondent This Report Is: Date of Report Year/Period of Report
Idaho Power Company (1)M An Original (Mo, Da, Yr)
(2)A Resubmission 04/15/2013 End of 20121Q4
GENERAL INFORMATION
1.Provide name and title of officer having custody of the general corporate books of account and address of
office where the general corporate books are kept, and address of office where any other corporate books of account
are kept, if different from that where the general corporate books are kept.
Ken Petersen Coporate Controller and CAO, Idaho Power Company
1221 W. Idaho Street, P.O. Box 70, Boise, Idaho 83707-0070
2.Provide the name of the State under the laws of which respondent is incorporated, and date of incorporation.
If incorporated under a special law, give reference to such law. If not incorporated, state that fact and give the type
of organization and the date organized.
Idaho, June 30, 1989
3.If at any time during the year the property of respondent was held by a receiver or trustee, give (a) name of
receiver or trustee, (b) date such receiver or trustee took possession, (c) the authority by which the receivership or
trusteeship was created, and (d) date when possession by receiver or trustee ceased.
Not applicable
4.State the classes or utility and other services furnished by respondent during the year in each State in which
the respondent operated.
Class of Utility Service State
Electric Idaho
Electric Oregon
5.Have you engaged as the principal accountant to audit your financial statements an accountant who is not
the principal accountant for your previous year's certified financial statements?
(1)n Yes.. .Enter the date when such independent accountant was initially engaged:
(2)DQ No
FERC FORM No.1 (ED. 12-87) PAGE 101
Name of Respondent This Report Is: Date of Report Year/Period of Report
Idaho Power Company (1)j An Original
(2)fl A Resubmission
(Mo, Da, Yr)
04/1512013 End of 2012IQ4
CONTROL OVER RESPONDENT
1. If any corporation, business trust, or similar organization or a combination of such organizations jointly held
control over the repondent at the end of the year, state name of controlling corporation or organization, manner in
which control was held, and extent of control. If control was in a holding company organization, show the chain
of ownership or control to the main parent company or organization. If control was held by a trustee(s), state
name of trustee(s), name of beneficiary or beneficiearies for whom trust was maintained, and purpose of the trust.
Idaho Power Company is a subsidiary of IDACORP, INC
IDACORP owns 100% of Idaho Power Company's Common Stock.
IDACORP is a public utility Holding Company incorporated effective 10-1-1998
FERC FORM NO. 1 (ED. 12-96) Page 102
Name of Respondent
Idaho Power Company
This Re ort Is
2,ssi on
Date of Report Year/Period of Report
End of 2012/Q4
CORPORATIONS CONTROLLED BY RESPONDENT
1.Report below the names of all corporations, business trusts, and similar organizations, controlled directly or indirectly by respondent
at any time during the year. If control ceased prior to end of year, give particulars (details) in a footnote.
2.If control was by other means than a direct holding of voting rights, state in a footnote the manner in which control was held, naming
any intermediaries involved.
3.If control was held jointly with one or more other interests, state the fact in a footnote and name the other interests.
Definitions
1.See the Uniform System of Accounts for a definition of control.
2.Direct control is that which is exercised without interposition of an intermediary.
3.Indirect control is that which is exercised by the interposition of an intermediary which exercises direct control.
4.Joint control is that in which neither interest can effectively control or direct action without the consent of the other, as where the
voting control is equally divided between two holders, or each party holds a veto power over the other. Joint control may exist by
mutual agreement or understanding between two or more parties who together have control within the meaning of the definition of
control in the Uniform System of Accounts, regardless of the relative voting rights of each party.
Line
No.
Name of Company Controlled
(a)
Kind of Business
(b)
Percent Voting
Stock Owned
(c)
Footnote
Ref.
(d)
I 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
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27
FERC FORM NO. I (ED. 12-96) Page 103
Name of Respondent
Idaho Power Company
This Report Is:
(2) E] A Resubmission
Date of Report
04/15/2013
Year/Period of Report
End of 2012/Q4
OFFICERS
1.Report below the name, title and salary for each executive officer whose salary is $50,000 or more. An "executive officer" of a
respondent includes its president, secretary, treasurer, and vice president in charge of a principal business unit, division or function
(such as sales, administration or finance), and any other person who performs similar policy making functions.
2.If a change was made during the year in the incumbent of any position, show name and total remuneration of the previous
incumbent, and the date the change in incumbency was made.
Line
No.
Title
(a)
Name of Officer
(b)
Salary for Year
(c)
2 Chief Executive Officer J. LaMont Keen 675,000
3
4 President & Chief Financial Officer Darrel T. Anderson 420,000
5
6 Executive Vice President, & Chief Operating Officer Dan Minor 385,000
7
8 Senior Vice President and General Counsel Rex Blackburn 300,000
9
10 Senior Vice President, Power Supply Use Grow 260,000
11
12 Senior Vice President, Finance & Treasurer Steven Keen 260,000
13
14 Vice President. Human Resources & Corporate Services Luc! McDonald 240,000
15
16 Vice President and Chief Information Officer Dennis Gnbble 222,000
17
18 Vice President, Customer Operations Warren Kline 222,000
19
20 Vice President, Public Affairs Jeffrey Malmen 215,000
21
22 Vice President, Chief Risk Officer Lori Smith 215,000
23
24 Vice President Delivery Engineering & Construction Vern Porter 202,000
25
26 Corporate Controller & Chief Accounting Officer Ken Petersen 190,000
27
28 Vice President, Regulatory Affairs Gregory Said 172,500
29
30 Corporate Secretary Patrick Harrington 170,000
31
32 Vice President, Supply Chain Naomi Crafton-Shankel 170,000
33
34
35
36
37
38
39
40
41
42
43
44
FERC FORM NO. 1 (ED. 12-96) Page 104
Name of Respondent
Idaho Power Company
This Re ort Is:
(2) E] A Resubmission
Date of Report
04/15/2013
Year/Period of Report
End of 2012/Q4
DIRECTORS
1 Report below the information called for concerning each director of the respondent who held office at any time during the year. Include in column (a), abbreviated
titles of the directors who are officers of the respondent.
2. Designate members of the Executive Committee by a triple asterisk and the Chairman of the Executive Committee by a double asterisk.
One
No. Name (and Title) of Director
(a)
principal Business Address (b)
2 Judith A Johansen 2786 Glenmorrie Dr. Lake Oswego, Oregon 97034
3
4 Christine King Standard Microsystems Corporation
5 80 Arkay Dr, Hauppauge, NY 11788
6
7 Gary Michael P.O. Box 1718, Boise, Idaho 83701
8
9 Stephen Allred 4642 W Dawson Dr Meridian, Id 83646
10
11 Jan B. Packwood 900 W. Bogus View Drive, Eagle, Idaho 83616
12
13 J. LaMont Keen, President and Chief Executive Officer** Idaho Power Company, 1221 W. Idaho Street,
14 P.O. Box 70, Boise, Idaho 83707-0070
15
16 Richard G. Reiten (1) Pacwest Center, 1211 SW Fifth Ave., Suite 1600
17 Portland, Oregon 97204
18
19 Joan Smith 2309 S.W. First Avenue, No. 1141, Portland, Oregon 97201
20
21 Robert A. Tinstman 4433W. Quail Point Court, Boise, Idaho 83703
22
23 Thomas Wilford Alscott Inc, P.O. Box 70001, Boise, Idaho 83701
24
25 Richard Dahl 11659 Presilla Road, Santa Rosa Valley Ca, 93012
26
27 Dennis L Johnson (2) United Heritage Life Insurance
28 707 E United Heritage Ct Ste 130 Meridian Idaho 83642
29
30 (1) Retired from Board of Directors 5/17/12.
31
32 (2) Approved 3/21/2013
33
34
35
36
37
38
39
40
41
42
43
44
45
46 j
47
48
FERC FORM NO. I (ED. 12-95) Page 105
Name of Respondent
Idaho Power Company
This
(l) J An
Report Is:
Original

(2)E] A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2013
Year/Period of Report
r of 2012/04
INFORMATION ON FORMULA RATES
FERC Rate Schedule/Tariff Number FERC Proceeding
Does the respondent have formula rates? [J Yes
No
1. Please list the Commission accepted formula rates including FERC Rate Schedule or Tariff Number and FERC proceeding (i.e. Docket No)
accepting the rate(s) or changes in the accepted rate.
Line
No. FERC Rate Schedule or Tariff Number FERC Proceeding
I FERC Electric Tariff FERC Docket No. ER06-787-002,003
2
3
4
5
6
7
8
9
10
11
12
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31
32
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36
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38
39
40
41
FERC FORM NO. I (NEW. 12-08) Page 106
Name of Respondent
Idaho Power Company
This Rep ort Is:
( 1 ) An Original
(2) fl A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2013
Year/Period of Report
End 2012/Q4
INFORMATION ON FORMULA RATES
FERC Rate Schedule/Tariff Number FERC Proceeding
Does the respondent file with the Commission annual (or more frequent)
filings containing the inputs to the formula rate(s)?
Yes
No
2. If yes, provide a listing of such filings as contained on the Commission's eLibrary website
-
Line
No. Accession No.
Document
Date
\ Filed Date Docket No. Description
Formula Rate FERC Rate
Schedule Number or
Tariff Number
1 201208275060 08/27/2012 ER09-1641-000 Idaho Power Company' FERC Electric Tariff
2 2012-2013 Annua
3 informational film
4 under ER09-1641-00
5
6
7
8
9
10
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46
FERC FORM NO. I (NEW. 12-08) Page lOGe
Name of Respondent
Idaho Power Company
This Rep ort Is: (l)3J An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2013
Year/Period of Report
n 0 2012/Q4
INFORMATION ON FORMULA RATES
Formula Rate Variances
1.If a respondent does not submit such filings then indicate in a footnote to the applicable Form I schedule where formula rate inputs differ from
amounts reported in the Form I.
2.The footnote should provide a narrative description explaining how the "rate" (or billing) was derived if different from the reported amount in the
Form 1.
3.The footnote should explain amounts excluded from the ratebase or where labor or other allocation factors, operating expenses, or other items
impacting formula rate inputs differ from amounts reported in Form I 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 None
2
3
4
5
6
7
8
9
10
II
12
13
14
15
16
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18
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FERC FORM NO. I (NEW. 12-08) Page 106b
Idaho Power Company (1)J An Original 04/15/2013 End of 2012/04
(2)LI A Resubmission
Give particulars (details) concerning the matters indicated below. Make the statements explicit and precise, and number them in
accordance with the inquiries. Each inquiry should be answered. Enter "none," "not applicable," or "NA" where applicable. If
information which answers an inquiry is given elsewhere in the report, make a reference to the schedule in which it appears.
1.Changes in and important additions to franchise rights: Describe the actual consideration given therefore and state from whom the
franchise rights were acquired. If acquired without the payment of consideration, state that fact.
2.Acquisition of ownership in other companies by reorganization, merger, or consolidation with other companies: Give names of
companies involved, particulars concerning the transactions, name of the Commission authorizing the transaction, and reference to
Commission authorization.
3.Purchase or sale of an operating unit or system: Give a brief description of the property, and of the transactions relating thereto,
and reference to Commission authorization, if any was required. Give date journal entries called for by the Uniform System of Accounts
were submitted to the Commission.
4.Important leaseholds (other than leaseholds for natural gas lands) that have been acquired or given, assigned or surrendered: Give
effective dates, lengths of terms, names of parties, rents, and other condition. State name of Commission authorizing lease and give
reference to such authorization.
5.Important extension or reduction of transmission or distribution system: State territory added or relinquished and date operations
began or ceased and give reference to Commission authorization, if any was required. State also the approximate number of
customers added or lost and approximate annual revenues of each class of service. Each natural gas company must also state major
new continuing sources of gas made available to it from purchases, development, purchase contract or otherwise, giving location and
approximate total gas volumes available, period of contracts, and other parties to any such arrangements, etc.
6.Obligations incurred as a result of issuance of securities or assumption of liabilities or guarantees including issuance of short-term
debt and commercial paper having a maturity of one year or less. Give reference to FERC or State Commission authorization, as
appropriate, and the amount of obligation or guarantee.
7.Changes in articles of incorporation or amendments to charter: Explain the nature and purpose of such changes or amendments.
8.State the estimated annual effect and nature of any important wage scale changes during the year.
9.State briefly the status of any materially important legal proceedings pending at the end of the year, and the results of any such
proceedings culminated during the year.
10.Describe briefly any materially important transactions of the respondent not disclosed elsewhere in this report in which an officer,
director, security holder reported on Page 104 or 105 of the Annual Report Form No. 1, voting trustee, associated company or known
associate of any of these persons was a party or in which any such person had a material interest.
11.(Reserved.)
12.If the important changes during the year relating to the respondent company appearing in the annual report to stockholders are
applicable in every respect and furnish the data required by Instructions I to 11 above, such notes may be included on this page.
13.Describe fully any changes in officers, directors, major security holders and voting powers of the respondent that may have
occurred during the reporting period.
14.In the event that the respondent participates in a cash management program(s) and its proprietary capital ratio is less than 30
percent please describe the significant events or transactions causing the proprietary capital ratio to be less than 30 percent, and the
extent to which the respondent has amounts loaned or money advanced to its parent, subsidiary, or affiliated companies through a
cash management program(s). Additionally, please describe plans, if any to regain at least a 30 percent proprietary ratio.
PAGE 108 INTENTIONALLY LEFT BLANK
SEE PAGE 109 FOR REQUIRED INFORMATION.
FERC FORM NO. I (ED. 12-96) Page 108
This Page Intentionally Left Blank
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
Idaho Power Company (2)- A Resubmission 04/15/2013 2012/04
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
1.None
2.None
3.None
4.None
5.New transmission line #728 Langley Gulch Power Plant to Willis Tap added 49.05 miles.
Changes to existing lines were:
Line #404 Rebuilt approx 30 wire miles added approx .85 miles new line.
Line #205 Deenergized transmisson line transferred to distribution 3.0 miles.
Line #529 New transmission line to distribution 3.0 miles.
Line #902-Line #433 Rerouted transmission to connect to new Justice station.
Line #328-Line #250 Connection to new Montour station .26 wire miles.
New Substations:
Montour switching station, Gem County, Idaho
Mountain Air Wind, Elmore County, Idaho
Langley Gulch Switchyard, Payette County, Idaho
New Power Plant:
Langely Gulch Power Plant, natural gas combined cycle power plant, Fayette County,
Idaho, in service 6/29/2012.
6.On April 13, 2012, Idaho Power issued $75 million of 2.95% first mortgage bonds,
medium-term notes, Series I, maturing on April 1, 2022, and $75 million of 4.30% first
mortgage bonds, medium-term notes, Series I, maturing on April 1, 2042. The first
mortgage bonds were issued under Idaho Power's shelf registration statement. As a result
of these issuances, as of December 31, 2012, $150 million remained on Idaho Power's shelf
registration for the issuance of first mortgage bonds and debt securities.
In May 2012, Idaho Power used a portion of the net proceeds of the April 2012 sale of
first mortgage bonds, medium-term notes to effect the early redemption in full of its $100
million of 4.75% first mortgage bonds, medium-term notes due November 2012.
7.None
8.Effective 1/11/12 a 3.0% general wage increase was implemented.
9.See pages 123.19 to 123.21
10.None
11.None
12.None
13.Idaho Power has added Dennis Johnson as a director effective 3/21/2013. The other
change was the retirement of Richard Reiten all changes listed on page 105. There were
however a couple of changes in the major security holders for 2012. The top ten
institutional shareholders list saw 2 changes from 3rd quarter to 4th quarter.In the 4th
quarter Thompson, Siegel & Walmsley LLC, and Schroder Investment Management Ltd. replaced
American Century Investment Mgmt. and Dreman Value Management, LLC.
14.Idaho Power and its uunregulated parent, IDACORP have seperate cash management
programs, (seperate bank accounts, liquidity facilities, short-term debt and investment
programs). No money has been loaned or advanced from Idaho Power to IDACORP through a cash
management program.
IFERC FORM NO. I (ED. 12-96) Page 109.1 1
Name of Respondent
Idaho Power Company
This Report Is:
(1)An Original
(2)fl A Resubmission
Date of Report
(Mb, Da, Yr)
04/15/2013
Year/Period of Report
End of 2012/Q4
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Line
No.
-
Title of Account
(a)
Ref.
Page No.
(b)
Current Year
End of Quarter/Year
Balance
(c)
Prior Year
End Balance
12/31
(d)
UTILITY PLANT
4,922,872,974 4,473,847,185 2 Utility Plant (101-1 06, 114) 200-201
3 Construction Work in Progress (107) 200-201 298,470,440 591,474,855
4 TOTAL Utility Plant (Enter Total of lines 2 and 3) 5,221,343,414 5,065,322,040
5 (Less)Accum. Prov. for Depr. Amoit DepI. (108,110, 111, 115) 200-201 1,871,810,171 1,840,782,085
6 Net Utility Plant (Enter Total of line 4 less 5) 3,349,533,243 3,224,539,955
7 Nuclear Fuel in Process of Ref., Conv.,Enrich., and Fab. (120.1) 202-203 0 0
8 Nuclear Fuel Materials and Assemblies-Stock Account (120.2) 0 0
9 Nuclear Fuel Assemblies in Reactor (120.3) 0 0
10 Spent Nuclear Fuel (120.4) 0
11 Nuclear Fuel Under Capital Leases (120.6) 0
12 (Less) Accum. Prov. for Amort. of Nud. Fuel Assemblies (120.5) 202-203 0
13 Net Nuclear Fuel (Enter Total of lines 7-11 less 12) 0 0
14 j Net Utility Plant (Enter Total of lines 6 and 13) 3,349,533,243 3,224,539,955
15 Utility Plant Adjustments (116) 0 0
16 Gas Stored Underground - Noncurrent (117) 0 0
17 OTHER PROPERTY AND INVESTMENTS
18 Nonutility Property (121) _______ 1,462,166 2,081,420
19 (Less) Accum. Prov. for Depr. and Amort. (122) ____ 0 0
20 Investments in Associated Companies (123) ____ 0 0
21 Investment in Subsidiary Companies (123.1) 224-225 84,680,24 78,529,519
22 (For Cost of Account 123.1, See Footnote Page 224, line 42) ________
0 23 Noncurrent Portion of Allowances 228-229
24 Other Investments (124) 1,518 1,852
25 Sinking Funds (125) 0 0
26 Depreciation Fund (126) 0 0
27 Amortization Fund - Federal (127) 0 0
28 Other Special Funds (128) 34,391,222 25,644,107
29 Special Funds (Non Major Only) (129) 0 0
30 Long-Term Portion of Derivative Assets (175) 284,782 359,418
31 Long-Term Portion of Derivative Assets - Hedges (176) 0 0
32 TOTAL Other Property and Investments (Lines 18-21 and 23-31) 120,819,931 106,616,316
33 CURRENT AND ACCRUED ASSETS
0 34 Cash and Working Funds (Non-major Only) (130)
35 Cash (131) 17,112,143 19,178,288
36 Special Deposits (132-134) 0 0
37 Working Fund (135) 39,100 37,352
38 Temporary Cash Investments (136) 100,000 100,000
39 Notes Receivable (141) 72,492 94,776
40 Customer Accounts Receivable (142) 67,661,588 67,534,731
41 Other Accounts Receivable (143) 20,876,001 8,206,727
42 (Less) Accum. Prov. hr Uncollectible Acct.-Credit (144) 1,872,855 1,435,434
43 Notes Receivable from Associated Companies (145) 1,008,249 17,335,019
44 Accounts Receivable from Assoc. Companies (146) 63,847 0
45 Fuel Stock (151) 227 42,388,239 47,865,097
46 Fuel Stock Expenses Undistributed (152) 227 0 0
47 Residuals (Elec) and Extracted Products (153) 227 0 0
48 Plant Materials and Operating Supplies (154) 227 47,455,954 42,015,731
49 Merchandise (155) 227 0 0
50 Other Materials and Supplies (156) 227 0 0
51 Nuclear Materials Held for Sale (157) 202-203/227 0 0
52 Allowances (158.1 and 158.2) 228-229 0 0
FERC FORM NO. I (REV. 12-03) Page 110
Name of Respondent
Idaho Power Company
This Report Is:
(1)An Original
(2)D A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2013
Year/Period of Report
End of 2012/Q4
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBlTontinued) -
Line
No.
-
Title of Account
(a)
Ref.
Page No.
(b)
Current Year
End of Quarter/Year
Balance
(c)
Prior Year
End Balance
12/31
(d)
53 (Less) Noncurrent Portion of Allowances 0 0
54 1 Stores Expense Undistributed (163) 227 3,581,218 4,474,719
55 Gas Stored Underground - Current (164.1) 0
56 Liquefied Natural Gas Stored and Held for Processing (164.2-164.3) 0
57 Prepayments (165) 12,688,220 12,273,571
58 Advances for Gas (166-167) 0
59 Interest and Dividends Receivable (171) 0 0
60 Rents Receivable (172) 0 0
61 Accrued Utility Revenues (173) 51,448,038 46,440,688
62 Miscellaneous Current and Accrued Assets (174) 0
63 Derivative Instrument Assets (175) 3,874,959 3,754,383
64 (Less) Long-Term Portion of Derivative Instrument Assets (175) 284,7821 359,418
65 Derivative Instrument Assets - Hedges (176) 0 0
66 (Less) Long-Term Portion of Derivative Instrument Assets - Hedges (176 0 0
67 Total Current and Accrued Assets (Lines 34 through 66) 266,212,411 267,516,230
68 DEFERRED DEBITS
69 Unamortized Debt Expenses (181) 17,143,425 16,992,504
70 Extraordinary Property 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 1,141,110,726 989,194,015
73 Prelim. Survey and Investigation Charges (Electric) (183) 819,409 491,041
74 Preliminary Natural Gas Survey and Investigation Charges 183.1) 0 0
75 Other Preliminary Survey and Investigation Charges (183.2) 0 0
76 Clearing Accounts (184) 1,364,037 630,208
77 Temporary Facilities (185) 0 0
78 Miscellaneous Deferred Debits (186) 233 53,913,850 50,880,202
79 Def. Losses from Disposition of Utility Pit. (187) 0 0
80 Research, Devel. and Demonstration Expend. (188) 352-353 0 0
81 Unamortized Loss on Reaquired Debt (189) 14,921,058 13,613,712
82 Accumulated Deferred Income Taxes (190) 234 316,262,777 227,977,046
83 Unrecovered Purchased Gas Costs (191) 0 0
84 Total Deferred Debits (lines 69 through 83) 1,545,535,282 1,299,778,728
85 TOTAL ASSETS (lines 14-16, 32, 67, and 84) 5,282,100,867 4,898,451,229
FERC FORM NO. I (REV. 12-03) Page 111
Name of Respondent
Idaho Power Company
This Report is:
(1)J An Original
(2) 0 A Resubmission
Date of Report
(mo, da, yr)
04/15/2013
Year/Period of Report
end of 2012/Q4
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER - CREDITS)
Line
No. Title of Account
(a)
Ref.
Page No.
(b)
Current Year
End of Quarter/Year
Balance
(c)
Prior Year
End Balance
12/31
(d)
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 Liability for Conversion (203, 206) 0 0
6 Premium on Capital Stock (207) 712,257,435 704,757,436
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) 118-119 752,514,607 659,237,261
12 Unappropriated Undistributed Subsidiary Earnings (216.1) 118-119 82,217,150 76,066,425
13 (Less) Reaquired Capital Stock (217) 250-251 0 0
14 Noncorporate Proprietorship (Non-major only) (218) 0 0
15 Accumulated Other Comprehensive Income (219) 122(a)(b) -17,115,669 -11,622,052
16 Total Proprietary Capital (lines 2 through 15) 1,625,653,628 1,524,219,175
17 LONG-TERM DEBT
18 Bonds (221) 256-257 1,515,460,000 1,465,460,000
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 25,203,182 26,266,818
22 Unamortized Premium on Long-Term Debt (225) ( 0
23 (Less) Unamortized Discount on Long-Term Debt-Debit (226) 2,967,860 3,113,413
24 Total Long-Term Debt (lines 18 through 23) 1,537,695,322 1,488,613,405
25 OTHER NONCURRENT LIABILITIES
26 Obligations Under Capital Leases - Noncurrent (227) 0 0
27 Accumulated Provision for Property Insurance (228.1) 0 0
28 Accumulated Provision for Injuries and Damages (228.2) 5,479,272 1,924,461
29 1 Accumulated Provision for Pensions and Benefits (228.3) 425,887,098 366,648,491
30 Accumulated Miscellaneous Operating Provisions (228.4) 2,261,891 0
31 Accumulated Provision for Rate Refunds (229) 45,672,853 33,145,395
32 Long-Term Portion of Derivative Instrument Liabilities 0 107,763
33 Long-Term Portion of Derivative Instrument Liabilities - Hedges 0 0
34 Asset Retirement Obligations (230) 22,982,049 21,366,767
35 Total Other Noncurrent Liabilities (lines 26 through 34) 502,283,163 423,192,877
36 CURRENT AND ACCRUED LIABILITIES
37 Notes Payable (231) 0 0
38 Accounts Payable (232) 108,223,362 97,996,387
39 Notes Payable to Associated Companies (233) 0 0
40 Accounts Payable to Associated Companies (234) 252,507 1,511,606
41 Customer Deposits (235) 1,966,205 10,799,095
42 Taxes Accrued (236) 262-263 8,109,787 4,895,725
43 Interest Accrued (237) 22,441,369 22,038,081
44 Dividends Declared (238) 0 0
45 Matured Long-Term Debt (239) 0
FERC FORM NO. I (rev. 12-03) Page 112
Name of Respondent
Idaho Power Company
This Report is:
(1)nx An Original
(2)fl A Resubmission
Date of Report
(mo, da, yr)
04/15/2013
Year/Period of Report
end of 20121Q4
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER - CREDiS)itinued)
Line
No. Title of Account
(a)
Ref.
Page No.
(b)
Current Year
End of Quarter/Year
Balance
(c)
Prior Year
End Balance
12/31
(d)
46 Matured Interest (240) 0 0
47 Tax Collections Payable (241) 1,905,279 1,719,933
48 Miscellaneous Current and Accrued Liabilities (242) 30,534,183 33,498,725
49 Obligations Under Capital Leases-Current (243) 0
50 Derivative Instrument Liabilities (244) 1,054,644 4,706,86
51 (Less) Long-Term Portion of Derivative Instrument Liabilities 0 107,76
52 Derivative Instrument Liabilities - Hedges (245) 0
53 (Less) Long-Term Portion of Derivative Instrument Liabilities-Hedges 0
54 Total Current and Accrued Liabilities (lines 37 through 53) 174,487,336 177,058,65
55 DEFERRED CREDITS
56 Customer Advances for Construction (252) 13,261,592 19,747,984
57 Accumulated Deferred Investment Tax Credits (255) 266-267 79,896,604 70.840,400
58 Deferred Gains from Disposition of Utility Plant (256) 0
59 Other Deferred Credits (253) 269 17,982,872 27,530,57
60 Other Regulatory Liabilities (254) 278 69,401,786 96,483,24
61 Unamortized Gain on Reaquired Debt (257) 0
62 Accum. Deferred Income Taxes-Accel. Amort.(281) 272-277 I
63 Accum. Deferred Income Taxes-Other Property (282) 1,080,279,413 933,326,224
64 Accum. Deferred Income Taxes-Other (283) 181,159,151 137,438,695
65 Total Deferred Credits (lines 56 through 64) 1,441,981,41 1,285,367,120
66 TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16,24, 35, 54 and 65) 5,282,100,86 4,898,451,229
FERC FORM NO. I (rev. 12-03) Page 113
Name of Respondent
Idaho Power Company
This Re ort Is: 2h1 RSSiOfl
Date of Report
04/15/2013
Year/Period of Report
End of 20121Q4
STATEMENT OF INCOME
Quarterly
1.Report in column (c) the current year to date balance. Column (c) equals the total of adding the data in column (g) plus the data in column (i) plus the
data in column (k). Report in column (d) similar data for the previous year. This information is reported in the annual filing only.
2.Enter in column (e) the balance for the reporting quarter and in column (f) the balance for the same three month period for the prior year.
3.Report in column (g) the quarter to date amounts for electric utility function; in column (i) the quarter to date amounts for gas utility, and in column (k)
the quarter to date amounts for other utility function for the current year quarter.
4.Report in column (h) the quarter to date amounts for electric utility function; in column (j) the quarter to date amounts for gas utility, and in column (I)
the quarter to date amounts for other utility function for the prior year quarter.
5.If additional columns are needed, place them in a footnote.
Annual or Quarterly if applicable
5. Do not report fourth quarter data in columns (e) and (f)
6.Report amounts for accounts 412 and 413, Revenues and Expenses from Utility Plant Leased to Others, in another utility columnin a similar manner to
a utility department Spread the amount(s) over lines 2 thru 26 as appropriate. Include these amounts in columns (c) and (d) totals.
7.Report amounts in account 414, Other Utility Operating Income, in the same manner as accounts 412 and 413 above.
Line
No.
-
Title of Account
(a)
(Ref.)
Page No.
(b)
Total
Current Year to
Date Balance for
Quarter/Year
(C)
Total
Prior Year to
Date Balance for
Quarter/Year
(d)
Current 3 Months
Ended
Quarterly Only
No 4th Quarter
(e)
Prior 3 Months
Ended
Quarterly Only
No 4th Quarter
(t)
11 UTILITY OPERATING INCOME
2 Operating Revenues (400) 300-301 1,075,085871 1,021,585,142
3 Operating Expenses
4 Operation Expenses (401) 320-323 596383,061 632,997,464
5 Maintenance Expenses (402) 320-323 74,129,496 76,104,523
6 Depreciation Expense (403) 336-337 116,113,891 113,001,742
7 Depreciation Expense for Asset Retirement Costs (403.1) 336-337 317,075
8 Amort. & Dept. of Utility Plant (404-405) 336-337 7,483,540 6,764,513
9 Amort. of Utility Plant Acq. Adj. (406) 336-337 -13,255 -22,723
10 Amort Property Losses, Unrecov Plant and Regulatory Study Costs (407)
11 Amort of Conversion Expenses (407)
12 Regulatory Debits (407.3) 39,764 28,099
13 (Less) Regulatory Credits (407.4) 788,738
14 Taxes Other Than Income Taxes (408.1) 262-263 30,488,808 28,894,715
15 Income Taxes - Federal (409.1) 262-263 -14,482,226 -57,754,420
16 - Other (409.1) 262-263 1,007,613 -803,160
17 Provision for Deferred Income Taxes (410.1) 234,272-277 239,208,729 116,679,418
18 (Less) Provision for Deferred Income Taxes-Cr. (411.1) 234,272-277 200,111,787 99,841,847
19 Investment Tax Credit Adj. - Net (411.4) 266 9,056,202 -1,131,934
20 (Less) Gains from Disp. of Utility Plant (411.6) -17,392
21 Losses from Disp. of Utility Plant (411.7)
22 (Less) Gains from Disposition of Allowances (411.8) 201,565 398,050
23 Losses from Disposition of Allowances (411.9)
24 Accretion Expense (411.10) 183,144
25 TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24) 858,813,772 814,535,732
26 Net Util Oper Inc (Enter Tot line 2 less 25) Carry to Pgl 17,line 27 216,272,099 207,049,410
FERC FORM NO. 113-Q (REV. 02-04) Page 114
Name of Respondent
Idaho Power Company
This Re ort Is:
AsIJlmi5skn
Date of Report
04/15/2013
Year/Period of Report
End of 20121Q4
STATEMENT OF INCOME FOR THE YEAR (Continued)
9.Use page 122 for important notes regarding the statement of income for any account thereof.
10.Give concise explanations concerning unsettled rate proceedings where a contingency exists such that refunds of a material amount may need to be
made to the utility's customers or which may result in material refund to the utility with respect to power or gas purchases. State for each year effected
the gross revenues or costs to which the contingency relates and the tax effects together with an explanation of the major factors which affect the rights
of the utility to retain such revenues or recover amounts paid with respect to power or gas purchases.
11 Give concise explanations concerning significant amounts of any refunds made or received during the year resulting from settlement of any rate
proceeding affecting revenues received or costs incurred for power or gas purches, and a summary of the adjustments made to balance sheet, income,
and expense accounts.
12.If any notes appearing in the report to stokholders are applicable to the Statement of Income, such notes may be included at page 122.
13.Enter on page 122 a concise explanation of only those changes in accounting methods made during the year which had an effect on net income,
including the basis of allocations and apportionments from those used in the preceding year. Also, give the appropriate dollar effect of such changes.
14.Explain in a footnote if the previous year's/quarters figures are different from that reported in prior reports.
15.If the columns are insufficient for reporting additional utility departments, supply the appropriate account titles report the information in a footnote to
this schedule.
ELECTRIC UTILITY GAS UTILITY OTHER UTILITY -
Current Year to Date
(in dollars)
(g)
Previous Year to Date
(in dollars)
(h)
Current Year to Date
(in dollars)
(i)
Previous Year to Date
(in dollars)
(j)
Current Year to Date
(in dollars)
(k)
Previous Year to Date
(in dollars)
Line
No.
85,871 1,021,585,142 2
632,997,464
60"______
4 596,383,061
74,129,496 76,104,523 5
116,113,891 113,001,742 6
317,075 7
7,483,540 6,764,513 8
-13,255 -22,723 9
10
11
39,784 28,099 12
788,738 13
30,488,808 28,894,715 14
-14,482,226 -57,754,420 15
1,007,613 -803,160 16
239,208,729 116,679,418 17
200,111,787 99,841,847 18
9,056,202 -1,131,934 19
-17,392 20
21
201,565 398,050 22
23
183,144 24
858,813,772 814,535,732 25
216,272,099 207,049,410 26
FERC FORM NO. I (ED. 12-96) Page 115
Name of Respondent
Idaho Power Company
This Re ort Is:
An
Rion
Date of Report
04/15/2013
Year/Period of Report
End of 20121Q4
STATEMENT OF INCOME FOR THE YEAR (continued)
Line
No.
-
Title of Account
(a)
(Ref.)
Page No.
(b)
TOTAL Current 3 Months
Ended
Quarterly Only
No 4th Quarter
(e)
Prior 3 Months
Ended
Quarterly Only
No 4th Quarter
(t)
Current Year
(c)
Previous Year
(d)
27 Net Utility Operating Income (Carried forward from page 114) I 216,272,0991 207,049,4101 I
28 Other Income and Deductions
29 Other Income
30 Nonutilty Operating Income
31 Revenues From Merchandising, Jobbing and Contract Work (415) 1,639,354 1,142,767
32 (Less) Costs and Exp. of Merchandising, Job. & Contract Work (416) 1,634,620 974,498
33 Revenues From Nonutility Operations (417) 46,890 51,602
34 (Less) Expenses of Nonutility Operations (417.1) 276,349 -18,126
35 Nonoperating Rental Income (418) -16185 -3,285
36 Equity in Earnings of Subsidiary Companies (418.1) 119 6,150,725 5,967,745
37 Interest and Dividend Income (419) 2,018,711 2,178,296
38 Allowance for Other Funds Used During Construction (419.1) 22,433,417 25,484,071
39 Miscellaneous Nonoperating Income (421) 1,990,234 1,428,531
40 Gain on Disposition of Property (421.1) 57,199
41 TOTAL Other Income (Enter Total of lines 31 thru 40) 32,352,1771 35,350,554
42 Other Income Deductions
43 Loss on Disposition of Property (421.2)
44 Miscellaneous Amortization (425)
45 Donations (426.1) 717,897 718,718
46 Life Insurance (426.2) -14,029 -757,078
47 Penalties (426.3) -560,608 430,042
48 Exp. for Certain Civic, Political & Related Activities (4264) 1,256,3471 1,167,810
49 Other Deductions (426.5) 7,533,7681 6,579,000
50 TOTAL Other Income Deductions (Total of lines 43 thru 49) 8,933,3751 8,138,492
51 Taxes Applic. to Other Income and Deductions
52 Taxes Other Than Income Taxes (408.2) 262-263 ,640 23,238
53 Income Taxes-Federal (409.2) 262-263 ,078
7-116!1,217
-638,707
54 Income Taxes-Other (409.2) 262-263 -112,459
55 Provision for Deferred Inc. Taxes (410.2) 234,272-277 652,958 511,882
56 (Less) Provision for Deferred Income Taxes-Cr. (411.2) 234, 272-277 2,320,966 1,327,221
57 Investment Tax Credit Adj.-Net (411.5)
58 (Less) Investment Tax Credits (420)
59 TOTAL Taxes on Other Income and Deductions (Total of lines 52-58) -1,906,663 -1,543,267
60 Net Other Income and Deductions (Total of lines 41,50,59) 25,325,4651 28,755,329
61 Interest Charges
62 Interest on Long-Term Debt (427) 78,922,057 79,348,955
63 Amort, of Debt Disc. and Expense (428) 1,570,010 1,653,291
64 Amortization of Loss on Reaquired Debt (428.1) 1,008,756 911,000
65 (Less) Amort. of Premium on Debt-Credit (429)
66 (Less) Amortization of Gain on Reaquired Debt-Credit (429.1)
67 Interest on Debt to Assoc. Companies (430)
68 Other Interest Expense (431) 3,858,107 2,474,590
69 (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432) 11,929,405 13,332,724
701 Net Interest Charges (Total of lines 62 thru 69) 73,429,525 71,055,112
71 Income Before Extraordinary Items (Total of lines 27,60 and 70) 168,168,039 164,749,627
72 Extraordinary Items
73 Extraordinary Income (434)
74 (Less) Extraordinary Deductions (435)
75 Net Extraordinary Items (Total of line 73 less line 74)
76 Income Taxes-Federal and Other (409.3) 262-263
77 Extraordinary Items After Taxes (line 75 less line 76)
78 Net Income (Total of line 71 and 77) 168,168,0391 164,749,627
FERC FORM NO. 113-0 (REV. 02-04) Page 117
This Page Intentionally Left Blank
Name of Respondent
Idaho Power Company
This Rport Is:
(1)An Original (2)flP Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2013
Year/Period of Report
2012/Q4 ' °
STATEMENT OF RETAINED EARNINGS
1.Do not report Lines 49-53 on the quarterly version.
2.Report all changes in appropriated retained earnings, unappropriated retained earnings, year to date, and unappropriated
undistributed subsidiary earnings for the year.
3.Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436
439 inclusive). Show the contra primary account affected in column (b)
4.State the purpose and amount of each reservation or appropriation of retained earnings.
5.List first account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow
by credit, then debit items in that order.
6.Show dividends for each class and series of capital stock.
7.Show separately the State and Federal income tax effect of items shown in account 439, Adjustments to Retained Earnings.
8.Explain in a footnote the basis for determining the amount reserved or appropriated. If such reservation or appropriation is to be
recurrent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated.
9.If any notes appearing in the report to stockholders are applicable to this statement, include them on pages 122-123.
Line
No.
Item
(a)
Contra Primary
Account Affected
(b)
Current
Quarter/Year
Year to Date
Balance
(c)
Previous
Quarter/Year
Year to Date
Balance
(d)
UNAPPROPRIATED RETAINED EARNINGS (Account 216)
1 Balance-Beginning of Period 558,128446
2 Changes
17657,027,5731
3 Adjustments to Retained Earnings (Account 439)
5
6
7
8
9 TOTAL Credits to Retained Earnings (Acct. 439)
10
11
12
13
14
15 TOTAL Debits to Retained Earnings (Acct. 439)
16 Balance Transferred from Income (Account 433 less Account 418.1) 162,017,3141 158,781,882
17 Appropriations of Retained Earnings (Acct. 436)
215.1 -1,193,716 ( 178,017) 18 Excess Earnings on Hydro Projects under FPA
19
20
21
22 TOTAL Appropriations of Retained Earnings (Acct. 436) -1,193,716 ( 178,017)
23 Dividends Declared-Preferred Stock (Account 437)
24
25
26
27
28
29 TOTAL Dividends Declared-Preferred Stock (Acct. 437)
301 Dividends Declared-Common Stock (Account 438)
31 -68,739,968 ( 59,704,738)
32
33
34
35
36 TOTAL Dividends Declared-Common Stock (Acct. 438) -68,739,968 ( 59,704,738)
37 Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings
38 Balance - End of Period (Total 1,9,15,16,22,29,36,37) 749,111,2031 657,027,573
APPROPRIATED RETAINED EARNINGS (Account 215)
FERC FORM NO. 113-0 (REV. 02-04) Page 118
Name of Respondent
Idaho Power Company
This Re ort Is:
AResubmission
Date of Report
04/15/2013
Year/Period of Report
End of 2012/04
STATEMENT OF RETAINED EARNINGS
1.Do not report Lines 49-53 on the quarterly version.
2.Report all changes in appropriated retained earnings, unappropriated retained earnings, year to date, and unappropriated
undistributed subsidiary earnings for the year.
3.Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436
- 439 inclusive). Show the contra primary account affected in column (b)
4.State the purpose and amount of each reservation or appropriation of retained earnings.
5.List first account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow
by credit, then debit items in that order.
6.Show dividends for each class and series of capital stock.
7.Show separately the State and Federal income tax effect of items shown in account 439, Adjustments to Retained Earnings.
8.Explain in a footnote the basis for determining the amount reserved or appropriated. If such reservation or appropriation is to be
recurrent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated.
9.If any notes appearing in the report to stockholders are applicable to this statement, include them on pages 122-123.
Line
No.
Item
(a)
Contra Primary
Account Affected
(b)
Current
Quarter/Year
Year to Date
Balance
(c)
Previous
Quarter/Year
Year to Date
Balance
(d)
39
40
41
42
43
44
45 TOTAL Appropriated Retained Earnings (Account 215) I I
APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Account 215.1)
3,403,4041 2209,688 46 TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (AccL 215.1)
47 TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46) 3,403,4041 2,209,688
48 TOTAL Retained Earnings (Acct. 215,215.1, 216) (Total 38,47) (216.1) 752,514,6071 659,237,261
- UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account
- Report only on an Annual Basis, no Quarterly
I 76,066,4251 70,098,680 49 Balance-Beginning of Year (Debit or Credit)
50 Equity in Earnings for Year (Credit) (Account 418.1) 6,150,725 5,967,745
51 (Less) Dividends Received (Debit)
52
53 Balance-End of Year (Total lines 49 thru 52) 82,217,150 76,066,425
FERC FORM NO. 113-Q (REV. 02-04) Page 119
Name of Respondent
Idaho Power Company
This Re ort Is:
(2) E] A Resubmission
Date of Report
04/15/2013
Year/Period of Report
End of 2012/Q4
STATEMENT OF CASH FLOWS
(1)Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt (c) Include commercial paper; and (d) Identify separately such items as
investments, fixed assets, intangibles, etc.
(2)Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliation between Cash and Cash
Equivalents at End of Period with related amounts on the Balance Sheet.
(3)Operating Activities - Other: Include gains and losses pertaining to operating activities only. Gains and losses pertaining to investing and financing activities should be reported
in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid.
(4)Investing Activities: Include at Other (line 31) net cash outflow to acquire other companies. Provide a reconciliation of assets acquired with liabilities assumed in the Notes to
the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the US0fA General Instruction 20; instead provide a reconciliation of the
dollar amount of leases capitalized with the plant cost.
Line
No.
-
Description (See Instruction No. I for Explanation of Codes)
(a)
Current Year to Date
Quarter/Year
(b)
Previous Year to Date
Quarter/Year
(c)
1 Net Cash Flow from Operating Activities:
168,168,0391 164,749,627 2 Net Income (Line 78(c) on page 117)
3 INoncash Charges (Credits) to Income:
116,113,8911 113,001,742 4 Depredation and Depletion
5 Amortization of 11,025,871
6
7
8 Deferred Income Taxes (Net) 40,671,950 -58,819,227
9 Investment Tax Credit Adjustment (Net) 5,813,188 -726,590
10 Net (Increase) Decrease in Receivables -1,457,986 -2,125,936
11 Net (Increase) Decrease in Inventory 930,136 -21,207,643
12 Net (Increase) Decrease in Allowances Inventory
13 Net Increase (Decrease) in Payables and Accrued Expenses 22,896,607
14 Net (Increase) Decrease in Other Regulatory Assets -42,236,101 23,708,446
15 Net Increase (Decrease) in Other Regulatory Liabilities -11,230,901 44,336,626
16 (Less) Allowance for Other Funds Used During Construction 22,433,417 25,484,072
17 (Less) Undistributed Earnings from Subsidiary Companies 6,150,724 5,967,745
18 Other (provide details in footnote): 27,407,253
19
20
21
22 Net Cash Provided by (Used in) Operating Activities (Total 2 thru 21) 241,526,208 292,794,959
23
24 Cash Flows from Investment Activities:
25 Construction and Acquisition of Plant (including land):
26 Gross Additions to Utility Plant (less nuclear fuel) -324,431,776
27 Gross Additions to Nuclear Fuel
28 1 Gross Additions to Common Utility Plant
29 Gross Additions to Nonutility Plant
30 (Less) Allowance for Other Funds Used During Construction 11,929,405 13,332,724
31 Other (provide details in footnote): 6,314,273
32
33
34 Cash Outflows for Plant (Total of lines 26 thru 33) -237,022,238 -331,450,227
35
36 Acquisition of Other Noncurrent Assets (d)
37 Proceeds from Disposal of Noncurrent Assets (d)
38
39 j 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) -7,000,000
45 Proceeds from Sales of Investment Securities (a)
FERC FORM NO. I (ED. 12-96) Page 120
Name of Respondent
Idaho Power Company
This Re ort Is:
(2) E] A Resubmission
Date of Report
04/15/2013
Year/Period of Report
End of 2012/Q4
STATEMENT OF CASH FLOWS
(1)Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial paper; and (d) Identify separately such items as
investments, fixed assets, intangibles, etc.
(2)Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliation between 'Cash and Cash
Equivalents at End of Period" with related amounts on the Balance Sheet
(3)Operating Activities - Other: Include gains and losses pertaining to operating activities only. Gains and losses pertaining to investing and financing activities should be reported
in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid.
(4)Investing Activities: Include at Other (line 31) net cash outflow to acquire other companies. Provide a reconciliation of assets acquired with liabilities assumed in the Notes to
the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the liSofA General Instruction 20; instead provide a reconciliation of the
dollar amount of leases capitalized with the plant cost.
Line
No.
-
Description (See Instruction No. 1 for Explanation of Codes)
(a)
Current Year to Date
Quarter/Year
(b)
Previous Year to Date
Quarter/Year
(c)
46 Loans Made or Purchased
47 Collections on Loans
48
49 Net (Increase) Decrease in Receivables 22,284 208,367
50 Net (Increase ) Decrease in Inventory
51 Net (Increase) Decrease in Allowances Held for Speculation
52 Net Increase (Decrease) in Payables and Accrued Expenses
53 Other (provide details in footnote): -493,891
54
55
56 Net Cash Provided by (Used in) Investing Activities
57 Total of lines 34 thru 55) -227,327,932 1 -331.735,751 1
58
59 Cash Flows from Financing Activities:
60 Proceeds from Issuance of:
61 Long-Term Debt (b) 150,000,000 1
62 Preferred Stock
63 Common Stock
64 Other (provide details in footnote):
65
66 Net Increase in Short-Term Debt (c)
67 Other (provide details in footnote): Capital Infusion from IDACORP 7,500,000 16,000,000
68
69
70 Cash Provided by Outside Sources (Total 61 thru 69) 157,500,000 16,000,000
71
72 Payments for Retirement of
73 Long-term Debt (b) -101,063,636 -121,063,636
74 Preferred Stock
75 Common Stock
76 Other (provide details in footnote): -3,959,067 -1,207,914
77
78 Net Decrease in Short-Term Debt (c)
79
80 Dividends on Preferred Stock
81 Dividends on Common Stock -68,739,968 -59,704,738
82 Net Cash Provided by (Used in) Financing Activities
83 (Total of lines 70 thru 81) -16,262,671 -165,976,288
84
85 Net Increase (Decrease) in Cash and Cash Equivalents
86 (Total of lines 22,57 and 83) -2,064,395 -204,917,080
87
88 Cash and Cash Equivalents at Beginning of Period 19,315,638 224,232,718
89
90 Cash and Cash Equivalents at End of period 17,251,243 19,315,638
FERC FORM NO. I (ED. 12-96) Page 121
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 0411512013 20121Q4
FOOTNOTE DATA
Schedule Page: 120 Line No.: 5 Column: b
Months Ended Twelve Amortization
12/31/12
Plant
Regulatory assets
Regulatory liabilities
Unamortized debt expense
Unamortized discount
Water rights
Other
Schedule Page: 120 Line No.: 13 Column: b
Cash paid during the period for:
Income taxes
Interest (net of amount capitalized)
7,470,286
137,771
2,625,931
145,553
1,042,009
790,228
12,211,778
(16,113,671)
70,447,471
Cash Flow from Twelve Months
12/31/12
Pension and postretirement benefit plan expense
Contributions to pension and postretirement benefit plans
Unbilled revenues
Customer deposits
Prepayments
Other
Schedule Paae: 120 Line No.: 26 Column: b
Non-cash investing activities:
Additions to PP&E in accounts payable
45,230,196
(47,695,063)
(5,007,351)
(8,832,890)
(7,133,563)
(8,152,211)
(31,590,882)
26,881,874
Schedule Page: 120 Line No.: 31 Column: b
Other Cash Flows from Plant Twelve Months Ended
12/31/12
Sale of emission allowances and renewable energy certificates 2,738,701
2,738,701
Schedule Page: 120 Line No.: 53 Column: b I
Other Investing Cash Flows Twelve Months Ended
12/31/12
Disbursements from rabbi trust 673,287
Net change in notes receivable from subsidiary 16,326,770
Miscellaneous other investing activities (328,035)
16,672,022
IFERC FORM NO. I (ED. 12-87) Page 450.1 I
(I) pq An Original I End of 20121Q4
(2) J A Resubmission 04/15/2013 Idaho Power Company
1.Use the space below for important notes regarding the Balance Sheet, Statement of Income for the year, Statement of Retained
Earnings for the year, and Statement of Cash Flows, or any account thereof. Classify the notes according to each basic statement,
providing a subheading for each statement except where a note is applicable to more than one statement.
2.Furnish particulars (details) as to any significant contingent assets or liabilities existing at end of year, including a brief explanation of
any action initiated by the Internal Revenue Service involving possible assessment of additional income taxes of material amount, or of
a claim for refund of income taxes of a material amount initiated by the utility. Give also a brief explanation of any dividends in arrears
on cumulative preferred stock.
3.For Account 116, Utility Plant Adjustments, explain the origin of such amount, debits and credits during the year, and plan of
disposition contemplated, giving references to Cormmission orders or other authorizations respecting classification of amounts as plant
adjustments and requirements as to disposition thereof.
4.Where Accounts 189, Unamortized Loss on Reacquired Debt, and 257, Unamortized Gain on Reacquired Debt, are not used, give
an explanation, providing the rate treatment given these items. See General Instruction 17 of the Uniform System of Accounts.
5.Give a concise explanation of any retained earnings restrictions and state the amount of retained earnings affected by such
restrictions.
6.If the notes to financial statements relating to the respondent company appearing in the annual report to the stockholders are
applicable and furnish the data required by instructions above and on pages 114-121, such notes may be included herein.
7.For the 3Q disclosures, respondent must provide in the notes sufficient disclosures so as to make the interim information not
misleading. Disclosures which would substantially duplicate the disclosures contained in the most recent FERC Annual Report may be
omitted.
8.For the 3Q disclosures, the disclosures shall be provided where events subsequent to the end of the most recent year have occurred
which have a material effect on the respondent. Respondent must include in the notes significant changes since the most recently
completed year in such items as: accounting principles and practices; estimates inherent in the preparation of the financial statements;
status of long-term contracts; capitalization including significant new borrowings or modifications of existing financing agreements; and
changes resulting from business combinations or dispositions. However were material contingencies exist, the disclosure of such
matters shall be provided even though a significant change since year end may not have occurred.
9.Finally, if the notes to the financial statements relating to the respondent appearing in the annual report to the stockholders are
applicable and furnish the data required by the above instructions, such notes may be included herein.
PAGE 122 INTENTIONALLY LEFT BLANK
SEE PAGE 123 FOR REQUIRED INFORMATION.
FERC FORM NO. 1 (ED. 12-96) Page 122
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 04/15/2013 2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
IDAHO POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Idaho Power Company (Idaho Power) is the principal operating subsidiary of IDACORP Inc. (IDACORP), a holding company formed
in 1998. Idaho Power is an electric utility with a service territory covering approximately 24,000 square miles in southern Idaho and
eastern Oregon. Idaho Power is regulated primarily by the Federal Energy Regulatory Commission (FERC) and the state regulatory
commissions of Idaho and Oregon. Idaho Power is the parent of Idaho Energy Resources Co. (IERCo), a joint venturer in Bridger
Coal Company (BCC), which mines and supplies coal to the Jim Bridger generating plant owned in part by Idaho Power.
Basis of Reporting
The financial statements include the assets, liabilities, revenues and expenses of Idaho Power and have been prepared in accordance
with the accounting requirements of the FERC as set forth in the applicable Uniform System of Accounts and published accounting
releases, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of
America (U.S. GAAP). As required by the FERC, Idaho Power accounts for its investments in its majority-owned subsidiary on the
equity method rather than consolidating the assets, liabilities, revenues and expenses of the subsidiary as required by U.S GAAP. The
accompanying financial statements include Idaho Power's proportionate share of the utility plant and related operations resulting from
its interest in jointly-owned plants. In addition, under the requirements of the FERC, there are differences from U.S. GAAP in the
presentation of (1) current portion of long-term debt, (2) assets and liabilities for cost of removal of assets, (3) regulatory assets and
liabilities (4) deferred income taxes, (5) income tax expense and (6) non-utility revenues (7) accrued taxes.
Management Estimates
Management makes estimates and assumptions when preparing these financial statements. These estimates and assumptions include
those related to rate regulation, retirement benefits, contingencies, litigation, asset impairment, income taxes, unbilled revenues, and
bad debt. These estimates and assumptions affect the reported amounts of assets and liabilities and the disclosure of contingent assets
and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period.
These estimates involve judgments with respect to, among other things, future economic factors that are difficult to predict and are
beyond management's control. As a result, actual results could differ from those estimates.
System of Accounts
The accounting records of Idaho Power conform to the Uniform System of Accounts prescribed by the FERC and adopted by the
public utility commissions of Idaho, Oregon, and Wyoming.
Regulation of Utility Operations
Idaho Power's financial statements reflect the effects of the different ratemaking principles followed by the jurisdictions regulating
Idaho Power. The application of accounting principles related to regulated operations sometimes results in Idaho Power recording
expenses and revenues in a different period than when an unregulated enterprise would. In these instances, the amounts are deferred as
regulatory assets or regulatory liabilities on the balance sheet and recorded on the income statement when recovered or returned in
rates. Additionally, regulators can impose regulatory liabilities upon a regulated company for amounts previously collected from
customers and for amounts that are expected to be refunded to customers. The effects of applying these regulatory accounting
principles to Idaho Power's operations are discussed in more detail in Note 3.
Cash and Cash Equivalents
Cash and cash equivalents include cash on hand and highly-liquid temporary investments that mature within 90 days of the date of
acquisition.
IFERC FORM NO. I (ED. 12-88) Page 123.1 1
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
Idaho Power Company (2)- A Resubmission 04/15/2013 20121Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Receivables and Allowance for Uncollectible Accounts
Customer receivables are recorded at the invoiced amounts and do not bear interest. A late payment fee of one percent may be
assessed on account balances after 30 days. An allowance is recorded for potential uncollectible accounts. The allowance is reviewed
periodically and adjusted based upon a combination of historical write-off experience, aging of accounts receivable, and an analysis of
specific customer accounts. Adjustments are charged to income. Customer accounts receivable balances that remain outstanding after
reasonable collection efforts are written off through a charge to the allowance and a credit to accounts receivable. Other receivables
are also reviewed for impairment periodically, based upon transaction-specific facts. When it is probable that Idaho Power will be
unable to collect all amounts due according to the contractual terms of the agreement, an allowance is established for the estimated
uncollectible portion of the receivable and charged to income.
There were no impaired receivables without related allowances at December 31, 2012 and 2011. Once a receivable is determined to
be impaired, any further interest income recognized is fully reserved.
Derivative Financial Instruments
Financial instruments such as commodity futures, forwards, options, and swaps are used to manage exposure to commodity price risk
in the electricity and natural gas markets. All derivative instruments are recognized as either assets or liabilities at fair value on the
balance sheet unless they are designated as normal purchases and normal sales. Idaho Power's physical forward contracts are
designated as normal purchases and normal sales with the exception of forward contracts for the purchase of natural gas for use at
Idaho Power's natural gas generation facilities. The objective of Idaho Power's risk management program is to mitigate the price risk
associated with the purchase and sale of electricity and natural gas. Because of Idaho Power's regulatory accounting mechanisms,
Idaho Power records the changes in fair value of derivative instruments related to power supply as regulatory assets or liabilities.
Revenues
Operating revenues related to Idaho Power's sale of energy are recorded when service is rendered or energy is delivered to customers.
Idaho Power accrues estimated unbilled revenues for electric services delivered to customers but not yet billed at year-end. Idaho
Power collects franchise fees and similar taxes related to energy consumption. None of these collections are reported on the income
statement. Beginning in February 2009, Idaho Power is collecting in base rates a portion of the allowance for funds used during
construction (AFTJDC) related to its Hells Canyon Complex relicensing project. Cash collected under this ratemaking mechanism is
not recorded as revenue but is instead recorded as a regulatory liability.
Property, Plant and Equipment and Depreciation
The cost of utility plant in service represents the original cost of contracted services, direct labor and material, AFUDC, and indirect
charges for engineering, supervision, and similar overhead items. Repair and maintenance costs associated with planned major
maintenance are expensed as the costs are incurred, as are maintenance and repairs of property and replacements and renewals of items
determined to be less than units of property. For utility property replaced or renewed, the original cost plus removal cost less salvage
is charged to accumulated provision for depreciation, while the cost of related replacements and renewals is added to property, plant
and equipment.
All utility plant in service is depreciated using the straight-line method at rates approved by regulatory authorities. Annual
depreciation provisions as a percent of average depreciable utility plant in service approximated 2.75 percent in 2012 and 2.83 percent
in 2011.
Long-lived assets are periodically reviewed for impairment when events or changes in circumstances indicate that the carrying amount
of an asset may not be recoverable. If the sum of the undiscounted expected future cash flows from an asset is less than the carrying
value of the asset, impairment must be recognized in the financial statements. There were no material impairments of these assets in
2012 or 2011.
IFERC FORM NO. I (ED. 12-88) Page 123.2 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 04/15/2013 2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Allowance for Funds Used During Construction
AFUDC represents the cost of financing construction projects with borrowed funds and equity funds. With one exception, as discussed
above for the Hells Canyon Complex relicensing project, cash is not realized currently from such allowance; it is realized under the
ratemaking process over the service life of the related property through increased revenues resulting from a higher rate base and higher
depreciation expense. The component of AFUDC attributable to borrowed funds is included as a reduction to total interest expense.
Idaho Power's weighted-average monthly AFUDC rates for 2012 and 2011 were 7.7 percent and 7.8 percent, respectively.
Income Taxes
Idaho Power accounts for income taxes under the asset and liability method, which requires the recognition of deferred tax assets and
liabilities for the expected future tax consequences of events that have been included in the financial statements. Under this method
(commonly referred to as normalized accounting), deferred tax assets and liabilities are determined based on the differences between
the financial statements and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are
expected to reverse. In general, deferred income tax expense or benefit for a reporting period is recognized as the change in deferred
tax assets and liabilities at the beginning and end of the period. The effect of a change in tax rates on deferred tax assets and liabilities
is recognized in income in the period that includes the enactment date unless Idaho Power's primary regulator, the Idaho Public
Utilities Commission (IPUC), orders direct deferral of the effect of the change in tax rates over a longer period of time.
Consistent with orders and directives of the IPUC, unless contrary to applicable income tax guidance, Idaho Power does not provide
deferred income taxes for certain income tax temporary differences and instead recognizes the tax impact currently (commonly
referred to as flow-through accounting) for rate making and financial reporting. Therefore, Idaho Power's effective income tax rate is
impacted as these differences arise and reverse. Regulated enterprises are required to recognize such adjustments as regulatory assets
or liabilities if it is probable that such amounts will be recovered from or returned to customers in future rates.
In compliance with the federal income tax requirements for the use of accelerated tax depreciation, Idaho Power provides deferred
income taxes related to its plant assets for the difference between income tax depreciation and book depreciation used for financial
statement purposes. Deferred income taxes are provided for other temporary differences unless accounted for using flow-through.
The state of Idaho allows a three percent investment tax credit on qualifying plant additions. Investment tax credits earned on
regulated assets are deferred and amortized to income over the estimated service lives of the related properties. Credits earned on
non-regulated assets or investments are recognized in the year earned.
Income taxes are discussed in more detail in Note 2.
Comprehensive Income
Comprehensive income includes net income, unrealized holding gains and losses on available-for-sale marketable securities, and
amounts related to a deferred compensation plan for certain senior management employees and directors called the Senior
Management Security Plan. The following table presents Idaho Power's accumulated other comprehensive loss balance at December
31 (net of tax):
2012 2011
(thousands of dollars)
Unrealized holding gains on available-for-sale securities $ 4,136 $ 2,569
Senior Management Security Plan (21,252) (14,191)
Total $ (17,116) $ (11,622)
Other Accounting Policies
Debt discount, expense, and premium are deferred and are being amortized over the terms of the respective debt issues.
FRC FORM NO. I (ED. 12-88) Page 123.3 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
Idaho Power Company (2)- A Resubmission 04/15/2013 2012/04
NOTES TO FINANCIAL STATEMENTS (Continued)
2. INCOME TAXES
A reconciliation between the statutory federal income tax rate and the effective tax rate is as follows:
Federal income tax expense at 35% statutory rate
Change in taxes resulting from:
Equity earnings of subsidiary companies
AFUDC
Capitalized interest
Investment tax credits
Removal costs
Capitalized overhead costs
Capitalized repair costs
Tax method change - 263A
Tax method change - repairs
Uncertain tax positions - established
Uncertain tax positions - settled
State income taxes, net of federal benefit
Depreciation
Other, net
Total income tax (benefit) expense
Effective tax rate
2012 2011
(thousands of dollars)
$ 70,320 $ 42,116
(2,153) (2,089)
(12,027) (13,586)
5,075 6,465
(3,267) (3,355)
(2,697) (2,244)
(8,750) (5,950)
(19,250) (14,000)
0 0
(7,845) 0
0 0
0 (63,138)
7,646 1,846
14,398 14,100
(8,703) (4,583)
$ 32,747 $ (44,418)
16.3% (36.9%)
The items comprising income tax expense (benefit) are as follows:
2012 2011
(thousands of dollars)
Income taxes currently payable:
Federal $ (14,584) $ 7,832
State 846 7,296
Total (13,738) 15,128
Income taxes deferred:
Federal 47,069 22,942
State (9,640) (6,920)
Total 37,429 16,022
Uncertain tax positions:
Federal 0 (66,225)
State 0 (8,211)
Total 0 (74,436)
Investment tax credits:
Deferred 12,323 2,223
Restored (3,267) (3,355)
Total 9,056 (1,132)
Total income tax (benefit) expense $ 32,747 $ (44,418)
IFERC FORM NO. I (ED. 12-88) Page 123.4 1
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
Idaho Power Company (2)- A Resubmission 04/15/2013 2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
The components of the net deferred tax liability are as follows:
2012 2011
(thousands of dollars)
Deferred tax assets:
Regulatory liabilities
Advances for construction
Deferred compensation
Advanced payments
PCA
Tax credits
Net operating losses
Revenue sharing
Retirement benefits
Other
Total
Deferred tax liabilities:
Property, plant and equipment
Regulatory assets
Conservation programs
PCA
Fixed cost adjustment
Retirement benefits
Other
Total
Net deferred tax liabilities
$ 55,085 $ 45,473
3,010 5,118
23,463 22,067
17,856 12,958
0 1,711
21,174 8,547
47,351 0
2,796 10,594
146,546 122,445
4,340 3,758
321,621 232,671
406,283 333,335
677,795 599,992
5,114 3,464
16,832 0
5,246 5,652
142,270 122,712
13,257 10,304
1,266,797 1,075,459
$ 945,176 $ 842,788
IDACORP's tax allocation agreement provides that each member of its consolidated group compute its income taxes on a separate
company basis. Amounts payable or refimdable are settled through IDACORP. See Note 1 for further discussion of accounting
policies related to income taxes.
Uncertain Tax Positions
A reconciliation of the beginning and ending amount of unrecognized tax benefits for Idaho Power is as follows (in thousands of
dollars):
2012 2011
Balance at January 1, $ - $ 74,436
Additions for tax positions of the current year - -
Additions for tax positions of prior years - -
Reductions for tax positions of prior years - (66,379)
Settlements with taxing authorities - (8.057)
Balance at December 31, $ - $ -
Idaho Power recognizes interest accrued related to unrecognized tax benefits as interest expense and penalties as other expense. Idaho
Power recognized no interest expense in 2012 and a net reduction of $0.2 million in 2011. Accrued interest was zero as of December
31, 2012 and 2011. No penalties are accrued.
Idaho Power is subject to examination by its major tax jurisdictions - U.S. federal and the state of Idaho. The open tax years for
examination are 2012 for federal and 2009-2012 for Idaho. In May 2009, IDACORP formally entered the U.S. Internal Revenue
Service (IRS) Compliance Assurance Process (CAP) program for its 2009 tax year and has remained in the CAP program for all
subsequent years. The CAP program provides for IRS examination and issue resolution throughout the current year with the objective
IFERC FORM NO. I (ED. 12-88) Page 123.5 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
Idaho Power Company (2)- A Resubmission 04/15/2013 20121Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
of return filings containing no contested items. In 2012, the IRS completed its examination of IDACORP's 2011 tax year with no
unresolved income tax issues. IDACORP and Idaho Power believe there are no material tax uncertainties for 2012 and prior tax years.
Tax Accounting Method Change for Repair-Related Expenditures
In April 2011, IDACORP and the IRS reached an agreement on Idaho Power's tax accounting method change for capitalized repairs.
Accordingly, the IRS finalized the 2009 CAP examination and submitted its report on the 2009 tax year to the U.S. Congress Joint
Committee on Taxation (Joint Committee) for review. The capitalized repairs method is effectively settled and no material income tax
uncertainties remain for the method. As such, Idaho Power recognized $3.4 million of its previously unrecognized tax benefits for this
method in 2011.
In the third quarter of 2012 Idaho Power completed an income tax accounting method change for its 2011 tax year related to a portion
of the capitalized repairs method. The change was made pursuant to Revenue Procedure 2011-43 to bring Idaho Power's existing
method into alignment with the Revenue Procedure's safe harbor unit-of-property definitions for electric transmission and distribution
property. Following the automatic consent procedures provided for in the Revenue Procedure, Idaho Power adopted this method with
the filing of IDACORP's 2011 consolidated federal income tax return. The IRS approved the method change prior to the filing of the
return as part of IDACORP's 2011 CAP examination. A $7.8 million tax benefit was recognized in 2012 for the filed deduction related
to the cumulative method change adjustment for years prior to 2011.
For the year ended December 31, 2012, the capitalized repairs annual tax deduction estimate included in Idaho Power's income tax
provision produced a $21.5 million tax benefit (federal and state). The amount of this annual tax deduction will vary depending on a
number of factors, but most directly by the amount and type of Idaho Power's annual capital additions. The reversal of this temporary
difference from prior years will offset a portion of the ongoing annual benefit. Idaho Power's primary regulator, the IPUC, requires
flow-through accounting for temporary tax differences of this type. A regulatory asset is established to reflect Idaho Power's ability to
recover increased income tax expense when such temporary differences reverse.
Tax Accounting Method Change for Uniform Capitalization
In September 2009, the IRS issued Industry Director Directive #5 (IDD), which discusses the IRS's compliance priorities and audit
techniques related to the allocation of mixed service costs in the uniform capitalization methods of electric utilities. Within
IDACORP's 2009 CAP examination, the IRS and Idaho Power worked through the impact the IDD guidance had on Idaho Power's
uniform capitalization method and reached agreement during 2010. The agreement provided that Idaho Power change its uniform
capitalization method to the agreed upon method under the IDD with the filing of IDACORP's 2009 consolidated federal income tax
return. While Idaho Power had an agreement with the IRS for examination and return filing purposes, the agreement required Joint
Committee approval to be final.
The resulting tax deductions available under the agreed upon uniform capitalization method were significantly greater than Idaho
Power's prior method. For the year ended December 31, 2010, Idaho Power recorded a tax benefit of $65.3 million related to the
cumulative method change adjustment (tax years 1986 through 2009) for this method and $5.6 million of tax expense from the reversal
of this temporary difference. As of December 31, 2010, Idaho Power had a current uncertain tax position liability equal to the $59.7
million net tax benefit recorded for the method change. Due to the method change agreement with the IRS, Idaho Power reversed the
uncertain tax position liability for its 2009 uniform capitalization deduction, resulting in a $1.1 million tax benefit for the year ended
December 31, 2010.
In September 2011, the IRS notified IDACORP that the Joint Committee had completed its review of IDACORP's 2009 tax year and
approved the uniform capitalization method agreement Idaho Power considers the uniform capitalization method effectively settled
and believes that no material income tax uncertainties remain for the method. Accordingly, Idaho Power recognized the remaining
$56.9 million of its previously unrecognized tax benefits for tax years 2009 and prior in 2011.
For the year ended December 31, 2012, the uniform capitalization annual tax deduction estimate included in Idaho Power's income tax
provision produced a $9.8 million tax benefit (federal and state). The amount of this annual tax deduction will vary depending on a
number of factors, but most directly by the amount and type of Idaho Power's annual capital additions. The reversal of this temporary
difference from prior years will offset a portion of the ongoing annual benefit. Idaho Power's primary regulator, the IPUC, requires
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NOTES TO FINANCIAL STATEMENTS (Continued)
flow-through accounting for temporary tax differences of this type. A regulatory asset is established to reflect Idaho Power's ability to
recover increased income tax expense when such temporary differences reverse.
3. REGULATORY MATTERS
As a regulated utility, many of Idaho Power's fundamental business decisions are subject to the approval of governmental agencies,
including the prices that Idaho Power is authorized to charge for its electric service. These approvals are a critical factor in
determining Idaho Power's results of operations and financial condition.
Regulatory Assets and Liabilities
Regulatory assets represent incurred costs that have been deferred because it is probable they will be recovered through future rates
collected from customers. Regulatory liabilities represent obligations to make refunds to customers for previous collections, except for
cost of removal (which represents the cost of removing future electric assets). The following table presents a summary of Idaho
Power's regulatory assets and liabilities (in thousands of dollars):
Remaining
Amortization Period
Description
Regulatory Assets:
Income taxes
Unfunded postretirement benefits(2)
Pension expense deferrals(3)
Energy efficiency program costs(3)
Power supply costs(3) varies
Fixed cost adjustment(3) 2013-2014
Earning a Return(1) Not Earning a Return Total as of December 31,
2012 2011
- $ 677,795 $ 677,795 $ 603,772
308,850 308,850 262,503
50,036 14,959 64,995 58,044
17,085 - 17,085 15,956
60,680 - 60,680 8,490
13,418 - 13,418 14,457
Asset retirement obligations(4) - 15,411 15,411 15,557
Mark-to-market liabilities(S) - 1,055 1,055 4,707
Other 2013-2021 1,202 2,547 3,749 3,861
Total $ 142,421 $ 1,020,617 $ 1,163,038 $ 987,347
Regulatory Liabilities:
Income taxes $ - $ 55,085 $ 55,085 $ 49,253
Investment tax credits - 79,897 79,897 70,841
Deferred revenue-AFUDC (3)
29,404 16,269 45,673 33,145
Energy efficiency program costs(3)
4,130 - 4,130 -
Power supply costs (3)
Varies 17,778 - 17,778 13,121
Settlement agreement sharing mechanism(3) 20132014 7,151 - 7,151 27,099
Mark-to-market assets(S) - 4,579 4,579 3,754
Other 2,439 256 2,695 1,409
Total $ 60,902 $ 156,086 $ 216,988 $ 198,622
(1)Earning a return includes either interest or a return on the investment as a component of rate base at the allowed rate of return.
(2)Represents the unfunded obligation of Idaho Power's pension and postretirement benefit plans, which are discussed in Note 10.
(3)These items are discussed in more detail in this Note 3.
(4)Asset retirement obligations and removal costs are discussed in Note 12.
(5)Mark-to-market assets and liabilities are discussed in Note 15.
Idaho Power's regulatory assets and liabilities are amortized over the period in which they are reflected in customer rates. In the event
that recovery of Idaho Power's costs through rates becomes unlikely or uncertain, regulatory accounting would no longer apply to
some or all of Idaho Power's operations and the items above may represent stranded investments. If not allowed full recovery of these
items, Idaho Power would be required to write off the applicable portion, which could have a significant financial impact.
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NOTES TO FINANCIAL STATEMENTS (Continued)
Power Cost Adjustment Mechanisms and Deferred Power Supply Costs
In both its Idaho and Oregon jurisdictions, Idaho Power's power cost adjustment (PCA) mechanisms address the volatility of power
supply costs and provide for annual adjustments to the rates charged to its retail customers. The PCA mechanisms compare Idaho
Power's actual and forecast net power supply costs (primarily fuel and purchased power less off-system sales) against net power supply
costs currently being recovered in retail rates. Under the PCA mechanisms, certain differences between actual net power supply costs
incurred by Idaho Power and the costs included in retail rates are recorded as a deferred charge or credit on the balance sheets for
future recovery or refund through retail rates. The power supply costs deferred primarily result from changes in wholesale market
prices and transaction volumes, changes in contracted power purchase prices and volumes (including PURPA power purchases), and
the levels of hydroelectric and thermal generation.
Idaho Jurisdiction Power Cost Adjustment Mechanism: In the Idaho jurisdiction, the annual PCA adjustments consist of (a) a
forecast component, based on a forecast of net power supply costs in the coming year as compared to net power supply costs in base
rates; and (b) a true-up component, based on the difference between the previous year's actual net power supply costs and the previous
year's forecast. The latter component also includes a balancing mechanism so that, over time, the actual collection or refimd of
authorized true-up dollars matches the amounts authorized. The Idaho PCA mechanism also includes:
a cost or benefit sharing ratio that allocates the deviations in net power supply expenses between customers (95 percent)
and shareholders (5 percent), with the exception of expenses associated with PURPA power purchases, which are
allocated 100 percent to customers;
a load change adjustment rate (LCAR), which is intended to eliminate recovery of power supply expenses already
collected in rates associated with load changes resulting from changing weather conditions, a growing customer base, or
changing customer use patterns; and
third-party transmission expenses (paid to third parties to facilitate wholesale purchases and sales of energy) as a
component of net power supply costs for purposes of calculating the PCA.
The table below summarizes Idaho PCA rate adjustments during each of the years ended December 31, 2012 and 2011.
Effective $ Change
Date (millions) Notes
June 1, 2012 $ 43.0 The PCA rate increase was offset by $27.1 million to be shared with customers pursuant to the
revenue sharing order described below, resulting in a net rate increase of $15.9 million for
these orders.
June 1, 2011 $ (40.4) The reduction to Idaho PCA rates was net of $10.0 million of Idaho Power's energy efficiency
rider deferral balance that the IPUC authorized for recovery in Idaho Power's Idaho PCA
rates.
Oregon Jurisdiction Power Cost Adjustment Mechanism: Idaho Power's power cost recovery mechanism in Oregon has two
components: an annual power cost update (APCU) and a power cost adjustment mechanism (PCAM). The APCU allows Idaho Power
to reestablish its Oregon base net power supply costs annually, separate from a general rate case, and to forecast net power supply costs
for the upcoming water year. The PCAM is a true-up filed annually in February. The filing calculates the deviation between actual net
power supply expenses incurred for the preceding calendar year and the net power supply expenses recovered through the APCU for
the same period. Under the PCAM, Idaho Power is subject to a portion of the business risk or benefit associated with this deviation
through application of an asymmetrical deadband (or range of deviations) within which Idaho Power absorbs cost increases or
decreases. For deviations in actual power supply costs outside of the deadband, the PCAM provides for 90/10 sharing of costs and
benefits between customers and Idaho Power. However, collection by Idaho Power will occur only to the extent that Idaho Power's
actual return on equity (ROE) for the year is no greater than 100 basis points below Idaho Power's last authorized ROE. A refund to
customers will occur only to the extent that Idaho Power's actual ROE for that year is no less than 100 basis points above Idaho
Power's last authorized ROE. Oregon jurisdiction power supply cost changes under the APCU and PCAM during each of the three
years ended December 31, 2012 and 2011 are summarized in the table that follows.
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Year and
Mechanism APCU or PCAM Adjustment
2012 PCAM Idaho Power estimates that actual net power supply costs were within the deadband, which would result in no
deferral.
2012 APCU A rate increase of $1.8 million annually took effect June 1, 2012.
2011 PCAM Actual net power supply costs were below the deadband, which would have resulted in a $1.5 million
deferral. However, Oregon-jurisdiction earnings were below the ROE threshold described above, resulting
in no deferral.
2011 APCU A rate decrease of $2.2 million annually took effect June 1, 2011.
Idaho Regulatory Matters
2011 Idaho General Rate Case Settlement: On June 1, 2011, Idaho Power filed a general rate case with the IPUC requesting
approximately $82.6 million in additional Idaho jurisdiction annual revenues through base rates. On September 23, 2011, Idaho
Power, the IPUC Staff, and other interested parties filed a settlement stipulation with the IPUC resolving most of the key contested
issues in the Idaho general rate case, and on December 30, 2011 the IPUC issued an order approving the settlement stipulation. The
settlement stipulation approved by the December 2011 order provided for a 7.86 percent authorized rate of return on an
Idaho-jurisdiction rate base of approximately $2.36 billion. The approved settlement stipulation resulted in a 4.07 percent, or $34.0
million, overall increase in Idaho Power's annual Idaho-jurisdiction base rate revenues, effective January 1, 2012. Neither the order
nor the settlement stipulation specified an authorized rate of return on equity and did not impose a moratorium on Idaho Power's filing
a general rate case at a future date.
In addition to a base rate increase, the settlement stipulation addressed Idaho Power's calculation of the load change adjustment rate
(LCAR) to be applied in Idaho Power's PCA mechanism. The LCAR is intended to eliminate recovery of power supply expenses
already collected in rates associated with load changes resulting from changing weather conditions, a growing customer base, or
changing customer use patterns. The LCAR adjusts power supply cost recovery within the Idaho-jurisdiction PCA formula upwards or
downwards for differences between actual load and the load used in calculating base rates. The settlement stipulation provided for a
LCAR of $18.16 per megawatt-hour, effective January 1, 2012, compared to the rate of$ 19.67 per megawatt-hour in effect prior to
that date.
January 2010 Idaho Settlement Agreement: In January 2010, the IPUC approved a settlement agreement among Idaho Power,
several of Idaho Power's customers, the IPUC Staff, and other interested parties. Significant elements of the settlement agreement
included:
a specified distribution of the reduction in 2010 PCA that would reduce customer rates, provide up to a $25 million
general increase in annual base rates, and reset base power supply costs for the PCA, effective with the June 1, 2010 PCA
rate change;
a provision to share with Idaho customers 50 percent of any Idaho-jurisdiction earnings in excess of a 10.5 percent return
on equity in any calendar year from 2009 to 2011; and
a provision to allow the additional amortization of accumulated deferred investment tax credits (ADITC) if Idaho Power's
Idaho-jurisdiction rate of return on year-end equity (Idaho ROE) is below 9.5 percent in any calendar year from 2009 to
2011. Idaho Power was permitted to amortize additional ADITC in an amount up to $45 million over the three-year
period, but could use no more than $15 million in any one year unless there is a carryover. Carryover amounts were added
to the $15 million annual allowance up to a maximum amortization of $25 million in any one year.
In April 2010, Idaho Power filed its annual application with the IPUC to implement new PCA rates to be effective June 1, 2010
through May 31, 2011, and to change base rates, pursuant to the terms of the January 2010 Idaho settlement agreement. In May 2010,
the IPUC issued its order approving a $146.9 million decrease in the PCA, along with a base rate increase of $88.7 million, effective
June 1, 2010. The $88.7 million base rate increase reflects a $63.7 million increase in base power supply costs and a $25 million
increase in base rates.
Because Idaho Power's actual Idaho ROE was between 9.5 and 10.5 percent in 2009 and 2010, the sharing and amortization
provisions of the January 2010 settlement agreement were not triggered. However, recognition of income tax benefits in 2011 had a
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significant impact on Idaho Power's actual Idaho ROE and contributed to the triggering of the sharing mechanism for 2011. In
accordance with the terms of the settlement agreement, Idaho Power recorded a $27.1 million reduction in revenue and regulatory
liability in 2011, reflecting 50 percent of Idaho Power's 2011 Idaho-jurisdiction earnings above a 10.5 percent Idaho ROE to be shared
with Idaho customers.
December 2011 Idaho Settlement Agreement: The sharing and ADITC amortization provisions of the January 2010 settlement
agreement terminated on December 31, 2011. On December 27, 2011, the IPUC issued an order, separate from the general rate case
proceeding, approving a settlement stipulation that had been executed by Idaho Power, the 1PUC Staff, and one large industrial
customer of Idaho Power extending, with modifications, some of the provisions of the January 2010 settlement agreement. The
settlement stipulation provided that:
• if Idaho Power's actual Idaho ROE for 2012, 2013, or 2014 is less than 9.5 percent, then Idaho Power may amortize
additional ADITC to help achieve a minimum 9.5 percent Idaho ROE in the applicable year. Idaho Power would be
permitted to amortize additional ADITC in an aggregate amount up to $45 million over the three-year period, but could use
no more than $25 million in 2012;
if Idaho Power's actual Idaho ROE for 2012, 2013, or 2014 exceeds 10.0 percent, the amount of Idaho Power's
Idaho-jurisdiction earnings exceeding a 10.0 percent and up to and including a 10.5 percent Idaho ROE for the applicable
year would be shared equally between Idaho Power and its Idaho customers in the form of a rate reduction to become
effective at the time of the subsequent year's PCA adjustment; and
if Idaho Power's actual Idaho ROE for 2012, 2013, or 2014 exceeds 10.5 percent, the amount of Idaho Power's Idaho
jurisdictional earnings exceeding a 10.5 percent Idaho ROE for the applicable year would be allocated 75 percent to Idaho
Power's Idaho customers as a reduction to the pension regulatory asset and 25 percent to Idaho Power.
The December 2011 settlement stipulation provides that the return on year-end equity thresholds (9.5 percent, 10.0 percent, and 10.5
percent) will be automatically adjusted prospectively in the event the IPUC approves a change to Idaho Power's authorized return on
equity as part of a general rate case proceeding seeking a rate change effective prior to January 1, 2015. The automatic adjustments
would be as follows: (a) the 9.5 percent return on year-end equity trigger in the settlement stipulation would be replaced by the
percentage equal to 95 percent of the new authorized return on equity, (b) the 10.0 percent return on year-end equity trigger in the
settlement stipulation would be re-established at the new authorized return on equity amount, and (c) the 10.5 percent return on
year-end equity trigger in the settlement stipulation would be replaced by the percentage equal to 105 percent of the new authorized
return on equity.
In consideration of these terms, the December 2011 settlement stipulation further provided that Idaho Power would allocate to
customers as a reduction to the pension regulatory asset 75 percent of Idaho Power's own share of 2011 Idaho jurisdictional earnings
over a 10.5 percent Idaho ROE.
Revenue Sharing Under January 2010 and December 2011 Idaho Settlement Agreements: On May 31, 2012, the IPUC issued an
order approving Idaho Power's request to share revenues under the January 2010 and December 2011 settlement agreements. Idaho
Power recorded in 2011 a $27.1 million reduction to revenue for amounts to be refunded to customers and a $20.3 million pre-tax
charge to pension expense and an associated decrease in deferred pension regulatory asset, representing the additional amount to be
allocated to Idaho customers (reducing Idaho customers' future obligation). The refund is being applied to the PCA rates in effect from
June 1, 2012 to May 31, 2013.
Idaho Power's 2012 Idaho ROE exceeded 10.5 percent, triggering the sharing mechanism of the December 2011 settlement stipulation.
For 2012, Idaho Power recorded a $7.2 million provision against current revenues, to be refunded to customers through a future rate
reduction, and an additional $14.6 million of pension expense, to benefit Idaho customers by reducing the amount of deferred pension
expense that will be collected from customers in the future.
Fixed Cost Adjustment: The fixed cost adjustment (FCA) began as a pilot program for Idaho Power's Idaho residential and small
general service customers, with a term from 2007 through 2009. The FCA is designed to remove Idaho Power's disincentive to invest
in energy efficiency programs by separating (or decoupling) the recovery of fixed costs from the variable kilowatt-hour charge and
linking it instead to a set amount per customer. The FCA is adjusted each year to collect, or refund, the difference between the allowed
fixed-cost recovery amount and the actual fixed costs recovered by Idaho Power during the year. In April 2010, the IPUC approved a
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two-year extension of the FCA pilot program, effective retroactive to January 1, 2010, through December 31, 2011, and in March 2012
the IPUC issued an order approving the FCA as a permanent program. The order also maintained the existing cap on the FCA of no
more than 3 percent of base revenue, with any excess deferred for collection in a subsequent year. The IPUC noted in its order,
however, that the FCA does not isolate or identify changes in cost recovery associated solely with Idaho Power's energy efficiency
programs, and instead responds to all changes in load, and directed Idaho Power to file with the IPUC a proposal to adjust the FCA.
On September 28, 2012, Idaho Power submitted a compliance filing and motion to the IPUC requesting that the IPUC approve the
FCA methodology used during the pilot program, without change, or an alternative methodology proposed by Idaho Power. On
January 31, 2013, the IPUC issued an order stating that the FCA will continue unchanged, but that the IPUC will continue to monitor
the FCA results annually.
On May 8, 2012, the IPUC issued an order authorizing Idaho Power to increase its annual FCA collection to $10.3 million for the
period from June 1, 2012 to May 31, 2013. The following table summarizes FCA rate adjustments since inception:
Annual Amount
FCA Year Period rates in effect (in millions)
2011 June 1,2012-May31,2013 $ 10.3
2010 June l,2011 -May 3l,2012 $ 9.3
2009 June 1,2010-May31,2011 $ 6.3
As of December 31, 2012, Idaho Power had a $13.4 million regulatory asset associated with the FCA.
Cost Recovery for Langley Gulch Power Plant: On March 2, 2012, Idaho Power filed an application with the IPUC requesting an
increase in annual Idaho-jurisdiction base rates of $59.9 million for recovery of Idaho Power's investment and associated costs for the
Langley Gulch power plant, which became commercially available on June 29, 2012. Idaho Power's application stated that its
estimated investment in the plant through June 2012 was approximately $398 million. After the impact of depreciation, deferred
income taxes, amounts currently included in rates, and an Idaho-jurisdictional cost allocation, Idaho Power's application requested a
$336.7 million increase in Idaho-jurisdiction rate base. Idaho Power's requested base rate increase was based on an overall rate of
return of 7.86 percent, as authorized by a prior IPUC order. On June 29, 2012, the IPUC issued an order approving a $58.1 million
increase in annual Idaho-jurisdiction base rates, effective July 1, 2012. The order also provided for a $335.9 million increase in Idaho
rate base. Inclusion of the Langley Gulch power plant in Idaho Power's power supply portfolio also resulted in a change in Idaho
Power's power supply cost assumptions. Accordingly, in the Langley Gulch order the IPUC also updated Idaho Power's LCAR to
$17.64 per MWh, effective July 1, 2012.
Defined Benefit Pension Plan Contribution Recovery: Idaho Power defers its Idaho-jurisdiction pension expense as a regulatory
asset until recovered from Idaho customers. As of December 31, 2012, Idaho Power's deferral balance associated with the
Idaho-jurisdiction was $62.9 million. Deferred pension costs are expected to be amortized to expense to match the revenues received
when contributions are recovered through rates. Idaho Power only records a carrying charge on the unrecovered balance of cash
contributions. Idaho Power has made substantial contributions to its defined benefit pension plan in recent years. The single largest
contribution occurred in September 2010, when Idaho Power elected to make a $60 million contribution to its defined benefit pension
plan, rather than the minimum required funding amount. The amount contributed over the minimum required contribution was
intended to bring the defined benefit pension plan to a more funded position, potentially reducing future required contributions and
Pension Benefit Guaranty Corporation premiums. On March 15, 2011, Idaho Power filed an application with the IPUC requesting an
increase in the amount included in base rates for recovery of the Idaho-allocated portion of Idaho Power's cash contributions to its
defined benefit pension plan from the then-current amount of $5.4 million to approximately $17.1 million annually. On May 19, 2011,
the IPUC approved Idaho Power's application, with new rates effective on June 1, 2011. In September 2011, Idaho Power contributed
an additional $18.5 million to its defined benefit pension plan and during 2012 contributed $44.3 million.
The order issued by the IPUC pertaining to the December 2011 Idaho settlement agreement described above provided that Idaho
Power's allocation to customers of 75 percent of Idaho Power's share of 2011 Idaho ROE over 10.5 percent would be in the form of a
$20.3 million reduction to Idaho Power's pension regulatory asset to reduce the future customer obligation.
Energy Efficiency and Demand Response Programs: Idaho Power has implemented and/or manages a wide range of opportunities
for its customers to participate in energy efficiency and demand response programs. Typically, a majority of energy efficiency
activities are funded through a rider mechanism on customer bills. Program expenditures are reported as an operating expense with an
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equal amount of revenues recorded in other revenues, resulting in no impact on earnings. The cumulative variance between
expenditures and amounts collected through the rider is recorded as a regulatory asset or liability pending future collection from or
obligation to customers. In the 2012 PCA filing, $14.5 million of certain demand response program costs were shifted from the rider
mechanism to the PCA mechanism, as these costs are closely related to and directly impact the other power supply costs collected
through the PCA.
On March 15, 2012, Idaho Power filed an application with the IPUC requesting an order designating Idaho Power's 2011 demand-side
management expenditures of $42.6 million as prudently incurred. On October 22, 2012 and December 11, 2012, the IPUC issued
orders approving as prudently incurred $42.5 million of demand-side management expenditures, and deferring a portion of Idaho
Power's additional requested amount for further review. Of Idaho Power's 2011 demand-side management expenditures,
approximately $36 million were funded through a rider mechanism on customer bills and approximately $7 million were recorded as a
regulatory asset. As of December 31, 2012, the Idaho energy efficiency rider balance was a regulatory liability of $4.1 million. Idaho
Power's previous application filed in March 2011, which was approved by the IPUC in August 2011, designated Idaho Power's 2010
Idaho energy efficiency rider expenditures of approximately $42 million as prudently incurred expenses.
On October 31, 2012, Idaho Power filed an application with the IPUC requesting authorization to begin amortization and collection of
the 2011 portion of the regulatory asset associated with its custom efficiency program (a demand-side resources program) over a
four-year period, equal to approximately $2.9 million per year, including a carrying charge. A decision of the IPUC is pending.
The December 2011 IPUC general rate case settlement order also reset Idaho Power's energy efficiency rider rate at 4.0 percent of the
sum of the monthly billed charges for the base rate components, a reduction from the 4.75 percent rider amount in effect prior to that
date.
Cost Recovery for Cessation of Boardman Coal-Fired Operations: In December 2010, the Oregon Environmental Quality
Commission approved a plan to cease coal-fired operations at the Boardman power plant not later than December 31, 2020. The plan
results in increased revenue requirements for Idaho Power related to accelerated depreciation expense, additional plant investments,
and decommissioning costs. In response to an application filed by Idaho Power, on February 15, 2012 the IPUC issued an order
accepting Idaho Power's regulatory accounting and cost recovery plan associated with the early plant shut-down and approving the
establishment of a balancing account whereby incremental costs and benefits associated with the early shut-down will be tracked for
recovery in a subsequent proceeding. On May 17, 2012, the IPUC issued an order approving a $1.5 million annual increase in
Idaho-jurisdiction base rates, with new rates effective June 1, 2012. As of December 31, 2012, Idaho Power's net book value in the
Boardman plant was $23.1 million.
Idaho Depreciation Rate Filings: Idaho Power's advanced metering infrastructure (AMI) project provides the means to automatically
retrieve and store energy consumption information, eliminating manual meter reading expense. Commencing June 1, 2009, the IPUC
approved a rate increase, coincident with a related increase in depreciation expense, allowing Idaho Power to recover the three-year
accelerated depreciation of the existing non-AMI metering equipment and to begin earning a return on its AMI investment. On April
27, 2012, the IPUC approved Idaho Power's February 15, 2012 application requesting approval of a $10.6 million decrease in rates for
specified customer classes, effective June 1, 2012, as a result of the removal of accelerated depreciation expense associated with
non-AMI metering equipment.
In connection with a depreciation study authorized by Idaho Power and conducted by a third party, on February 15, 2012, Idaho Power
filed an application with the IPUC seeking to institute revised depreciation rates for electric plant-in-service, based upon updated
service life estimates and net salvage percentages for all plant assets, and adjust Idaho-jurisdiction base rates to reflect the revised
depreciation rates. Idaho Power's application requested a $2.7 million increase in Idaho-jurisdiction base rates. On May 31, 2012, the
IPUC issued an order approving a settlement stipulation agreed to by Idaho Power, the IPUC Staff, and a large industrial customer of
Idaho Power, which provided for a $1.3 million annual decrease in Idaho-jurisdiction base rates, effective June 1, 2012.
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Oregon Regulatory Matters
2011 Oregon General Rate Case: On July 29, 2011, Idaho Power filed a general rate case and proposed rate schedules with the
OPUC. The filing requested a $5.8 million increase in annual Oregon jurisdictional revenues and an authorized rate of return on
equity of 10.5 percent, with an Oregon retail rate base of approximately $121.9 million. Idaho Power, the OPUC Staff; and other
interested parties executed and filed a partial settlement stipulation with the OPUC on February 1, 2012, which resolved all matters in
the general rate case other than the prudence of costs associated with pollution control investments at the Jim Bridger coal plant. The
OPUC approved the settlement stipulation on February 23, 2012, which provided for a $1.8 million base rate increase, a return on
equity of 9.9 percent, and an overall rate of return of 7.757 percent in the Oregon jurisdiction. New rates in conformity with the
settlement stipulation were effective March 1, 2012. The OPUC is conducting a second phase of the proceedings to address the
prudence of Idaho Power's pollution control investments at the Jim Bridger plant.
Cost Recovery for Langley Gulch Power Plant: On March 9, 2012, Idaho Power filed an application with the OPUC requesting an
annual increase in Oregon jurisdiction revenues of $3.0 million for inclusion of the Langley Gulch power plant in Idaho Power's
Oregon rate base. On September 20, 2012, the OPUC issued an order approving an approximately $3.0 million increase in annual
Oregon jurisdiction base rates effective October 1, 2012.
Federal Regulatory Matters - Open Access Transmission Tariff Rates
In 2006, Idaho Power moved from a fixed rate to a formula rate for transmission service provided under its open access transmission
tariff (OATT), which allows transmission rates to be updated annually based on financial and operational data Idaho Power files with
the FERC. Idaho Power's OATT rates submitted to the FERC in Idaho Power's four most recent annual OATT Final Informational
Filings were as follows:
OATT Rate
Applicable Period (per kW-year)
October 1, 2012 to September 30, 2013 $ 21.32
October 1, 2011 to September 30, 2012 $ 19.79
October 1, 2010 to September 30, 2011 $ 19.60
Idaho Power's most recent OATT filing was based on a net annual transmission revenue requirement of$ 108.4 million.
IFERC FORM NO. 1 (ED. 12-88) Page 123.13 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 04/1512013 2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
4. LONG-TERM DEBT
The following table summarizes Idaho Power's long-term debt at December 31 (in thousands of dollars):
2012 2011
First mortgage bonds:
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
2.95% Series Due 2022
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
4.30% Series due 2042
70,000
120,000
100,000
130,000
100,000
75,000
100,000
70,000
50,000
55,000
60,000
140,000
100,000
100,000
75,000
100,000
70,000
120,000
100,000
130,000
100,000
100,000
70,000
50,000
55,000
60,000
140,000
100,000
100,000
Total first mortgage bonds 1,345,000 1,295,000
Pollution control revenue bonds:
5.15% Series due 2024(1) 49,800 49,800
5.25% Series due 2026(1) 116,300 116,300
Variable Rate Series 2000 due 2027 4,360 4,360
Total pollution control revenue bonds 170,460 170,460
American Falls bond guarantee 19,885 19,885
Milner Dam note guarantee 5,318 6,382
Unamortized premium/discount - net (2,967) (3,113)
Total Idaho Power outstanding debt(2) 1,537,696 1,488,614
Current maturities of long-term debt (71,064) (101,064)
Total long-term debt $ 1,466,632 $ 1,387,550
(1)Humboldt County and Sweetwater County Pollution Control Revenue Bonds are secured by the first mortgage, bringing the total first mortgage bonds
outstanding at December 31, 2012 to $1.511 billion.
(2)At December 31, 2012 and 2011, the overall effective cost of Idaho Power's outstanding debt was 5.44 percent and 5.43 percent, respectively.
At December 31, 2012, the maturities for the aggregate amount of long-term debt outstanding were as follows (in thousands of
dollars):
2013 2014 2015 2016 2017 Thereafter
$ 71,064 $ 1,064 $ 1,064 $ 1,064 $ 1,064 $ 1,465,343
Idaho Power Long-Term Financing
In May 2010, Idaho Power registered with the SEC the issuance of up to $500 million of first mortgage bonds and debt securities. On
June 17, 2010, Idaho Power entered into a selling agency agreement with ten banks named in the agreement in connection with the
potential issuance and sale from time to time of up to $500 million aggregate principal amount of first mortgage bonds. In August
2010, Idaho Power issued $100 million of 3.40% first mortgage bonds, medium-term notes, Series I maturing in August 2020, and
$100 million of 4.85% first mortgage bonds, medium-term notes, Series I maturing in August 2040. On April 13, 2012, Idaho Power
issued $75 million of 2.95% first mortgage bonds, medium-term notes, Series I, maturing on April 1, 2022, and $75 million of 4.30%
first mortgage bonds, medium-term notes, Series I, maturing on April 1, 2042. The first mortgage bonds were issued under Idaho
IFERC FORM NO. I (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 04/15/2013 2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Power's shelf registration statement. As a result of these issuances, as of December 31, 2012, $150 million remained on Idaho Power's
shelf registration for the issuance of first mortgage bonds and debt securities.
In May 2012, Idaho Power used a portion of the net proceeds of the April 2012 sale of first mortgage bonds, medium-term notes to
effect the early redemption in full of its $100 million of 4.75% first mortgage bonds, medium-term notes due November 2012.
Mortgage: As of December 31, 2012, Idaho Power could issue under its Indenture of Mortgage and Deed of Trust, dated as of
October 1, 1937, between Idaho Power and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company)
and R.G. Page, as Trustees (Stanley Burg, successor individual trustee) (Mortgage) approximately $1.4 billion of additional first
mortgage bonds based on retired first mortgage bonds and total unfunded property additions. These amounts are further limited by the
maximum amount of first mortgage bonds set forth in the Mortgage.
The Mortgage secures all bonds issued under the indenture equally and ratably, without preference, priority, or distinction. First
mortgage bonds issued in the future will also be secured by the Mortgage. The lien of the indenture constitutes a first mortgage on all
the properties of Idaho Power, subject only to certain limited exceptions including liens for taxes and assessments that are not
delinquent and minor excepted encumbrances. Certain of the properties of Idaho Power are subject to easements, leases, contracts,
covenants, workmen's compensation awards, and similar encumbrances and minor defects and clouds common to properties. The
Mortgage does not create a lien on revenues or profits, or notes or accounts receivable, contracts or choses in action, except as
permitted by law during a completed default, securities, or cash, except when pledged, or merchandise or equipment manufactured or
acquired for resale. The Mortgage creates a lien on the interest of Idaho Power in property subsequently acquired, other than excepted
property, subject to limitations in the case of consolidation, merger, or sale of all or substantially all of the assets of Idaho Power. The
Mortgage requires Idaho Power to spend or appropriate 15 percent of its annual gross operating revenues for maintenance, retirement,
or amortization of its properties. Idaho Power may, however, anticipate or make up these expenditures or appropriations within the
five years that immediately follow or precede a particular year.
On February 17, 2010, Idaho Power entered into the Forty-fifth Supplemental Indenture, dated as of February 1, 2010, to the Mortgage
for the purpose of increasing the maximum amount of first mortgage bonds issuable by Idaho Power from $1.5 billion to $2.0 billion.
The amount issuable is also restricted by property, earnings, and other provisions of the Mortgage and supplemental indentures to the
Mortgage. Idaho Power may amend the Mortgage and increase this amount without consent of the holders of the first mortgage bonds.
The Mortgage requires that Idaho Power's net earnings be at least twice the annual interest requirements on all outstanding debt of
equal or prior rank, including the bonds that Idaho Power may propose to issue. Under certain circumstances, the net earnings test
does not apply, including the issuance of refunding bonds to retire outstanding bonds that mature in less than two years or that are of an
equal or higher interest rate, or prior lien bonds.
5. NOTES PAYABLE
Credit Facilities
Idaho Power has $300 million credit facility which may be used for general corporate purposes and commercial paper backup. Idaho
Power's credit facility consists of a revolving line of credit, through the issuance of loans and standby letters of credit, not to exceed the
aggregate principal amount at any one time outstanding of $300 million, including swingline loans in an aggregate principal amount at
any time outstanding not to exceed $30 million. Idaho Power has the right to request an increase in the aggregate principal amount of
the facility to $450 million, subject to certain conditions.
The interest rate for any borrowings under the facility is based on either (1) a floating rate that is equal to the highest of the prime rate,
federal funds rate plus 0.5 percent, or LIBOR rate plus 1.0 percent, or (2) the LIBOR rate, plus, an applicable margin. The margin is
based on Idaho Power's senior unsecured long-term indebtedness credit rating by Moody's Investors Service, Inc., Standard and Poor's
Ratings Services, and Fitch Rating Services, Inc., as set forth on a schedule to the credit agreement. Under the facility, Idaho Power
pays a facility fee on the commitment based on Idaho Power's credit rating for senior unsecured long-term debt securities. While the
credit facility provides for an original maturity date of October 26, 2016, the credit agreement grants Idaho Power the right to request
up to two one-year extensions, subject to certain conditions. On October 12, 2012, Idaho Power executed First Extension Agreements
with each of the lenders, extending the maturity date under the agreement to October 26, 2017.
IFERC FORM NO. I (ED. 12-88) Page 123.15
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)_ A Resubmission 04/15/2013 20121Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
At December 31, 2012, no amounts were outstanding under Idaho Power's facility. At December 31, 2012, Idaho Power had
regulatory authority to incur up to $450 million principal amount of short-term indebtedness at any one time outstanding. Balances (in
thousands of dollars) and interest rates of Idaho Power's short-term borrowings were as follows at December 31:
2012
Commercial paper balances:
At the end of year $ - $ -
Average during the year $ 3,578 $ -
Weighted-average interest rate
At the end of the year
6.COMMON STOCK
Idaho Power Common Stock
In 2012 and 2011, IDACORP contributed $7.5 million and $16 million, respectively, of additional equity to Idaho Power. No
additional shares of Idaho Power common stock were issued in exchange for the contributions.
Restrictions on Dividends
A covenant under Idaho Power's credit facility requires Idaho Power to maintain a leverage ratio of consolidated indebtedness to
consolidated total capitalization, as defined therein, of no more than 65 percent at the end of each fiscal quarter. Idaho Power's ability
to pay dividends on its common stock held by IDACORP is limited to the extent payment of such dividends would violate the
covenants in the credit facility or Idaho Power's Revised Code of Conduct. At December 31, 2012, the leverage ratio for Idaho Power
was 49 percent. Based on these restrictions, Idaho Power's dividends were limited to $794 million at December 31, 2012. There are
additional facility covenants, subject to exceptions, that prohibit certain mergers, acquisitions, and investments; restrict the creation of
certain liens; and prohibit entering into any agreements restricting dividend payments to Idaho Power from any material subsidiary. At
December 31, 2012, Idaho Power was in compliance with all facility covenants.
Idaho Power's Revised Code of Conduct, approved by the IPUC on April 21, 2008, states that Idaho Power will not pay any dividends
to IDACORP that will reduce Idaho Power's common equity capital below 35 percent of its total adjusted capital without IPUC
approval. At December 31, 2012, Idaho Power's common equity capital was 51 percent of its total adjusted capital. Further, Idaho
Power must obtain the approval of the OPUC before it may directly or indirectly loan finds or issue notes or give credit on its books to
IDACORP.
Idaho Power's articles of incorporation also contain restrictions on the payment of dividends on its common stock if preferred stock
dividends are in arrears. As of the date of this report, Idaho Power has no shares of preferred stock outstanding.
In addition to contractual restrictions on the amount and payment of dividends, the Federal Power Act prohibits the payment of
dividends from "capital accounts." The term "capital accounts" is undefined in the Federal Power Act but could be interpreted to limit
the payment of dividends by Idaho Power to the amount of Idaho Power's retained earnings.
In accordance with Section 10(d) of the Federal Power Act, Idaho Power has $3.4 million of amortization reserves established for
certain of its licensed hydroelectric facilities.
7.STOCK-BASED COMPENSATION
Through its parent company IDACORP, Idaho Power has two share-based compensation plans -- the 2000 Long-Term Incentive and
Compensation Plan (LTICP) and the 1994 Restricted Stock Plan (RSP). These plans are intended to align employee and shareholder
objectives related to IDACORP's long-term growth.
IFERC FORM NO. I (ED. 12-88) Page 123.16 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 04/15/2013 2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
The LTICP (for officers, key employees, and directors) permits the grant of nonqualified stock options, restricted stock, performance
shares, and several other types of stock-based awards. The RSP permits only the grant of restricted stock or performance-based
restricted stock. At December 31, 2012, the maximum number of shares available under the LTICP and RSP were 1,371,305 and
15,796, respectively.
Stock Awards: Restricted stock awards have three-year vesting periods and entitle the recipients to dividends and voting rights.
Unvested shares are restricted as to disposition and subject to forfeiture under certain circumstances. The fair value of these awards is
based on the closing market price of common stock on the grant date and is charged to compensation expense over the vesting period,
based on the number of shares expected to vest.
Performance-based restricted stock awards have three-year vesting periods and entitle the recipients to voting rights. Unvested shares
are restricted as to disposition, subject to forfeiture under certain circumstances, and subject to the attainment of specific performance
conditions over the three-year vesting period. Based on the level of attainment of the performance conditions, the final number of
shares awarded can range from zero to 150 percent of the target award. Dividends are accrued during the vesting period and paid out
based on the final number of shares awarded.
The performance awards are based on two equally-weighted metrics, cumulative earnings per share (CEPS) and total shareholder
return (TSR) relative to a peer group. The fair value of the CEPS portion is based on the closing market value at the date of grant,
reduced by the loss in time-value of the estimated future dividend payments. The fair value of these awards is charged to
compensation expense over the requisite service period, based on the number of shares expected to vest. The fair value of the TSR
portion is estimated using the market value at the date of grant and a statistical model that incorporates the probability of meeting
performance targets based on historical returns relative to the peer group. The fair value of these awards is charged to compensation
expense over the requisite service period, provided the requisite service period is rendered, regardless of the level of TSR metric
attained.
A summary of restricted stock and performance share activity is presented below.
Nonvested shares at January 1, 2012
Shares granted
Shares forfeited
Shares vested
Nonvested shares at December 31, 2012
Number of
Shares
337,183
120,549
(2,098)
(138,923)
316,711
Weighted-Average
Grant Date
Fair Value
$ 26.40
37.56
35.59
22.42
$ 32.32
The total fair value of shares vested during the years ended December 31, 2012 and 2011 was $4.8 million and $4.1 million,
respectively. At December 31, 2012, Idaho Power had $4.7 million of total unrecognized compensation cost related to nonvested
share-based compensation that was expected to vest. These costs are expected to be recognized over a weighted-average period of
1.71 years. IDACORP uses original issue and/or treasury shares for these awards.
In 2012, a total of 14,820 shares of IDACORP common stock were awarded to directors of IDACORP and Idaho Power at a grant date
fair value of $40.48 per share. Directors elected to defer receipt of 7,410 of these shares, which are being held as deferred stock units
with dividend equivalents reinvested in additional stock units.
Stock Options: No stock options have been granted since 2006. The remaining unexercised stock option awards were granted with
exercise prices equal to the market value of the stock on the date of grant, with a term of 10 years from the grant date and a five-year
vesting period. The fair value of each option was amortized into compensation expense using graded vesting and, as of December 31,
2012, all compensation costs have been recognized. Idaho Power uses IDACORP's original issue and/or treasury shares to satisfy
exercised options.
IFERC FORM NO. I (ED. 12-88) Page 123.17
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 04/15/2013 2012/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Idaho Power's stock option transactions are summarized below. Idaho Power share amounts represent the portion of IDACORP
amounts related to Idaho Power employees:
Number Weighted- Weighted Aggregate
of Average Average Intrinsic
Shares Exercise Remaining Value
Price Contractual (000s)
Term (Years)
Idaho Power
Outstanding at December 31, 2011 9,456 $ 33.67 1.58 $ 83
Exercised (1,500) 28.45
Expired (4,000) 39.50
Outstanding at December 31, 2012 3,956 $ 29.75 2.05 $ 54
Vested and exercisable at December 31, 2012 3,956 $ 29.75 2.05 $ 54
The following table presents information about options vested and exercised (in thousands of dollars):
2012 2011
Fair value of options vested $ - $ -
Intrinsic value of options exercised 36 535
Cash received from exercises 77 3,838
Tax benefits realized from exercises 14 209
Compensation Expense: The following table shows the compensation cost recognized in income and the tax benefits resulting from
these plans, as well as the amounts allocated to Idaho Power for those costs associated with Idaho Power's employees (in thousands of
dollars):
2012 2011
Compensation cost $ 4,577 $ 4,082
Income tax benefit 1,789 1,596
No equity compensation costs have been capitalized.
8. COMMITMENTS
Purchase Obligations
At December 31, 2012, Idaho Power had the following long-term commitments relating to purchases of energy, capacity, transmission
rights, and fuel (in thousands of dollars):
2013 2014 2015 2016 2017 Thereafter
Cogeneration and power production $170,939 $182,123 $187,151 $189,880 $188,734 $ 2,938,582
Power and transmission rights 6,408 5,035 4,320 3,992 2,840 4,743
Fuel 73,627 63,236 56,942 9,418 9,317 94,849
As of December 31, 2012, Idaho Power had 779 MW nameplate capacity of PUIRPA-related projects on-line, with an additional 52
MW nameplate capacity of projects projected to be on-line by the end of 2014. The power purchase contracts for these projects have
terms ranging from one to 35 years. During 2012, Idaho Power purchased 1,961,208 megawatt-hours (MWh) from these projects at a
cost of $118 million, resulting in a blended price of $59.98 per MWh. Idaho Power purchased 1,495,108 MWh at a cost of $90
million in20ll.
IFERC FORM NO. 1 (ED. 12-88) Page 123.18
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 04/15/2013 2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
In addition, Idaho Power has the following long-term commitments for lease guarantees, equipment, maintenance and services, and
industry related fees (in thousands of dollars):
2013 2014 2015 2016 2017 Thereafter
Operating leases $ 1,888 $ 2,116 $ 2,123 $ 1,243 $ 955 $ 15,741
Equipment, maintenance, and service agreements 35,233 9,483 5,464 4,277 4,484 21,176
FERC and other industry-related fees 13,789 11,066 11,066 7,472 7,472 37,361
Idaho Power's expense for operating leases was approximately $6.0 million in 2012 and $5.2 million in 2011.
Guarantees
Idaho Power has agreed to guarantee a portion of the performance of reclamation activities and obligations at BCC, of which IERCo
owns a one-third interest. This guarantee, which is renewed each December, was $66 million at December 31, 2012, representing
IERCo's one-third share of BCC's total reclamation obligation of $199 million. BCC has a reclamation trust fund set aside specifically
for the purpose of paying these reclamation costs. As of December 31, 2012, the value of the reclamation trust iliad totaled $72
million. During 2012 the reclamation trust fund distributed approximately $20 million for reclamation activity costs associated with
the BCC surface mine. BCC periodically assesses the adequacy of the reclamation trust find and its estimate of future reclamation
costs. To ensure that the reclamation trust fund maintains adequate reserves, BCC has the ability to add a per-ton surcharge to coal
sales, all of which are made to the Jim Bridger plant. Starting in 2010, BCC began applying a nominal surcharge to coal sales in order
to maintain adequate reserves in the reclamation trust fund. Because of the existence of the Iliad and the ability to apply a per-ton
surcharge, the estimated fair value of this guarantee is minimal.
Idaho Power enters into financial agreements and power purchase and sale agreements that include indemnification provisions relating
to various forms of claims or liabilities that may arise from the transactions contemplated by these agreements. Generally, a maximum
obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under
such indemnification provisions cannot be reasonably estimated. Idaho Power periodically evaluates the likelihood of incurring costs
under such indemnities based on historical experience and the evaluation of the specific indemnities. As of December 31, 2012,
management believes the likelihood is remote that Idaho Power would be required to perform under such indemnification provisions or
otherwise incur any significant losses with respect to such indemnification obligations. Idaho Power has not recorded any liability on
the consolidated balance sheet with respect to these indemnification obligations.
9. CONTINGENCIES
Idaho Power has in the past and expects in the future to become involved in various claims, controversies, disputes, and other
contingent matters, including the items described in this Note 9. Some of these claims, controversies, disputes, and other contingent
matters involve litigation and regulatory or other contested proceedings. The ultimate resolution and outcome of litigation and
regulatory proceedings is inherently difficult to determine, particularly where (a) the remedies or penalties sought are indeterminate,
(b) the proceedings are in the early stages or the substantive issues have not been well developed, or (c) the matters involve complex or
novel legal theories or a large number of parties. In accordance with applicable accounting guidance, Idaho Power establishes an
accrual for legal proceedings when those matters proceed to a stage where they present loss contingencies that are both probable and
reasonably estimable. In such cases, there may be a possible exposure to loss in excess of any amounts accrued. Idaho Power
monitors those matters for developments that could affect the likelihood of a loss and the accrued amount, if any, thereof, and adjust
the amount as appropriate. If the loss contingency at issue is not both probable and reasonably estimable, Idaho Power does not
establish an accrual and the matter will continue to be monitored for any developments that would make the loss contingency both
probable and reasonably estimable. As of the date of this report, Idaho Power's accrual for loss contingencies is not material to the
financial statements as a whole; however, future accruals could be material in a given period. Idaho Power's determination is based on
currently available information, and estimates presented in financial statements and other financial disclosures involve significant
judgment and may be subject to significant uncertainty. As available information changes, the matters for which Idaho Power is able
to estimate the loss may change, and the estimates themselves may change. For matters that affect Idaho Power's operations, Idaho
Power intends to seek, to the extent permissible and appropriate, recovery through the ratemaking process of costs incurred.
IFERC FORM NO. I (ED. 12-88) Page 123.19 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
Idaho Power Company (2)- A Resubmission 04/15/2013 2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Western Energy Proceedings
High prices for electricity, energy shortages, and blackouts in California and in western wholesale markets during 2000 and 2001
caused numerous purchasers of electricity in those markets to initiate proceedings seeking refunds or other forms of relief and the
FERC to initiate its own investigations. Some of these proceedings remain pending before the FERC or are on appeal to the United
States Court of Appeals for the Ninth Circuit. Idaho Power and IESCo (as successor to IE) believe that settlement releases they have
obtained will restrict potential claims that might result from the disposition of pending petitions and predict that these matters will not
have a material adverse effect on Idaho Power's results of operations or financial condition. However, the settlements and associated
FERC orders have not fully eliminated the potential for so-called "ripple claims," which involve potential claims for refunds from an
upstream seller of power based on a finding that its downstream buyer was liable for refunds as a seller of power during the relevant
period. The FERC characterized these ripple claims as "speculative." However, the FERC refused to dismiss Idaho Power and IESCo
from the proceedings in the Pacific Northwest and refused to approve a settlement that provided for waivers of all claims in those
proceedings, despite only limited objections from two market participants. Idaho Power and IESCo have petitioned for review of the
FERC's decision. Based on its evaluation of the merits of such claims and the inability to estimate any potential exposure should the
claims ultimately have merit, Idaho Power and IESCo have no remaining amount accrued for financial statement purposes relating to
the western energy proceedings. To the extent the availability of any ripple claims materializes, Idaho Power and IESCo will continue
to vigorously defend their positions in the proceedings.
Water Rights - Snake River Basin Adjudication
Idaho Power holds water rights, acquired under applicable state law, for its hydroelectric projects. In addition, Idaho Power holds
water rights for domestic, irrigation, commercial, and other necessary purposes related to project lands and other holdings within the
states of Idaho and Oregon. Idaho Power's water rights for power generation are, to varying degrees, subordinated to future upstream
appropriations for irrigation and other authorized consumptive uses. Over time, increased irrigation development and other
consumptive uses within the Snake River watershed led to a reduction in flows of the Snake River. In the late 1970s and early 1980s
these reduced flows resulted in a conflict between the exercise of Idaho Power's water rights at certain hydroelectric projects on the
Snake River and upstream consumptive diversions. The Swan Falls Agreement, signed by Idaho Power and the State of Idaho on
October 25, 1984, resolved the conflict and provided a level of protection for Idaho Power's hydropower water rights at specified
projects on the Snake River through the establishment of minimum stream flows and an administrative process governing future
development of water rights that may affect those minimum stream flows. In 1987, Congress enacted legislation directing the FERC to
issue an order approving the Swan Falls settlement together with a finding that the agreement was neither inconsistent with the terms
and conditions of Idaho Power's project licenses nor the Federal Power Act. The FERC entered an order implementing the legislation
in March 1988.
The Swan Falls Agreement provided that the resolution and recognition of Idaho Power's water rights together with the State Water
Plan provided a sound comprehensive plan for management of the Snake River watershed. The Swan Falls Agreement also
recognized, however, that in order to effectively manage the waters of the Snake River basin, a general adjudication to determine the
nature, extent, and priority of the rights of all water uses in the basin was necessary. Consistent with that recognition, in 1987 the State
of Idaho initiated the Snake River Basin Adjudication (SRBA), and pursuant to the commencement order issued by the SRBA court
that same year, all claimants to water rights within the basin were required to file water rights claims in the SRBA. Idaho Power has
filed claims to its water rights and has been actively participating in the SRBA since its commencement. Questions concerning the
effect of the Swan Falls Agreement on Idaho Power's water rights claims, including the nature and extent of the subordination of Idaho
Power's rights to upstream uses, resulted in the filing of litigation in the SRBA in 2007 between Idaho Power and the State of Idaho.
This litigation was resolved by the Framework Reaffirming the Swan Falls Settlement (Framework) signed by Idaho Power and the
State of Idaho on March 25, 2009. In that Framework, the parties acknowledged that the effective management of Idaho's water
resources remains critical to the public interest of the State of Idaho by sustaining economic growth, maintaining reasonable electric
rates, protecting and preserving existing water rights, and protecting water quality and environmental values. The Framework further
provided that the State of Idaho and Idaho Power would cooperate in exploring approaches to resolve issues of mutual concern relating
to the management of Idaho's water resources. Idaho Power continues to work with the State of Idaho and other interested parties on
these issues.
IFERC FORM NO. I (ED. 12-88) Page 123.20 1
Name of Respondent This Report is: Date of Report Year/ Period of Report
(1)X An Original (Mo, Da, Yr)
Idaho Power Company (2)- A Resubmission 04/15/2013 2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
One such issue involves the management of the Eastern Snake Plain Aquifer (ESPA), a large underground aquifer in southeastern
Idaho that is hydrologically connected to the Snake River. House Concurrent Resolution No. 28, adopted by the Idaho Legislature in
2007, directed the Idaho Water Resource Board to pursue the development of a comprehensive management plan for the ESPA, to
include measures that would enhance aquifer levels, springs, and river flows on the eastern Snake River plain to the benefit of both
agricultural development and hydropower generation. In May of 2007, the Idaho Water Resource Board appointed an advisory
committee, charged with the responsibility of developing a management plan for the ESPA. Idaho Power was a member of that
committee. In January 2009, the Idaho Water Resource Board, based on the committee's recommendations, adopted a Comprehensive
Aquifer Management Plan (CAMP) for the ESPA. The Idaho Legislature approved the CAMP that same year. Idaho Power is a
member of the CAMP Implementation Committee and continues to work with the Idaho Water Resource Board, other stakeholders,
and the Idaho Legislature in exploring opportunities for implementation of the CAMP management plan.
Idaho Power also continues its active participation in the SRBA in seeking to ensure that its water rights are protected and that the
operation of its hydroelectric projects is not adversely impacted. While Idaho Power cannot predict the outcome, as of the date of this
report Idaho Power does not anticipate any material modification of its water rights as a result of the SRBA process.
Other Proceedings
Idaho Power is party to legal claims and legal and regulatory actions and proceedings in the ordinary course of business that are in
addition to those discussed above and, as noted above, records an accrual for associated loss contingencies when they are probable and
reasonably estimable. As of the date of this report Idaho Power believes that resolution of those matters will not have a material
adverse effect on the consolidated financial statements. Idaho Power is also actively monitoring various environmental regulations
that may have a significant impact on its future operations. Given uncertainties regarding the outcome, timing, and compliance plans
for these environmental matters, Idaho Power is unable to determine the financial impact of these regulations but does believe that
future capital investment for infrastructure and modifications to its electric generating facilities to comply with these regulations could
be significant.
10. BENEFIT PLANS
Idaho Power sponsors defined benefit and other postretirement benefit plans that cover the majority of its employees. Through its
parent company IDACORP, Idaho Power also sponsors a defined contribution 40 1(k) employee savings plan and provides certain
post-employment benefits.
Pension Plans
Idaho Power's pension plans include a noncontributory defined benefit pension plan (pension plan) and a nonqualifled defined benefit
plan for certain senior management employees and directors called the Senior Management Security Plan (SMSP). The benefits under
these plans are based on years of service and the employee's final average earnings.
Idaho Power's funding policy for its pension plan is to contribute at least the minimum required under the Employee Retirement
Income Security Act of 1974 (ERISA) but not more than the maximum amount deductible for income tax purposes. In 2012 and 2011
Idaho Power elected to contribute more than the minimum required amounts in order to bring the pension plan to a more funded
position, to reduce future required contributions, and to reduce Pension Benefit Guaranty Corporation premiums.
IFERC FORM NO. I (ED. 12-88) Page 123.21 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
Idaho Power Company (2)- A Resubmission 04/15/2013 2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
The following table summarizes the changes in benefit obligations and plan assets of these plans (in thousands of dollars):
Pension Plan SMSP
2012 2011 2012 2011
Change In benefit obligation:
Benefit obligation at January 1
Service cost
Interest cost
Actuarial loss
Benefits paid
Benefit obligation at December 31
Change in plan assets:
Fair value at January 1
Actual return on plan assets
Employer contributions
Benefits paid
Fair value at December31
Funded status at end of year
Amounts recognized in the statement of financial position consist of:
Other current liabilities
Noncurrent liabilities
Net amount recognized
Amounts recognized in accumulated other comprehensive income consist of:
Net loss
Prior service cost
Subtotal
Less amount recorded as regulatory asset
Net amount recognized in accumulated other comprehensive income
Accumulated benefit obligation
$ 655,439 $ 569,934 $ 65,043 $ 59,126
25,571 20,478 2,151 1,950
31,489 30,322 3,218 3,094
77,328 55,535 13,335 4,251
(22,135) (20,830) (3,232) (3,378)
767,692 655,439 80,515 65,043
390,081 397,003 - -
48,616 (4,592) - -
44,300 18,500 - -
(22,135) (20,830) - -
460,862 390,081 - -
$ (306,830) $ (265,358) $ (80,515) $ (65,043)
$ - $ - $ (3,651) $ (3,496)
(306,830) (265,358) (76,864) (61,547)
$ (306,830) $ (265,358) $ (80,515) $ (65,043)
291,966 $ 245,632
989 1,335
292,955 246,967
(292,955) (246,967)
$ - $ - $ 34,894 $ 23,301
$ 640,330 $ 549,503 $ 72,288 $ 59,836
$ 33,605 $ 21,799

1,289 1,502

34,894 23,301
As a non-qualified plan, the SMSP has no plan assets. However, Idaho Power has a Rabbi trust designated to provide funding for
SMSP obligations. The Rabbi trust holds investments in marketable securities and corporate-owned life insurance. These investments
totaled approximately $50.4 million and $41.2 million at December 31, 2012 and 2011, respectively, and are reflected in Investments
and Company-owned life insurance on the consolidated balance sheets.
The table that follows shows the components of net periodic benefit cost for these plans (in thousands of dollars). For purposes of
calculating the expected return on plan assets, the market-related value of assets is equal to the fair value of the assets.
Pension Plan SMSP
2012 2011 2012 2011
Service cost $ 25,571 $ 20,478 $ 2,151 $ 1,950
Interest cost 31,489 30,322 3,218 3,094
Expected return on assets (31,737) (32,322) - -
Amortization of net loss 14,114 8,673 1,530 1,293
Amortization of prior service cost 347 519 212 242
Net periodic pension cost 39,784 27,670 7,111 6,579
Adjustments due to the effects of regulation(1) (5,860) 6,662 - -
Net periodic benefit cost recognized for
financial reporting $ 33,924 $ 34,332 $ 7,111 $ 6,579
(I) Net periodic benefit costs for the pension plan are recognized for financial reporting based upon the authorization of each regulatory jurisdiction in which Idaho
Power operates. Under IPUC order, income statement recognition of pension plan costs is deferred until costs are recovered through rates. See Note 3 for information
on Idaho Power's revenue sharing mechanism approved by the IPUC, which resulted in additional Idaho pension expense of $14.6 million and $20.3 million in 2012
and 2011, respectively.
IFERC FORM NO. 1 (ED. 12-88) Page 123.22 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
Idaho Power Company (2)- A Resubmission 04/15/2013 2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
The following table shows the components of other comprehensive income for the plans (in thousands of dollars):
Pension Plan SMSP
2012 2011 2012 2011
Actuarial loss during the year $ (60,448) $ (92,449) $ (13,335) $ (4,251)
Reclassification adjustments for:
Amortization of net loss 14,114 8,673 1,530 1,293
Amortization of prior service cost 347 519 212 242
Adjustment for deferred tax effects 17,979 32,193 4,532 1,062
Adjustment due to the effects of regulation 28,008 51,064 - -
Other comprehensive income recognized related to
pension benefit plans $ - $ - $ (7,061) $ (1,654)
In 2013, Idaho Power expects to recognize as components of net periodic benefit cost $20.4 million from amortizing amounts recorded
in accumulated other comprehensive income (or as a regulatory asset for the pension plan) as of December 31, 2012, relating to the
pension plan and SMSP. This amount consists of $17.0 million of amortization of net loss and $0.4 million of amortization of prior
service cost for the pension plan, and $2.8 million of amortization of net loss and $0.2 million of amortization of prior service cost for
the SMSP.
The following table summarizes the expected future benefit payments of these plans (in thousands of dollars):
2013 2014 2015 2016 2017 2018-2022
Pension Plan $ 23,882 $ 25,591 $ 27,490 $ 29,729 $ 32,179 $ 199,630
SMSP 3,721 3,948 4,130 4,129 4,326 23,932
As of December 31, 2012, Idaho Power's minimum required contributions to the pension plan is estimated to be zero in 2013. Idaho
Power may elect to make discretionary contributions above the minimum funding requirements or at times earlier than the required
dates.
Postretirement Benefits
Idaho Power maintains a defined benefit postretirement benefit plan (consisting of health care and death benefits) that covers all
employees who were enrolled in the group plan at the time of retirement as well as their spouses and qualifying dependents. Retirees
hired on or after January 1, 1999 have access to the standard medical option at full cost, with no contribution by Idaho Power.
Benefits for employees who retire after December 31, 2002 are limited to a fixed amount, which has limited the growth of Idaho
Power's future obligations under this plan.
IFERC FORM NO. 1 (ED. 12-88) Page 123.23 1
$ 66,669
1,292
3,135
3,180
(1,729)
72,547
31,901
3,346
(131)
(1,729)
33,387
$ (39,160)
$ 68,048
1,323
3,434
(2,850)
(2,968)
(318)
66,669
33,176
1,065
628
(2,968)
31,901
$ (34,768)
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 04/15/2013 2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
The following table summarizes the changes in benefit obligation and plan assets (in thousands of dollars):
2012 2011
Change in accumulated benefit obligation:
Benefit obligation at January 1
Service cost
Interest cost
Actuarial loss (gain)
Benefits paid(1 ) Plan amendments
Benefit obligation at December 31
Change in plan assets:
Fair value of plan assets at January 1
Actual return on plan assets
Employer contributions(l)
Bemfit paid(l)
Fair value of plan assets at December 31
Funded status at end of year (included in noncurrent liabilities)
(1) Contributions and benefits paid are each net of $3,268 and $3,405 of plan participant contributions, and $430 and $444 of Medicare Part D subsidy receipts for
2012 and 2011, respectively.
Amounts recognized in accumulated other comprehensive income consist of the following (in thousands of dollars):
2012 2011
Net loss
Prior service cost (credit)
Transition obligation
Subtotal
Less amount recognized in regulatory assets
Less amount included in deferred tax assets
Net amount recognized in accumulated other comprehensive income
$ 15,796
99
15,895
(15,895)
$
$ 14,112
(323)
2,040
15,829
(15,536)
(293)
$
The net periodic postretirement benefit cost was as follows (in thousands of dollars):
2012
Service cost $ 1,292
Interest cost 3,135
Expected return on plan assets (2,234)
Amortization of net loss 384
Amortization of prior service cost (422)
Amortization of unrecognized transition obligation 2,040
Net periodic postretirement benefit cost $ 4,195
2011
$ 1,323
3,434
(2,641)
577
(421)
2,040
$ 4,312
IFERC FORM NO. I (ED. 12-88) Page 123.24
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 04/15/2013 20121Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
The following table shows the components of other comprehensive income for the plan (in thousands of dollars):
Actuarial (loss) gain during the year
Prior service cost arising during the year
Reclassification adjustments for:
Amortization of net loss
Amortization of prior service cost
Amortization of unrecognized transition obligation
Adjustment for deferred tax effects
Adjustment due to the effects of regulation
Other comprehensive income related to postretirement benefit plans
2012
$ (2,068)
384
(422)
2,040
(153)
219
$
2011
$ 1,274
318
577
(421)
2,040
(1,659)
(2,129)
$
In 2013, Idaho Power expects to recognize as components of net periodic benefit cost $0.6 million from amortizing amounts recorded
in accumulated other comprehensive income as of December 31, 2012, relating to the postretirement benefit plan. This amount
consists of $0.7 million of amortization of net loss and $(0. 1) million of amortization of prior service cost.
Medicare Act: The Medicare Prescription Drug, Improvement and Modernization Act of 2003 was signed into law in December 2003
and established a prescription drug benefit under Medicare Part D, as well as a federal subsidy to sponsors of retiree health care benefit
plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare's prescription drug coverage.
The following table summarizes the expected future benefit payments of the postretirement benefit plan and expected Medicare Part D
subsidy receipts (in thousands of dollars):
2013 2014 2015 2016 2017 2018-2022
Expected benefit payments $ 4,010 $ 4,180 $ 4,320 $ 4,430 $ 4,530 $ 23,420
Expected Medicare Part D subsidy receipts 480 520 560 620 670 4,360
Plan Assumptions
The following table sets forth the weighted-average assumptions used at the end of each year to determine benefit obligations for all
Idaho Power-sponsored pension and postretirement benefits plans:
Postretirement
Pension Plan SMSP Benefits
2012 2011 2012 2011 2012 2011.
4.20% 4.90% 4.15% 5.10% 4.20% 5.05%
4.35% 4.35% 4.50% 4.50%
- - - - 6.5% 7.0%
- - - - 5.0% 5.0%
12/31/2012 12/31/2011 12/31/2012 12/31/2011 12/31/2012 12/31/2011
Discount rate
Rate of compensation increase(l)
Medical trend rate
Dental trend rate
Measurement date
(1) The 2012 rate of compensation increase assumption for the pension plan includes an inflation component of 2.75% plus a 1.60% composite merit increase
component that is based on employees years of service. Merit salary increases are assumed to be 8.0% for employees in their first year of service and scale down to
0% for employees in their fortieth year of service and beyond.
IFERC FORM NO. I (ED. 12-88) Page 123.25 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 04/15/2013 2012/04
NOTES TO FINANCIAL STATEMENTS (Continued)
The following table sets forth the weighted-average assumptions used to determine net periodic benefit cost for all Idaho
Power-sponsored pension and postretirement benefit plans:
Discount rate
Expected long-term rate of return on assets
Rate of compensation increase

Pension Plan SMSP
2012 2011 2012 2011
4.90% 5.40% 5.10% 5.40%
7.75% 8.25% -
4.35% 4.50% 4.50% 4.50%
Postretirement
Benefit
2012 2011
5.05% 540 %
7.25% 8.25 %
Medical trend rate 6.5% 7.0%
Dental trend rate 5.0% 5.0 %
The assumed health care cost trend rate used to measure the expected cost of health benefits covered by the postretirement plan was
6.5 percent in 2012 and is assumed to decrease gradually to 4.9 percent by 2094. The assumed dental cost trend rate used to measure
the expected cost of dental benefits covered by the plan was 5.0 percent in 2012 and is assumed to decrease gradually to 4.9 percent by
2094. A one percentage point change in the assumed health care cost trend rate would have the following effects at December 31,
2012 (in thousands of dollars):
One-Percentage-Point

Increase Decrease
Effect on total of cost components $ 343 $ (255)
Effect on accumulated postretirement benefit obligation 3,482 (21708)
Plan Assets
Pension Asset Allocation Policy: The target allocation and actual allocations at December 31, 2012 for the pension asset portfolio by
asset class is set forth below.
Target Actual
Allocation Allocation
December 31,
Asset Class 2012
Debt securities 24% 24%
Equity securities 54% 55%
Real estate 6% 6%
Other plan assets 16% 15%
Total 100% 1000/0
Assets are rebalanced as necessary to keep the portfolio close to target allocations.
The plan's principal investment objective is to maximize total return (defined as the sum of realized interest and dividend income and
realized and unrealized gain or loss in market price) consistent with prudent parameters of risk and the liability profile of the portfolio.
Emphasis is placed on preservation and growth of capital along with adequacy of cash flow sufficient to fund current and future
payments to pensioners.
The three major goals in Idaho Power's asset allocation process are to:
• determine if the investments have the potential to earn the rate of return assumed in the actuarial liability calculations;
• match the cash flow needs of the plan. Idaho Power sets bond allocations sufficient to cover at least five years of benefit
payments and cash allocations sufficient to cover the current year benefit payments. Idaho Power then utilizes growth
instruments (equities, real estate, venture capital) to fund the longer-term liabilities of the plan; and
• maintain a prudent risk profile consistent with ERISA fiduciary standards.
IFERC FORM NO. I (ED. 12-88) Page 123.26 1
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)_ A Resubmission 04/15/2013 2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Allowable plan investments include stocks and stock funds, investment-grade bonds and bond funds, core real estate funds, private
equity funds, and cash and cash equivalents. With the exception of real estate holdings and private equity, investments must be readily
marketable so that an entire holding can be disposed of quickly with only a minor effect upon market price.
Rate-of-return projections for plan assets are based on historical risk/return relationships among asset classes. The primary measure is
the historical risk premium each asset class has delivered versus the return on 10-year U.S. Treasury Notes. This historical risk
premium is then added to the current yield on 10-year U.S. Treasury Notes, and the result provides a reasonable prediction of future
investment performance. Additional analysis is performed to measure the expected range of returns, as well as worst-case and
best-case scenarios. Based on the current low interest rate environment, current rate-of-return expectations are lower than the nominal
returns generated over the past 20 years when interest rates were generally much higher.
Idaho Power's asset modeling process also utilizes historical market returns to measure the portfolio's exposure to a "worst-case"
market scenario, to determine how much performance could vary from the expected "average" performance over various time periods.
This "worst-case" modeling, in addition to cash flow matching and diversification by asset class and investment style, provides the
basis for managing the risk associated with investing portfolio assets.
Fair Value of Plan Assets: Idaho Power classifies its pension plan and postretirement benefit plan investments using the three-level
fair value hierarchy described in Note 15. The following table presents the fair value of the plans' investments by asset category (in
thousands of dollars). If the inputs used to measure the securities fall within different levels of the hierarchy, the categorization is
based on the lowest level input (Level 3 being the lowest) that is significant to the fair value measurement of the security.
Level 1 Level 2 Level 3 Total
Assets at December 31, 2012
Pension assets:
Cash and cash equivalents $ 7,628 $ - $ - $ 7,628
Short-term bonds - 12,373 - 12,373
Long-term bonds - 96,671 - 96,671
Equity Securities: Large-Cap 57,526 - - 57,526
Equity Securities: Mid-Cap 19,944 16,780 - 36,724
Equity Securities: Small-Cap 36,409 - - 36,409
Equity Securities: Micro-Cap 19,923 - - 19,923
Equity Securities: International 19,461 59,142 - 78,603
Equity Securities: Emerging Markets 3,101 21,370 - 24,471
Equity Securities: Market Neutral 7,675 - - 7,675
Real estate - - 27,874 27,874
Private market investments - - 30,507 30,507
Commodities funds 1,420 23,058 - 24,478
Total pension assets $ 173,087 $ 229,394 $ 58,381 $ 460,862
Paitrptirempnt a ssets 1) $ 325 $ 33,062 $ - $ 33,387
(1) The postretirement benefits assets are primarily life insurance contracts.
IFERC FORM NO. 1 (ED. 12-88) Page 123.27
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 04/15/2013 2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Level 1 Level 2 Level 3 Total
Assets at December 31, 2011
Pension assets:
Cash and cash equivalents $ 6,141 $ - $ - $ 6,141
Short-term bonds - 23,443 - 23,443
Long-term bonds - 74,658 - 74,658
Equity Securities: Large-Cap 51,780 - - 51,780
Equity Securities: Mid-Cap 17,961 14,002 - 31,963
Equity Securities: Small-Cap 31,825 - - 31,825
Equity Securities: Micro-Cap 16,087 - - 16,087
Equity Securities: International 30,444 32,118 - 62,562
Equity Securities: Emerging Markets 1,745 15,112 - 16,857
Real estate - - 25,119 25,119
Private market investments - - 27,786 27,786
Commodities funds 2,929 18,931 - 21,860
Total pension assets $ 158,912 $ 178,264 $ 52,905 $ 390,081
Pncfrpfir'mpnf assetç(1) $ - $ 31,901 $ - $ 31,901
(1) The postretirement benefits assets are primarily life insurance contracts.
The following table presents a reconciliation of the beginning and ending balances of the fair value measurements using significant
unobservable inputs (Level 3):
Private Real
Equity Estate Total
Beginning balance - January 1, 2011 $ 29,932 $ 22,069 $ 52,001
Realized gains - 598 598
Realized losses (133) - (133)
Unrealized gains 1,425 1,854 3,279
Purchases, issuances, and settlements, net (3,438) 598 (2,840)
Ending balance - December 31, 2011 27,786 25,119 52,905
Realized gains 95 742 837
Unrealized gains 1,387 1,271 2,658
Purchases 1,779 742 2,521
Sales (540) - (540)
Endingbalance - December 31, 2012 $ 30,507 $ 27,874 $ 58,381
Fair Value Measurement of Level 2 and Level 3 Plan Asset Inputs:
Level 2 Bonds, Equity Securities, and Level 2 Commodities: These investments represent U.S. government and agency bonds,
corporate bonds, and connningled funds consisting of publicly traded equity securities or exchange-traded commodity contracts and
other contractual claims to commodity holdings. The U.S. government and agency bonds, as well as the corporate bonds, are not
traded on an exchange and are valued utilizing quoted prices for similar assets or liabilities in active markets. The commingled funds
themselves are not publicly traded, and therefore no publicly quoted market price is readily available. The value of these investments
is calculated by the custodian for the fund company on a monthly basis, and is based on market prices of the assets held by the
commingled fund divided by the number of fund shares outstanding.
Level 3 Real Estate: Real estate holdings represent investments in open-ended commingled real estate funds. As the property interests
held in these real estate funds are not frequently traded, establishing the market value of the property interests held by the fund, and the
resulting unit value of fund shareholders, is based on unobservable inputs including property appraisals by the fund company, property
appraisals by independent appraisal firms, analysis of the replacement cost of the property, discounted cash flows generated by
property rents and changes in property values, and comparisons with sale prices of similar properties in similar markets. These
open-ended real estate funds also furnish annual audited financial statements that are also used to further validate the information
provided.
IFERC FORM NO. I (ED. 12-88) Page 123.28 1
2011
Balance Avg Rate
$ 1,832,287 2.22%
871,784 2.06%
1,434,925 3.12%
327,877 7.32%
4,466,873 2.83%
(1,840,782)
$ 2,626,091
Name of Respondent This Report is: Date of Report Year/Period of Report
(11)X An Original (Mo, Da, Yr)
Idaho Power Company (2) - A Resubmission 04115/2013 2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Level 3 Private Market Investments: Private market investments represent two categories: fund of hedge funds and venture capital
funds. These funds are valued by the fund company based on the estimated fair value of the underlying fund holdings divided by the
fund shares outstanding. Some hedge fund strategies utilize securities with readily available market prices, while others utilize less
liquid investment vehicles that are valued based on unobservable inputs including cost, operating results, recent funding activity, or
comparisons with similar investment vehicles. Venture capital fund investments are valued by the fund company based on estimated
fair value of the underlying fund holdings divided by the fund shares outstanding. Some venture capital investments have progressed
to the point that they have readily available exchange-based market valuations. Early stage venture investments are valued based on
unobservable inputs including cost, operating results, discounted cash flows, the price of recent funding events, or pending offers from
other viable entities. These private market investments furnish annual audited financial statements that are also used to further validate
the information provided.
The fair value of the Level 3 assets is determined based on pricing provided or reviewed by third-party vendors to our investment
managers. While the input amounts used by the pricing vendors in determining fair value are not provided, and therefore unavailable
for Idaho Power's review, the asset results are reviewed and monitored to ensure the fair values are reasonable and in line with market
experience in similar assets classes. Additionally, the audited financial statements of the funds are reviewed at the time they are issued.
There were no material changes in valuation techniques or inputs during the years ended December 31, 2012 and 2011.
Employee Savings Plan
Idaho Power has a defined contribution plan designed to comply with Section 40 1(k) of the Internal Revenue Code and which covers
substantially all employees. Idaho Power matches specified percentages of employee contributions to the plan. Matching annual
contributions were $7 million and $6 million, and $5 million in 2012 and 2011, respectively.
Post-employment Benefits
Idaho Power provides certain benefits to former or inactive employees, their beneficiaries, and covered dependents after employment
but before retirement, in addition to the health care benefits required under the Consolidated Omnibus Budget Reconciliation Act.
These benefits include salary continuation, health care and life insurance for those employees found to be disabled under Idaho
Power's disability plans, and health care for surviving spouses and dependents. Idaho Power accrues a liability for such benefits. The
post employment benefit amounts included in other deferred credits on Idaho Power's consolidated balance sheet at December 31,
2012 and 2011 is $2.6 million and $3.8 million, respectively.
11. PROPERTY, PLANT AND EQUIPMENT AND JOINTLY-OWNED PROJECTS
The following table presents the major classifications of Idaho Power's utility plant in service, annual depreciation provisions as a
percent of average depreciable balance, and accumulated provision for depreciation for the years 2012 and 2011 (in thousands of
dollars):
2012
Balance Avg Rate
Production $ 2,217,334 2.36%
Transmission 931,403 2.02%
Distribution 1,411,740 2.89%
General and Other 355,295 6.47%
Total in service 4,915,772 2.75%
Accumulated provision for depreciation (1,871,810)
In service - net $ 3,043,962
Idaho Power's ownership interest in three jointly-owned generating facilities is included in the table above. Under the joint operating
agreements for these facilities, each participating utility is responsible for financing its share of construction, operating, and leasing
costs. Idaho Power's proportionate share of operating expenses are included in the Consolidated Statements of Income. These
IFERC FORM NO. I (ED. 12-88) Page 123.29 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
Idaho Power Company (2)- A Resubmission 04/15/2013 2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
jointly-owned facilities, including balance sheet amounts and the extent of Idaho Power's participation, were as follows at December
31, 2012 (in thousands of dollars):
Name of Plant Location Utility Construction Accumulated Ownership MW (1)
Plant in Work in Provision for %
Service Progress Depreciation ____________
Jim Bridger Units 1-4 Rock Springs, WY $ 542,894 $ 16,528 $ 280,875 33 771
Boardman Boardman, OR 79,031 1,355 55,940 10 64
Vahny Units l and 2 Winnemucca, NV 353,541 10,163 198,190 50 284
(I) Idaho Power's share of nameplate capacity.
IERCo, Idaho Power's wholly-owned subsidiary, is a joint venturer in BCC. Idaho Power's coal purchases from the joint venture were
$75 million and $65 million in 2012 and 2011, respectively.
Idaho Power has contracts to purchase the energy from four PURPA qualified facilities that are 50 percent owned by Ida-West. Idaho
Power's power purchases from these facilities were $9 million in both 2012 and 2011.
12. ASSET RETIREMENT OBLIGATIONS (ARO)
The guidance relating to accounting for AROs requires that legal obligations associated with the retirement of property, plant and
equipment be recognized as a liability at fair value when incurred and when a reasonable estimate of the fair value of the liability can
be made. Under the guidance, when a liability is initially recorded, the entity increases the carrying amount of the related long-lived
asset to reflect the future retirement cost. Over time, the liability is accreted to its present value and paid, and the capitalized cost is
depreciated over the useful life of the related asset. If, at the end of the asset's life, the recorded liability differs from the actual
obligations paid, a gain or loss would be recognized. As a rate-regulated entity, Idaho Power records regulatory assets or liabilities
instead of accretion, depreciation, and gains or losses, as approved by the IPUC. The regulatory assets recorded under this order do
not earn a return on investment. Beginning June 1, 2012, accretion, depreciation, and gains or losses related to the Boardman
generating facility have been exempted from such regulatory treatment as Idaho Power is now collecting amounts related to the
decommissioning of Boardman in rates.
Idaho Power's recorded AROs relate to the removal of polychlorinated biphenyls-contaminated equipment at its distribution facilities
and the reclamation and removal costs at its jointly-owned coal-fired generation facilities. In 2012, changes in estimates at its
distribution facilities and at the coal-fired generation facilities resulted in a net increase of $1.4 million in the recorded AROs. The
primary cause of the increase in the AROs in 2012 is an increased ARC) for the Valmy generating facility evaporation pond as
determined by a revised evaporation pond decommissioning study.
Idaho Power also has additional AROs associated with its transmission system, hydroelectric facilities, and jointly owned coal-fired
generation facilities; however, due to the indeterminate removal date, the fair value of the associated liabilities currently cannot be
estimated and no amounts are recognized in the consolidated financial statements.
The regulated operations of Idaho Power also collect removal costs in rates for certain assets that do not have associated AROs. Idaho
Power is required to redesignate these removal costs as regulatory liabilities. See Note 3 for the costs recorded as regulatory liabilities
on Idaho Power's Consolidated Balance Sheet as of December 31, 2012 and 2011.
The following table presents the changes in the carrying amount of AROs (in thousands of dollars):
2012 2011
Balance at beginning of year $ 21,367 $ 16,952
Accretion expense 984 936
Revisions in estimated cash flows 1,416 3,930
Liability settled (785) (451)
FERC FORM NO. I
123.30
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 04/15/2013 20121Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
13.INVESTMENTS
The table below summarizes Idaho Power's investments in debt and equity securities as of December 31 (in thousands of dollars).
2012 2011
Available-for-sale equity securities 31,913 22,205
Executive deferred compensation plan investments 2,478 3,439
Total Idaho Power investments 34,391 25,644
Investments in Equity Securities
Investments in securities classified as available-for-sale securities are reported at fair value, using either specific identification or
average cost to determine the cost for computing gains or losses. Any unrealized gains or losses on available-for-sale securities are
included in other comprehensive income.
The table below summarizes investments in equity securities by Idaho Power as of December 31, 2012 and December 31, 2011 (in
thousands of dollars).
December 31, 2012 December 31, 2011
Gross Gross Fair Gross Gross Fair
Unrealized Unrealized Value Unrealized Unrealized Value
Gain Loss Gain Loss
Available-for-sale securities $ 6,792 $ - $ 31,913 $ 4,220 $ I $ 22,205
At the end of each reporting period, Idaho Power analyzes securities in loss positions to determine whether they have experienced a
decline in market value that is considered other-than-temporary. At December 31, 2012, there were no securities in an unrealized loss
position. At December 31, 2011, one security was in an immaterial unrealized loss position. No other-than-temporary impairment was
recognized for this security due to the limited severity and duration of the unrealized loss position. There were no sales of
available-for-sale securities during the year ended December 31, 2012 or 2011.
14.DERIVATIVE FINANCIAL INSTRUMENTS
Commodity Price Risk
Idaho Power is exposed to market risk relating to electricity, natural gas, and other fuel commodity prices, all of which are heavily
influenced by supply and demand. Market risk may also be influenced by market participants' nonperfonnance of their contractual
obligations and commitments, which affects the supply of or demand for the commodity. Idaho Power uses derivative instruments,
such as physical and financial forward contracts, for both electricity and fuel to manage the risks relating to these commodity price
exposures. The objective of Idaho Power's energy purchase and sale activity is to meet the demand of retail electric customers,
maintain appropriate physical reserves to ensure reliability, and make economic use of temporary surpluses that may develop.
All commodity-related derivative instruments not meeting the normal purchases and normal sales exception to derivative accounting
are recorded at fair value on the balance sheet. Because of Idaho Power's PCA mechanisms, unrealized gains and losses associated
with the changes in fair value of these derivative instruments are recorded as regulatory assets or liabilities. With the exception of
forward contracts for the purchase of natural gas for use at Idaho Power's natural gas generation facilities, Idaho Power's physical
forward contracts qualify for the normal purchases and normal sales exception.
All of Idaho Power's derivative instruments have been entered into for the purpose of economically hedging forecasted purchases and
sales, though none of these instruments have been designated as cash flow hedges under derivative accounting guidance. Idaho Power
offsets fair value amounts recognized on its balance sheet related to derivative instruments executed with the same counterparty under
the same master netting agreement.
IFERC FORM NO. I (ED. 12-88) Page 123.31 1
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
Idaho Power Company (2)- A Resubmission 04/15/2013 2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Derivative Instruments Summary
The tables below presents the fair values and locations of derivative instruments not designated as hedging instruments recorded on the
balance sheets at December 31, 2012 and 2011 (in thousands of dollars).
December 31, 2012
Current:
Financial swaps
Financial swaps
Forward contracts
Forward contracts
Long-term:
Financial swaps
Forward contracts
Total
December 31, 2011
Current:
Financial swaps
Financial swaps
Forward contracts
Long-term:
Financial swaps
Total
Asset Derivatives Liability Derivatives
Balance Sheet Fair Balance Sheet Fair
Location Value Location Value
Other current assets $ 5,122 Other current assets $ 978
Other current liabilities 320 Other current liabilities 1,372
Other current assets 155 Other current assets 4
Other current liabilities 2
Other assets 96
Other assets 189
$ 5,882 $ 2,356
Other current assets $ 4,361 Other current assets $ 1,036
Other current liabilities 1,526 Other current liabilities 4,755
Other current assets 70 Other current liabilities 1,370
Other assets 359 - Other liabilities 108
$ 6,316 _________ $ 7,269
The table below presents the gains and losses on derivatives not designated as hedging instruments for the year ended December 31,
2012 and 2011 (in thousands of dollars).
Location of Gain/(Loss) on Gain/(Loss) on Derivatives Recognized in
Derivatives Recognized in Income Inenmp(l)
2012 2011
Financial swaps Off-system sales $ 15,104 $ 9,594
Financial swaps Purchased power (6,280) (7,124)
Financial swaps Fuel expense (6,359) 501
Financial swaps Other operations and maintenance (302) 425
Forward contracts Fuel exuense (1.755) -
(1) Excludes changes in fair value of derivatives, which are recorded on the balance sheet as regulatory assets or regulatory liabilities
Settlement gains and losses on electricity swap contracts are recorded on the income statement in off-system sales or purchased power
depending on the forecasted position being economically hedged by the derivative contract. Settlement gains and losses on both
financial and physical contracts for natural gas are reflected in fuel expense. Settlement gains and losses on diesel derivatives are
recorded in other operations and maintenance expense. See Note 15 for additional information concerning the determination of fair
value for Idaho Power's assets and liabilities from price risk management activities.
IFERC FORM NO. I (ED. 12-88) Page 123.32 1
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr) 1 Idaho Power Company (2)- A Resubmission 04/15/2013 2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Idaho Power had volumes of derivative commodity forward contracts and swaps outstanding at December 31, 2012 and 2011 set forth
in the table below.
December 31,
2012 2011
404,990 225,600
1,373,525 1,298,420
13,476,660 7,928,311
3,932,889 352,129
833,921 1,273,997
Commodity Units
Electricity purchases MWh
Electricity sales MWh
Natural gas purchases MMBtu
Natural gas sales MMBtu
Diesel purchases Gallons
Credit Risk
At December 31, 2012, Idaho Power did not have material credit exposure from financial instruments, including derivatives. Idaho
Power monitors credit risk exposure through reviews of counterparty credit quality, corporate-wide counterparty credit exposure, and
corporate-wide counterparty concentration levels. Idaho Power manages these risks by establishing appropriate credit and
concentration limits on transactions with counterparties and requiring contractual guarantees, cash deposits, or letters of credit from
counterparties or their affiliates, as deemed necessary. Idaho Power's physical power contracts are under Western Systems Power Pool
agreements, physical gas contracts are under North American Energy Standards Board contracts, and financial transactions are under
International Swaps and Derivatives Association, Inc. contracts. These contracts all contain adequate assurance clauses requiring
collateralization if a counterparty has debt that is downgraded below investment grade by at least one rating agency.
Credit-Contingent Features
Certain of Idaho Power's derivative instruments contain provisions that require Idaho Power's unsecured debt to maintain an
investment grade credit rating from Moody's Investors Service and Standard & Poor's Ratings Services. If Idaho Power's unsecured
debt were to fall below investment grade, it would be in violation of these provisions, and the counterparties to the derivative
instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative
instruments in net liability positions. The aggregate fair value of all derivative instruments with credit-risk-related contingent features
that were in a liability position at December 31, 2012, was $2.4 million. Idaho Power posted no collateral related to this amount. If
the credit-risk-related contingent features underlying these agreements were triggered on December 31, 2012, Idaho Power would have
been required to post $5.9 million of cash collateral to its counterparties.
15. FAIR VALUE MEASUREMENTS
Idaho Power has categorized their financial instruments into a three-level fair value hierarchy, based on the priority of the inputs to the
valuation technique. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or
liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). If the inputs used to measure the financial instruments fall
within different levels of the hierarchy, the categorization is based on the lowest level input that is significant to the fair value
measurement of the instrument.
Financial assets and liabilities recorded on the consolidated balance sheets are categorized based on the inputs to the valuation
techniques as follows:
Level 1: Financial assets and liabilities whose values are based on unadjusted quoted prices for identical assets or
liabilities in an active market that Idaho Power has the ability to access.
Level 2: Financial assets and liabilities whose values are based on:
a)quoted prices for similar assets or liabilities in active markets;
b)quoted prices for identical or similar assets or liabilities in non-active markets;
C) pricing models whose inputs are observable for substantially the full term of the asset or liability; and
d) pricing models whose inputs are derived principally from or corroborated by observable market data through
correlation or other means for substantially the full term of the asset or liability.
IFERC FORM NO. 1 (ED. 12-88) Page 123.33 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
Idaho Power Company (2)- A Resubmission 04/15/2013 2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Idaho Power Level 2 inputs are based on quoted market prices adjusted for location using corroborated, observable market
data.
Level 3: Financial assets and liabilities whose values are based on prices or valuation techniques that require inputs that
are both unobservable and significant to the overall fair value measurement. These inputs reflect management's own
assumptions about the assumptions a market participant would use in pricing the asset or liability.
Idaho Power's derivatives are contracts entered into as part of its management of loads and resources. Electricity swaps are valued on
the Intercontinental Exchange with quoted prices in an active market. Natural gas and diesel derivative valuations are performed using
New York Mercantile Exchange (NYMEX) pricing, adjusted for location basis, which are also quoted under NYMEX. Trading
securities consist of employee-directed investments held in a Rabbi Trust and are related to an executive deferred compensation plan.
Available-for-sale securities are related to the SMSP and are held in a Rabbi Trust and are actively traded money market and equity
funds with quoted prices in active markets.
The table below presents information about Idaho Power's assets and liabilities measured at fair value on a recurring basis as of
December 31, 2012 and 2011 (in thousands of dollars). Idaho Power's assessment of the significance of a particular input to the fair
value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair
value hierarchy. There were no transfers between levels for the years presented.
Assets:
Derivatives
Money market funds
Trading securities: Equity securities
Available-for-sale securities: Equity
securities
Liabilities:
Derivatives
December 31, 2012 - December 31, 2011 -
Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
$ 2,201 $ 1,674 $ - $ 3,875 $ 3,654 $ 100 $ - $ 3,754
100 - - 100 100 - - 100
2,478 - - 2,478 3,439 - - 3,439
31,913 - - 31,913 22,205 - - 22,205
$ - $ 1,055 $ - $ 1,055 $ 405 $ 4,302 $ - $ 4,707
The table below presents the carrying value and estimated fair value of financial instruments that are not reported at fair value, as of
December 31, 2012 and 2011, using available market information and appropriate valuation methodologies. The use of different
market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts. Cash and cash
equivalents, deposits, customer and other receivables, notes payable, accounts payable, interest accrued, and taxes accrued are reported
at their carrying value as these are a reasonable estimate of their fair value. The estimated fair values for long-term debt is based upon
quoted market prices of the same or similar issues or discounted cash flow analysis as appropriate.
December 31, 2012 December 31, 2011
Estimated Fair Estimated Fair
Carrying Amount Value Carrying Amount Value
(thousands of dollars)
Liabffities:
Inng-term debt (l) $ 1,537,696 $ 1,819,213 $ 1,491,727 $ 1,737,912
(1) Long-term debt is categorized as Level 2 within the fair value hierarchy, as defined earlier in this Note 15.
16. RELATED PARTY TRANSACTIONS
IDACORP: Idaho Power performs corporate functions such as financial, legal, and management services for IDACORP and its
subsidiaries. Idaho Power charges IDACORP for the costs of these services based on service agreements and other specifically
identified costs. For these services Idaho Power billed IDACORP $0.8 million in both 2011 to 2012.
Ida-West: Idaho Power purchases all of the power generated by four of Ida-West's hydroelectric projects located in Idaho.
Idaho Power paid $9 million to Ida-West in both 2012 and 2011.
IFERC FORM NO. I (ED. 12-88) Page 123.34
Name of Respondent This Re oil Is: Date of Report Year/Period of Report
Idaho Power Company gARSSOfl End of 2012/Q4
04/15/2013
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
1.Report in columns (b),(c),(d) and (e) the amounts of accumulated other comprehensive income items, on a net-of-tax basis, where appropriate.
2.Report in columns (f) and (g) the amounts of other categories of other cash flow hedges.
3.For each category of hedges that have been accounted for as fair value hedges", report the accounts affected and the related amounts in a footnote.
4.Report data on a year-to-date basis.
Item Unrealized Gains and Minimum Pension Foreign Currency Other Line Losses on Available- Liability adjustment Hedges Adjustments No for-Sale Securities (net amount)
(a) (b) (c) (d) (e)
I Balance of Account 219 at Beginning of
- Preceding Year 2,969,301 ( 12,536,816)
2 Preceding Qtr/Yr to Date Reclassifications
- from Acct 219 to Net Income 934,902
3 Preceding Quarter/Year to Date Changes in
- Fair Value ( 400,010) ( 2,589,429)
4 Total (lines 2 and 3) ( 400,010) ( 1,654,527)
5 Balance of Account 219 at End of
- Preceding Quarter/Year 2,569,291 ( 14,191,343)
6 Balance of Account 219 at Beginning of
Current Year - 2,569,291 ( 14,191,343)
7 Current Qtr/Yr to Date Reclassifications
- from Acct 219 to Net Income 1,060,888
8 Current Quarter/Year to Date Changes in
- Fair Value 1,567,262 ( 8,121,767)
9 Total (lines 7 and 8) 1,567,262 ( 7,060,879)
10 Balance of Account 219 at End of Current
- Quarter/Year 4,136,553 ( 21,252,222)
FERC FORM NO. 1 (NEW 06.02) Page 122a
Idaho Power Company
This Re port Is: Date of Rel
(1)An Original (Mo, Da, Y
(2)flA Resubmission 1 04/15/2013
Year/Period of Report
End of 20121Q4
Other Cash Flow
Line Hedges
No. Interest Rate Swaps
Other Cash Flow
Hedges
[Specify]
Totals for each
category of items
recorded in
Account 219
(h)
9,567,515)
934,902
2,989,439)
2,054,537)
11,622,052)
11,622,052)
1,060,888
6,554,505)
5,493,617)
17,115,669)
Net Income (Carried
Forward from
Page 117, Line 78)
(i)
164,749,627
168,168,039
Total
Comprehensive
Income
0)
162,695,090 I
162,674,422 I
FERC FORM NO. I (NEW 06-02) Page 122b
This Page Intentionally Left Blank
Name of Respondent
Idaho Power Company
eport I This R Is: I
Original
j
(2) E] A Resubmission
Date of Report
04/15/2013
Year/Period of Report
End of 2012/04
LAT SUMMARY OF UTILITY PLANT AND ACCUM ED PROVISIONS
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Report in Column (c) the amount for electric function, in column (d) the amount for gas function, in column (e), (f), and (g) report other (specify) and in
column (h) common function.
Line
No.
Classification
(a)
Total Company for the
Current Year/Quarter Ended
(b)
Electric
(c)
1 Utility Plant
2 In Service
3 Plant in Service (Classified) I 4,915,771,669 4,915,771,669'
4 Property Under Capital Leases
5 Plant Purchased or Sold
6 Completed Construction not Classified
7 Experimental Plant Unclassified
8 Total (3 thru 7) 4,915,771,669 4,915,771,669
9 Leased to Others
10 Held for Future Use 7,101,305 7,101,305
11 Construction Work in Progress 298,470,440 298,470,440
12 1 Acquisition Adjustments
13 Total Utility Plant (8 thru 12) 5,221,343,414 5,221,343,414
14 Accum Prov for Depr, Amort, & DepI 1,871,810,171 1,871,810,171
15 Net Utility Plant (13 less 14) 3,349,533,243 3,349,533,243
16 Detail of Accum Prov for Depr, Amort & Depl
17 In Service:
18 Depreciation 1,848,861,1 13 1,848,861,113
19 Amort & Depl of Producing Nat Gas Land/Land Right
20 Amort of Underground Storage Land/Land Rights
21 Amort of Other Utility Plant 22,949,0581 22,949,058
22 Total In Service (18 thru 21) 1,871,810,171 1,871,810,171
23 Leased to Others
24 Depreciation
25 Amortization and Depletion
26 Total Leased to Others (24 & 25)
27 Held for Future Use
28 Depreciation
29 Amortization
30 Total Held for Future Use (28 & 29)
31 Abandonment of Leases (Natural Gas)
32 Amort of Plant Acquisition Adj
33 Total Accum Prov (equals 14) (22,26,30,31,32) 1,871,810,171 1,871,810,171
FERC FORM NO. I (ED. 12-89) Page 200
Name of Respondent
Idaho Power Company
This Report Is: Dateof Report
04/15/2013
Year/Period of Report
End of 2012/Q4
ELECTRIC PLANT IN SERVICE (Account 101, 102,103 and 106)
1.Report below the original cost of electric plant in service according to the prescribed accounts.
2.In addition to Account 101, Electric Plant in Service (Classified), this page and the next include Account 102, Electric Plant Purchased or Sold;
Account 103, Experimental Electric Plant Unclassified; and Account 106, Completed Construction Not Classified-Electric.
3.Include in column (c) or (d), as appropriate, corrections of additions and retirements for the current or preceding year.
4.For revisions to the amount of initial asset retirement costs capitalized, included by primary plant account, increases in column (c) additions and
reductions in column (e) adjustments.
5.Enclose in parentheses credit adjustments of plant accounts to indicate the negative effect of such accounts.
6.Classify Account 106 according to prescribed accounts, on an estimated basis if necessary, and include the entries in column (c). Also to be included
in column (c) are entries for reversals of tentative distributions of prior year reported in column (b). Likewise, if the respondent has a significant amount
of plant retirements which have not been classified to primary accounts at the end of the year, include in column (d) a tentative distribution of such
retirements, on an estimated basis, with appropriate contra entry to the account for accumulated depreciation provision. Include also in column (d)
Line
No
Account
(a)
Balance Beginning of Year
(b)
Additions
(c)
1 1. INTANGIBLE PLANT
2 (301) Organization 5,703
3 (302) Franchises and Consents 23,171,392 5,821,094
4 (303) Miscellaneous Intangible Plant 34,317,102 3,996,149
5 TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4) 57,494,1971 9,817,243
6 2. PRODUCTION PLANT
7 A. Steam Production Plant
8 (31 0) Land and Land Rights 1,707,109
9 (311) Structures and Improvements 143,758,647 4,462,234
10 (312) Boiler Plant Equipment 569,484,225 6,942,778
11 (313) Engines and Engine -Driven Generators
12 (314) Turbogenerator Units 150,650,806 1,837,467
13 (315)Accessory Electric Equipment 60,126,1301 8,217,762
14 (316) Misc. Power Plant Equipment 15,180,4751 1,700,368
15 (317) Asset Retirement Costs for Steam Production 8,005,226 2,208,288
16 TOTAL Steam Production Plant (Enter Total of lines 8 thru 15) 948,912,618 25,368,897
17 B. Nuclear Production Plant
18 (32 0) Land and Land Rights
19 (321) Structures and Improvements
20 (322) Reactor Plant Equipment
21 (323) Turbogenerator Units
22 (324) Accessory Electric Equipment
23 (325) Misc. Power Plant Equipment
24 (326) Asset Retirement Costs for Nuclear Production
25 TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24)
26 C. Hydraulic Production Plant
27 (33 0) Land and Land Rights 30,132,870 709,417
28 (331) Structures and Improvements 156,227,013 1,306,025
29 (332) Reservoirs, Dams, and Waterways 252,890,100 288,688
30 (333) Water Wheels, Turbines, and Generators 197,920,861 3,082,590
31 (334) Accessory Electric Equipment 45,854,367 1,142,182
32 (335) Misc. Power PLant Equipment 19,081,4341 1,372,330
33 (336) Roads, Railroads, and Bridges 8,112,4911 5,122
34 (337) Asset Retirement Costs for Hydraulic Production
35 TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34) 710,219,136 7,906,354
36 D. Other Production Plant
37 (34 0) Land and Land Rights 2,690,006
38 (341) Structures and Improvements 7,169,5951 125,884,758
39 (342) Fuel Holders, Products, and Accessories 4,445,866 3,542,032
40 (343) Prime Movers 98,951,696 127,879,002
41 (344) Generators 31,681,900 41,765,594
42 (345) Accessory Electric Equipment 25,077,582 70,480,766
43 (346) Misc. Power Plant Equipment 3,138,437 2,600,177
44 (347) Asset Retirement Costs for Other Production
45 TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44) 173,155,082 372,152,329
46 1 TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45) 1,832,286,836 405,427,580
FERC FORM NO. 1 (REV. 12-05) Page 204
Name of Respondent
Idaho Power Company
This Re ort Is:
ssion
Date of Report Year/Period of Report
End of 2012/04
ELECTRIC PLANT IN SERVICE (Account 1(1 102, 103 and 106) (Continued)
distributions of these tentative classifications in columns (c) and (d), including the reversals of the prior years tentative account distributions of these
amounts. Careful observance of the above instructions and the texts of Accounts 101 and 106 will avoid serious omissions of the reported amount of
respondent's plant actually in service at end of year.
7.Show in column (f) reclassifications or transfers within utility plant accounts. Include also in column (f) the additions or reductions of primary account
classifications arising from distribution of amounts initially recorded in Account 102, include in column (e) the amounts with respect to accumulated
provision for depreciation, acquisition adjustments, etc., and show in column (f) only the offset to the debits or credits distributed in column (f) to primary
account classifications.
8.For Account 399, state the nature and use of plant included in this account and if substantial in amount submit a supplementary statement showing
subaccount classification of such plant conforming to the requirement of these pages.
9.For each amount comprising the reported balance and changes in Account 102, state the property purchased or sold, name of vendor or purchase,
and date of transaction. If proposed journal entries have been filed with the Commission as required by the Uniform System of Accounts, give also date
Retirements
(d)
Adjustments
(e)
Transfers Balance at
End r)Year
Line
5,703 2
60,000 28,932,486 3
7,062,241 1 1 31,251,0101 1 4
7,122,241 I .60,189,1991 5
I 1 ,707,109 1
6
7
8
510,858 147,710,023 9
13,077,075 563,349,928 10
11
4,716,265 147,772,008 12
144,087 68,199,8051 13
1,163,072 15,717,771 14
10,213,514 15
19,611,357 954,670,158 16
17
18
19
20
21
22
23
24
25
30,842,287
26
27
15,258 157,517,780 28
34,486 __________________________ ________________________ 253,144,302 29
159,917 200,843,534 30
349,138 46,647,411 31
162,205 20,291,559 32
8,117,613 33
34
721,0041 1 717,404,486 35
_________________________ 2,690,006
36
37
28,341 133,026,012 38
_________________________ 7,987,898 39
20,000 226,810,698 40
_________________________ __________________________ _________________________ 73,447,494 41
95,558,348 42
5,738,614 43
44
48,341 545,259,070 45
20,380,702 2,217,333,714 46
FERC FORM NO. I (REV. 12-05) Page 205
Name of Respondent
Idaho Power Company
This Report Is: Original
2"Resu bmission
Date of Report
(Mo, Da, Yr)
04/15/2013 End of 20121Q4
Year/Period of Report
- ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued)
Line
No
Account
(a)
Balance Beginning of Year
(b)
Additions
(c)
47 3. TRANSMISSION PLANT
48 (35 0) Land and Land Rights 35,130605 445,557
49 (352) Structures and Improvements 57,994,797 12,150,635
50 (353) Station Equipment 351.924,749 14,049,079
51 (35 4) Towers and Fixtures 147,491,416 7,679,305
52 (355) Poles and Fixtures 107,026,913 13,764,963
53 (35 6) Overhead Conductors and Devices 171,801,963 13,274,942
54 (357) Underground Conduit
55 (358) Underground Conductors and Devices
56 (359) Roads and Trails 413,346 -23,080
57 (359.1) Asset Retirement Costs for Transmission Plant
58 TOTAL Transmission Plant (Enter Total of lines 48 thru 57) 871,783,789 61,341,401
59 4. DISTRIBUTION PLANT
60 (360) Land and Land Rights 5,423,471 -648,228
61 (361) Structures and Improvements 32,336,183 -956,431
62 (362) Station Equipment 194,190,240 -3,641,870
63 (363) Storage Battery Equipment
64 (364) Poles, Towers, and Fixtures 228,880,444 2,946,117
65 (365) Overhead Conductors and Devices 122,536,891 3,105,791
66 (366) Underground Conduit 47,989,345 -1,002,615
67 (367) Underground Conductors and Devices 196,700,971 1,730,268
68 (368) Line Transformers 429,419,556 26,406,882
69 (36 9) Services 57,225,209 -73,102
70 (370) Meters 112,429,849 570,493
71 (371) Installations on Customer Premises 2,754,620 166,375
72 (372) Leased Property on Customer Premises
73 (373) Street Lighting and Signal Systems 4,394,855 130,714
74 (374) Asset Retirement Costs for Distribution Plant 643,639
75 TOTAL Distribution Plant (Enter Total of lines 60 thru 74) 1,434,925,273 28,734,394
76 5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT
77 (380) Land and Land Rights
78 (38 1) Structures and Improvements
79 (382) Computer Hardware
80 (383) Computer Software
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. GENERAL PLANT
86 (389) Land and Land Rights 16,128,65 -8,45
87 (390) Structures and Improvements 84,984,787 8,918,68
88 (391) Offi ce Furniture and Equipment 40,558,356 10,610,17
89 (392) Transportation Equipment 60,978,129 5,524,77
90 (393) Stores Equipment 1,600,036 285,52
91 (3 94) Tools, Shop and Garage Equipment 6,054,996 515,974
92 (395) Laboratory Equipment 11,866,322 643,13
93 (396) Power Operated Equipment 10,696,486 833,78
94 (397) Communication Equipment 32,714,344 7,877,76
95 (398) Miscellaneous Equipment 5,255,018 401,27
96 SUBTOTAL (Enter Total of lines 86 thru 95) 270,837,132 35,602,64
97 (399) Other Tangible Property
98 (399.1) Asset Retirement Costs for General Plant
99 1 TOTAL General Plant (Enter Total of lines 96, 97 and 98) 270,837,132 35,602,646
100 TOTAL (Accounts 101 and 106) 4,467,327,227 540,923,264
101 (102) Electric Plant Purchased (See lnstr. 8)
102 (Less) (102) Electric Plant Sold (See lnstr. 8)
103 (103) Experimental Plant Unclassified
104 TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103) 4,467,327,227 540,923,264
FERC FORM NO. I (REV. 12-05) Page 206
Name of Respondent
Idaho Power Company
This Report Is:
'R' Resubmission
Date of Report
04/15/2013
Year/Period of Report
End of 2012/Q4
ELECTRIC PLANT IN SERVICE (Account 101, 102,103 and 106) (Continued)
Retirements
(d)
Adjustments
(e)
Transfers
(f)
Balance at
End g) ear
Line
47
35,576,162 48
8,541 70,136,891 49
529,861 -89,005 365,354,962 50
74,995 155,095,726 51
435,295 120,356,581 52
584,891 184,492,014 53
54
_____________________________ 55
_____ __________________________ 390,266 56
______ _____________________________ 57
1,633,583 -89,005 931,402,602 58
_____ __________________________ 4,775,243
59
60
25,585 31,354,167 61
945,164 61,696 189,664,902 62
63
1,470,555 230,356,006 64
1,630,230 124,012,452 65
152,847 46,833,883 66
699,100 197,732,139 67
4,614,794 451,211,644 68
298,753 56,853,354 69
42,067,815 70,932,527 70
55,841 2,865,154 71
72
20,358 4,505,211 73
643,639 74
51,981,042 61,696 1,411,740,321 75
76
77
78
79
80
81
82
83
84
16,120,205
85
86
250,021 93,653,452 87
8,373,808 42,794,726 88
1,612,476 64,890,431 89
7,739 1,877,822 90
105,260 6,465,710 91
254,363 12,255,095 92
34,346 11,495,923 93
689,228 27,309 39,930,187 94
34,013 5,622,282 95
11,361,254 27,309 295,105833 96
97
98
11,361,254 27,309 295,105,833 99
92,478,822 4,915,771,669 100
101
102
103
92,478,822 4,915,771,669 104
FERC FORM NO. 1 (REV. 12-05) Page 207
Name of Respondent
Idaho Power Company
This Re oil Is:
2h1 Resubmission
Date of Report
04/15/2013
Year/Period of Report
End of 2012/Q4
ELECTRIC PLANT HELD FOR FUTURE USE (Account 105)
1.Report separately each property held for future use at end of the year having an original cost of $250,000 or more. Group other items of property held
for future use.
2.For property having an original cost of $250,000 or more previously used in utility operations, now held for future use, give in column (a), in addition to
other required information, the date that utility use of such property was discontinued, and the date the original cost was transferred to Account 105.
Line No.
-
Description and Location
Of Property (a)
Date Originally Included
in This Account (b)
Date Expected to be used in Utility Service (c)
Balance at
End of Year (d)
1 Land and Rights:
2 Boise Operations Center 12/31/82 655,550
3 Production 112,703
4 Transmission Stations 429,822
5 Transmission Lines 195,517
6 Distribution Stations 1,078,591
7 Beacon Light Substation 12/30/02 465,662
8 Homedale Substation 2/29/08 109,453
91 North River Operations Center 1/31/08 2,630412
10 Line #854 500 Ky 3/31/09 308,066
11
12
13
14 Column B if no date listed it is various
15
16
17
18
19
20
21 Other Property:
Boise Operations Center 12/31182 72,785 22
23 Transmission Stations 199,069
24 Distribution Stations 72,016
25 Homedale Substation 2/29/08 215,719
26 Beacon Light Substation 12/30/02 555,940
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41 j
42
43
44
45
46
47 Total 7,101,305
FERC FORM NO. 1 (ED. 12-96) Page 214
Name of Respondent
Idaho Power Company
This Re ort Is: Date of Report
04/15/2013
Year/Period of Report
End of 2012/Q4
CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)
1.Report below descriptions and balances at end of year of projects in process of construction (107)
2.Show items relating to 'research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see
Account 107 of the Uniform System of Accounts)
3.Minor projects (5% of the Balance End of the Year for Account 107 or $1,000,000, whichever is less) may be grouped.
Line
No
Description of Project
(a)
Construction work in progress - Electric (Account 107)
(b)
1 ROLLUP RELIC COST BROWNLEE 61,547,907
2 ROLLUP RELIC COST HELLS CANYON 42,037,561
3 BOARDMAN - HEMINGWAY 500 Ky LI 26,705,806
4 GATEWAY WEST 500KV LINE 20,908,755
5 ROLLUP RELIC COST OXBOW 19,419,114
6 HELLS CANYON RELICENSING OUTSI 15,674,400
7 NIAGARA SPRINGS HATCHERY EXPAN 9,194,254
8 BRIDGER 2008C123LP UI TURBINE 8,911,069
9 WQ - ONGOING HELLS CANYON RELI 6,829,646
10 CIAC LIABILITY RECLASS 6,046,206
II BUILD NEW JUSTICE TRANSMISSION 5,082,098
12 RIVER ENG.-HELLS CANYON CONTIN 4,693,433
13 BOBN REPLACE C233 AND C234 SER 4,297,924
14 BRIDGER UNDISTRIBUTED WORK ORD 3,646,399
151 B2H PERMITTING 11/1/2011 & FOR 3,139,305
16 VALMY UNDISTRIBUTED WORK ORDER 2,357,929
17 B21-1 TLINE CONSTRUCTION COSTS 1,935,953
18 LEGAL DEPT. LABOR FOR RELICENS 1,852,244
19 VALMY 98250588 DUST COLLECTOR 1,851,747
201 REL-HCC OREGON REAUTHORIZATION 1,741,966
21 BCW- UG FIBER INSTALLATION 1,718,795
22 VALMY 98301759 Vl UTILITY MACT 1,695,010
23 SOlO - INTEGRATIONS 1,554,085
24 SGIG - OUTAGE MANAGEMENT SYSTE 1,411,182
25 2012 PC PURCHASES - CUSTOMER 0 1,319,812
26 IPCO/ / 2011 DOWNTOWN CAPITAL 1,316,681
27 KPRTI 002: EVAL SYNCHRONOUS CON 1,201,239
28 OBPR LOCAL SERVICE UPGRADE 1,147,272
29 SGIG CUSTOMER DATA MART 1,081,974
30 OTHER MINOR PROJECTS UNDER $1,000,000 38,150,674
31
32
33
34
35
36
37
38
39
40
41
42
43 TOTAL 298,470,440
FERC FORM NO. I (ED. 12-87) Page 216
This Page Intentionally Left Blank
Name of Respondent
Idaho Power Company
This Re ort Is: Date of Report
04/15/2013
Year/Period of Report
End of 20121Q4
ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT (Account 108)
1.Explain in a footnote any important adjustments during year.
2.Explain in a footnote any difference between the amount for book cost of plant retired, Line 11, column (c), and that reported for
electric plant in service, pages 204-207, column 9d), excluding retirements of non-depreciable property.
3.The provisions of Account 108 in the Uniform System of accounts require that retirements of depreciable plant be recorded when
such plant is removed from service. If the respondent has a significant amount of plant retired at year end which has not been recorded
and/or classified to the various reserve functional classifications, make preliminary closing entries to tentatively functionalize the book
cost of the plant retired. In addition, include all costs included in retirement work in progress at year end in the appropriate functional
classifications.
4.Show separately interest credits under a sinking fund or similar method of depreciation accounting.
Section A. Balances and Changes During Year
iiië
N 0.
Item
(a)
Total (c+d+e)
(b)
bIerIc Plant in bervice
(c)
Electric Plant Held for Future Use (d)
Eiectllc j1t Leas ea to otners
(e)
I Balance Beginning of Year I 1,818,635,521 1,818,635,521
_2 Depreciation Provisions for Year, Charged to
116,113,891! 116,113,8911 3 (403) Depreciation Expense
4 (403.1) Depreciation Expense for Asset
Retirement Costs
317,075 317,075
I I
5 (413) Exp. of Elec. Pit. Leas. to Others
_6 Transportation Expenses-Clearing 3,189,325 3,189,325I
71 Other Clearing Accounts 1
8 Other Accounts (Specify, details in footnote):
9 Fuel Stock 100,439 100,439
10 TOTAL Deprec. Prov for Year (Enter Total of
lines 3 thru 9)
119,720,730 119,720,730
11
12
Net Charges for Plant Retired:
Book Cost of Plant Retired 85,356,581 85,356,581
13 Cost of Removal 7,686,282 7,686,282
14 Salvage (Credit) 2,327,547 2,327,547
15 TOTAL Net Chrgs. for Plant Ret. (Enter Total
of lines 12 thru 14)
90,715,316 90,715,316
16 Other Debit or Cr. Items (Describe, details in
footnote):
17 CIAC, Reserve adj and Asset Retireme 1,220,178 1,220,178
18 Book Cost or Asset Retirement Costs Retired
19 Balance End of Year (Enter Totals of lines 1,
10, 15, 16, and 18)
1,848,861,113 1,848,861,113
Section B. Balances at End of Year According to Functional Classification
20 Steam Production 529,534,301 529,534,301
21 Nuclear Production
22 Hydraulic Production-Conventional 366,042,954 366,042,954
23 Hydraulic Production-Pumped Storage
24 Other Production 41,316,874 41,316,874
25 Transmission 285,425,520 285,425,520
26 Distribution 516,534,664 516,534,664
27 Regional Transmission and Market Operation
28 General 110,006,800 110,006,800
29 TOTAL (Enter Total of lines 20 thru 28) 1,848,861,113 1,848,861,113
FERC FORM NO. I (REV. 12-05) Page 219
Name of Respondent
Idaho Power Company
This Re oil Is:
ARsUbflISSion
Date of Report
04/15/2013
Year/Period of Report
End of 20 12/04
INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1)
1. Report below investments in Accounts 123.1, investments in Subsidiary Companies.
2. Provide a subheading for each company and List there under the information called for below. Sub - TOTAL by company and give a TOTAL in
columns (e),(f),(g) and (h)
(a)Investment in Securities - List and describe each security owned. For bonds give also principal amount, date of issue, maturity and interest rate.
(b)Investment Advances - Report separately the amounts of loans or investment advances which are subject to repayment, but which are not subject to
current settlement With respect to each advance show whether the advance is a note or open account. List each note giving date of issuance, maturity
date, and specifying whether note is a renewal.
3. Report separately the equity in undistributed subsidiary earnings since acquisition. The TOTAL in column (e) should equal the amount entered for
Account 418.1.
Line
No.
Description of Investment
(a)
Date Acquired
(b)
Date Of Maturity
Arnountof nvestment at
Beginning of Year
1 Idaho Energy Resources Company
2 Common Stock 02/01/74 500
3 Capital contributions 2,462,594
4 Equity in earnings 76,066,425
5
6 Subtotal Idaho Energy Resources Company 78,529,519
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 al Cost of Account 123.1 $ 2,463,0941 TOTAL 78,529,519
FERC FORM NO. 1 (ED. 12-89) Page 224
Name of Respondent
Idaho Power Company
This Report Is:
(1)An Original
(2)[JA Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2013
Year/Period of Report
End of 2012/04
INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1) (Continued)
4.For anysecurities, notes, or accounts that were pledged designate such securities, notes, or accounts in a footnote, and state the name of pledgee
and purpose of the pledge.
5.If Commission approval was required for any advance made or security acquired, designate such fact in a footnote and give name of Commission,
date of authorization, and case or docket number.
6.Report column (f) interest and dividend revenues form investments, including such revenues form securities disposed of during the year.
7.In column (h) report for each investment disposed of during the year, the gain or loss represented by the difference between cost of the investment (or
the other amount at which carried in the books of account if difference from cost) and the selling price thereof, not including interest adjustment includible
in column (f).
8.Report on Line 42, column (a) the TOTAL cost of Account 123.1
Equity in Subsidiary
Earnins?fYear
Revenues for Year
(0
Amount of Investment at
End f
)
Year
Gain or Loss from Investment
Disd of Line
500 2
2,462,594 3
6,150,725 82,217,149 4
5
6,150,725 84,680,243 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
6,150,725 84,680,243
FERC FORM NO. I (ED. 12-89) Page 225
This Page Intentionally Left Blank
Name of Respondent
Idaho Power Company
This Re ort Is:
'Rssion
Date of Report
04/15/2013
Year/Period of Report
End of 2012/Q4
MATERIALS AND SUPPLIES
I. For Account 154, report the amount of plant materials and operating supplies under the primary functional classifications as indicated in column (a);
estimates of amounts by function are acceptable. In column (d), designate the department or departments which use the class of material.
2. Give an explanation of important inventory adjustments during the year (in a footnote) showing general classes of material and supplies and the
various accounts (operating expenses, cleating accounts, plant, etc.) affected debited or credited. Show separately debit or credits to stores expense
cleating, if applicable.
Line
No.
-
Account
(a)
Balance
Beginning of Year
(b)
Balance
End of Year
(c)
Department or
Departments which
Use Material (d)
I Fuel Stock (Account 151) 47,865,097 42,388,239 Electric
2 Fuel Stock Expenses Undistributed (Account 152)
3 Residuals and Extracted Products (Account 153)
4 Plant Materials and Operating Supplies (Account 154)
5 Assigned to - Construction (Estimated)
6 Assigned to - Operations and Maintenance
7 Production Plant (Estimated) 14808,824 15,899,274
8 Transmission Plant (Estimated) 12,917,846 12,836,658
9 Distribution Plant (Estimated) 13,087,873 17,335,350
10 Regional Transmission and Market Operation Plant
(Estimated)
11 Assigned to - Other (provide details in footnote) 1,201,188 1,384,672
12 TOTAL Account 154 (Enter Total of lines 5 thru 11) 42,015,731 47,455,954 Electric
13 Merchandise (Account 155)
14 Other Materials and Supplies (Account 156)
15
-
Nuclear Materials Held for Sale (Account 157) (Not
applic to Gas Util)
16 Stores Expense Undistributed (Account 163) 4,474,719 3,581,218 Electric
17
18
19
20 TOTAL Materials and Supplies (Per Balance Sheet) 94,355,547 93,425,411
FERC FORM NO. I (REV. 12-05) Page 227
Name of Respondent
Idaho Power Company
This Re ort Is: (1) An Original
AResubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of 20121Q4
Transmission Service and Generation Interconnection Study Costs
1.Report the particulars (details) called for concerning the costs incurred and the reimbursements received for performing transmission service and
generator interconnection studies.
2.List each study separately.
3.In column (a) provide the name of the study.
4.In column (b) report the cost incurred to perform the study at the end of period.
5.In column (c) report the account charged with the cost of the study.
6.In column (d) report the amounts received for reimbursement of the study costs at end of period.
7.In column (e) report the account credited with the reimbursement received for performing the study.
No. Description
(a)
Line Costs Incurred During
Period
(b)
Account Charged
(c)
Received During the Period
(d)
Account Credited
With Reimbursement
(e)
I Transmission Studies
IPC TRANS SIS 74705988,74705990, 2
3 74705993,7470995, 74706017 186623 8,661 186623
4 IPC TRANS SIS 76655746 2,514 186623 ( 2,514) 186623
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21 Generation Studies
1,324 186623 10,871 186623 22 LAVA BEDS WIND PARK
23 HIDDEN HOLLOW EXPANSION Gl#291 186623 ( 2,247) 186623
24 WHEATGRASS RIDGE WIND PROJECT 294 943 186623 78,847 186623
25 COTTEREL MTN WIND PROJECT 302 101 186623 73,413 186623
26 ADAMS COUNTY BIOMASS GI#304 186623 26,652 186623
27 1 SWAGER FARMS Gl#307 3,823 186623 12,427 186623
28 DOUBLE B DAIRY Gl#308 179 186623 6,517 186623
29 GRAND VIEW SOLAR GI#312 657 186623 13,711 186623
30 YELLOWSTONE PWR Gl#315 186623 18,586 186623
31 JACK RANCH WIND GI 322 5,847 186623 28,322 186623
32 1 SALMON CREEK GI 325 1,990 186623 31,366 186623
33 TUMBLE WEED 34.5 GI 332 186623 ( 6,006) 186623
34 HIGH MESA WIND GI 334 4,020 186623 89,366 186623
35 DYNAMIS LANDFILL GI 344 17,086 186623 1,235 186623
36 MURPHY FLAT WIND GI 346 385 186623 99,615 186623
37 1 NOTCH BUTTE GI 349 13,602 186623 ( 5,839) 186623
38 RAINBOW WEST GI 352 14,645 186623 16,557 186623
39 SALMON FALLS WIND 01 357 186623 98,158 186623
40 NOTCHBUTTE GI 359 186623 17,414 186623
FERC FORM NO. 1I1-F13-Q (NEW. 03-07) Page 231
Name of Respondent
Idaho Power Company
This Re ort Is:
AResubmission
Date of Report (Mo,Da,Yr)
Year/Period of Report
End of 201 2/Q4
Transmission Service and Generation Interconnection Study Costs (continued)
Line
No
-
Description
(a)
Costs Incurred During
Period
(b)
Account Charged
(C)
Reimbursements
Received During
the Period
(d)
Account Credited
With Reimbursement
(e)
1 Transmission Studies
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21 Generation Studies
266 186623 13,662 186623 22 COLEMAN HYDRO GI 362
23 GRAND VIEW SOLAR TWO 01 369 8,881 186623 ( 10,000) 186623
24 MEADOW CREEK WIND GI 370 186623 139,096 186623
25 MTNAIR EXPANSION 01 373-378 186623 28,899 186623
26 BANNOCK COUNTY LANDFILL GI 380 7,517 186623 1,253 186623
27 1 FARGO DROP GI 382 ( 4,348) 186623 7,023 186623
28 BETASEED BIOGAS GI 383 186623 ( 1,913) 186623
29 JETTCREEKW1NDFARM GI 384 3,252 186623 ( 2,252) 186623
30 PROSPECTOR WINDFARM GI 385 186623 1,000 186623
31 BENSON CREEK WINDFARM 01 386 186623 1,000 186623
321 DURBIN CREEK WINDFARM 01387 186623 1,000 186623
33 MIDPOINT SOLAR G1388 6,861 186623 ( 6,861) 186623
34 AMALSUGAR PAUL 01 389 3,067 186623 ( 1,000) 186623
35 EAGLE VIEW DAIRY 01 390 11,487 186623 ( 17,686) 186623
36 GRANDVIEW SOLAR 3 01 394 2,616 186623 ( 16,000) 186623
371 GRANDVIEW SOLAR 4 GI 395 13,268 186623 ( 16,000) 186623
38 MURPHY FLAT WIND FARM 7,112 186623 ( 20,000) 186623
39 BLACK CANYON BLISS HYDRO 186623 ( 500) 186623
40 BENSON CREEK WINDFARM GI 401 186623 ( 51,000) 186623
FERC FORM NO. I/l -F!3-Q (NEW. 03-07) Page 231.1
Name of Respondent
Idaho Power Company
This Report Is:
(1)IX1 An Original L_4
(2)0 A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2013
Year/Period of Report
nu OT 2012/Q4
Transmission Service and Generation Interconnection Study Costs (continued)
No Description
(a)
Line Costs Incurred During
Period
(b)
Account Charged
(c)
Received During
the Period
(d)
Account Credited
With Reimbursement
(e)
I
2
Transmission Studies
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21 Generation Studies
186623 ( 1,000) 186623 22 DURBIN CREEK WINDFARM GI 402
23 JETT CREEK WINDFARM GI 403 186623 ( 1,000) 186623
24 PROSPECTOR WINDFARM GI 404 186623 ( 1,000) 186623
25 WILLOW CREEK WINDFARM GI 405 186623 ( 1,000) 186623
26 SHOSHONE FALLS GI 136 47,511 186623 186623
27
28
29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO. 1I1-F13-Q (NEW. 03-07) Page 231.2
This Page Intentionally Left Blank
Name of Respondent
Idaho Power Company
This Re ort Is:
Resubmission
Date of Report
04/15/2013
Year/Period of Report
End of 2012/Q4
OTHER REGULATORY ASSETS (Account 182.3)
1.Report below the particulars (details) called for concerning other regulatory assets, including rate order docket number, if applicable.
2.Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $100,000 which ever is less), may be grouped
by classes.
3.For Regulatory Assets being amortized, show period of amortization.
Line
No.
-
Description and Purpose of
Other Regulatory Assets
(a)
Balance at Beginning
of Current
Quarter/Year
(b)
Debits
(c)
CREDITS Balance at end of
Current Quarter/Year
(f)
Written off During the
Quarter (Year Account
Charged (d)
Written off During
the Period Amount
(e)
1 Asset Retirement Obligations (182341) 15,557,422 475,084 1823/230 2,448,633 13,583,873
2 IPUC Order# 29414-OPUC Order# 04-585
3
4 ASC 815 Mark to Market- ST (182330) 4,599,099 15,345,805 244 18,890,261 1,054,643
5
6 ASC 815 Mark to Market LT (182333) 107,763 754,454 244 862,217
7
8 Regulatory Unfunded (182322) 603,772,178 74,023,292 677,795,470
9 Accum Deferred Income Noncurrent
10
11 PCA Deferral Idaho - IPUC Order #27660 129,900,586 Various 77,551,097 52,349,489
12 (Amort period 06/12 thru 05/13) (182323)
13
14 PCA Prior Year Deferral Idaho - IPUC Order #27660 117,190,627 Various 137,659,759 -20,469,132
15 (Amort period 06/11 thru 05/12) (182324)
16
171 Fixed Cost Adjusment (FCA) (182302) 10,273,296 15,154,508 1823 16,597,586 8,830,218
18 IPUC Order #30267 (amort period 06/12 thru 05/13)
19
20 Prior Year FCA IPUC Order #30267 (182309) 4,183,172 34,887,291 1823/400 34,483,059 4,587,404
21
22 FERC Grid West Expense (182304) 111,728 401 83,796 27,932
23 ER08-629-000 (amort period 05/08 thru 04/13)
24
25 AOCI Impact of Unfunded Post Retirement Liability 15,536,177 2,440,534 228 2,081,396 15,895,315
26 IPUC Order #30256(182306)
27
28 Oregon Pension Expense Capitalized 1,345,487 609,906 401/4073 51,008 1,904,385
29 OPUC Order #10-064 (182339)
30 (Avg amort 35ym for each yr capitalized expense)
31
32 Deferred Pension Expense Net of Contributions 17,140,322 38,341,161 Various 42,641,622 12,839,861
33 IPUC Order #30333 (182321)
34
35 AOCI Impact of Unfunded Pension Liability 246,966,765 60,448,165 228 14,460,369 292,954,561
36 IPUC Order #30256(182320)
37
38 ID DSM Rider Reclass IPUC Order #29026 (182301) 5,321,997 2,803,416 254 8,125,413
39
40 PCAM Oregon 2008 (182346) 6,454,985 522,415 6,977,400
41 OPUC Order #08-238
42
43 PCAM Interest Reserve 2008 (182329) ( 429,062) 4210 171,220 -600,282
FERC FORM NO. 113-Q (REV. 02-04) Page 232
Name of Respondent
Idaho Power Company
This Re art Is:
'RSSiOn
Date of Report
04/15/2013
Year/Period of Report
End of 2012/Q4
OTHER REGULATORY ASSETS (Account 182.3)
1.Report below the particulars (details) called for concerning other regulatory assets, including rate order docket number, if applicable.
2.Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $100,000 which ever is less), may be grouped
by classes.
3.For Regulatory Assets being amortized, show period of amortization.
Line
No.
Description and Purpose of
Other Regulatory Assets
(a)
Balance at Beginning
of Current
Quarter/Year
(b)
Debits
(c)
CREDITS Balance at end of
Current QuarterlYear
(f)
Written off During the
Quarter Near Account
Charged (d)
Written off During
the Period Amount
(e)
I OPUC Order #08-238
2
3 Excess Power Cost Deferral 2007 (182358) 4,762,316 2,178,235 254 4,537,039 2,403,512
4 IPUC Order #09-189
5
6 2007 EPC Interest Reserve (182351) ( 308,869) 149,208 -159,661
7 IPUC Order #09-189
8
9 Oregon DSM Rider Reclass (182359) 3,537,442 11,370,116 254 14,907,558
10 OPUC Advice #05-03
11
12 2009 Reorg IPUC Order #330914 (182318) 691,967 401 230,656 461,311
13 (amort period 01/10 thru 12114)
14
15 OATT Revenue Deferred Reserve (182336) 2,064,469 400 401,425 1,663,044
16 IPUC Order 930940 (amort period 01111 thru 12/13)
17
18 Idaho Pension Cash (182327) 38,976,484 48,631,908 401/4210 37,572,305 50,036,087
19 IPUC Order #32248 (amort period 06/11 thru 05/14)
20
21 FERC Pension Cash (182328) 582,156 70,000 401 437,695 214,461
22 IPUC Order #32248 (amort period 06/11 thru 05/14)
23
24 Excess Power Cost Unbilled Amort (186356) ( 142,646) 1,888,291 401 1,883,067 -137,422
25
26 Gus Efficiency Incentive IPUC Order #32245 (182317) 7,230,724 6,889,623 254 34,146 14,086,201
27
281 Gus Efficiency Incen Res IPUC Order #32245 (182314) ( 134,282) 291,455 1823/4210 1,073,638 -916,465
29
30 Lidar Surveys IPUC Order #32426(182361) 436,047 402 43,605 392,442
31 (amort period 01/12 thru 12121)
32
331 Bennett Mtn Maintenance IPUC Order #32426 299,546 402 74,886 224,660
34 (amort period 01/12 thru 12/15) (182379)
35
36 PCA Unbilled Amortization (182316) 27,899,136 254/401 25,207,858 2,691,278
37
381 Idaho BoardlmanARO Order #32549 (182393) 1,476,390 403114110 100,337 1,376,053
39
40 Langley Revenue Accrual Order #12-226(182398) 814,665 4074 7,271 807,394
41
42 257,332 1,926,126 Various 1,946,764 236,694
43
44 TOTAL: 989,194,015 596,482,397 444,565,686 1,141,110,726
FERC FORM NO. 113-Q (REV. 02-04) Page 232.1
This Page Intentionally Left Blank
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
Idaho Power Company (2)- A Resubmission 04/15/2013 2012/Q4
FOOTNOTE DATA
Schedule Page: 232.1 Line No.: 42 Column: a
Accounts included in minor items:
182305
182331
182334
182335
182340
182344
182345
182349
182350
182352
182353
182355
182362
182369
182371
182372
182374
182375
182376
182377
182380
182390
182391
182392
182394
182396
182397
182399
FERC FORM NO. I (ED. 12-87) Page 450.1 1
Name of Respondent
Idaho Power Company
This Re ort Is:
2nRsiQn
Date of Report
04115/2013
Year/Period of Report
End of 2012/Q4
MISCELLANEOUS DEFFERED DEBITS (Account 186)
1.Report below the particulars (details) called for concerning miscellaneous deferred debits.
2.For any deferred debit being amortized, show period of amortization in column (a)
3.Minor item (1% of the Balance at End of Year for Account 186 or amounts less than $100,000, whichever is less) may be grouped by
classes.
Line
No
-
Description of Miscellaneous
Deferred Debits
(a)
Balance at
Beginning of Year
(b)
Debits
(C)
CREDITS Balance at
End of Year
(f)
Account Charaed
(d)
t'dItOUnL
(e)
1 Prepaid ROW (186160) 715,957 113,600 401 91,362 738,195
2 Rents/Easements Long Term
3
4 Advance Prepaid (186709) 1,367,261 143/151 33,315 1,333,946
5 Coal Royalties
6
7 Security plan (186720) 19,001,732 881,380 165/4262 1,386,445 18,496,667
8 Net Insurance Asset
9
10 American Falls Bond Ref(1 86722) 191 ,604 401 14,552 177,052
11 (Amort 04/00 - 02/25)
12
13 Prepaid Credit Facility(186025) 992,670 1,445,227 431 1,475,836 962,061
14 (amort period 10/12 thru 10/17)
15
16 Company Owned (186726) 5,058,356 1,982,401 Various 2,891,345 4,149,412
17 Life Insurance
18
19 American Falls Water Rights 13,632,948 401 1,042,009 12,590,939
20 (amort 01/06 - 02125) (186727)
21
221 Milner Bond Guarantee (186734) 6,381,818 253 1,063,636 5,318,182
23 (Amort 02/07 - 2/17)
24
25 American Falls - Bond refinance 631.989 401 47,999 583,990
26 (Amort through 02/25)(186770)
27
281 Transmission Deposit(186784) 710,578 6,987 131 717,565
29
30 Prepaid Exp (186052) 650,472 1,163,703 401 665,987 1,148,188
31 Contract I.T. Long Term
32
33 Long Term (186121) 1,268,456 228 53,791 1,214,665
34 Workers Compensation
35
36 Power Plant- Valmy (186793) 136,406 683,486 107 803,397 16,495
37
38 Power Plant- Boardman (186794) 104,813 61,020 107/401 164,234 1,599
39
40 Transmission & Generation 6,651,247 Various 5,429,021 1,222,226
41 Studies (186623)
42
43 Prepaid Coal LT (186797) 1 5,958,328 5,958,328
44
45 35,142 8,175,376 Various 8,208,613 1,905
46
47 Misc. Work in Progress
-
Deferred Regulatory Comm.
Expenses (See pages 350 - 351)
49 TOTAL 50,880,20 53,913,850
FERC FORM NO. I (ED. 12-94) Page 233
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 04/15/2013 2012/Q4
FOOTNOTE DATA
Schedule Paqe: 233 Line No.: 45 Column: a
Accounts included in minor items:
186100
186304
186731
186946
IFERC FORM NO. I (ED. 12-87) Page 450.1 I
Name of Respondent
Idaho Power Company
This Rei,ort Is:
(1)An Original
(2)fl A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2013
Year/Period of Report
2012/Q4
ACCUMULATED DEFERRED INCOME TAXES (Account 190)
1.Report the information called for below concerning the respondent's accounting for deferred income taxes.
2.At Other (Specify), include deferrals relating to other income and deductions.
Dire
N °.
Description and Location
(a)
Balance of Begining
of Year
(b)
Balance at End
of Year
(c)
I Electric
2
3
4
5 Other Electric (See footnote) 109,509,600
6
7 Other (See footnote) 185,672,424
8 TOTAL Electric (Enter Total of lines 2 thru 7) 208,895,006 295,182,024
9 Gas
10
11
12
13
1
15 Other
IC TOTAL Gas (Enter Total of lines 10 thru 15
17 Other Non Electric See footnote 21,080,753
18 TOTAL (Acct 190) (Total of lines 8,16 and 17) 227,977,046 316,262,777
Notes
FERC FORM NO. I (ED. 12-88) Page 234
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
Idaho Power Company (2)- A Resubmission 04/15/2013 20121Q4
FOOTNOTE DATA
Schedule Page: 234 Line No.: 5 Column: b I
Federal NOL-Operating
AFUDC Hells Canyon Relicensing
Deferred Idaho ITC
Post Retiree Benefits-VEBA
Regulatory Asset-Non Current
Stock Based Compensation
Advances for Construction
Revenue Sharing
Rate Case Disallowance
Oregon-Pension Expense
Regulatory Liability-Current
Executive Deferred Compensation
Valmy Union Pacific Contract
Post Retirement Benefits
Oregon NOL-Operating
Non-VEBA Pension and Benefits
Montana NOL-Operating
Bridger Revenue Deferral
Deferred GBC
Prov For Rate Refunds-Bridger PC
Boardman Decommission
Total Other Electric
Beginning Balance Ending Balance
- 45,964,500
12,958,192 17,855,802
5,539,827 13,747,559
7,474,519 9,221,017
- 4,458,718
2,777,081 3,148,063
5,117,985 3,009,900
10,594,314 2,795,770
2,621,256 2,505,417
1,504,842 1,897,934
- 1,722,247
1,344,427 968,904
- 884,286
1,172,345 822,852
- 262,521
265,356 217,768
- 78,812
- 65,767
24,000 24,000
- 8,895
- (151,131)
51,394,143 109,509,600
Schedule Page: 234 Line No.: 7 Column: b
Pension 96,551,657 114,530,586
Regulatory Liability for Income Taxes 45,472,547 51,285,735
Minimum Pension Liability 9,109,442 13,641,829
Postretirement Plan 6,367,217 6,214,273
Total Other 157,500,863 185,672,424
Schedule Page: 234 Line No.: 17 Column: b
Senior Management Security Plan 16,319,201 17,720,515
SMSP-Market Change of Rabbi Investments 1,626,015 1,626,015
Federal NOL-Non Operating - 850,678
Micron-CIAC 1,050,482 812,600
Meridian Gold Contributions 86,342 64,230
Oregon NOL-Non Operating - 5,037
Montana NOL-Non Operating - 1,679
Total Non Electric 19,082,040 21,080,753
IFERC FORM NO. 1 (ED. 12-87) Page 450.1 I
Name of Respondent
Idaho Power Company
This Report Is:
(2) F]A Resubmission
Date of Report
04/15/2013
Year/Period of Report
End of 2012/Q4
CAPITAL STOCKS (Account 201 and 204)
1.Report below the particulars (details) called for concerning common and preferred stock at end of year, distinguishing separate
series of any general class. Show separate totals for common and preferred stock. If information to meet the stock exchange reporting
requirement outlined in column (a) is available from the SEC 10-K Report Form filing, a specific reference to report form (i.e., year and
company title) may be reported in column (a) provided the fiscal years for both the 10-K report and this report are compatible.
2.Entries in column (b) should represent the number of shares authorized by the articles of incorporation as amended to end of year.
Call Price at Line
No.
-
Class and Series of Stock and
Name of Stock Series
(a)
Number of shares
Authorized by Charter
(b)
Par or Stated
Value per share
(c)
End of Year
(d)
1 Account 201
2 Common Stock registered on New York 50,000,000 2.50
3 and Pacific Stock Exchange
4 Total Common Stock 50,000,000 2.50
5
6 Account 204 - None
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
FERC FORM NO. 1 (ED. 12-91) Page 250
Name of Respondent
Idaho Power company
This Re ott Is:
(1)An Original
(2)0A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2013
Year/Period of Report
End of 2012104
CAPITAL STOCKS (Account 201 and 204) (Continued)
3.Give particulars (details) concerning shares of any class and series of stock authorized to be issued by a regulatory commission
which have not yet been issued.
4.The identification of each class of preferred stock should show the dividend rate and whether the dividends are cumulative or
non-cumulative.
5.State in a footnote if any capital stock which has been nominally issued is nominally outstanding at end of year.
Give particulars (details) in column (a) of any nominally issued capital stock, reacquired stock, or stock in sinking and other funds which
is pledged, stating name of pledgee and purposes of pledge.
OUTSTANDING PER BALANCE SHEET (Total amount outstanding without reduction
for amounts held by respondent)
HELD BY RESPONDENT Line
No. AS REACQUIRED STOCK (Account 217) IN SINKING AND OTHER FUNDS
Shares (e) Amount (f) Shares
(g) Cost (h) Shares (i)
Amount
39,150,812 97,877,030 2
3
39,150,812 97,877,030 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
Idaho Power Company
This Report Is: Date of Report
04/15/2013
Year/Period of Report
End of 2012/04
OTHER PAID-IN CAPITAL (Accounts 208-211, Inc.)
Report below the balance at the end of the year and the information specified below for the respective other paid-in capital accounts. Provide a
subheading for each account and show a total for the account, as well as total of all accounts for reconciliation with balance sheet, Page 112. Add more
columns for any account if deemed necessary. Explain changes made in any account during the year and give the accounting entries effecting such
change.
(a)Donations Received from Stockholders (Account 208)-State amount and give brief explanation of the origin and purpose of each donation.
(b)Reduction in Par or Stated value of Capital Stock (Account 209): State amount and give brief explanation of the capital change which gave rise to
amounts reported under this caption including identification with the class and series of stock to which related.
(c)Gain on Resale or Cancellation of Reacquired Capital Stock (Account 210): Report balance at beginning of year, credits, debits, and balance at end
of year with a designation of the nature of each credit and debit identified by the class and series of stock to which related.
(d)Miscellaneous Paid-in Capital (Account 211 )-Classify amounts included in this account according to captions which, together with brief explanations,
disclose the general nature of the transactions which gave rise to the reported amounts.
len Arynt
1 Account 208 - Donations received from stockholders - None
2
3 Account 209 - Reduction in par or stated value of Capital Stock - None
4
5 Account 210- Gain on reacquired Capital Stock - None
6
7
8 Account 211 - Miscellaneous paid-in Capital - None
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40 TOTAL
FERC FORM NO. 1 (ED. 12-87) Page 253
Name of Respondent
Idaho Power Company
This Re ort Is:
2'sSi on
Date of Report
04/15/2013
Year/Period of Report
End of 20121Q4
CAPITAL STOCK EXPENSE (Account 214)
1.Report the balance at end of the year of discount on capital stock for each class and series of capital stock.
2.If any change occurred during the year in the balance in respect to any class or series of stock, attach a statement giving particulars
(details) of the change. State the reason for any charge-off of capital stock expense and specify the account charged.
Line
No.
Class and Series of Stock
(a)
Balance at End of Year
(b)
1 common Stock 2,096,925
2
3
4
5
6
7
8
9
10 Explanation of Changes during the year:
11
12
13
14
15
16
17
18
19
20
21
22 TOTAL 2,096,925
FERC FORM NO. I (ED. 12-87) Page 254b
Name of Respondent
Idaho Power Company
This Re oil Is:
AResLJbrflISSion
Date of Report
04/15/2013
Year/Period of Report
End of 2012/04
LONG-TERM DEBT (Account 221, 222, 223 and 224)
1.Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221, Bonds, 222,
Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt.
2.In column (a), for new issues, give Commission authorization numbers and dates.
3.For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds.
4.For advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate
demand notes as such. Include in column (a) names of associated companies from which advances were received.
5.For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were
issued.
6.In column (b) show the principal amount of bonds or other long-term debt originally issued.
7.In column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued.
8.For column (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount.
Indicate the premium or discount with a notation, such as (P) or (D). The expenses, premium or discount should not be netted.
9.Furnish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with
issues redeemed during the year. Also, give in a footnote the date of the Commission's authorization of treatment other than as
specified by the Uniform System of Accounts.
Line
No.
-
Class and Series of Obligation, Coupon Rate
(For new issue, give commission Authorization numbers and dates)
(a)
Principal Amount
Of Debt issued
(b)
Total expense,
Premium or Discount
(c)
I Account 221:
2 First Mortgage Bonds:
314.50% Series due 2020 130,000,000 1,190,698
4 234,601 D
5
6 5.50% Series due 2033 70,000,000 728,701
7 36,400 0
8
9 6.15% Series Due 2019 100,000,000 1,034,909
10 184,949 D
11
12 3.40% Series due 2020 100,000,000 1,159,871
13 ______________ 498,864 D
14
15 5.30% Series Due 2035 60,000,000 408,411 D
16 3,802,019
17
18 4.25%Series due 2013 70,000,000 641,201
19 372,696 D
20
21 4.75% Series due 2012 100,000,000 944,356
22 1,047,617 0
23
24 6.00% Series due 2032 100,000,000 1,191,216
25 543,244 D
26
27 5.875% Series due 2034 55,000,000 -585,759
28 746,961 0
29
30 5.50% Series due 2034 50,000,000 524,419
31 383,322 D
32
33 TOTAL 1,647,045,0001 27,957,280
FERC FORM NO. 1 (ED. 1296) Page 256
Name of Respondent
Idaho Power Company
This Re ort Is: Date of Report
04(15/2013
Year/Period of Report
End of 2012/Q4
LONG-TERM DEBT (Account 221, 222, 223 and 224) (Continued)
10.Identify separate undisposed amounts applicable to issues which were redeemed in prior years.
11.Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, Premium
on Debt - Credit.
12.In a footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to long-term
advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c)principle repaid
during year. Give Commission authorization numbers and dates.
13.If the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee
and purpose of the pledge.
14.If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end of
year, describe such securities in a footnote.
15.If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest
expense in column (I). Explain in a footnote any difference between the total of column (i) and the total of Account 427, interest on
Long-Term Debt and Account 430, Interest on Debt to Associated Companies.
16.Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.
Nominal Date
of issue
Date of
Maturity
AMORTIZATION PERIOD Outstanding (Total amount outstanaing without
reductIonrp held by Interest for Year
Amount
Line
Date From Date To
11/20/09 3/1/20 11/20/09 3/1/20 130,000,000 5,850,000 3
4
5
05/01/03 04/01/33 05/01/03 03/31/33 70,000,000 3,850,000 6
7
8
4/1/09 4/1119 4/1/09 4/1/19 100,000,000 6,150,000 9
10
11
11/1/10 5/1/2020 11/1/10 5/1/20 100,000,000 3,400,000 12
13
14
08126/05 08/26/35 08/26/05 08/26135 60,000,000 3,180,000 15
16
17
05/01/03 10/01/13 05/01/03 09/29/13 70,000,000 2,975,000 18
19
20
11/15/02 11/15/12 11/15/02 11/15/12 1,781,250 21
22
23
11/15/02 11/15/32 11/15/02 11/15/32 100,000,000 6,000,000 24
25
26
08/16/04 08/16/34 08/16/04 08/16/34 55,000,000 3,231,250 27
28
29
03/26/04 03/15/34 03/26/04 03/15/34 50,000,000 2,750,000 30
31
32
1,540,663,182 78,922,057 33
FERC FORM NO. I (ED. 12-96) Page 257
Name of Respondent
Idaho Power Company
This Re oil Is: Date of Report
04/15/2013
Year/Period of Report
End of 20121Q4
LONG-TERM DEBT (Account 221, 222, 223 and 224)
1.Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221, Bonds, 222,
Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other tong-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 tong-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
No.
Class and Series of Obligation, Coupon Rate
(For new issue, give commission Authorization numbers and dates)
(a)
Principal Amount
Of Debt issued
(b)
Total expense,
Premium or Discount
(C)
1 4.85% Series Due 2040 100,000,000 1,284,871
2 169,984 D
3
4 6.30% Series due 2037 140,000,000 1,495,799
5 278,367 0
6
7 6.25% Series due 2037 100,000,000 1,141,489
8 267,677 D
9
10 Port of Morrow Variable due 2027 4,360,000 188,545
11
12 Humboldt Variable due 2024 49,800,000 1,697,856
13
141 Sweetwater Variable due 2026 116,300,000 3,026,122
15
16
17 6.025 % Series Due 2018 120,000,000 1,630,120
18
19 4.30% Series Due 2042 75,000,000 802,240
20 49,417 D
21 2.95% Series Due 2022 75,000,000 708,490
22 127,607 D
23 Subtotal Account 221 1,615,460,000 27,957,280
24
25 Account 222 - Reaquired Bonds
26
27 Account 223: Advances for Associated Companies
28
29 Account 224:
30 Bond Guarantee - American Falls 19,885,000
31 Note Guarantee - Milner Dam 11,700,000
32 Subtotal Account 224 31,585,000
33 TOTAL 1,647,045,0001 27,957280
FERC FORM NO. 1 (ED. 1296) Page 256.1
Name of Respondent
Idaho Power Company
This Re ort Is:
2''s sion
Date of Report
/113
Year/Period of Report
End of 2012/04
LONG-TERM DEBT (Account 221, 222, 223 and 224) (Continued)
10. Identify separate undisposed amounts applicable to issues which were redeemed in prior years.
II. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, Premium
on Debt - Credit.
12.In a footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to long-term
advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid
during year. Give Commission authorization numbers and dates.
13.If the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee
and purpose of the pledge.
14.If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end of
year, describe such securities in a footnote.
15.If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest
expense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427, interest on
Long-Term Debt and Account 430, Interest on Debt to Associated Companies.
16.Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.
Nominal Date
of Issue
(d)
Date of
Maturity
(e)
AMORTIZATION PERIOD 0u1dui9 (Total amount outstanaing without
reduchonrpar18tts held by
?h)
Interest for Year
Amount
(i)
Line
-
Date From
(f)
Date To
(g)
2/15/10 8/15/40 2/15/10 8/15/40 100,000,000 4,850,000 1
2
3
6/22/07 6/15/2037 6/22/07 6/15/37 140,000,000 8,820,000 4
5
6
10/18/07 10/15/2037 10/18/07 10/15/37 100,000,000 6,250,000 7
8
9
05/17/00 02/01/27 05/17/00 02/01/27 4,360,000 37,232 10
11
10/22/03 12/01/24 11/01/03 12101/24 49,800,000 2,564,700 12
13
10/3/06 7/15/26 10/3/06 7/15/26 116,300,000 6,105,750 14
15
16
7/10/08 7/15/18 7/10/08 7/15/08 120,000,000 7,230,000 17
18
4/13/12 4/1/42 4/13/12 4/1/42 75,000,000 2,311,250 19
20
4/13/12 4/1/22 4/13/12 4/1/22 75,000,000 1,585,625 21
22
1,515,460,000 78,922,057 23
24
25
26
27
28
29
04/26/00 2/1/25 19,885,000 30
02/10/92 5,318,182 31
25,203,182 32
1,540,663,182 78,922,057 33
FERC FORM NO. 1 (ED. 12-96) Page 257.1
Name of Respondent
Idaho Power Company
This Re ort Is:
AReSUb1flission
Date of Report
04/15/2013
Year/Period of Report
End of 2012/Q4
RECONCILIATION OF REPORTED NET INCOME WITH TAXABLE INCOME FOR FEDERAL INCOME TAXES
1.Report the reconciliation of reported net income for the year with taxable income used in computing Federal income tax accruals and show
computation of such tax accruals. Include in the reconciliation, as far as practicable, the same detail as furnished on Schedule M-1 of the tax return for
the year. Submit a reconciliation even though there is no taxable income for the year. Indicate dearly the nature of each reconciling amount.
2.If the utility is a member of a group which files a consolidated Federal tax return, reconcile reported net income with taxable net 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.
N
Line (Details)
(a)
Amount
(b)
1 Net Income for the Year (Page 117) 168,168,039
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
-
22
23
24
25
26
27 Federal Tax Net Income
28 Show Computation of Tax:
29 Tenative Federal Tax @ 35%
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
FERC FORM NO. I (ED. 12-96) Page 261
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 04/15/2013 2012/Q4
FOOTNOTE DATA
Schedule Page: 261 Line No.: 5 Column: b
4000-FEDERAL NOL $ 133,757,649
4003-CONSTRUCTION ADV-252 (6,023,102)
4005-AVOIDED COST tNT CAP 14,498,584
4006-RETIREMENTS-RECORD TAX GAIN/LOSS 4,000,000
4010-EMISSION ALLOWANCE-254.409-411 239,401
4013-CIAC TAXABLE INCOME-IN ACCT 107 (4,044,584)
4021-ENGINEERING FEES-TAXABLE-IN ACCT 107 185,124
4024-RENEWABLE ENERGY CERTIFICATES (REC) SALES 4,914,112
4506-CIAC-MERIDIAN GOLD (56,560)
4507-CIAC-MICRON-DRAM (608,470)
Total $ 146,862,154
ISchedule Page: 261 Line No.: 10 Column: b I
Total Federal and State taxes deducted on books $ 32,747,228
4011-RETIREMENTS-BOOK ACCTG REVERSED 324,912
4014-DARK FIBER CNTRCTS (33,333)
5001-BAD DEBT EXPENSE 437,421
5010-SFAS I 12-POST-EMPLY BEN 182/253 (893,956)
501 4-OVERACCRUED VACATION-ACCT 242 (351,199)
5017-INJURIES & DAMAGES 808,602
5019-DIRECTORS FEES DEE 19,066
5022-CAPITALIZED OVERHEADS (24,792,454)
5024-MEALS (50% NON-DEDUCTIBLE) CHRGD TO R.E. 600,000
5025-MILNER FALLING WATER - REV ACCRL (238,941)
5027-AMORTIZATION OF ACCOUNT 114 441,194
5028-OREGON OPER PROPERTY TAX ADJ (158,609)
5030-IPCO MIGRATION/SHAREOWNER RGHTS (248,959)
5023-PENSION EXPENSE-Acct 228 21,839,939
5033-NONVEBA PEN&BEN-Acct 228 (121,725)
5035-PCA EXPENSE DEFERRAL (47,922,795)
5043-AMERICAN FALLS - FALLING WATER CONTRACT-FT 219,181
5046-EXECUTIVE DEFERRED COMP-SHORT TERM 147,701
5047-EXECUTIVE DEFERRED COMP-LONG TERM (1,108,242)
5052-AMORTIZATION OF ACCOUNT 181 310,738
5053-STOCK BASED COMPENSATION 838,659
5055-OPUC GRID WEST LOANS-ACCT 182 14,191
5056-FERC GRID WEST EXP-ACCT 182 83,796
5057-INTERVENER FUNDING ORDERS-ACCT 182 32,135
5058-FIXED COST ADJUSTMENT (FCA)-ACCT 182 1,038,846
5059-PS & I COSTS-ACCT 182 33,915
5060-OREGON-PCAM (POWER COST ADJ MECHANISM) (1,689,298)
5061-PENSION EXPENSE-OREGON 1,824,384
5062-LIDAR SURVEYS DEFFERAL-ACCT 182 43,605
5063-BENNETT MTN MAINT DEFERRAL 74,886
5064-BRIDGER REVENUE DEFERRAL 168,224
5065-VALMY UNION PACIFIC CONTRACT 2,261,891
5066-BOARDMAN DECOMMISSION (386,574)
5501-SEC PLAN-NET INSURANCE COSTS (49,323)
5503-128-EDC-UNREALIZED GAIN/LOSS FROM RABBI TRUST (843,602)
5504-NONDEDUCTIBLE POLITICAL EXP-426.4 942,261
IFERC FORM NO. 1 (ED. 12-87) Page 450.1 I
This Page Intentionally Left Blank
Name of Respondent This Report is: Date of Report Year/Period of Report
(I) An Original (Mo, Da, Yr)
Idaho Power Company (2) - A Resubmission 04/15/2013 20121Q4
FOOTNOTE DATA
5505-SEC PLAN-BENEFIT ACCR 3,584,382
5510-FINES & PENALTIES-OPERATING (560,511)
5531-RATE CASE DISALLOWANCES-REVERSE AMORT (296,299)
5532-DELIVERY ACCRUALS-253.550 2,696
5536-VEBA INCOME TAXES (1,537)
CM14-RECALSS ACQUISTION ADJ 114 (454,449)
Irotal $ (11,311,
Schedule Page: 261 Line No.: 15 Column: b 1
7009-PROV FOR RATE REFUND-BRIDGER POLLUTION CONTROL $ (22,751)
701 0-AFUDC HC RELICENSING-ACCT 229 (12,527,458)
7011-OATT REVENUE DEFICIENCY (401,425)
7012-REVENUE SHARING ACCT 25-CURR 19,947,676
701 3-LANGLEY REVENUE ACCRUAL 802,262
7501-REVERSE EQUITY EARNINGS OF SUBSIDIARIES 6,150,724
7502-ALLOWANCE FOR OFUDC 22,433,417
7503-ALLOWANCE FOR BFUDC 11,929,405
7509-SECURITY PLAN-INSURANCE PROCEEDS 236.376
chedule Page: 261 Line No.: 20 Column: b 1
8001 -VEBA-POST RET BNFTS-TRUST-ACCT 228 $ (4,437,438)
8009-DEPR-FEDERAL ADJ 182,781,618
801 6-VEBA-POST RET BNFTS-TRUST-MEDICARE PART D 398,251
8020-CONSERVATION PROGRAMS (8,949,040)
8027-NEVADA OPERATING PROPERTY TAX ADJ (42,023)
8034-REMOVAL COSTS 7,706,171
8038-OREGON EXCESS PWR SUPPLY COSTS (2,204,373)
8039-STATE TAX-NOT DEDUCTED ON PRIOR RETURN 168,884
8041-AM FALLS - UNAMORTIZED DEBT EXP (47,999)
8042-GAIN/LOSS ON REACQUIRED DEBT-FT 1,307,345
8057-REORGANIZATION COSTS (230,656)
8072-INTANGIBLE ASSET-LABOR DEDUCT-IN ACCT 107 1,605,000
8073-REPAIRS DEDUCTION 55,000,000
8077-PP INS & OTR EXP (1 YR OR LESS)-165 64,321
8079-CUSTOM EFFICIENCY INCENTIVE PAY 6,073,295
8080-APPLY DOE FUNDS TO AMI CLOSED WO'S 11,716,783
8501 -COLI-TAX ADJ FROM BOOKS 123,678
8504-OREGON NONOP PROPERTY TAX ADJUST 16
8703-IPCO - 162 (M) $lm THRESHOLD (147,264)
8901-REGULATORY ASSET-CURRENT 11,404,830
8901-REGULATORY ASSET-NON CURRENT (11,404,830)
8902-REGULATORY LIABILITY-CURRENT (4,405,288)
8902-REGULATORY LIABILITY-NON CURRENT 4,405,288
STATE INCOME TAX DEDUCTED ON FEDERAL RETURN 4,283,445
Total $ 255,170,014
IFERC FORM NO. I (ED. 12-87) Page 450.2 I
Name of Respondent
Idaho Power Company
This Re ort Is:
AR5UbmIS5ion
Date of Report
04115/2013
Year/Period of Report
End of 201 2/Q4
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
1.Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during
the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the
actual, or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts.
2.Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.)
Enter the amounts in both columns (d) and (e). The balancing of this page is not affected by the inclusion of these taxes.
3.Include in column (d) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued,
(b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other
than accrued and prepaid tax accounts.
4.List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained.
Line
No.
-
Kind of Tax
(See instruction 5)
(a)
BALANCE AT BEGINNING OF YEAR Charged Duig Year
(d)
I)(%5
During Year
(e)
Adjust
ments
(f)
Taxes Accrued (Account 236)
(b)
Prepaid Taxes
(include in Account 165)
(c)
I Federal:
2 Income -4,057,093 -14,584,809 -18,652,448
3 Social Security - (FOAB) 1,188 13,701,846 13,703,041
4 Unemployment 93,541 93,541
5 Subtotal Federal -4,055,905 -789,422 -4,855,866
6
7 State of Idaho:
8 Property 8,416,100 20,904,095 19,869,999
9 Non-Operating 10,914 23,078 22,457
10 Income -664,104 814,349 2,640,227
11 KWH 180,678 1,909,280 1,996,097
12 Unemployment 1 681,157 681,157 ______________
13 Regulatory Commission 2,042,319 2,042,319 ______________
14 Business License - Sho Ban 150 150
15 Subtotal Idaho 7,943,589 26,374,428 27,252,406 -2,000
16
17 State of Oregon
18 Property 1,182,418 2,525,392 2,684,001
19 Non-Operating Property 834 1,562 1,700
20 Income -110,793 -114,483 -99,661
21 Regulatory Commission 162,571 162,571
22 Unemployment 45,074 45,074
23 Franchise 167,970 748,331 723,173
24 Subtotal Oregon 57,177 1,183,252 3,368,447 3,516,858
25
26 State of Montana:
27 Property 135,483 270,942 271,049
28 Subtotal Montana 135,483 270,942 271,049
29
30 State of Nevada:
31 Property 508,757 985,247 943,225
32 Subtotal Nevada 508,757 985,247 943,225
33
34 State of Wyoming
35 Corporate License 4,850 4,850
36 Property 763,723 1,642,855 1,585,150
37 Subtotal Wyoming 763,723 1,647,705 1,590,000
38 Other States Income 51,658 -42,123 -1,789
39 Payroll Tax Credit -14,521,618
40
41 TOTAL 4,895,725 1,692,0091 17,293,606 28,715,883 -2,000
FERC FORM NO. 1 (ED. 12-96) Page 262
Name of Respondent
Idaho Power Company
This Re ort Is: Date of Report
04/15/2013
Year/Period of Report
End of 2012/Q4
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued)
5.If any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year,
identifying the year in column (a).
6.Enter all adjustments of the accrued and prepaid tax accounts in column (f) and explain each adjustment in a foot- note. Designate debit adjustments
by parentheses.
7.Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending
transmittal of such taxes to the taxing authority.
8.Report in columns (i) through (I) how the taxes were distributed. Report in column (I) only the amounts charged to Accounts 408.1 and 409.1
pertaining to electric operations. Report in column (I) the amounts charged to Accounts 408.1 and 109.1 pertaining to other utility departments and
amounts charged to Accounts 408.2 and 409.2. Also shown in column (I) the taxes charged to utility plant or other balance sheet accounts.
9.For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax.
BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED Line
(Taxes accrued
Accoqn 236) g)
Prepaid Taxes
(Ind. in Account 165)
(h)
Electric (Account 408.1, 409.1)
(I)
Extraordinary Items
(Account 409.3)
(j)
Adjustments to Ret.
Earnings (Account 439)
(k)
Other No.
10,546 -14,482,226 2
-8 13,701,846 3
93,541 4
10,538 -686,839 -102,583 5
6
7.
9,450,196 20,314,893
11,534 850
VW8
-2,489,982 1,150,954
91,860 1,909,280 I I ii
1 681,157 12
2,042,319 13
150
7,063,609 850 26,098,753 275,675 15
16
1,341,027 2,407,945 18
19
-125,615 -104,242 20
162,571 ' 21
45,074 22
193,128 748,331 23
67,513 1,341,027 3,259,679 108,768 24
25
26
135,376 270,367 27
135,376 270,367 575 28
29
30
466,735 985,247 31
466,735 985,247 32
33
34
4,850 35
821,427 1,642,855 36
821,427 1,647,705 37
11,324 -39,099 38
39
40
8,109,787 1,808,6121 17,014,195 279,411 41
FERC FORM NO. I (ED. 12-96) Page 263
This Page Intentionally Left Blank
Account
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 04/15/2013 2012/Q4
FOOTNOTE DATA
Schedule Paae: 262 Line No.: 2 Column: I
Account 409.2 $ (102,078)
Account 234.2 (505)
Total $ (102,583)
ISchedule Page: 262 Line No.:8 Column: I
Account 107 $ 587,202
Account 409.2 $ (159,930)
Account 234.2 (176,675)
Total $ (336,605)
Schedule Page: 262 Line No.: 11 Column: b
This balance is different from year end by $2,000. The $2,000 was for irrigation customer
refunds. The refunds had a contra balance and were inadverently reclassed from account
236208 to 143900.
Schedule Page: 262 Line No.: 18 Column: I
Account 107 $ 117,447
Schedule Page: 262 Line No.: 19 Column: I
Account 408.2 $ 1,562
Schedule Page: 262 Line No..: 20 Column: I
Account 409.2 $ (1,258)
Account 234.2 (8,983)
Total $ (10,241)
Schedule Page: 262 Line No.: 27 Column: I
Account 131 $ 575
Schedule Page: 262 Line No.: 38 Column: I
Account 409.2 $ (29)
Account 234.2 (2,995)
Total $ (3,024)
Schedule Page: 262 Line No.: 39 Column: i
This amount is an offset to lines 3, 4, 11 & 22. Each month employer paid payroll taxes
flow into various 408.1 accounts. Also each month these amounts are offset with a
different 408.1 account. These payroll taxes are then allocated back to balance sheet and
o & m accounts based on labor.
IFERC FORM NO. I (ED. 12-87) Page 450.1 I
Name of Respondent I This Report Is:
Idaho Power Company JAn Original
(2) n Resubmission
I Date of Report
(Mo, Da, Yr)
I 04/15/2013
Year/Period of Report
End of 2012/Q4
ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255)
Report below information applicable to Account 255. Where appropriate, segregate the balances and transactions by utility and
nonutility operations. Explain by footnote any correction adjustments to the account balance shown in column (g),Include in column (i)
the average period over which the tax credits are amortized.
Le
0.
Account
Subdivisions
a
Balance at Beginning of Year
(b)
Deferred for Year Allocations to Current Year's Income Adjustments
(9) Account No.
(c)
Amount
(d)
Account No.
(e)
Amount (f)
I Electric Utility
23%
34% 665,312 63,861
47%
510% 23,955,140 1,491,71,
611% 1240,255 26,37
7 Other - State 44,979,6941 411.4 1 12,322,9531 411.4 1684,801 =8 TOTAL 70,840,401 i 12,322,9531 3,266,751i
9
lO
Other (List separately
and show 3%, 4%, 7%,
10% and TOTAL)
Line 6 Col All% I
11
12 State of Idaho 44,979,695 411.4 12,322,953 411.4 1,684,801
13
14
15
16
17
11
19
20
21
22
23
24
25
26
2
28
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
FERC FORM NO. I (ED. 12-89) Page 266
Name of Respondent
Idaho Power Company
This Re ort Is:
(2) F] A Resubmission
Date of Report
04/15/2013 L
Year/Period of Report
End of 2012/Q4
ACCUMULATED D FERRED INVESTMENT TAX CREDI S (Account 255) (continued)
Balance at End of Year
(h)
Average PpriOd
to Income
(I)
ADJUSTMENT EXPLANATION Line
-
2
601,446 10.42 3
4
22,463,428 16.06 5
1,213,883 47.03 6
55,61 7,846 26.70 7
79,896,603 8
9
55,617,847 12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
FERC FORM NO. 1 (ED. 12-89) Page 267
Name of Respondent
Idaho Power Company
This R,Fort Is:
AResUb(flission
Date of Report
04/15/2013
Year/Period of Report
End of 2012/Q4
OTHER DEFFERED CREDITS (Account 253)
1.Report below the particulars (details) called for concerning other deferred credits.
2.For any deferred credit being amortized, show the period of amortization.
3.Minor items (5% of the Balance End of Year for Account 253 or amounts less than $100,000, whichever is greater) maybe grouped by classes.
Line
No.
Description and Other
Deferred Credits
(a)
Balance at
Beginning of Year
(b)
DEBITS
Credits
(e)
Balance at
End of Year
(f)
Contra
Account (c)
Amount
(d)
I Smart Grid (253200) 12,764,219 107/401 294,038,860 285,919,580 4,644,939
2
3j Point to Point Trans Study(253201) 876,153 232 500 875,653
4
5 FTV (253202) 4,066,666 400 400,000 3,666,666
6 (Arnort Period Mar 1998-Feb 2023)
7
8 Boardman To Hemingway (253220) 143/107 11,951,306 12,803,157 851,851
9
10 Sho Ban Trans ROW (253480) 247,500 242 15,000 232,500
11 (Amort Period Jan 2005 -Dec 2027)
12
13 Milner Falling Water (253953) 1,098,421 186/401 1,063,636 824,695 859,480
14 Amort Period (Feb 1992 - Feb 2017)
15
16 Postretirement Benefits (253960) 2,998,707 401 893,956 2,104,751
17
18 Directors Deferred Compensation 4,638,308 131 505,560 524,626 4,657,374
19 (253980-253999)
20
21 IBM Mainframe Software Licenses 734,853 232 775,115 40,262
22 (Amort period 2010-2015) (253950)
23
24 USAF Battery Replacement (253906) 105,706 107 137,263 31,575 18
25
26 39 various 22 89,623 89,640
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47 TOTAL 27,530,572 309,781,218 300,233,518 17,982,872
FERC FORM NO. I (ED. 12-94) Page 269
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
Idaho Power Company (2)- A Resubmission 04/1512013 20121Q4
FOOTNOTE DATA
ISchedule Page: 269 Line No.: 26 Column: a 1
Accounts included in minor items:
253000
253042
IFERC FORM NO. I (ED. 12-87) Page 450.1 I
Name of Respondent
Idaho Power Company
This Report Is: (1)An Original (2)M Resubmission
Date of Report (Mo, Da,Yr)
04/15/2013
Year/Period of Report
n 0 2012/Q4
ACCUMULATED DEFFERED INCOME TAXES - OTHER PROPERTY (Account 282)
1.Report the information called for below concerning the respondent's accounting for deferred income taxes rating to property not
subject to accelerated amortization
2.For other (Specify),include deferrals relating to other income and deductions.
-
Line
No.
Account
(a)
Balance at
Beginning of Year
(b)
CHANGES DURING YEAR
Amounts Debited
to Account 4lO.1
(c)
Amounts Credited
to Account 4ll.1
(d)
I Account 282
Electric I 82,177,337 9,229,1121 2
3Gas
4 Other
5 TOTAL (Enter Total of lines 2 thru 4) 333,334,634 82,177,337 9,229,112
6 Non-Operating Property
7 Other - Regulatory Asset for I 1 599,991,590
8
9 TOTAL Account 282 (Enter Total of lines 5 thru 933.326,224 82,177,337 9,229,112
10
111
Classification of TOTAL
Federal Income Tax 795,963,655 81,445,627 9,160,530
12 State Income Tax 137,362,569 731,710 68,582
13 Local Income Tax
NOTES
FERC FORM NO. 1 (ED. 12-96) Page 274
Name of Respondent
Idaho Power Company
This Report Is:
(1)F3flAn Original
(2)E A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2013
Year/Period of Report
End of
ACCUMULATED DEFERRED INCOME TAXES - OTHER PROPERTY (Account 282) (Continued)
3. Use footnotes as required.
CHANGES DURING YEAR ADJUSTMENTS
Balance at
End of Year
(k)
Line
No.
Amounts Debited
to Account 410.2
(e)
Amounts Credited
to Account 411.2
(f)
Debits Credits
Account
Credited Amount
(h)
Account
Debited
Amount
a)
406,282,859 2
3
4
406,282,859 5
6
182 18,32f 182 74,023,292 673,996,554 7
8
18,32E 74,023,292 1,080,279,413 9
15,376 59,850,992 928,084,366
10
II
2,952 14,172,300 152,195,045 12
13
NOTES (Continued) -
FERC FORM NO. I (ED. 12.96) Page 275
This Page Intentionally Left Blank
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
Idaho Power Company (2)- A Resubmission 04/15/2013 2012/Q4
FOOTNOTE DATA
ISchedule Page: 274 Line No.: 2 Column: b
2012 Changes during Year Adjmts Dr Adjmts 2012
Cr.
Beginning DR to CR to DR CR Acct. Acct Ending
to to
Account Balance 410.1 411.1 410.2 411.2 Cr. Amt Dr. Amt Balance
(a) b c d e f g h I k
Accelerated Depreciation 321,467,908 78,371,738 9,085,759 390,753,887
Intangible Asset-Labor 13,817,345 677,108 14,494,453
Deduction
Taxable CIAC in CWIP Bal. (2,146,044) 3,004,854 858,810
Valmy Capitalized Items 351,266 76,500 274,766
Misc Software Develop Costs 17,655 120,598 138,254
Engineering Fees in Acct 107 1 (173,496)1 3,0381 66,8531 1 1 - - - - (237,311)
TOTAL 1333,334,634 1 82,177,337 19,229,112 1 0 1 0 1 - 01 0 1406,282,859
I FERC FORM NO I (ED. 12-87) Page 450.1 1
Name of Respondent
Idaho Power Company
This Report Is:
(1)An Original
(2)[]A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2013
Year/Period of Report " ° 2012/Q4
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.
-
Line
No.
Account
(a)
Balance at
Beginning ofYear
CHANGES DURING YEAR
Amounts Debited
toAccoet41o.1
Amounts Credited
toAccoJJt411.1
1
2
3
Account 283
Electric
Other Electric - See Note 111,408,529 87,144,355'
- I
5
6
7
8 Other - See Note
9 TOTAL Electric (Total of lines 3 thru 8) 136,997,166 111,408,529 87,144,355
10 Gas
11
12
13
14
15
16
17 TOTAL Gas (Total of lines 11 thru 16)
18 Other -- See Note
19 TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18) 137,438,695 111,408,529 87,144,355
20
21
Classification of TOTAL
Federal Income Tax 115,291,045 93,455,498 73,101,397
22 j State Income Tax 22,147,650 17,953,031 14,042,958
23 Local Income Tax
NOTES
FERC FORM NO. I (ED. 12-96) Page 276
Name of Respondent
Idaho Power Company p y
This Re ort Is: (1)An Original (2)n Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2013
Year/Period of Report
End of 20121Q4
ACCUMULATED DEFERRED INCOME TAXES - OTHER (Account 283) (Continued)
3.Provide in the space below explanations for Page 276 and 277. Include amounts relating to insignificant items listed under Other.
4.Use footnotes as required.
CHANGES DURING YEAR ADJUSTMENTS
Balance at
End of Year
(k)
-
Line
No.
Amounts Debited
to Account 410.2
(e)
Amounts Credited
to Account 411.2
(f)
Debits Credits
Account Amount
(h)
Account Amount
(I) (I)
I I I I I 56,986,228
2
3
4
5
6
7
19,125,576 123,400,688 8
19,125,576 180,386,916 9
11
12
13
14
15
16
17
330,7061 1 1 1 1 772,2361 18
330,706 19,125,576 181,159,151 19
277,414 16,043,587 151,966,147
20
21
53,292 3,081,989 29,193,004 22
23
NOTES (Continued)
FERC FORM NO. 1 (ED. 12-96) Page 277
This Page Intentionally Left Blank
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
Idaho Power Company (2)- A Resubmission 04/15/2013 2012/Q4
FOOTNOTE DATA
LSchedule Page: 276 Line No.: 3 Column: b
Changes during Year AdiDr. I AdiCr.
Beginning DR to CR to DR to CR to Acct Acct Ending
Account Balance 410.1 411.1 410.2 411.2 Cr. Amt Dr. Amt Balance
(a) b c d e f _•g_ h I j_ k
Pension 20,087,171 18,054,956 16,616,850 21,525,276
PCA Expense Deferral (5,129,482) 41,004,777 22,359,515 13,515,780
Conservation Programs 6,237,951 2,602,188 3,726,460 5,113,679
Fixed Cost Adjustment 5,651,756 4,483,220 4,889,356 5,245,619
Regulatory Asset-Current 0 10,756,134 6,297,416 4,458,718
Oregon PCAM 1,742,549 1,800,157 1,049,571 2,493,134
Regulatory Liability-Non Current 0 17,529,102 15,806,854 1,722,247
Oregon Excess Power Costs 1,685,308 13,139,849 14,001,648 823,508
OATT Revenue Deficiency 807,104 156,937 650,167
Renewable Engy Certif -rec sales 859,641 1,698,868 1,921,172 637,337
Langley Revenue Accrual 0 313,644 313,644
Reorganization Costs 270,524 0 90,175 180,350
LIDAR Surveys Deferral 170,473 17,047 153,425
Bennett Mtn Maintenance Deferral 117,108 29,277 87,831
Intervenor Funding Orders 68,803 16,805 29,369 56,239
OPUC Grid West Loans 17,568 5,548 12,020
FERC Grid West Expense 43,680 32,760 10,920
Emission Allowance 95,142 1,584 93,594 3,132
PS & I Costs-Coal & CHP Pits-Write Off 14,233 13,259 974
Bonus Deferral (11,653) 3,134 (8,518)
Delivery accruals (5,822) 4,111 7,545 - - - - (9,255)
TOTAL 32,722,054 111,408,529 87,144,355 0 0 0 0 56,986,228
Schedule Page: 276 Line No.: 8 Column: b
Changes during Year Adj Dr. Adj Cr. -
Beginning DR to CR DR to CR to Acct Acct Ending
to
Account Balance 410.1 411. 410.2 411.2 Cr. Amt Dr. Amt Balance
(a) b c d e f h i k
Pension 96,551,657 190 17,978,929 114,530,586
Postretirement Plan 6,073,869 190 140,405 6,214,273
Unrealized gains on Mkt Securities 1,649,586 - - - 219 1,006,242 2,655,828
Changes during Year Mi Dr. - Adj Cr.
Beginning DR to CR to DR to CR to Acct Acct Ending
Account Balance 410.1 411.1 410.2 411.2 Cr. Amt Dr. Amt Balance
(a) b c d e f g h I i k
Unrealized Gain/Loss From Rabbi 139,718 329,806 469,524
Trust
Advance Coal Royalties 301,486 893 302,379
Oregon Non-Op Prop Tax Adj 326 7 - - - - 332
TOTAL 441,529 0 1 0 330,706 0 1 - 1 0 - 0 1 772,235
- 0 - 19,125,576 TOTAL 104,275,112 0 0 0 0 123,400,687
Schedule Ave: 276 Line No.: 18 Column: b _ I
IFERC FORM NO. I (ED. 12-87) Page 450.1 1
Name of Respondent I This Report Is:
Idaho Power Company 2 RSSIOfl
Date of Report
04/15/2013
Year/Period of Report
End of 2012/Q4
01 HER REGULATORY LIABILITIES (Account 254)
1.Report below the particulars (details) called for concerning other regulatory liabilities, including rate order docket number, if
applicable.
2.Minor items (5% of the Balance in Account 254 at end of period, or amounts less than $100,000 which ever is less), may be grouped
by classes.
3.For Regulatory Liabilities being amortized, show period of amortization.
Line
No.
-
Description and Purpose of
Other Regulatory Liabilities
(a)
Balance at Begining
of Current
Quarter/Year
(b)
DEBITS
Credits
(e)
Balance at End
Quarter/Year
(f)
ACCOUnt Credited
(c)
Amount
(d)
1 Market to Market Short Term- (254001) 3,394,965 175 13,988,797 14,888,370 4,294,538
2 IPUC Order #28661
3
4 FAS 133- Market to Market -(254203) 359,418 175 1,263,773 1,189,137 284,782
5 IPUC Order #28661
6
71 OER 32368-323697 -(254007) 581,743 581,743
8 Order# 32368
9
10 Unfunded Accum Def Income Tax (254966) 45,472,547 various 530,982 6,344,170 51,285,735
11
12 Idaho DSM Rider (254201) various 34,245,702 38,286,324 4,040,622
13 Order #29026
14
15 Oregon OSM Rider-(254202) various 16,626,489 12,711,554 -3,914,935
16 Advise #05-03
17
18 Oregon Solar Pilot -(254005) 766,096 various 233,363 659,888 1,192,621
19 Order #10-198
20
21 Oregon Reclass (254204) 4,110,320 1823 5,580,001 1,469,681
22
23 Green Tags Oregon (254415) 279,605 various 286,696 161,484 154,393
24 Order #11 -086
25
26 Power Cost Adjustment-Current (254423) 10,578,946 1823 63,448,231 52,869,26
27
28 Regulatory Unfunded Accum Def Income Tax (254419) 3,780,588 1823 60,778 79,106 3,798,916
29
30 Revenue Sharing (254101) 27,098,897 various 27,200,636 7,252,960 7,151,221
31 IPUC Order #32558
32
33 BPA Credit Residential Idaho (254401) 411,557 various 1,534,209 1,672,522 549,870
34 Advice# 11 -03 (ID) #11-15(OR)
35
36 WAQC Carryover (254901) 159,309 various 159,309 87,634 87,634
37 IPUC Order #29505
38
39
40
41 TOTAL 96,483,245 166,095,646 139,014,187 69,401,786
FERC FORM NO. 113-Q (REV 02-04) Page 278
Name of Respondent
Idaho Power Company
This Report Is:
(2) E]A Resubmission
Dateof Report
04/15/2013
Year/Period of Report
End of 2012/Q4
OTHER REGULATORY LIABILITIES (Account 254)
1.Report below the particulars (details) called for concerning other regulatory liabilities, including rate order docket number, if
applicable.
2.Minor items (5% of the Balance in Account 254 at end of period, or amounts less than $100,000 which ever is less), may be grouped
by classes.
3.For Regulatory Liabilities being amortized, show period of amortization.
Line
No.
-
Description and Purpose of
Other Regulatory Liabilities
(a)
Balance at Begining
of Current
Quarter/Year
(b)
DEBITS
________________ Credits
(e)
Balance at End
of Current
Quarter/Year
(f)
___________ Account
Credited
(c)
Amount
(d)
I Idaho Boardman Decommissing -(254393) 143/400 444,146 152,957 -291,189
2 IPUC Order #32549
3
4 Oregon Boardman Decommissing -(254394) 143/400 144,780 49,395 -95,385
5 OPUC Order #12235
6
71 Bridger Depreciation 912-296 -(254800) 168,224 168,224
8
IC 70,997 various 347,754 389,753 112,996
II
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 TOTAL 96,483,245 166,095,646 139,014,187 69,401,786
FERC FORM NO. 113-Q (REV 02-04) Page 278.1
This Page Intentionally Left Blank
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
Idaho Power Company (2)- A Resubmission 04/15/2013 2012/Q4
FOOTNOTE DATA
ISchédule Page: 278.1 Line No.: 10 Column: a
Accounts included in minor items:
254004
254006
254008
254402
254402
254403
254404
254411
254412
IFERC FORM NO. I (ED. 12-87) Page 450.1 I
Name of Respondent
Idaho Power Company
This Re ort Is
(2) EjA Resubmission
Date of Report
04/15/2013
Year/Period of Report
End of 2012/Q4
ELECTRIC OPERATING REVENUES (Account 400)
1.The following instructions generally apply to the annual version of these pages. Do not report quarterly data in columns (c), (e), (f), and (g). Unbilled revenues and MWH
related to unbilled revenues need not be reported separately as required in the annual version of these pages.
2.Report below operating revenues for each prescribed account, and manufactured gas revenues in total.
3.Report number of customers, columns (f) and (g), on the basis of meters, in addition to the number of flat rate accounts; except that where separate meter readings are added
for billing purposes, one customer should be counted for each group of meters added. The -average number of customers means the average of twelve figures at the close of
each month.
4.If increases or decreases from previous period (columns (c),(e), and (g)), are not derived from previously reported figures, explain any inconsistencies in a footnote.
5.Disclose amounts of $250,000 or greater in a footnote for accounts 451,456, and 457.2.
Line
No.
-
Title of Account
(a)
Operating Revenues Year
to Date Quarterly/Annual
(b)
Operating Revenues
Previous year (no Quarterly)
(c)
I Sales of Electricity
431,555,478 405,981,556 2 (440) Residential Sales
3 (442) Commercial and Industrial Sales
375,354,223 322,307,065 4 Small (or Comm.) (See lnstr. 4)
5 Large (or Ind.) (See lnstr. 4) 145,054,266 140,701,371
6 (444) Public Street and Highway Lighting 3,588,495 3,289,385
7 (445) Other Sales to Public Authorities
8 (446) Sales to Railroads and Railways
9 (448) Interdepartmental Sales
10 TOTAL Sales to Ultimate Consumers 955,552,462 872,279,377
11 (447) Sales for Resale 61,534,224 101,602,140
12 TOTAL Sales of Electricity 1,017,086,686 973,881,517
13 (Less) (449.1) Provision for Rate Refunds 17,809,784 37,734,709
14 TOTAL Revenues Net of Prov. for Refunds 999,276,902 936,146,808
15 Other Operating Revenues
16 (450) Forfeited Discounts
17 (451) Miscellaneous Service Revenues 3,564,200
18 (453) Sales of Water and Water Power
19 (454) Rent from Electric Property 23,226,450 24,256,300
20 (455) Interdepartmental Rents
21 (456) Other Electric Revenues 38,244,930
21,054,698 19,372,904 22 (456.1) Revenues from Transmission of Electricity of Others
23 (457.1) Regional Control Service Revenues
24 j (457.2) Miscellaneous Revenues
25
26 TOTAL Other Operating Revenues 75,808,969 85,438,334
27 TOTAL Electric Operating Revenues 1,075,085,871 1,021,585,142
FERC FORM NO. 113-Q (REV. 12-05) Page 300
Name of Respondent
Idaho Power Company
This Re ort Is: Date of Report
04/15/2013
Year/Period of Report
End of 2012/Q4
ELECTRIC OPERATING REVENUES (Account 400)
6.Commercial and industrial Sales, Account 442, may be classified according to the basis of classification (Small or Commercial, and Large or Industrial) regularly used by the
respondent if such basis of classification is not generally greater than 1000 Kw of demand. (See Account 442 of the Uniform System of Accounts. Explain basis of classification
in a footnote.)
7.See pages 108-109, Important Changes During Period, for important new territory added and important rate increase or decreases.
8.For Lines 2,4,5,and 6, see Page 304 for amounts relating to unbilled revenue by accounts.
9.Include unmetered sales. Provide details of such Sales in a footnote.
MEGAWATT HOURS SOLD AVG.NO. CUSTOMERS PER MONTH Line
Year to Date Quarterly/Annual
(d)
Amount Previous year (no Quarterly)
(e)
Current Year (no Quarterly)
(f)
Previous Year (no Quarterly)
(g)
No.
-
5,039,358 5,146,013 413,610 409,786 2
3
5,881,587 5,458,954 82,485 82,045 4
3,132,573 3,099,743 118 123 5
31,798 29,720 2,069 1,578 6
7
8
9
14,085,316 13,734,430 498,282 493,532 10
2,183,262 3,634,924 11
16,268,578 17,369,354 498,282 493,532 12
13
16,268,578 17,369,354 498,282 493,532 14
Line 12, column (b) includes $ 4,136,172 of unbilled revenues.
Line 12, column (d) includes -18,962 MWH relating to unbilled revenues
FERC FORM NO. 113-Q (REV. 12-05) Page 301
This Page Intentionally Left Blank
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
Idaho Power Company (2)_A Resubmission 04/15/2013 2012/Q4
FOOTNOTE DATA
Schedule Page: 300 Line No.: 17 Column: b
This consists of
Service Establishment/Connection Charges 2,836,590
(Includes late and after hour charges)
Field Collections Charges 350,900
Misc. Under $250,000 457,528
3,645,018
chedule Page: 300 Line No.: 21 Column: b
This consists of
DSM Activity 27,299,917
Stand-by-Service 306,070
Misc, items under $250,000 276,816
27,882,803
IFERC FORM NO. 1 (ED. 12-87) Page 450.1 I
Name of Respondent
Idaho Power Company
This Re ort Is:
2I1R SSiOn
Date of Report
04/15/2013
Year/Period of Report
End of 201 2/Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
1.Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2.Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3.Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4.The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12
if all billings are made monthly).
5.For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6.Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line
No.
Number and I itle ot Kate schedule
(a)
MWfl Sold
(b)
Kevenue
(c)
Average Number
of Cimers
KWh ot salesPer Customer K.eue re
(f) o d
1 440 - Residential Sales:
_2 01 - Residential 5,036,448 421,030,853 412,920 12,197 0.0836
3 03- Residential Master Meter 4,493 354,253 23 195,348 0.0788
4 04 - Residential - EW -15
5 05 - Residential - TOD 8,553 710,075 667 12,823 0.0830
_6 15 - Dusk to dawn lighting 2,807 618,102 0.2202
7 Unbilled Revenues -12,992 1,986,871 -0.1529
8 Other Revenues 6,855,335
9 Total 440 413,610 12,184 0.0856
158,68t
10
11 442-Commercial & Industrial Sales
12 07- General service 16,695,877 30,745 5,161 0.1052
13 09P - General service 455,960 23,295,097 194 2,350,309 0.0511
14 09S - General service 3,202,887 192,136,834 31,743 100,901 0.0600
15 09T - General service 5,025 273,445 1,675,000 0.0544
16 15- Dusk to Dawn Light 4,092 678,277 0.1658
17 19P - Uniform rate contracts 2,157,337 96,558,875 110 19,612,155 0.0448
18 19S - Uniform rate contracts 6,493 325,376 1 6,493,000 0.0501
19. 19T - Uniform rate contracts 107,954 5,260,412 4 26,988,500 0.0487
20 24- Irrigation Pumping 2,048,435 134,326,911 18,955 108,068 0.0656
21 40- General service 11,188 804,135 845 13,240 0.0719
22 Special Contracts 862,444 39,505,500 215,611,000 0.0458
23 Commercial & Industrial Unbill -6,291 2,111,315 -0.3355
24 Other Revenues 8,436,43
25 Total 442 82,604 109,126 0.0577
26
27 444- Public Street Lighting:
28 40- General service 1,167 83,845 444 2,628 0.0718
29141 - Street lighting 27,477 3,257,727 1,208 22,746 0.1186
30 42 -Traffic control lighting 2,831 141,880 417 6,789 0.0501
31 Unbilled 323 37,986 0.1176
32 Other Revenues 67,057
33 Total 444 31,798 3,588,495 2,069 15,369 0.1129
34
35
36
3
38
39
40
1 TOTAL Billed 14,104,27E 951,416,290 498,283 28,30E 0.067
42 Total Unbilled Rev.(See lnstr. 6) -18,962 4,136,172 a -0.2181
43 TOTAL 14,085,311 955,552,462 498,28 28,261 0.067
FERC FORM NO. I (ED. 12-95) Page 304
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)_ A Resubmission 04/15/2013 2012/Q4
FOOTNOTE DATA
ISchedule Page: 304 Line No.: 9 Column: b
This amount is different from page 301 column D line 2 in the amount of 48 MWh due to an
error during the year where a rate 09S was recorded to the residential account. Page 301
is broken down by FERC account and page 304 is by rate schedule.
ISchedule Page: 304 Line No.: 9 Column: c
This amount is different from page 301 column B line 2 in the amount of $4 due to an error
during the year where a rate 07 was recorded to the residential account. Page 301 is
broken down by FERC account and page 304 is by rate schedule.
Schedule Page: 304 Line No.: 25 Column: b
This amount is different from page 301 column D total of line 4 and 5 in the amount of 48
MWh due to an error during the year where a rate 09S was recorded to the residential
account. Page 301 is broken down by FERC account and page 304 is by rate schedule.
hedule Page: 304 Line No.: 25 Column: c
This amount is different from page 301 column B total of line 4 and 5 in the amount of $4
due to an error during the year where a rate 09S was recorded to the residential account.
Page 301 is broken down by FERC account and page 304 is by rate schedule.
I FERC FORM NO. I (ED. 12-87) Page 450.1 I
Name of Respondent This Re rt Is: Date of Report Year/Period of Report
Idaho Power Company End of 2012/Q4
Resubmission 04/15/2013
SALES FOR RESALE (Account 447)
1.Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity (i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2.Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
Averacle Monthly NCR Deman Avera e Monthly CF-Demand No. (Footnote Affiliations) Classifi-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (c) (d) (e) (f)
I Raft River Rural Electric
2
3 Arizona Public Service Co. SF WSPP n/a n/a n/a
4 Arizona Public Service Co. WSPP n/a n/a n/a
5 Avista Corp. 1SF WSPP n/a n/a n/a
6 Avista Corp. WSPP n/a n/a n/a
7 Barclays Bank PLC - n/a n/a n/a
8 Black Hills Power Inc. 1SF I WSPP n/a n/a n/a
9 Bonneville Power Administration SF WSPP n/a n/a n/a
10 Bonneville Power Administration WSPP n/a n/a n/a
II BP Energy Company SF WSPP n/a n/a n/a
12 Brookfield Energy Marketing LP SF WSPP n/a n/a n/a
13 Calpine Energy Services, L.P. SF WSPP n/a n/a n/a
14 Cargill Power Markets LLC WSPP n/a n/a n/a
Subtotal RQ 0 0 0
Subtotal non-RQ 01 0 0
Total 0 0 0
FERC FORM NO. I (ED. 12-90) Page 310
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Idaho Power Company (1)x An Original
(2)flA Resubmission
(Mo, Da, Yr)
04/15/2013 En 0 d f 2012104
SALES FOR RESALE (Account 447) (Continued)
OS - for other service, use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD -for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5.In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6.For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CID demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7.Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8.Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9.The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401 ,iine 24.
10.Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($) Line
Demand Charges Energy Charges Other Charges Sold (h+i+j) No.
(g) (h) (i) (j) (k) -
2
107,575 2,122,843 2,122,843 3
1,593 3,530 3,530 4
32,746 654,534 654,534 5
550 6,875 6,87E 6
1,775,255 1,775,255 7
2,105 41,615 41,615 8
109,259 2,527,790 2,527,790 9
450 3,150 3,150 10
2,492 1,329 1,329 11
400 6,000 6,000 12
201 1,696 1,696 13
535,817 535,817 14
0 0 0 0 0
2,183,262 0 60,673,995 860,229 61,534,224 -
2,183,262 0 60,673,995 860,229 61,534,224
FERC FORM NO. 1 (ED. 12.90) Page 311
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Idaho Power Company (1)X An Original (Mo, Da, Yr) n d f 2012/04
(2)[]A Resubmission 04/15/2013
SALES FOR RESALE (Account 447)
1.Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity (i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalancecl exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2.Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit
lU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line rity Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
Averaqe
Monthly NCP Deman Avers e
Monthly CP9Demand No. (Footnote Affiliations) Classifi- Schedule or Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (c) (d) (e) (f)
I Cargill Power Markets LLC - n/a n/a n/a
2 Cargill Power Markets LLC SF WSPP n/a n/a n/a
3 j Citigroup Energy Inc. SF WSPP n/a n/a n/a
4 Citigroup Energy Inc. WSPP n/a n/a n/a
5 Citigroup Energy Inc. - n/a n/a n/a
6 Constellation Energy Commodities Group, 1SF i WSPP n/a n/a n/a
7 DB Energy Trading LLC SF WSPP n/a n/a n/a
8 EDF Trading North America, LLC SF WSPP n/a n/a n/a
9 Eugene Electric 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 I WSPP n/a n/a n/a
13 IBERDROLA RENEWABLES, Inc. WSPP n/a n/a n/a
14 J.P. Morgan Ventures Energy Corporation - n/a n/a n/a
I I
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORM NO. I (ED. 12-90) Page 310.1
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Idaho Power Company (1)X An Original (Mo, Da, Yr) E d f 201 2/Q4 n 0 (2)El A Resubmission 04115/2013
SALES FOR RESALE (Account 447) (Continued)
OS - for other service, use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5.In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6.For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7.Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8.Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column ). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9.The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401 ,iine 24.
10.Footnote entries as required and provide explanations following all required data.
MegaWatt Flours REVENUE Total Line
Demand Charges Energy Charges Other Charges Sold (h+i+j) No.
(g) (h) (I) (j) (k) -
770,334 770,334 1
170,572 3,910,214 3,910,214 2
3,251 75,238 75,238 3
3 93 934
4,324,363 4,324,363 5
165,250 5,158,976 5,158,976 6
321 544 544 7
27,628 741,529 741,529 8
4,400 48,892 48,892 9
600 8,850 8,850 10
20,474 20,474 11
14,977 384,149 384,149 12
29,380 206,149 206,149 13
46,560 46,560 14
0 0 0 0 0
2,183,262 0 60,673,995 860,229 61,534,224 -
2,183,262 0 60,673,995 860,229 61,534,224 -
FERC FORM NO. I (ED. 12-90) Page 311.1
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Idaho Power Company (1)X An Original
(2)flA Resubmission
(Mo, Da, Yr)
04/15/2013 End f 2012/Q4 n
SALES FOR RESALE (Account 447)
1.Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity (i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2.Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Averag Actual Demand (MW)
Averacle Monthly NC Demand Averacie
Monthly CPbemand No. (Footnote Affiliations) Classifi-
cation
Schedule or Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (c) (d) (e) (f)
I J.P. Morgan Ventures Energy Corporation SF WSPP n/a n/a n/a
2 J.P. Morgan Chase Bank, N.A. WSPP n/a n/a n/a
3 Jeffries Bache - n/a n/a n/a
4 Macquarie Energy LLC WSPP n/a n/a n/a
5 Macquarie Energy LLC 1SF I WSPP n/a n/a n/a
6 Macquarie Energy LLC WSPP n/a n/a n/a
7 Morgan Stanley Capital Group Inc. WSPP n/a n/a n/a
8 NextEra Energy Power Marketing, LLC 1SF WSPP n/a n/a n/a
9 Noble Americas Gas & Power corp. SF WSPP n/a n/a n/a
10 NorthWestern Energy WSPP n/a n/a n/a
11 North Western Energy ISF WSPP n/a n/a n/a
12 PaciflCorp Inc. ISF WSPP n/a n/a n/a
13 PacifiCorp Inc. WSPP n/a n/a n/a
14 j PacifiCorp Inc. T-7 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 310.2
Name of Respondent Date of Report Year/Period of Report
Idaho Power Company
This
An Original
RM
ort Is:
(Mo, Da, Yr) E d f 2012/Q4 n 0 A Resubmission 04/15/2013
SALES FOR RESALE (Account 447) (Continued)
OS - for other service, use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5.In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6.For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7.Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8.Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9.The data in column (g) through (k) must be subtotaled based on the RQINon-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sates For Resale on Page
401 ,iine 24.
10.Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($) Line ____________________
Demand Charges Energy Charges Other Charges Sold (h+i+j) No.
(g) (h) (I) (j) (k) -
1,600 69,584 69,584 1
66,515 66,515 2
6,390,737 6,390,737 3
744,771 744,771 4
520,986 10,201,383 10,201,383 5
4,500 32,115 32,115 6
70,126 70,126 7
650 3,700 3,700 8
4,000 36,000 36,000 9
29,892 83,106 83,106 10
86 2,333 2,333 11
53,381 1,194,384 1,194,384 12
607 8,583 8,583 13
139 3,017 3,017 14
0 0 0 0 0
2,183,262 0 60,673,995 860,229 61,534,224
2,183,262 0 60,673,995 860,229 61,534,224 -
FERC FORM NO. I (ED. 12-90) Page 311.2
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Idaho Power Company p y (1)X An Original (Mo, Da, Yr) End of 2012/Q4
(2)[]A Resubmission 04/15/2013
SALES FOR RESALE (Account 447)
1.Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity (i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2.Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
Averaqe Monthly NCR Deman Avera e
Monthly CFDemand No. (Footnote Affiliations) Classifi-
cation
Schedule or Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (c) (d) (e) (f)
I Portland General Electric Company WSPP n/a n/a n/a
2 Portland General Electric Company WSPP n/a n/a n/a
3 Portland General Electric Company 1SF I WSPP n/a n/a n/a
4 Powerex Corp. WSPP n/a n/a n/a
5 Powerex Corp. 1SF I WSPP n/a n/a n/a
6 PPL EnergyPlus, LLC WSPP n/a n/a n/a
7 PPL EnergyPlus, LLC WSPP n/a n/a n/a
8 PPL EnergyPlus, LLC SF WSPP n/a n/a n/a
9 Puget Sound Energy, Inc. SF WSPP n/a n/a n/a
10 Puget Sound Energy, Inc. WSPP n/a n/a n/a
11 Rainbow Energy Marketing Corporation WSPP n/a n/a n/a
12 Rainbow Energy Marketing Corporation jSF I WSPP n/a n/a n/a
13 Royal Bank of Canada - n/a n/a n/a
14 1 Seattle City Light WSPP n/a n/a n/a
I I
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORM NO. 1 (ED. 12-90) Page 310.3
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Idaho Power Company (1)x An Original (Mo, Da, Yr) End of 2012/04
(2)J A Resubmiss ion 04/15/2013
SALES FOR RESALE (Account 447) (Continued)
OS - for other service, use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5.In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6.For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7.Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8.Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9.The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401 ,iine 24.
10.Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($) Line
Demand Charges Energy Charges Other Charges Sold (h+i+j) No.
(g) (h) (i) (j) (k)
187 187 1
500 8,450 8,450 2
10,200 227,585 227,585 3
68,282 716,707 716,707 4
27,580 309,325 309,325 5
5,383 5,383 6
1,113 8,860 8,860 7
4,316 80,444 80,444 8
5,937 101,787 101,787 9
4,145 53,390 53,390 10
65,710 65,710 11
166,796 3,512,095 3,512,095 12
749,628 749,628 13
525 11,075 11,075 14
0 0 0 0 0
2,183262 0 60,673,995 860,229 61,534,224
2,183,262 0 60,673,995 860,229 61,534,224 -
FERC FORM NO. I (ED. 12-90) Page 311.3
Name of Respondent This Report Is: Date of Report Year/Period of Report
Idaho Power Company (1)An Original
(2)[]A Resubmission
(Mo, Da, Yr)
04/15/2013 End f 20121Q4
SALES FOR RESALE (Account 447)
1.Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity (i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2.Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term' means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
Average
Monthly NCP Demand Averacie Monthly CP1)emand No. (Footnote Affiliations) Classifi- cation Schedule or Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (c) (d) (e) (f)
1 Seattle City Light SF WSPP n/a n/a n/a
2 Shell Energy North America (US), L.P. WSPP n/a n/a n/a
3 Shell Energy North America (US), L.P. WSPP n/a n/a n/a
4 Shell Energy North America (US), L.P. WSPP n/a n/a n/a
5 Shell Energy North America (US), L.P. 1SF I WSPP n/a n/a n/a
6 Sierra Pacific Power Co., dba NV Energy T-7 n/a n/a n/a
7 Sierra Pacific Power Co., dba NV Energy WSPP n/a n/a n/a
8 Snohomish County PUD JSF WSPP n/a n/a n/a
9 Tenaska Power Services Co. WSPP n/a n/a n/a
10 Tenaska Power Services Co. SF WSPP n/a n/a n/a
11 The Energy Authority, Inc. WSPP n/a n/a n/a
12 The Energy Authority, Inc. SF WSPP n/a n/a n/a
13 TransAlta Energy Marketing (U.S.) Inc. WSPP n/a n/a n/a
14 TransAlta Energy Marketing (U.S.) Inc. WSPP n/a n/a n/a
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORM NO. I (ED. 12-90) Page 310.4
Name of Respondent This Re ort Is: Date o f Report Year/Period of Report
Idaho Power Company (1)X An Original (Mo, Da, Yr) E 2012104 n 0 (2)11A Resubmission 04/15/2013
SALES FOR RESALE (Account 447) (Continued)
OS - for other service, use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5.In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6.For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7.Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8.Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9.The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401 ,iine 24.
10.Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($) Line
Demand Charges Energy Charges Other charges Sold (h+i+j) No.
(g) (h) (i) a) (k)
8,574 232,685 232,685 1
325,722 325,722 2
24,613 24,613 3
14,914 264,149 264,149 4
424,110 9,424,227 9,424,227 5
137 3,053 3,053 6
85,860 85,860 7
200 4,600 4,600 8
67 679
3,200 68,800 68,800 10
637 637 11
5,340 130,942 130,942 12
5,284 5,284 13
26,516 237,872 237,872 14
0 0 0 0 0
2,183,262 0 60,673,995 860,229 61,534,224
2,183,262 0 60,673,995 860,229 61,534,224 -
FERC FORM NO. I (ED. 12-90) Page 311.4
Name of Respondent This Report Is: Date of Report Year/Period of Report
Idaho Power Company (2) AResubrnission fl2I3 End of 2012/Q4
SALES FOR RESALE (Account 447)
1.Report all sales for resale (i.e., sates to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity (i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2.Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Average
Monthly Billing
Actual Demand (MW)
Averaae Monthly NCO Demand Avera e Monthly CPMDemand No. (Footnote Affiliations) Classifi-
cation
Schedule or Tariff Number Demand (MW)
- (a) (b) (c) (d) (e) (f)
I TransAlta Energy Marketing (U.S.) Inc. SF WSPP n/a n/a n/a
2 LF 61 n/a n/a n/a
3 Prior Year Adjustments AD - n/a n/a n/a
4 Prior Year Write Off Recovered AD - n/a n/a n/a
5
6
7
8
9
10
11
12
13
14
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORM NO. I (ED. 12-90) Page 310.5
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Idaho Power Company (1)X An Original
(2)A Resubmission
(Mo, Pa, Yr)
04/15/2013 End of 2012/Q4
SALES FOR RESALE (Account 447) (Continued)
OS - for other service, use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment
4.Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
'Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5.In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6.For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7.Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8.Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9.The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401 ,iine 24.
10.Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($) Line
Demand Charges Energy Charges Other Charges Sold (h+i+j) No.
(9) (h) (i) (j) (k) -
121,283 2,520,399 2,520,399 1
25,467 25,46 2
-33
46,071 46,071 4
5
6
7
8
9
10
11
12
13
14
0 0 0 0 0
2,183,262 0 60,673,995 860,229 61,534,224
2,183,262 0 60,673,995 860,229 61,534,224 -
FERC FORM NO. 1 (ED. 12-90) Page 311.5
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 04/15/2013 2012/Q4
FOOTNOTE DATA
Schedule Page: 310 Line No.: 4 Column: b
Non-Firm Sales
ISchedule Paqe: 310 Line No.: 6 Column: b
Non-Firm Sales
Schedule Page: 310 Line No.: 7 Column: b
ISDA Master Agreement with Barclays Bank dated May 2, 2011
ISchedule Paoe: 310 Line No.: 10 Column: b I
Non-Firm Sales
Schedule Page: 310 Line No.: 14 Column: b I
Financial Transmission Losses
Schedule Page: 310.1 Line No.: I Column: b I
ISDA Master Agreement with Cargill Power Markets LLC, dated June 13, 2011
chedule Page: 310.1 Line No.: 4 Column: b I
Non-Firm Sales
Schedule Page: 310.1 Line No.: 5 Column: b
ISDA Master Agreement with Citigroup Energy, Inc., dated March 7, 2011
ISchedule Page: 310.1 Line No.: 11 Column: b
Financial Transmission Losses
hedule Page: 310.1 Line No.: 13 Column: b
Non-Firm Sales
ISchedule Page: 310.1 Line No.: 14 Column: b
ISDA Master Agreement with JP Morgan Ventures Energy Corporation dated May 1, 2011
Schedule Page: 310.2 Line No.: 2 Column: b
ISDA Master Agreement with JP Morgan Chase Bank, N.A. dated November 4, 2005
Schedule Page: 310.2 Line No.: 3 Column: b I
Prudential Bache Commodities
Septmber 4, 2008
(Jeffries Bache), LLC Futures Account Document, dated
Schedule Page: 310.2 Line No.: 4 Column: b
ISDA Master Agreement with Macquarie Energy, LLC dated April 12, 2011
chedule Page: 310.2 Line No.: 6 Column: b
Non-Firm Sales
Schedule Page: 310.2 Line No.: 7 Column: b I
Financial Transmission Losses
Schedule Page: 310.2 Line No.: 10 Column: b I
Non-Firm Sales
Schedule Page: 310.2 Line No.: 13 Column: b I
Non-Firm Sales
chedule Page: 310.2 Line No.: 14 Column: b
Spinning or Operating Reserves
Schedule Page: 310.3 Line No.: 1 Column: b
Financial Transmission Losses
cheduIe Page: 310.3 Line No.: 2 Column: b I
Non-Firm Sales
Schedule Page: 310.3 Line No.: 4 Column: b I
Non-Firm Sales
Schedule Page: 310.3 Line No.: 6 Column: b I
Financial Transmission Losses
Schedule Page: 310.3 Line No.: 7 Column: b I
Non-Firm Sales
Schedule Page: 310.3 Line No.: 10 Column: b I
Non-Firm Sales
Schedule Page: 310.3 Line No.: 11 Column: b I
Financial Transmission Losses
Schedule Page: 310.3 Line No.: 13 Column: b
I FERC FORM NO. I (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 (2)- A Resubmission 04/15/2013 2012/04
FOOTNOTE DATA
ISDA Master Agreement with Royal Bank of Canada dated August 26, 2005
Schedule Page: 310.3 Line No.: 14 Column: b
Non-Firm Sales
Schedule Page: 310.4 Line No.: 2 Column: b
ISDA Master Agreement with Shell Energy North America dated November 1, 2009
ISchedule Page: 310.4 Line No.: 3 Column: b
Financial Transmission Losses
Schedule Page: 310.4 Line No.: 4 Column: b
Non-Firm Sales
ISchedule Page: 310.4 Line No.: 6 Column: b
Spinning or Operating Reserves
lSchedule Page: 310.4 Line No.: 7 Column: b
Financial Transmission Losses
Schedule Page: 310.4 Line No.: 9 Column: b
Financial Transmission Losses
Schedule Page: 310.4 Line No.: 11 Column: b
Financial Transmission Losses
ISchedule Page: 310.4 Line No.: 13 Column: b
Financial Transmission Losses
Schedule Page: 310.4 Line No.: 14 Column: b
Non-Firm Sales
Schedule Page: 310.5 Line No.: 2 Column: a
Contract expiration date 05/31/2013
I FERC FORM NO. I (ED. 12-87) Page 450.2 I
Name of Respondent
Idaho Power Company
This Re ort Is:
Asubmissiofl
Date of Report
04/15/2013
Year/Period of Report
End of 2012104
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line
N °•
Account
(a)
Amount ear for Current Y
(b)
Anouviount fpr Pres Year
(c)
1 1. POWER PRODUCTION EXPENSES
2 A. Steam Power Generation 0 3 Operation
4 (500) Operation Supervision and Engineering 1,402,743 1,690,161
5 (501)Fuel 134,501,103 119,844,954
8 (502)Steam Expenses 8,279,623 6,950,410
7 (50 3) Steam from Other Sources
8 (Less) (504) Steam Transferred-Cr.
9 (505) Electric Expenses 1,539,354 2,231,309
10 (506) Miscellaneous Steam Power Expenses 8,331,843 9,734,263
11 (507) Rents 285,311 498,085
12 (50 9) Allowances
13 TOTAL Operation (Enter Total of Lines 4 thru 12) 154,339,9771 140,949,1821
14 Maintenance
15 (510) Maintenance Supervision and Engineering 331,355 2,075,559
16 (511) Maintenance of Structures 759,002 920,609
17 (512) Maintenance of Boiler Plant 12,605,603 15,351,039
18 (513) Maintenance of Electric Plant 5,139,307 6,827,635
19 (51 4) Maintenance of Miscellaneous Steam Plant 4,996,6171 6,486,063
20 TOTAL Maintenance (Enter Total of Lines 15 thru 19) 23,831,8841 31,660,905
21 TOTAL Power Production Expenses-Steam Power (Entr Tot lines 13 & 20) 178,171,8611 172,610,087
22 1 B. Nuclear Power Generation
23 Operation
24 (517) Operation Supervision and Engineering I
25 (518) Fuel
26 (519) Coolants and Water
27 (520) Steam Expenses
28 (521) Steam from Other Sources
29 (Less) (522) Steam Transferred-Cr.
30 (523) Electric Expenses
31 (52 4) 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 (53 0) 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 1 TOTAL Power Production Expenses-Nuc. Power (Entr tot lines 33 & 40)
42 C. Hydraulic Power Generation
43 Operation
44 (535) Operation Supervision and Engineering 7,437,986 5,380,371
45 (536) Water for Power 7,810,554 8,772,110 .....
46 (537) Hydraulic Expenses 12,715,046 12,513,192
47 (538) Electric Expenses 1,376,025 1,611,582
48 (539) Miscellaneous Hydraulic Power Generation Expenses 2,634,251 3,081,121
49 (540)Rents 329,2091 209,213
50 TOTAL Operation (Enter Total of Lines 44 thru 49) 32,303,0711 31,567,589
51 C. Hydraulic Power Generation (Continued)
52 Maintenance
53 (541) Mainentance Supervision and Engineering 305,070 1,763,673
54 (542) Maintenance of Structures 1,329,157 1,722,862
55 (543) Maintenance of Reservoirs, Dams, and Waterways 1,343,402 1,563,284
56 (544) Maintenance of Electric Plant 3,114,538 1,789,947
57 (5 5) Maintenance of Miscellaneous Hydraulic Plant 3,071,383 2,719,281
58 TOTAL Maintenance (Enter Total of lines 53 thru 57) 9,163,5501 9,559,047
59 TOTAL Power Production Expenses-Hydraulic Power (tot of lines 50 & 58) 41,466,6211 41,126,636
FERC FORM NO. 11 (ED. 12-93) Page 320
Name of Respondent
Idaho Power Company
This Re ort Is: 1 (2) AResubmission
Date of Report
04/15/2013
Year/Period of Report
End of 2012/04
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line
No.
Account
(a)
Amount for Current Year
(b)
Am.ount fjx Previous Year
(c)
60 D. Other Power Generation
61 Operation
62 (546) Operation Supervision and Engineering 1,342,636 820,192
63 (547) Fuel 24,912,210 11,696,917
64 (548) Generation Expenses 2,167,816 749,804
65 (549) Miscellaneous Other Power Generation Expenses 403,386 779,335
66 (550) Rents
67 TOTAL Operation (Enter Total of lines 62 thru 66) 28,826,048 14,046,248
68 Maintenance
69 (551) Maintenance Supervision and Engineering
70 (552) Maintenance of Structures 208,028 179,520
71 (553) Maintenance of Generating and Electric Plant 99,722 115,128
72 (554) Maintenance of Miscellaneous Other Power Generation Plant 2,537,689 1,861,365
73 TOTAL Maintenance (Enter Total of lines 69 thru 72) 2,845,439 2,156,013
74 TOTAL Power Production Expenses-Other Power (Enter Tot of 67 & 73) 31,671,487 16,202,2611
75 1 E. Other Power Supply Expenses
76 (555) Purchased Power I 190,640,708 156,873,749
77 (556) System Control and Load Dispatching 2,250 1,219
78 (557) Other Expenses -57,611,492 41,459,600
79 TOTAL Other Power Supply Exp (Enter Total of lines 76 thru 78) 133,031,466 198,334,568
80 TOTAL Power Production Expenses (Total of lines 21, 41, 59, 74 & 79) 384,341,4351 428,273,552
81 2. TRANSMISSION EXPENSES
82 1 Operation
83 (560) Operation Supervision and Engineering 3,580,5611 3,326,8911
84
85 (561.1) Load Dispatch-Reliability I 130,631 192,086'
86 (561.2) Load Dispatch-Monitor and Operate Transmission System 1,170,321 1,188,357
87 (561.3) Load Dispatch-Transmission Service and Scheduling 1,345,152 1,423,636
88 (561.4) Scheduling, System Control and Dispatch Services
89 (561.5) Reliability, Planning and Standards Development
90 (561.6) Transmission Service Studies
91 (561.7) Generation Interconnection Studies 97,740 102,697
92 (561.8) Reliability, Planning and Standards Development Services
93 (562) Station Expenses 2,359,494 2,252,352
94 (563) Overhead Lines Expenses 659,259 746,070
95 (564) Underground Lines Expenses
96 (565) Transmission of Electricity by Others 6,294,410 6,462,104
97 (566) Miscellaneous Transmission Expenses 175,701 307,899
98 (567) Rents 3,002,229 3,283,621
99 TOTAL Operation (Enter Total of lines 83 thru 98) 18,815,498 19,285,7
100 Maintenance
101 (568) Maintenance Supervision and Engineering 484,817 220,6
102 (569) Maintenance of Structures
103 (569.1) Maintenance of Computer Hardware 13,444 54,018
104 (569.2) Maintenance of Computer Software 749,101 347,77
105 (569.3) Maintenance of Communication Equipment 4,138 26,18
106 (569.4) Maintenance of Miscellaneous Regional Transmission Plant
107 (570) Maintenance of Station Equipment 3,689,469 2,975,539
108 (571) Maintenance of Overhead Lines 5,293,220 3,675,361
109 (572) Maintenance of Underground Lines
110 (573) Maintenance of Miscellaneous Transmission Plant 1,530 5,474
111 TOTAL Maintenance (Total of lines 101 thru 110) 10,235,719 7,304,963
112 TOTAL Transmission Expenses (Total of lines 99 and 111) 29,051,217 26,590,676
FERC FORM NO. I (ED. 12-93) Page 321
Name of Respondent
Idaho Power Company
This Re ort Is:
AResUbssion ITh
Date of Report
04/15/2013
Year/Period of Report
End of 2012/Q4
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line
N °•
Account
(a)
Amount for Current Year
(b)
Am.ount fpr Previous Year (c)
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 Monitoring and Compliance I
121 (575.7) Market Facilitation, Monitoring 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 Software
128 (576.4) Maintenance of Communication Equipment
129 (576.5) Maintenance of Miscellaneous Market Operation Plant
130 Total Maintenance (Lines 125 thru 129)
131 TOTAL Regional Transmission and Market Op Expns (Total 123 and 130)
132 4. DISTRIBUTION EXPENSES
133 Operation
134 (580) Operation Supervision and Engineering I 4,118,843 3,746,431
135 (581) Load Dispatching 3,549,914 3,482,055
136 (582) Station Expenses 1,157,508 1,192,869
137 (58 3) Overhead Line Expenses 3,786,758 3,039,224
138 (584) Underground Line Expenses 1,870,345 1,825,857
139 (585) Street Lighting and Signal System Expenses 109,636 122,065
140 (586) Meter Expenses 4,132,819 4,130,937
141 (587) Customer Installations Expenses 642,062 1,092,077
142 (58 8) Miscellaneous Expenses 5,622,888 5,494,553
143 (589) Rents 493,172 830,940
144 TOTAL Operation (Enter Total of lines 134 thru 143) 25,483,945 24,957,008
145 Maintenance
146 (590) Maintenance Supervision and Engineering 224,177 402,38
147 (591) Maintenance of Structures 5,71
148 (592) Maintenance of Station Equipment 3,819,880 3,230.8
149 (593) Maintenance of Overhead Lines 15,554,326 14,495.48
150 (594) Maintenance of Underground Lines 1,046,527 1,054.
151 (595) Maintenance of Line Transformers 422,582 433,
152 (596) Maintenance of Street Lighting and Signal Systems 568,715 554.04
153 (597) Maintenance of Meters 725,957 472.
154 (598) Maintenance of Miscellaneous Distribution Plant 529,9771 252,
155 TOTAL Maintenance (Total of lines 146 thru 154) 22,892,1411 20,901,484
156 TOTAL Distribution Expenses (Total of lines 144 and 155) I 48,376,0861 45,858,492
157 5. CUSTOMER ACCOUNTS EXPENSES
158 Operation
159 (901) Supervision 441,306 427,283
160 (902) Meter Reading Expenses 1,379,745 2,453,647
161 (903) Customer Records and Collection Expenses 13,188,955 12,944,062
162 (904) Uncollectible Accounts 4,512,906 4,269,718
163 (905) Miscellaneous Customer Accounts Expenses 413 252
164 TOTAL Customer Accounts Expenses (Total of lines 159 thru 163) 19,523,325 20,094,962
FERC FORM NO. I (ED. 12-93) Page 322
Name of Respondent
Idaho Power Company
This Re ort Is: Date of Report
04/15/2013
Year/Period of Report
End of 2012/Q4
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line
No.
Account
(a)
Amount for (..urrent Year
(b)
Ampunt fpr Previous Year
(c)
165 6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
166 Operation
167 (907) Supervision 535,711 528,250
168 (908) Customer Assistance Expenses 33,737,489 44034,548
169 (909) Informational and Instructional Expenses 295,583 82,775
170 (910) Miscellaneous Customer Service and Informational Expenses 554,027 531,823
171 TOTAL Customer Service and Information Expenses (Total 167 thru 170) 35,122,810 45,177,396
172 7. SALES EXPENSES
173 Operation
174 1 (911) Supervision I
175 (912) Demonstrating and Selling Expenses
176 (913) Advertising Expenses
177 (916) Miscellaneous Sales Expenses
178 TOTAL Sales Expenses (Enter Total of lines 174 thru 177)
179 8. ADMINISTRATIVE AND GENERAL EXPENSES
180 1 Operation
181 920) Administrative and General Salaries I 70,376,748 1 67,143,039 1
182 921) Office Supplies and Expenses 18,940,073 15,742,902
183 (Less) (922) Administrative Expenses Transferred-Credit 28,236,018 26,009,805
184 (923) Outside Services Employed 5,177,361 4,925,844
185 (924) Property Insurance 3,506,576 3,207,120
186 (925) Injuries and Damages 7,150,892 5,806,100
187 (926) Employee Pensions and Benefits 61,791,248 60,010,908
188 (927) Franchise Requirements 9
189 (928) Regulatory Commission Expenses 5,692,486 3,449,337
190 (929) (Less) Duplicate Charges-Cr.
191 (930.1) General Advertising Expenses 493,0571 552,129
192 (930.2) Miscellaneous General Expenses 4,026,891 3,750,121
193 (931) Rents 17,598 7,103
194 TOTAL Operation (Enter Total of lines 181 thru 193) 148,936,921 138,584,798
195 Maintenance
196 (935) Maintenance of General Plant 5,160,763 4,522,111
197 TOTAL Administrative & General Expenses (Total of lines 194 and 196) 154,097,684 143,106,909
198 1 TOTAL Elec Op and Maint Expns (Total 80,112,131,156,164,171,178,197) 670,512,557 709,101,987
FERC FORM NO. 1 (ED. 12-93) Page 323
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Idaho Power Company 04n5/2013 End of 20121Q4
PURCHASED POWER (Account 555) (Including power exchanges)
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ- for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
Average
Monthly NCP Deman
Average
Monthly CP Demand No. (Footnote Affillations) Classifi-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
(a) (b) (c) (d) (e) (f)
I Cogeneration and Small Power Producers
2 AgPower Jerome/Double A Digester LU - .488
3 Allan Ravenscroft/Malad River LU - NA NA NA
4 Bennett Creek Wind Farm LU - NA NA NA
5 Bettencourt DryCreek Biofactory LU - NA NA NA
6 Big Sky West Dairy Digester LU - NA NA NA
7 Big Wood Canal Company
8 Black Canyon #3 LU - NA NA NA
9 Jim Knight LU - NA NA NA
10 Sagebrush LU - NA NA NA
11 Blind Canyon Hydro LU - NA NA NA
12 BranchflowerlTrout Company LU - NA NA NA
13 Burley Butte Wind Park LU - NA NA NA
14 Bypass Limited LU - NA NA NA
Total
FERC FORM NO. I (ED. 12-90) Page 326
Name of Respondent I This Re ort Is: Date of Report Year/Period of Report
Idaho Power Company (2) A Resubmission L
End of 2012/Q4
PU CHAS' PQWER(Account 555) (Continued) (Including power exchanges)
AD -for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5.For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7.Report demand charges in column U) energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8.The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9.Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total U+k+l) Purchased No. Received Delivered ($) ($) of Settlement($)
(g) (h) (i)
22,561 1,391,161 1,391,161 2
3,011 155,672 87,511 243,182 3
48,271 2,812,091 2,812,098 4
5,321 450,31 450,312 5
8,761 383,05 383,059 6
7
331 22,131 22,136 8
1,257 85,80f 85,808 9
1,252 85,38q 85,385 10
4,462 423,721 423,727 11
74,9 52,65f 52,655 12
59,961 2,768,291 2,768,295 13
28,49 1,486,303 14
3,667,462 392,313 395,257 2,815,124 180,900,690 6,924,894 190,640,701
FERC FORM NO. I (ED. 12-90) Page 327
Name of Respondent This Re oil Is: Date of Repo rt Year/Period of Report
Idaho Power Company (1)X An Original
(2)9A Resubmission
(Mo, Da, Yr)
04/15/2013 n f 2012/Q4
PURCHASED POWER (Account 555) (Including power exchanges)
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
Average
Monthly NCP Demand
Average
Monthly CP Demand ,o. (Footnote ,,iu,Iauonsj Classifi-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
(a) (b) (c) (d) (e) (f)
I Camp Reed Wind Park LU - NA NA NA
2 Cargill lnc./B6 Anaerobic Digester LU - NA NA NA
3 Cassia Gulch Wind Park LU - NA NA NA
4 Cassia Wind Farm LU - NA NA NA
5 City of Cove, Oregon/Mill Creek LU - NA NA NA
6 City of Halley LU - NA NA NA
7 City of Pocatello LU - NA INA NA
8 Clear Springs Food Inc. LU - NA INA NA
9 Clifton E. Jenson/Birchcreek LU - .05
10 Cold Springs Windfarm, LLC LU - NA NA NA
11 Consolidated Hydro lnc./Enel
12 Barber Dam LU - NA NA NA
13 Dietrich Drop LU NA NA NA
14 GeoBon #2 LU - NA NA NA
Total
FERC FORM NO. I (ED. 12-90) Page 326.1
Name of Respondent I This Re ort Is: Date of Report Year/Period of Report
Idaho Power Company 1(1) X An Original (Mo, Da, Yr) End of 2012/04 (2) JA Resubmission 04/15/2013
PUkCHAS PQWER(Account 555) (Continued) (Including power exchanges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5.For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7.Report demand charges in column U) energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8.The data in column (g)through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (I) must be reported as Exchange Delivered on Page 401, line 13.
9.Footnote entries as required and provide explanations following all required data.
POWER EXCHANGES MegaWatt Hours COST/SETTLEMENT OF POWER Line MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (J+k+l) Purchased No Received Delivered ($) of Settlement($)
(g) (h) (I) (j) (k) (I) (m)
64,726 5,424,211 5,424,211 1
9,14: 672,982 672,982 2
3
23,92: 1,175,521 1,175,521 4
2,991 209,635 209,635 5
8( 5,415 5,415 6
1,46 106,811 106,811 7
3,51 296,13 296,133 8
351 17,500 9,94 27,444 9
12,43t 346,40 346,402 10
11
14,691 698,48: 698,483 12
15,381 825,49E 825,499 13
4,171 300,9a 300,983 14
3,667,462 392,313 395,257 2,815,124 180,900,690 6,924,89 190,640,701
FERC FORM NO. 1 (ED. 12-90) Page 327.1
Name of Respondent This Report Is: Date of Report Year/Period of Report
Idaho Power Company (1)X An Original
(2)flA Resubmission
(Mo, Da, Yr)
04/15/2013 E d f 2012/04 n 0
PURCHASED POWER (Account 555) (Including power exchanges)
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
Average
Monthly NCP Demand
Average
Monthly CP Demand No. (Footnote Affiliations) Classifi-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (c) (d) (e) (f)
I Lowline #2 LU NA NA NA
2 Rock Creek #2 LU - NA INA NA
3 Contractors Power Group Inc./Mile 28 LU - NA INA NA
4 Crystal Springs Hydro LU - NA INA NA
5 Curry Cattle Company LU - NA
6 David McCollum/Canyon Springs LU - NA NA NA
7 David R Snedigar LU - NA NA NA
8 Desert Meadow Wind Farm LU - NA NA NA
9 Faulkner Brothers Hydro Inc. LU - NA NA NA
10 Fisheries Development - NA NA NA
11 Fossil Gulch Wind LU - NA NA NA
12 G2 Energy Hidden Hollow LU - NA NA NA
13 Glenns Ferry Cogan Partners/Magic LU - NA NA NA
14 Golden Valley Wind Park LU - NA NA NA
Total
FERC FORM NO. 1 (ED. 12-90) Page 326.2
Name of Respondent I This Re art Is: Date of Report Year/Period of Report
Idaho Power Company (1)X An Original (Mo, Da, Yr) End of 20121Q4
(2)EA Resubmission 04/15/2013
PUkCHASED PQWER(Account 555) (Continued) (Including power exchanges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5.For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (I) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7.Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8.The data in column (g)through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9.Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l) Purchased No. Received Delivered ($) ($) ($) of Settlement($)
(g) (h) (i) (j) (k) (I) (m)
8,576 440,062 440,062 1
6,671 330,044 330,044 2
4,931 333,110 333,110 3
11,044 725,126 725,126 4
689 26,79e 19,481 46,277 5
864 8,441 8,441 6
1,514 102,931 102,934 7
16,461 433,131 433,134 8
3,78! 287,73 287,733 9
1,09! 11,10 11,102 10
23,731 1,284,641 1,284,648 11
21,72C 11,286,02 1,286,02 12
-16! -7,85( -7,850 13
34,43f 1,580,261 1,580,265 14
3,667,462 392,3131 395,257 2,815,12 180,900,691 6,924,894 190,640,701
FERC FORM NO. I (ED. 12-90) Page 327.2
Name of Respondent This Re ort Is: Date o f Report Year/Period of Report
Idaho Power Company (1)X An Original (Mo, Da, Yr)
(2)A Resubmission 04/15/2013 d f 2012/Q4 n 0
PURCHASED POWER (Account 555) (inducling power excflanges)
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU -for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
Average
Monthly NCP Demand
Average
Monthly CP Demand i'iO. i,roOuiote Affiliations) Classifi-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
(a) (b) (c) (d) (e) (f)
1 Hammett Hill Windfarm, LLC LU NA NA NA
2 JJ - NA NA NA
3 High Mesa Energy LU NA NA NA
4 H.K. Hydro Mud Creek S & S LU - NA NA NA
5 Horeshoe Bend Hydro LU - NA NA NA
6 Horseshoe Bend Wind/United Materials LU - NA NA NA
7 1 Hot Springs Wind Farm LU - NA NA NA
8 Idaho Winds/Sawtooth Wind Project LU - NA NA NA
9 JR Simplot Co. LU - NA NA NA
10 J.M. Miller/Sahko Hydro LU - NA NA NA
11 James B. Howell/CHI Elk Creek LU - NA NA NA
12 John R LeMoyne LU - NA NA NA
13 Kesel & Witherspoon LU - NA NA NA
14 Koyle Hydro Inc. LU - NA NA NA
Total
FERC FORM NO. I (ED. 12-90) Page 326.3
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Idaho Power Company End of 2012/Q4 L
AResubmission 04/15/2013
PU CHASED PQWER(Account 555) (Continued) (Including power exchanges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5.For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7.Report demand charges in column (I), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8.The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9.Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l) Purchased No. Received Delivered ($) ($) of Settlement($)
(g) (h) (i) (j) (k) (I) (m) -
16,441 414,328 414,328 1
23,791 1,621,877 1,621,877 2
2,95: 54,021 54,023 3
1,44( 104,26 104,264 4
49,521 3,362,211 3,362,216 5
18,43 933,381 933,389 6
46,101 2,663,75' 2,663,754 7
60,421 4,423,971 4,423,976 8
71,48: 4,222,5611 4,222,561 9
1,211 76,451 76,458 10
4,571 313,441
641
313,446 11
35,80E 35,806 12
3,361 257,792 257,792 13
3,65C 297,697 297,697 14
3,667,462 392,3131 395,257 2,815,12' 180,900,690 6,924,89 190,640,701
FERC FORM NO. I (ED. 12-90) Page 327.3
Name of Respondent This [Report Is: Date of Report Year/Period of Report
Idaho Power Company (2) EJ A Resubmission 04/15/2013 End of 2012/Q4
PURCHASED POWER (Account 555) (Induding power exchanges)
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
Average
Monthly NCP Demand
Average
Monthly CP Demand No. (Footnote Affiliations) Classifl-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (c) (d) (e) (f)
I Lateral 10 Ventures LU - NA NA NA
2 Lemhi Hydro Power Co./Schaffner LU - NA NA NA
3 Lime Wind LU - NA NA NA
4 Little Mac Power Co./Cedar Draw LU - NA NA NA
5 Little Wood River Irrigation District LU - NA NA NA
6 Magic Reservoir Hydro LU - NA NA NA
7 Mainline Windfarm LU NA NA NA
8 1 Marco Rancher's Irrigation Inc. LU - NA NA NA
9 W - NA NA NA
10 Milner Dam Wind Park LU - NA NA NA
11 Mud Creek White Hydro, Inc LU - NA NA NA
12 New Energy One/Rock Creek Diary LU NA NA NA
13 Oregon Trail Wind Park LU - NA NA NA
14 Owyhee Irrigation District
Total
FERC FORM NO. I (ED. 12-90) Page 326.4
Name of Respondent Date of Report Year/Period of Report
Idaho Power Company
I This
RMA
ort Is L
Resubrnsion 04/15/2013 End of 2012/Q4
PU CHAS PQWER(Account 555) (Continued) (Including power exchanges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5.For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7.Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8.The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9.Footnote entries as required and provide explanations following all required data.
POWER EXCHANGES Mega Watt Hours COST/SETTLEMENT OF POWER Line
MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l) Purchased No.
Received Delivered ($) $ M of Settlement ($)
(g) (h)
5,627 352,781 352,786 1
1,321 98,001 98,00g 2
5,93A 418,42 418,425 3
5,811 365,66 365,660 4
6,781 466,142 466,142 5
28,951 1,408,094 1,408,094 6
19,031 505,255 505,255 7
2,861 192,451 192,451 8
57,151 3,606,451 3,606,451 9
54,581 2,621,322 2,621,322 10
451 30,464 30,464 11
3,79 183,609 183,609 12
36,591 1,793,891 1,793,891 13
14
3,667,462 392,313 395,257 2,815,124 180,900,690 6,924,89 190,640,70
FERC FORM NO. I (ED. 12-90) Page 327.4
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Idaho Power Company An Original
(2) E] A Resubmission
Da, Y
04/15/2013 End of 2012/04
PURCHASED POWER (Account 555) (Including power exchanges)
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term' means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
Average
Monthly NCP Demand
Average
Monthly CP Demand 0. (Footnote Affiliations) Classifi-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (c) (d) (e) (f)
1 Mitchell Butte LU - NA NA NA
21 Owyhee Dam LU - NA INA NA
3 Tunnel #1 LU - NA NA NA
4 Paynes Ferry Wind Park LU - NA NA NA
5 Pigeon Cove Power LU NA
6 Pilgrim Stage Station Wind Park LU - NA NA NA
7 Pristine Springs Inc #1 LU - NA NA NA
8 Pristine Springs Inc #3 LU - NA NA NA
9 Reynolds Irrigation District LU - NA NA NA
10 Richard Kaster
11 Box Canyon LU - NA NA NA
12 Briggs Creek LU - NA NA NA
13 Rim View Trout Company - NA NA NA
14 Riverside Hydro/Mora Drop LU - NA NA NA
Total
FERC FORM NO. I (ED. 12-90) Page 326.5
Name of Respondent I This Re ort Is: Date of Report Year/Period of Report
Idaho Power Company End of 2012/04
(2) F~ A Resubmission 04/15/2013
PUCHAS PQWER(Account 555) (Continued) (Including power exchanges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment
4.In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5.For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7.Report demand charges in column U) energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8.The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (I) must be reported as Exchange Delivered on Page 401, line 13.
9.Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l) Purchased No. Received Delivered ($) ($) of Settlement($)
(g) (h) (i) U) (k) (I) (m) -
4,921 115,851 115,851 1
19,471 -368,154 368,154 2
15,10: 1,587,741 1,587,748 3
61,851 5,187,7611 5,187,761 4
8,641 486,150 212,531 698,685 5
32,481 1,560,711 1,560,718 6
86d 49,421 49,425 7
1,251 67,171 67,177 8
891 64,11: 64,112 9
10
1,921 126,661 126,660 11
3,741 250,421 250,421 12
961 6,811 6,811 13
5,04: 285,46 285,464 14
3,667,4621 392,313 395,257 2,815,124 180,900,690 6,924,894 190,640,701
FERC FORM NO. I (ED. 12-90) Page 327.5
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Idaho Power Company (1)X An Original
(2)JA Resubmission
(Mo, Da, Yr)
04/15/2013 End of 2012/04
PURCHASED POWER (Account 555) (unduoung power exchanges)
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the suppliers service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX -For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
Average
Monthly NCP Deman
Average
Monthly CP Demand 0. (Footnote Affiliations) Classifi-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
(a) (b) (c) (d) (e) (t)
I Riverside Investments/Arena Drop LU - NA NA NA
2 1 Rock Creek #1 Joint Venture LU NA
3 Rockland Wind Project LU - NA NA NA
4 Rupert Cogan Partners/Magic Valley LU - NA NA NA
5 Ryegrass Windfarm LU NA NA NA
6 Salmon Falls Wind Park LU - NA NA NA
7 SE Hazelton ALP LU - NA NA NA
8 Shorock Hydro Inc. NA
9 Shoshone Cspp LU - NA NA NA
10 Shoshone #2 LU - NA NA NA
11 1 Snake Rivery Pottery ILLI - NA INA NA
12 LU - NA NA NA
NA
14 Tasco -Nampa I NA NA NA
Total
FERC FORM NO. I (ED. 12-90) Page 326.6
Name of Respondent I This Re art Is: Date of Report Year/Period of Report
Idaho Power Company (1)X An Original (Mo, Da, Yr) End of 2012/Q4
(2)[JA Resubmission 04/15/2013
PUkCHAS PQWER(Account 555) (Continued) (Including power exchanges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5.For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7.Report demand charges in column energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8.The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9.Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line Megawatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l) Purchased No. Received Delivered ($) ($) of Settlement($)
(g) (h)
1,635 121,273 121,273 1
9,94q 552,508 281,419 833,927 2
249,79 14,364,819 14,364,815 3
77,01 4,921,09: 4,921,093 4
13,17 344,581 344,581 5
62,08 3,154,621 3,154,626 6
24,71 1,572,58 1,572,582 7
8
2,114 167,381 167,389 9
2,601 171,411 171,41 10
380 25,52 25,525 11
27,963 1,974,671 12
35,686 1,576,498 1,342,97 2,919,473 13
477 3,831 3,830 14
3,667,4621 392,3131 395,257 2,815,124 180,900,690 6,924,89 190,640,701
FERC FORM NO. I (ED. 12-90) Page 327.6
Name of Respondent This Re ort Is: Date of Report
Idaho Power Company (1)X An Original
(2)[]A Resubmission
(Mo, Da, Yr)
Year/Peri
n
od of Report
04/15/2013 En f 2012/Q4 0
PURCHASED POWER (Account 555) (Induaing power excflanges)
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF -for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
Average
Monthly NCP Deman
Average
Monthly CP Demand No. (Footnote Affiliations) Classifi-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (c) (d) (e) (f)
I Tasco - Twin Falls NA NA NA
2 Ted S. Sorenson/Tiber Dam LU - NA NA NA
3 Thousand Spring Wind Park LU - NA NA NA
4 Tuana Gulch Wind Park LU - NA NA NA
5 Tuana Springs Expansion LU - NA NA NA
6 Twin Falls Energy/Lowline Midway Hydro LU - NA NA NA
7 Two Ponds Windfarm LU NA NA NA
8 White Water Ranch LU - NA NA NA
9 William Arkoosh/Littlewood LU - NA NA NA
10 Willis and Betty Deveny/Shingle Creek LU - NA NA NA
II .0 - NA NA NA
12 1 Yahoo Creek Wind Park 1LU - NA NA NA
13
14
Total
FERC FORM NO. I (ED. 12-90) Page 326.7
Name of Respondent I This Re ort Is: Date of Report Year/Period of Report
Idaho Power Company (1)X An Original (Mo, Da, Yr) End of 2012/Q4
(2)UAResubmission 04/15/2013
PUICHA$E PQWER(Account 555) (Continued) lncluding power exchanges)
AD -for out-of-period adjustment. Use this code for any accounting adjustments or true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5.For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7.Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8.The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9.Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Megawatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l) Purchased No. Received Delivered ($) of Settlement($)
(g) (h)
1 1
26,209 1,375,275 1,375,275 2
32,751 1,565,151 1,565,157 3
29,247 1,448,561 1,448,563 4
81,576 4,895,281 4,895,281 5
8,766 523,24: 523,243 6
17,921 437,521 437,526 7
753 50,231 50,238 8
4,494 327,31 327,315 9
977 67,771 67,778 10
27,60E 1,883,241 1,883,240 11
62,83 5,250,641 5,250,646 12
870,94: 870,942 13
-2,40 14
3,667,4621 392,313 395,257 2,815,124 180,900,690 6,924,89 190,640,701
FERC FORM NO. 1 (ED. 12-90) Page 327.7
Name of Respondent This Report Is: Date of Report Year/Period of Report
Idaho Power Company (1)X An Original
(2)flA Resubmission
(Mo, Da, Yr)
04/15/2013 E d f 2012/04 End 0
PUFCHA$ED POWER (Account 555) (including power excManges) -
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
Average
Monthly NCP Demand
Average
Monthly CP Demand t,O. (Footnote Affiliations) Classifi-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (c) (d) (e) (f)
1 Other Purchased Power
2 Arizona Public Service Co. SF JWSPP NA NA NA
3 Avista Corp. SF T-12 NA NA NA
4 Avista Corp. SF JWSPP NA NA NA
5 Avista Corp. WSPP NA NA NA
6 Barclays Bank PLC NA NA NA
7 Black Hills Power Inc. SF WSPP NA NA NA
8 Bonneville Power Administration WSPP NA NA NA
9 Bonneville Power Administration SF IwSPP NA NA NA
10 BP Energy Company SF WSPP NA NA NA
11 Brookfield Energy Marketing LP SF WSPP NA NA NA
12 Calpine Energy Services, L.P. SF WSPP NA NA NA
13 Cargill Power Markets LLC WSPP NA NA NA
14 Cargill Power Markets LLC SF WSPP NA NA NA
Total
FERC FORM NO. 1 (ED. 12-90) Page 326.8
Name of Respondent I This Re ort Is: Date of Report Year/Period of Report
Idaho Power Company L
2nRssion 04/15/2013 End of 20121Q4
PU CHASED PQWER(Account 555) (Continued) (Including power exchanges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or 'true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5.For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7.Report demand charges in column ), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8.The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9.Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l) Purchased No. Received Delivered ($) of Settlement($)
(g) (h)
12,347 307,211 307,211 2
51 1,127 1,127 3
129,07 2,135,092 2,135,092 4
221,285 221,285 5
569,254 569,254 6
1,70( 43,601 43,600 7
284,953 284,953 8
93,771 1,852,17 1,852,172 9
54,801 578,291 578,296 10
771 12,361 12,361 11
8,801 130,09 130,092 12
245,194 245,194 13
102,391 1,409,954 1,409,954 14
3,667,462 392,3131 395,257 2,815,124 180,900,690 6,924,894 190,640,701
FERC FORM NO. 1 (ED. 12-90) Page 327.8
Name of Respondent This Re oil Is: Date of Report Year/Period of Report
Idaho Power Company (1)X An Original
(2)flA Resubmission
(Mo, Da, Yr)
04/15/2013 n 2012/Q4
PURCHASED POWER (Account 555) (Including power exchanges)
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF -for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
Average
Monthly NCP Demand
Average
Monthly CP Demand No. (Footnote . rOOu,OLe tnuIdOflSj Classifi-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (c) (d) (e) (f)
I Chelan Co PUD SF WSPP NA NA NA
2 Citigroup Energy Inc. SF WSPP NA NA NA
3 Citigroup Energy Inc. ________ - NA NA NA
4 Clatskanie PUD SF WSPP NA NA NA
5 Constellation Energy Commodities Group WSPP NA NA NA
6 Constellation Energy Commodities Group SF WSPP NA NA NA
7 DB Energy Trading LLC SF WSPP NA NA NA
8 Douglas County PUD SF WSPP NA NA NA
9 EDF Trading North America, LLC SF WSPP NA NA NA
10 Eugene Water & Electric Board SF WSPP NA NA NA
11 Grant CO Public Utility District #2 - SF WSPP NA NA NA
12 1 IBERDROLA RENEWABLES, Inc. SF WSPP NA NA NA
13 J.P. Morgan Ventures Energy Corporatio NA NA NA
14 J.P. Morgan Ventures Energy Corporatio SF WSPP NA NA NA
Total
FERC FORM NO. I (ED. 12-90) Page 326.9
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Idaho Power Company End of 20121Q4
(2) []A Resubmission L
04/15/2013
PU CHASED PQWER(Account 555) (Continued) (Including power exchanges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5.For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7.Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8.The data in column (g)through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9.Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l) Purchased No. Received Delivered ($) ($) of Settlement ($)
(m) (g) (h) (i) (j) (k) (I)
8,03 121,705 121,705 1
91,621 2,281,427 2,281,427 2
1,551 ,477 1,551,477 3
80 11,501 11,500 4
9 945
8,071 242,451 242,456 6
28,571 99,471 99,479 7
2,004 23,201 23,20e
123,225 2,955,70C 2,955,700 9
23,904 351,504 351,504 10
42 9,13E 9,136 11
115,728 1,741,871 1,741,871 12
112,088 112,088 13
58,800 1,170,570 1,170,570 14
3,667,462 392,313 395,257 2,815,124 180,900,690 6,924,89 190,640,701
FERC FORM NO. 1 (ED. 12-90) Page 327.9
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Idaho Power Company (1)X An Original (Mo, Da, Yr) End of 2012/Q4 (2)[:)A Resubmissron 04/15/2013
PURCHASED POWER (Account 555) (Including power exchanges)
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
Average
Monthly NCP Demand
Average
Monthly CP Demand 0. (Footnote ra OflS Classuti-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (c) (d) (e) (f)
I JPMorgan Chase Bank, N.A. - NA NA NA
2 Jeffenes Bache -- NA NA NA
3 Macquarie Cook Power Inc. SF IWSPP NA NA NA
4 Macquarie Cook Power Inc. - NA NA NA
5 NaturEner USA, LLC SF 1WSPP NA NA NA
6 Nevada Power Co, DBA NV Energy SF WSPP NA NA NA
7 NextEra Energy Power Marketing, LLC SF WSPP NA NA NA
8 Noble Americas Gas&Power Corp SF WSPP NA NA NA
9 NorthWestern Energy SF T-7 NA NA NA
10 PacifiCorp Inc. SF T-13 NA NA NA
11 PacifiCorp Inc. SF WSPP NA NA NA
12 PacifiCorp Inc. WSPP NA NA NA
13 Portland General Electric Company SF 1-14 NA NA NA
14 Portland General Electric Company SF WSPP NA NA NA
Total
FERC FORM NO. 1 (ED. 12-90) Page 326.10
Name of Respondent I This Report Is: Date of Report Year/Period of Report
Idaho Power Company (2) [JAResubmisson 04/15/2013 End of 2012/Q4
PUCHAS PQWER(Account 555) (Continued) IncIuding power exchanges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5.For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7.Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8.The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9.Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l) Purchased No.
Received Delivered ($) of Settlement($)
(g) (h) (i) U) (k) (I) (m)
416,376 416,376 1
2,250,030 2,250,030 2
18,825 156,4611 156,461 3
1,110,405 1,110,405 4
8f 885
379 12,92 12,925 6
5,941 69,77 69,771 7
401 12,20q 12,200 8
4 1,01 1,013 9
36 6,78: 6,782 10
5,301 142,90' 142,900 11
104,495 104,495 12
45 1,298 1,298 13
25,464 320,476 320,478 14
3,667,462 392,313 395,257 2,815,124 180,900,690 6,924,894 190,640,70
FERC FORM NO. I (ED. 12-90) Page 327.10
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Idaho Power Company (1)X An Original (Mo, Da, Yr) n 0 20121Q4 (2)flA Resubmission 04/15/2013
PURCHASED POWER (Account 555) (incluciing power excflanges)
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF -for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Urie Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
Average
Monthly NCP Demand
Average
Monthly CP Demand 0. (Footnote iiiiiiauonsj Classifi-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (c) (d) (e) (f)
I Portland General Electric Company WSPP NA NA NA
2 Powerex Corp. SF WSPP NA NA NA
3 PPL EnergyPlus, LLC SF WSPP NA NA NA
4 Public Service Company of New Mexico SF WSPP NA NA NA
5 Puget Sound Energy, Inc. SF T-9 NA NA NA
6 Puget Sound Energy, Inc. SF WSPP NA NA NA
7 Rainbow Energy Marketing Corporation SF JWSPP NA NA NA
8 Royal Bank of Canada NA NA NA
9 Salt River Project SF JWSPP NA NA NA
10 Seattle City Light SF JWSPP NA NA NA
11 Shell Energy North America (US), L.P. SF WSPP NA NA NA
12 Shell Energy North America (US), L.P. _______ - NA NA NA
13 Sierra Pacific Power Co., dba NV Energ SF T-55 NA NA NA
14 Sierra Pacific Power Co., dba NV Energ SF WSPP NA NA NA
Total
FERC FORM NO. 1 (ED. 12-90) Page 326.11
Name of Respondent I This Re ort Is: Date of Report Year/Period of Report
Idaho Power Company 2"R 'ssion 04/15/2013 End of 2012/Q4
PU iCHAStU PQWERAcunt 555) (Continued) (Including power exchanges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5.For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7.Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8.The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9.Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l) Purchased No. Received Delivered ($) ($) ($) of Settlement ($)
(g) (h) (I) (j) (k) (I) (m)
76 90C 90(1
27,551 871,45 871,453 2
174,031 6,390,73q 6,390,738 3
2,921 106,47 106,475 4
51 1,3& 1,3645
25,771 552,221 552,221 6
15,06 417,754 417,75 7
-203,658 -203,658 8
901 39,501 39,500 9
23,671 475,71 E 475,718 10
47,46: 717,31: 717,312 11
282,420 282,420 12
63 1,314 1,314 13
28,418 739,123 739,123 14
3,667,462 392,313 395,257 2,815,124 180,900,690 6,924,894 190,640,70
FERC FORM NO. I (ED. 12-90) Page 327.11
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Idaho Power Company (1)X An Original (Mo, Da, Yr) nu 0. 2012/04
(2)JA Resubmission 04115/2013
PURCHASED POWER (Account 555) (Including power excflanges)
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
Average
Monthly NCP Demand
Average
Monthly CP Demand '.0. (Footnote Affiliations) Classifi-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (c) (d) (e) (f)
I Sierra Pacific Power Co., dba NV Energ WSPP NA NA NA
2 Snohomish County PUD SF WSPP NA NA NA
3 Tacoma Power SF WSPP NA NA NA
4 Tenaska Power Services Co. SF WSPP NA NA NA
5 The Energy Authority, Inc. SF WSPP NA NA NA
6 TransAlta Energy Marketing (U.S.) Inc. SF WSPP NA NA NA
7 Western Area Power Administration SF WSPP NA NA NA
8 Raft River Energy I LLC _______ - NA NA NA
9 Telocaset Wind Power Partners LLC LU APP-A NA NA NA
10 Neal Hot Springs Unit #1 LU NA NA NA
11 Net Metering Customers - NA NA NA
12 Oregon Solar Customers -- NA NA NA
13 Power Exchanges
14 Bonneville Power Administration ________ - NA NA NA
Total
FERC FORM NO. I (ED. 12-90) Page 326.12
Name of Respondent I This Re ort Is: Date of Report Year/Period of Report
Idaho Power Company L
AResubmission 04/15/2013 End of 2012/04
PU CHAS PQWER(Account 555) (Continued) (Including power exchanges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or true-up? for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5.For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7.Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8.The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9.Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+I) Purchased No. Received Delivered ($) ($) of Settlement ($)
(g) (h) (i) (j) (k) (I) (m)
790 790 1
1,73( 22,42C 22,420 2
48A 7,601 7,608 3
421 6,731 6,738 4
6,491 69,451 69,458 5
15,831 272,36 272,36 6
1 71 717
74,621 4,549,181 4,549,186 8
314,141 17,153,271 17,153,270 9
23,692 2,262,881 2,262,881 10
811 61,649 61,641 11
314 7,954 7,954 12
13
61,650 14
3,667,462 392,3131 395,257 2,815,124 180,900,690 6,924,894 190,640,701
FERC FORM NO. I (ED. 12-90) Page 327.12
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Idaho Power Company 2l?iIssion 04/15/2013 End of 2012/Q4
PURCHASED POWER (Account 555) (lnduaing power exchanges)
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
Average
Monthly NCP Demand
Average
Monthly CP Demand ,'iO. rOOuiote Affiliations) Classifi-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (c) (d) (e) (f)
I EDF Trading North America, LLC NA NA NA
2 1 NorthWestern Energy -- NA NA NA
3 PadfiCorp Inc. -- NA NA NA
4 Puget Sound Energy, Inc. - NA NA NA
5 Powerex Corp. NA NA NA
6 Sierra Pacific Power Co., dba NV Energ NA NA NA
7 Utah Associated Municipal Power System NA NA NA
8 Clatskanie PUD EX 1153 NA NA NA
9 Sierra Pacific Power Co., dba NV Energ EX WSPP NA NA NA
10 Other Transactions
11 Acct Valuation-Clatskanie PUD Exchange -
12 Langley Test Power Valuation OS - NA NA NA
13 Liquidated Damages-Yellowstone Power OS NA NA NA
14 Demand Response Avoided Energy OS NA NA NA
Total
FERC FORM NO. I (ED. 12-90) Page 326.13
Name of Respondent I This Re ort Is: Date of Report Year/Period of Report
Idaho Power Company End of 20121Q4 L
04/15/2013
PU CHA$ PQWER(Account 555) (Continued) (Including power exchanges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5.For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (I) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7.Report demand charges in column O) energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8.The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9.Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l) Purchased No. Received Delivered ($) of Settlement($)
(9) (h)
92 1
6,119 2
170,446 257,349 3
8 4
29,370
3,936 6
262
75,807 73,175 8
54,678 54,678
10
-20,215 -20,215 11
726,126 726,12612
-251,435 -251,435 13
14,479,447 14,479,447 14
3,667,4621 392,313 395,257 2,815,124 180,900,690 6,924,89 190,640,70
FERC FORM NO. 1 (ED. 12-90) Page 327.13
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Idaho Power Company (1)X An Original
(2)flA Resubmission
(Mo, Da, Yr)
04/15/2013 End of 2012/Q4
PURCHASED POWER (Account 555) (Inducling power exchanges)
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
Average
Monthly NCP Demand
Average
Monthly CP Demand 0. (Footnote Affi liations) Iauons, Classifl-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
(a) (b) (c) (d) (e) (f)
I Boardman Assured Delivery OS NA NA NA
2 1 Write-Off AD NA NA NA
3
4
5
6
71 1
8
9
10
11
12
13
14
Total
FERC FORM NO. I (ED. 12-90) Page 326.14
Name of Respondent I This Re ott Is: Date of Report Year/Period of Report
Idaho Power Company
L2 gAResubmission 04/15/2013 End of 201 2/Q4
PU CHASED PQWER(Account 555) (Continued) (Including power exchanges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or 'true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5.For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7.Report demand charges in column (fl, 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.
POWER EXCHANGES MegaWatt Hours COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+khi) No. Received Delivered ($) of Settlement($)
(g) (h) (i) (j) (k) (I) (m) -
213,491 213,491 1
2
3
4
5
6
7
8
9
10
11
12
13
14
3,667,462 392,313 395,257 2,815,124 180,900,690 6,924,8941 190,640,70
FERC FORM NO. I (ED. 12-90) Page 327.14
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
Idaho Power Company (2)- A Resubmission 04/15/2013 2012/Q4
FOOTNOTE DATA
Schedule Page: 326 Line No.: 2 Column: e
Unavailable
[Schedule Page: 326 Line No.: 2 Column: f
Una
Schedule Page: 326.1 Line No.: 9 Column: e
Unavailable
chedule Page: 326.1 Line No.: 9 Column: IF I Unavailable
Schedule Page: 326.2 Line No.: 5 Column: e I Unavailable
Schedule Page: 326.2 Line No.: 5 Column: f
Unavailable
Schedule Page: 326.2 Line No.: 10 Column: b
Non Firm Purchases
Schedule Page: 326.3 Line No.: 2 Column: a
Ida West, a subsidiary of IDACORP, has partial ownership of these projects.
ISchedule Page: 326.4 Line No.: 9 Column: a I Ida West, a subsidiary of IDACORP, has partial ownership of these projects.
Schedule Page: 326.5 Line No.: 5 Column: e I
Unavailable
Schedule Page: 326.5 Line No.: 5 Column: f I Unavailable
ISchedule Page: 326.5 Line No.: 13 Column: b I Non Firm Purchases
Schedule Page: 326.6 Line No.: 2 Column: e
Unavailable
Schedule Page: 326.6 Line No.: 2 Column: IF I Unavailable
Schedule Page: 326.6 Line No.: 12 Column: a
Ida West, a subsidiary of IDACORP, has partial ownership of these projects.
Schedule Page: 326.6 Line No.: 13 Column: a
The Tamarack Energy Partnership demand readings are taken
recorder provided by Idaho Power Co. The actual demand is
of energy.
from an electronic demand
not used in determining the cost
ISchedule Page: 326.6 Line No.: 13 Column: e 1 Unavailable
Schedule Page: 326.6 Line No.: 13 Column: f I
Unavailable
Schedule Page: 326.6 Line No.: 14 Column: b I Non Firm Purchases
Schedule Page: 326.7 Line No.: I Column: b
Non Firm Purchases
ISchedule Page: 326.7 Line No.: 11 Column: a I Ida West, a subsidiary of IDACORP, has partial ownership of these projects.
Schedule Page: 326.7 Line No.: 13 Column: a I Accrued additional purchased power expense subject to payment upon approval by IPUC.
Schedule Page: 326.7 Line No.: 14 Column: a I Difference between booked and scheduled energy
Schedule Page: 326.8 Line No.: 5 Column: b
Financial Transmission Losses
Schedule Page: 326.8 Line No.: 6 Column: b
ISDA Master Agreement with Barclays Bank PLC dated March 2, 2011
Schedule Page: 326.8 Line No.: 8 Column: b I Financial Transmission Losses
[FERC FORM NO. I (ED. 12-87) Page 450.1 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Idaho Power Company (2)_ A Resubmission 04/15/2013 2012/Q4
FOOTNOTE DATA
Schedule Page: 326.8 Line No.: 13 Column: b
ISDA Master Agreement with Cargill Power Markets, LLC, dated June 13, 2011
Schedule Page: 326.9 Line No.: 3 Column: b
ISDA Master Agreement with Citigroup Energy PLC dated March 7, 2011
Schedule Page: 326.9 Line No.: 5 Column: b
Non Firm Purchases
Schedule Page: 326.9 Line No.: 13 Column: b
ISDA Master Agreement with JP Morgan Ventures Energy Corporation dated May 1, 2011
ISchedule Page: 326.10 Line No.: I Column: b
ISDA Master Agreement with JP Morgan Chase Bank dated November 4, 2005
140edule Page: 326.10 Line No.: 2 Column: b
Prudential Bache Commodities, LLC (Jefferies Bache) Futures Account Document, dated
September 4, 2008
lSchedule Page: 326.10 Line No.: 4 Column: b
ISDA Master Agreement with Macquarie Energy PLC dated April 12, 2011
ISchedule Page: 326.10 Line No.: 12 Column: b
Financial Transmission Losses
Schedule Page: 326.11 Line No.: I Column: b
Non Firm Purchases
Schedule Page: 326.11 Line No.: 8 Column: b
ISDA Master Agreement with Royal Bank of Canada dated August 26,2005
ISchedule Page: 326.11 Line No.: 12 Column: b
ISDA Master Agreement with Shell Energy North America dated November 1, 2009
Schedule Page: 326.12 Line No.: I Column: b
Financial Transmission Losses
Schedule Page: 326.12 Line No.: 8 Column: b
Unavailable
ISchedule Page: 326.12 Line No.: 11 Column: b
Schedule 84 Net Metering
[Schedule Page: 326.12 Line No.: 12 Column: b
Schedule 88 Oregon Solar
Schedule Page: 326.12 Line No.: 14 ColumA: b
Scheduled losses not removed with loss transactions
[Schedule Page: 326.13 Line No.: I Column: b
Scheduled losses not removed with loss transactions
Schedule Page: 326.13 Line No.: 2 Column: b
Scheduled losses not removed with loss transactions
Schedule Page: 326.13 Line No.: 3 Column: b
Scheduled losses not removed with loss transactions
Schedule Page: 326.13 Line No.: 4 Column: b
Scheduled losses not removed with loss transactions
chedule Page: 326.13 Line No.: 5 Column: b
Scheduled losses not removed with loss transactions
chedule Page: 326.13 Line No.: 6 Column: b
Scheduled losses not removed with loss transactions
lSchedule Page: 326.13 Line No.: 7 Column: b
Scheduled losses not removed with loss transactions
IFERC FORM NO. I (ED. 12-87) Page 450.2 I
Name of Respondent
Idaho Power Company
I This Re art Is:
I (1) X An Original i (2) Q Resubmission
I Date of Report
I (Mo, Da, Yr)
04/15/2013
Year/Period of Report
End 0 f 2012104
TRANSMISION OF ELECTRICITY FOR OTHEkS (Account 456.1) (including transactions referred to as 'wheeling')
1.Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2.Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3.Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4.In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line
N0.
-
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
1 Bonneville Power Administration - OTEC Bonneville Power Administration Oregon Trails Electric Co-op FNO
2 Bonneville Power Administration - USBR Bonneville Power Administration United States Bureau of Reclamati FNO
3 Bonneville Power Administration - PF Bonneville Power Administration Priority Firm Customers FNO
4 Milner Irrigation District United States Bureau of Redamati Milner Irrigation District OLF
5 Cargill Seattle City Light Bonneville Power Administration OS
6 PaciflCorp PaaflCarp West PacifiCorp West FNO
7 United States Bureau of Indian Affairs Bonneville Power Administration United States Bureau of Indian Af OS
8 BC Hydra Powerex North Western/PaciflCorp East PaciflCorp East NF
9 BC Hydra Pawerex North Westem/PadfiCorp East PacifiCorp East NF
10 BC Hydra Powerex North Western/PaciflCorp East Sierra Pacific Power NF
11 BC Hydra Powerex PaciflCorp East North Westem/PaciflCorp East NF
12 BC Hydra Pawerex PaciflCarp East PacifiCorp East NF
13 BC Hydra Powerex PaciflCorp East Idaho Power Company NF
14 BC Hydra Powerex PaciflCorp East North Westem/PaciflCarp East NF
15 BC Hydra Pawerex PaciflCorp East Bonneville Power Administration NF
16 BC Hydra Powerex PaciflCorp East Sierra Pacific Power NF
17 BC Hydra Powerex North Westem/PacifiCorp East PaciflCarp East NF
18 BC Hydra Powerex North Westem/PacifiCorp East PaciflCorp East SFP
19 BC Hydro Powerex North Westem/PacifiCarp East PadflCorp East NF
20 BC Hydra Pawerex North Western/PaciflCarp East PaciflCorp East SFP
21 BC Hydra Pawerex North Westem/PaciflCarp East Bonneville Power Administration NF
22 BC Hydra Powerex North Western/PaciflCorp East Sierra Pacific Power NF
23 BC Hydra Powerex North Western/PaciliCorp East Sierra Pacific Power SFP
24 BC Hydra Powerex PaciflCorp East PaciflCorp East NF
25 BC Hydra Pawerex PaciflCarp East PaciflCarp East SFP
26 BC Hydra Powerex PaciflCorp East NorthWestem/PaciflCorp East NF
27 BC Hydra Pawerex PaciflCarp East PaciflCorp West NF
28 BC Hydra Powerex PadflCorp East Idaho Power Company NF
29 BC Hydra Pawerex PaciflCorp East North Westem/PaciflCarp East NF
30 BC Hydra Powerex PadflCorp East Bonneville Power Administration NF
31 BC Hydra Pawerex PaciflCarp East Sierra Pacific Power NF
32 BC Hydra Pawerex PaciflCorp West PacifiCarp East NF
33 BC Hydra Powerex PaciflCarp West PaciflCarp East SFP
34 BC Hydra Powerex PaciflCorp West PacifiCorp East NF
TOTAL
FERC FORM NO. 1 (ED. 12-90) Page 328
Name of Respondent
Idaho Power Company
This [Report Is:
A"R "9'•
Date of Report
04/15/2013
Year/Period of Report
End of 20121Q4
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456XContinued) (Including transactions reffered to as 'wheeling')
5.In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6.Report receipt and delivery locations for all single contract path, 'point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7.Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8.Report in column (i) and (j) the total megawatthours received and delivered.
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(0
Point of Delivery
(Substation or Other
Designation)
(g)
Billing TRANSFER OF ENERGY
Demand MegaWatt Hours MegaWatt Hours (MW) Received Delivered
(h)
utie
No.
324,580 324,580 1
5 376,076 376,07 2
5 1 1,243,883 1,243,88: 3
Minidoka, Idaho Various in Idaho 10,123 10,12: 4
10 401,225 401,22 5
5 1,965 1,96 6
LaGrande, Oregon Various in Idaho 18,245 18,24 7
5 AVAT.NWMT BORA I 855 85 8
5 AVAT.NWMT BRDY 540 54' 9
5 AVAT.NWMT M345 143 14 10
5 BORA BPAT.NWMT 10 1 11
5 BORA BRDY 44 4 12
5 BORA HMWY 2,088 2,08E 13
5 BORA JEFF 352 35 14
5 BORA LAGRANDE 3,450 3,45 15
5 BORA M345 2,242 2,24 16
5 BPAT.NWMT BORA 410 419 17
5 BPAT.NWMT BORA 39,557 39,551 18
5 BPAT.NWMT BRDY 1,203 1,20 19
5 BPAT.NWMT BRDY 4,169 4,16 20
5 BPAT.NWMT LAGRANDE 99 91 21
5 BPAT.NWMT M345 1,214 1,21 22
5 BPAT.NWMT M345 672 67A 23
5 BRDY BORA 1,856 1,851 24
5 BRDY BORA 38 31 25
5 BRDY BPAT.NWMT 411 411 26
5 BRDY ENPR 4 1 27
5 BRDY HMWY 1,423 1,42 28
5 BRDY JEFF 4 1 29
5 BROY LAGRANDE 2,785 2,781 30
5 BRDY M345 1,263 1,261 31
5 ENPR BORA 373,642 373,64A 32
5 ENPR BORA 35,034 35,031 33
5 ENPR BRDY 26,927 26,92 34
0 6,075,1201 6,075,121
FERC FORM NO. I (ED. 12-90) Page 329
Name of Respondent
Idaho Power Company
I This
RM A
cit Is:
I (1) An Original

(2) Resubmission
I Date of Report
I (Mo, Da, Yr)
04/15/2013
Year/Period of Report
End f 2012/Q4
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1)
(including transactions referred to as 'wheeling')
1.Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2.Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3.Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4.In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line
N 0.
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
I BC Hydro Powerex PaciflCorp West PaciflCorp East SFP
2 BC Hydro Powerex PacifiCorp West Bonneville Power Administration NF
3 BC Hydro Powerex PacifiCorp West Avista NF
4 BC Hydro Powerex PacifiCorp West Sierra Pacific Power NF
5 BC Hydro Powerex North Westem/PadfiCorp East North Western/PacifiCorp East NF
6 BC Hydro Powerex North Westem/PacifiCorp East Idaho Power Company NF
7 BC Hydro Powerex North Westem/PacifiCorp East Bonneville Power Administration NF
8 BC Hydro Powerex North Western/PacifiCorp East Sierra Pacific Power NF
9 BC Hydro Powerex Idaho Power Company PacifiCorp East NF
10 BC Hydro Powerex Idaho Power Company PacifiCorp East SFP
11 BC Hydro Powerex Idaho Power Company PaciflCorp East NF
12 BC Hydro Powerex Idaho Power Company PacifiCorp West NF
13 BC Hydro Powerex Idaho Power Company North Westem/PadfiCorp East NF
14 BC Hydro Powerex Idaho Power Company Sierra Pacific Power NF
15 BC Hydro Powerex PaciflCorp West PaciflCorp East NF
16 BC Hydro Powerex PacifiCorp West PaclfiCorp East NF
17 BC Hydro Powerex PaciflCorp West PacifiCorp West NF
18 BC Hydro Powerex PaciflCorp West Idaho Power Company NF
19 BC Hydro Powerex PacifiCorp West Bonneville Power Administration NF
20 BC Hydro Powerex PacifiCorp West Sierra Pacific Power NF
21 BC Hydro Powerex Idaho Power Company Bonneville Power Administration NF
22 BC Hydro Powerex NorthWestem/PacifiCorp East PacifiCorp East NF
23 BC Hydro Powerex NorthWestem/PacifiCorp East PacifiCorp East SFP
24 BC Hydro Powerex North Westem/PacifiCorp East NorthWestem/PacifiCorp East NF
25 BC Hydro Powerex North Westem/PacifiCorp East PacifiCorp East NF
26 BC Hydro Powerex North Westem/PacifiCorp East PacifiCorp East SFP
27 BC Hydro Powerex North Western/PacifiCorp East Idaho Power Company NF
28 BC Hydro Powerex North Western/PacifiCorp East PacifiCorp West NF
29 BC Hydro Powerex North Western/PacifiCorp East Bonneville Power Administration NF
30 BC Hydro Powerex North Western/PacifiCorp East Sierra Pacific Power NF
31 BC Hydro Powerex Bonneville Power Administration PaciflCorp East NF
32 BC Hydro Powerex Bonneville Power Administration PacifiCorp East SFP
33 BC Hydro Powerex Bonneville Power Administration PaciflCorp East NF
34 BC Hydro Powerex Bonneville Power Administration PaciflCorp East SFP
TOTAL
FERC FORM NO. 1 (ED. 12-90) Page 328.1
Name of Respondent
Idaho Power Company
This Re ort Is:
2nRS ion
Date of Report
04/15/2013
Year/Period of Report
End of 20121Q4
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued) (Including transactions reffered to as 'wheeling')
5.In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6.Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7.Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8.Report in column (i) and (j) the total megawatthours received and delivered.
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(f)
Point of Delivery
(Substation or Other
Designation)
(g)
Billing
Demand
(MW)
(h)
TRANSFER OF ENERGY Line
No. MegaWatt Hours
Received (i)
MegaWatt Hours
Delivered
5 ENPR BRDY 1,816 1,816 1
5 ENPR LAGRANDE 229 229 2
5 ENPR LOLO 76 7 3
5 ENPR M345 2,622 2,62A 4
5 GSHN BPAT.NWMT 5 1 5
5 GSHN HMWY 177 171 6
5 GSHN LAGRANDE 1,741 1,7411 7
5 GSHN M345 45 4 8
5 HMWY BORA 73,164 73,16 9
5 HMWY BORA 2,163 2,161 10
5 HMWY BRDY 3,772 3,771 11
5 HMWY JBSN 218 218 12
5 HMWY JEFF 724 724 13
5 HMWY M345 5,414 5,414 14
5 JBSN BORA 82 82 15
5 JBSN BRDY 24 21 16
5 JBSN ENPR 67 6 17
5 JBSN HMWY 173 171 18
5 JBSN LAGRANDE 842 841 19
5 JBSN M345 14 1 20
5 JBWT LAGRANDE 35 3 21
5 JEFF BORA 3,845 3,84 22
5 JEFF BORA 24 21 23
5 JEFF BPAT.NWMT 37 31 24
5 JEFF BRDY 9,819 9,81 25
5 JEFF BRDY 272 27 26
5 JEFF HMWY 351 3511 27
5 JEFF JBSN 45 41 28
5 JEFF LAGRANDE 48 41 29
5 JEFF M345 79 71 30
5 LAGRANDE BORA 92,482 92,482 31
5 LAGRANDE BORA 1,201 1,201 32
5 LAGRANDE BRDY 54,739 54,739 33
5 LAGRANDE BRDY 17,297 17,297 34
01 6,075,1201 6,075,121
FERC FORM NO. 1 (ED. 12-90) Page 329.1
Name of Respondent
Idaho Power Company
I This RM
A
ort Is I (1) An Original
1(2) Resubmission
I Date of Report I (Mo, Da, Yr)
04/15/2013
Year/Period of Report
n d f 2012/04
TRANSMISIONP ELECTRICITY FOR OTHEkS (Account 456.1)
(Including transactions referred to as 'wheeling')
1.Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2.Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3.Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4.In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - tong-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line
N
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
1 BC Hydro Powerex Bonneville Power Administration Sierra Pacific Power NF
2 BC Hydro Powerex Bonneville Power Administration Sierra Pacific Power SFP
3 BC Hydro Powerex Avista Padfiorp East NF
4 BC Hydro Powerex Avista PacifiCorp East SFP
5 BC Hydro Powerex Avista PaciflCorp East NF
6 BC Hydro Powerex Avista PadflCorp East SFP
7 BC Hydro Powerex Avista Sierra Pacific Power NF
8 BC Hydro Powerex Avista Sierra Pacific Power SFP
9 BC Hydro Powerex Sierra Pacific Power PaciflCorp East NF
10 BC Hydro Powerex Sierra Pacific Power North Westem/PacifiCorp East NF
11 BC Hydro Powerex Sierra Pacific Power PaciflCorp East NF
12 BC Hydro Powerex Sierra Pacific Power Bonneville Power Administration NF
13 Bonneville Power Administration PaciflCorp East Bonneville Power Administration NF
14 Bonneville Power Administration North Westem/PaciflCorp East PacifiCorp East NF
15 Bonneville Power Administration North Westem/PaciflCorp East Bonneville Power Administration NF
16 Bonneville Power Administration PaciflCorp East Bonneville Power Administration NF
17 Bonneville Power Administration PaciflCorp West Bonneville Power Administration NF
18 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration NF
19 Bonneville Power Administration Bonneville Power Administration Sierra Pacific Power NF
20 Bonneville Power Administration Avista Bonneville Power Administration NF
21 Bonneville Power Administration Avista Bonneville Power Administration SFP
22 Bonneville Power Administration Avista Sierra Pacific Power NF
23 Bonneville Power Administration Avista Bonneville Power Administration NF
24 Cargill-Alliant North Westem/PaciflCorp East Sierra Pacific Power NF
25 Cargill-Alliant North Westem/PaciflCorp East Sierra Pacific Power SFP
26 Cargill-Alliant PaciflCorp East North Westem/PaciflCorp East NF
27 Cargill-Alliant PaciflCorp East North Westem/PaciflCorp East NF
28 Cargill-Alliant PaciflCorp East PaciflCorp East SFP
29 Cargill-Alliant PaciflCorp East PaciflCorp West NF
30 Cargill-Alliant PacifiCorp East Bonneville Power Administration NF
31 Cargill-Alliant PaciflCorp East Sierra Pacific Power NF
32 Cargill-Alliant PaciflCorp East Sierra Pacific Power SFP
33 Cargill-Alliant NorthWestem/PaciflCorp East PacifiCorp East NF
34 Cargill-Pdliant NorthWestern/PaciflCorp East PacifiCorp East SFP
TOTAL
FERC FORM NO. 1 (ED. 12-90) Page 328.2
Name of Respondent
Idaho Power Company
This Re ort Is:
AR5iJbfflission
Date of Report
04/15/2013
Year/Period of Report
End of 20121Q4
TRANSMISSION OF ELEtTRICITY FOR OTHERS (Account 456)(Continued)
(Including transactions reffered to as 'wheeling')
5.In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6.Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7.Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8.Report in column (i) and (j) the total megawatthours received and delivered.
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(0
Point of Delivery
(Substation or Other
Designation)
(g)
Billing
Demand
(MW)
(h)
TRANSFER OF ENERGY Line
No. Megawatt Hours
Received (I)
Megawatt Hours
Delivered a)
5 LAGRANDE M345 9,467 9,467 I
5 ILAGRANDE M345 1,296 1,291 2
5 LOLO BORA 8,133 8,13: 3
5 LOLO BORA 11,134 11,13 4
5 LOLO BRDY 1,886 1,881 5
5 LOLO BRDY 2,059 2,051 6
5 LOLO M345 1,999 1,991 7
5 LOLO M345 586 586 8
5 M345 BORA 155 155 9
5 M345 BPAT.NWMT 701 701 10
5 M345 BRDY 61 61 11
5 M345 LAGRANDE 1,067 1,0671 12
5 BORA LAGRANDE 306 301 13
5 BPAT.NWMT BRDY 717 71 14
5 BPAT.NWMT LAGRANDE 546 541 15
5 BRDY LAGRANDE 717 71 16
5 ENPR LAGRANDE 300 301 17
5 LAGRANDE LAGRANDE 2,334 2,33 18
5 LAGRANDE M345 8,144 8,14A 19
5 LOLO LAGRANDE 3,509 3,50 20
5 LOLO LAGRANDE 720 729 21
5 LOLO M345 1,756 1,751 22
5 LOLO OTEC 1 11 23
5 AVAT.NWMT M345 70 7' 24
5 AVAT.NWMT M345 72 7: 25
5 BORA AVAT.NWMT 459 451 26
5 BORA BPAT.NWMT 150 151 27
5 BORA BRDY 800 801 28
5 BORA ENPR 3,884 3,88 29
5 BORA LAGRANDE 1,776 1,771 30
5 BORA M345 4,232 4,23 31
5 BORA M345 1,448 1,44 32
5 BPAT.NWMT BORA 1,468 1,46 33
5 BPAT.NWMT BORA 8,827 8,82 34
0 6,075,120 6,075,12
FERC FORM NO. I (ED. 12-90) Page 329.2
Name of Respondent
Idaho Power Company
I This Re ort Is
1) An Original
(2) n A Resubmission
I Date of Report L Year/Period of Report
End of 2012/Q4
TRANSMISSION EC ELTRICITY FOR OTRE S(Account 456.1) (including transactions referred to as 'wheeling')
1.Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2.Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3.Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4.In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line
N°.
-
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
1 Cargill-Alliant North Western/PaciflCorp East PaciflCorp East NF
2 Cargill-Alliant NorthWestem/PaciflCorp East Bonneville Power Administration NF
3 Cargill-Alliant NorthWestem/PaciflCorp East Sierra Pacific Power NF
4 Cargill-Alliant North Westem/PaciflCorp East Sierra Pacific Power SFP
5 Cargill-Alliant PaciflCorp East NorthWestern/PadfiCorp East NF
6 Cargill-Alliant PaciflCorp East PacifiCorp East NF
7 Cargill-Alliant PaciflCorp East North Western/PacifiCorp East NF
8 Cargill-Auiant PaciflCorp East Bonneville Power Administration NF
9 Cargill-Alliant PaciflCorp East Sierra Pacific Power NF
10 Cargill-Alliant PaciflCorp East Sierra Pacific Power SFP
11 Cargill-Alliant PaciflCorp West PaciflCorp East NF
12 Cargill-Alliant PaaflCorp West PaciflCorp East SFP
13 Cargill-Alliant PaciflCorp West Sierra Pacific Power NF
14 Cargill-Alliant PaciflCorp West Sierra Pacific Power SFP
15 Cargill-Alliant Idaho Power Company PaciflCorp East NF
16 Cargill-Alliant Idaho Power Company PacifiCorp East SFP
17 Cargill-Alliant Idaho Power Company Sierra Pacific Power NF
18 Cargill-Alliant PaciflCorp West Sierra Pacific Power NF
19 Cargill-Alliant PaciflCorp West Sierra Pacific Power SFP
20 Cargill-Alliant North Westem/PaciflCorp East PacifiCorp East NF
21 Cargill-Alliant North Westem/PaciflCorp East PacifiCorp East NF
22 Cargill-Alliant North Westem/PaciflCorp East Sierra Pacific Power NF
23 Cargill-Alliant Bonneville Power Administration PaciflCorp East NF
24 Cargill-Alliant Bonneville Power Administration PaciflCorp East SFP
25 Cargill-Alliant Bonneville Power Administration PacifiCorp East NF
26 Cargill-Alliant Bonneville Power Administration PacifiCorp West NF
27 Cargill-Alliant Bonneville Power Administration Sierra Pacific Power NF
28 Cargill-Alliant Bonneville Power Administration Sierra Pacific Power SFP
29 Cargill-Alliant Avista PadflCorp East NF
30 Cargill-Alliant Avista PaciflCorp East SFP
31 Cargill-Alliant Avista PaciflCorp East NF
32 Cargill-Alliant Avista Sierra Pacific Power NF
33 Cargill-Alliant Avista Sierra Pacific Power SFP
34 Cargill-Alliant Sierra Pacific Power PaciflCorp East NF
TOTAL
FERC FORM NO. 1 (ED. 12-90) Page 328.3
Name of Respondent
Idaho Power Company
This Re ort Is
gAResubmission
Date of Report
04/15/2013
Year/Period of Report
End of 2012/Q4
TRANSMISSION OF ELEtTRICITY FOR OTHERS (Account 45eXContinued) (Including transactions reffered to as 'wheeling')
5.In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6.Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7.Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8.Report in column (i) and (j) the total megawatthours received and delivered.
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(f)
Point of Delivery
(Substation or Other
Designation)
(g)
Billing
Demand
(MW)
TRANSFER OF ENERGY Line
No.
(h)
MegaWatt Hours
Received
MegaWatt Hours
Delivered
5 BPAT.NWMT BRDY 60 6C 1
5 IBPAT.NWIVIT LAGRANDE 109 101 2
5 BPAT.NWMT M345 8,109 8,101 3
5 BPAT.NWMT M345 16,361 16,3611 4
5 BRDY AVAT.NWMT 200 201 5
5 BRDY BORA 544 54 6
5 BRDY BPAT.NWMT 25 2 7
5 BRDY LAGRANDE 383 38: 8
5 BRDY M345 16,036 16,031 9
5 BRDY M345 3,756 3,751 10
5 ENPR BORA 55,633 55,63: 11
5 ENPR BORA 26,345 26,34 12
5 ENPR M345 100 101 13
5 ENPR M345 400 401 14
5 HCPR BORA 1,096 1,091 15
5 HCPR BORA 216 211 16
5 HCPR M345 960 96q 17
5 JBSN M345 1,220 1,220 18
5 JBSN M345 4,104 4,104 19
5 JEFF BORA 107 107 20
5 JEFF BRDY 671 671 21
5 JEFF M345 10,766 10,76q 22
5 LAGRANDE BORA 7,587 7,58 23
5 LAGRANDE BORA 1,021 1,0211 24
5 LAGRANDE BRDY 1,114 1,111 25
5 LAGRANDE JBSN 10 1 26
5 LAGRANDE M345 8,084 8,08 27
5 LAGRANDE M345 736 731 28
5 LOLO BORA 13,689 13,68 29
5 LOLO BORA 11,490 11,49 30
5 LOLO BRDY 1,542 1,54 31
5 LOLO M345 52,221 52,221 32
5 LOLO M345 16,981 16,981 33
5 LYPK BORA 9,558 9,551 34
0 6,075,1201 6,075,121
FERC FORM NO. 1 (ED. 12-90) Page 329.3
Name of Respondent
Idaho Power Company
This RM
A
oil Is:
Resubmission
I Date of Report L 04n5/2013
Year/Period of Report
End of 2012/04
TRANSMISSION ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as 'wheeling')
1.Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2.Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3.Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4.In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLE - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line
N
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
I Cargill-Alliant Sierra Pacific Power PacifiCorp East SFP
2 Cargill-Alliant Sierra Pacific Power North Westem/PacifiCorp East NF
3 Cargill-Alliant Sierra Pacific Power PacifiCorp East NF
4 Cargill-Pjliant Sierra Pacific Power PaciflCorp East SFP
5 Cargill-Alliant Sierra Pacific Power PacifiCorp West NF
6 1 Cargill-Alliant Sierra Pacific Power PaciflCorp West SEP
7 Cargill-Alliant Sierra Pacific Power NorthWestem/PacifiCorp East NF
8 Cargill-Alliant Sierra Pacific Power North WestemlPacifiCorp East SEP
9 Cargill-Alliant Sierra Pacific Power Bonneville Power Administration NF
10 Cargill-Alliant Sierra Pacific Power Bonneville Power Administration SEP
11 Cargill-Alliant Sierra Pacific Power Bonneville Power Administration LFP
12 Cargill-Alliant Sierra Pacific Power Sierra Pacific Power NF
13 Cargill-Alliant Sierra Pacific Power Sierra Pacific Power SEP
14 Cargill-Alliant Sierra Pacific Power NorthWestem/PacifiCorp East NE
15 Cargill-Alliant Sierra Pacific Power PacifiCorp East NE
16 Cargill-Alliant Sierra Pacific Power NorthWestem/PacifiCorp East NF
17 Cargill-Alliant Idaho Power Company PacifiCorp East NF
18 Cargill-Alliant Idaho Power Company North Westem/PacifiCorp East NE
19 Cargill-Alliant Idaho Power Company Sierra Pacific Power NE
20 Cargill-Alliant Idaho Power Company Sierra Pacific Power SEP
21 Citigroup Energy NE
22 Eagle Energy Partners PacifiCorp West PaciflCorp East NE
23 Eagle Energy Partners Bonneville Power Administration PaciflCorp East NE
24 lberdrola Energy PacifiCorp East Idaho Power Company NE
25 lberdrola Energy PacifiCorp East Bonneville Power Administration NE
26 Iberdrola Energy PaclflCorp East Bonneville Power Administration NE
27 lberdrola Energy PacifiCorp East Sierra Pacific Power NE
28 lberdrola Energy Idaho Power Company PaciflCorp East NE
29 lberdrola Energy Idaho Power Company PacifiCorp East NE
30 lberdrola Energy Idaho Power Company Sierra Pacific Power NE
31 lberdrola Energy Bonneville Power Administration PacifiCorp East NF
32 lberdrola Energy Bonneville Power Administration PacifiCorp East NE
33 lberdrola Energy Bonneville Power Administration Sierra Pacific Power NE
34 lberdrola Energy Avista PaciflCorp East NE
TOTAL
FERC FORM NO. 1 (ED. 12-90) Page 328.4
Name of Respondent
Idaho Power Company
This Re ort Is:
(2) AResubmission
Date of Report
04/15/2013
Year/Period of Report
End of 2012/Q4
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued) (Including transactions reffered to as 'wheeling')
5.In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6.Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7.Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8.Report in column (i) and (j) the total megawatthours received and delivered.
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(0
Point of Delivery
(Substation or Other
Designation)
(g)
Billing
Demand
(MW)
TRANSFER OF ENERGY Line
No.
(h)
Megawatt Hours
Received
MegaWatt Hours
Delivered
5 LYPK BORA 63,560 63,56C 1
5 LYPK BPAT.NWMT 525 521 2
5 LYPK BRDY 269 261 3
5 LYPK BRDY 303 301 4
5 LYPI< JBSN 150 151 5
5 LYPK JBSN 169 161 6
5 LYPK JEFF 255 251 7
5 LYPK JEFF 4,557 4,557 8
5 LYPK LAGRANDE 2,495 2,495 9
5 LYPK LAGRANDE 51 51 10
5 LYPK LAGRANDE 6,995 6,995 11
5 LYPK M345 20,441 20,441 12
5 LYPK M345 261,496 261,49q 13
5 M345 AVAT.NWMT 15 II 14
5 M345 BRDY 239 231 15
5 M345 JEFF 44 4 16
5 OBBLPR BORA 231 231 17
5 OBBLPR BPAT.NWMT 82 8 18
5 OBBLPR M345 1,024 1,02 19
5 OBBLPR M345 608 601 20
5 1 21
5 ENPR BORA 1,767 1,76 22
5 LAGRANDE BORA 107 10 23
5 BORA HMWY 45 41 24
5 BORA LAGRANDE 310 31 25
5 BRDY LAGRANDE 155 151 26
5 BRDY M345 173 171 27
5 HMWY BORA 4,255 4,251 28
5 HMWY BRDY 941 941 29
5 HMWY M345 6,148 6,141 30
5 LAGRANDE BORA 3,912 3,911 31
5 LAGRANDE BRDY 63 61 32
5 LAGRANDE M345 3,934 3,934 33
5 LOLO BORA 29 21 34
0 6,075,1201 6,075,12
FERC FORM NO. I (ED. 12-90) Page 329.4
Name of Respondent
Idaho Power Company
I This Re ort Is:
I (1) X An Original

(2) n A Resubmission
I Date of Report
I (Mo, Da, Yr) t 04/15/2013
Year/Period of Report
nu of 2012/04
TRANSMISSION OF ELECTRICITY FOR OTHE1S (Account 456.1) (Including transactions referred to as wheeling')
1.Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2.Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3.Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4.In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line
N 0.
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
I Iberdrola Energy Avista Sierra Pacific Power NE
2 lberdrola Energy Sierra Pacific Power PacifiCorp East NF
3 lberdrola Energy Sierra Pacific Power Bonneville Power Administration NE
4 Morgan Stanley Capital Group North Westem/PacifiCorp East PacifiCorp East NE
5 Morgan Stanley Capital Group North Westem/PacifiCorp East Bonneville Power Administration NE
6 Morgan Stanley Capital Group North Westem/PacifiCorp East Sierra Pacific Power NE
7 Morgan Stanley Capital Group PacifiCorp East PacifiCorp East NF
8 Morgan Stanley Capital Group PaciflCorp East Bonneville Power Administration NE
9 Morgan Stanley Capital Group PacifiCorp East Sierra Pacific Power NE
10 Morgan Stanley Capital Group North Westem/PaciflCorp East PacifiCorp East NE
11 Morgan Stanley Capital Group North Westem/PaciflCorp East PacifiCorp East NE
12 Morgan Stanley Capital Group North Westem/PacifiCorp East Bonneville Power Administration NF
13 Morgan Stanley Capital Group North Westem/PacifiCorp East Sierra Pacific Power NE
14 Morgan Stanley Capital Group PaciflCorp East North Western/PaciflCorp East NE
15 Morgan Stanley Capital Group PacifiCorp East PacifiCorp East NE
16 Morgan Stanley Capital Group PacifiCorp East PacifiCorp East SFP
17 Morgan Stanley Capital Group PaciflCorp East North Western/PacifiCorp East NE
18 Morgan Stanley Capital Group PacifiCorp East Bonneville Power Administration NE
19 Morgan Stanley Capital Group PaafiCorp East Sierra Pacific Power NE
20 Morgan Stanley Capital Group PacifiCorp West PacifiCorp East NE
21 Morgan Stanley Capital Group PacifiCorp West PacifiCorp West NF
22 Morgan Stanley Capital Group North Western/PacifiCorp East NorthWestem/PadfiCorp East NE
23 Morgan Stanley Capital Group Idaho Power Company PacifiCorp East NE
24 Morgan Stanley Capital Group Idaho Power Company PacifiCorp East NE
25 Morgan Stanley Capital Group Idaho Power Company Sierra Pacific Power NE
26 Morgan Stanley Capital Group PacifiCorp West PaciflCorp East NE
27 Morgan Stanley Capital Group PacifiCorp West PacifiCorp East NE
28 Morgan Stanley Capital Group PaciflCorp West Sierra Pacific Power NE
29 Morgan Stanley Capital Group NorthWestem/PacifiCorp East PacifiCorp East NF
30 Morgan Stanley Capital Group North Western/PacifiCorp East PacifiCorp East SEP
31 Morgan Stanley Capital Group North Westem/PacifiCorp East PacifiCorp East NF
32 Morgan Stanley Capital Group North Western/PacifiCorp East Bonneville Power Administration NE
33 Morgan Stanley Capital Group North Western/PacifiCorp East Sierra Pacific Power NE
34 Morgan Stanley Capital Group North Westem/PaciflCorp East Sierra Pacific Power SFP
TOTAL
FERC FORM NO. I (ED. 12-90) Page 328.5
Name of Respondent
Idaho Power Company
This Re ort Is
2nRsi on
Date of Report
04/15/2013
Year/Period of Report
End of 2012/04
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 4s6XContinued) (Including transactions reffered to as 'wheeling')
5.In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6.Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7.Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8.Report in column (i) and (j) the total megawatthours received and delivered.
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(0
Point of Delivery
(Substation or Other
Designation)
(g)
Billing
Demand
(MW)
TRANSFER OF ENERGY Line
No.
(h)
MegaWatt Hours
Received
MegaWatt Hours
Delivered
5 LOLO M345 145 145 1
5 IM345 BORA 50 59 2
5 M345 LAGRANDE 842 84A 3
5 AVAT.NWMT BRDY 146 14 4
5 AVAT.NWMT LAGRANDE 6 1 5
5 AVAT.NWMT M345 236 231 6
5 BORA BRDY 292 29A 7
5 BORA LAGRANDE 5 1 8
5 BORA M345 463 461 9
5 BPAT.NWMT BORA 251 251 10
5 BPAT.NWMT BRDY 45 4! 11
5 BPAT.NWMT LAGRANDE 206 201 12
5 BPAT.NWMT M345 1,301 1,301 13
5 BRDY AVAT.NWMT 35 31 14
5 BRDY BORA 2,628 2,621 15
5 BRDV BORA 4,560 4,56( 16
5 BRDY BPAT.NWMT 27 27 17
5 BRDY LAGRANDE 12,846 12,841 18
5 BRDY M345 7,507 7,507 19
5 ENPR BORA 131 131 20
5 ENPR JBSN 437 431 21
5 GSHN BPAT.NWMT 50 51 22
5 HMWY BORA 143 14 23
5 HMWY BRDY 45 4! 24
5 HMWY M345 1,843 1,84 25
5 JBSN BORA 4,204 4,20 26
5 JBSN BRDY 656 651 27
5 JBSN M345 200 201 28
5 JEFF BORA 17,863 17,86 29
5 JEFF BORA 795 79 30
5 JEFF BRDY 633 63 31
5 JEFF LAGRANDE 4,509 4,501 32
5 JEFF M345 12,949 12,941 33
5 JEFF M345 926 921 34
0 6,075,120 6,075,121
FERC FORM NO. I (ED. 12-90) Page 329.5
Name of Respondent
Idaho ower Company 0 o pa y
I This Re ort Is:

(1) X An Original
I (2) Q Resubmission
I Date of Report
(Mo, Da, Yr)
I 04/15/2013
Year/Period of Report
End of 2012/Q4
TRANSMISION ELECTRICITY FOR OTHEkS (Account 456.1)
(Including transactions referred to as 'wheeling')
1.Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2.Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3.Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4.In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line
N
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
1 Morgan Stanley Capital Group Bonneville Power Administration Paciflorp East NF
2 Morgan Stanley Capital Group Bonneville Power Administration PacifiCorp East NF
3 Morgan Stanley Capital Group Bonneville Power Administration PaciflCorp West NF
4 Morgan Stanley Capital Group Bonneville Power Administration Sierra Pacific Power NF
5 Morgan Stanley Capital Group Avista PacifiCorp East NF
6 1 Morgan Stanley Capital Group Avista PacifiCorp East NF
7 Morgan Stanley Capital Group Avista PadfiCorp West NF
8 Morgan Stanley Capital Group Avista Sierra Pacific Power NF
9 Morgan Stanley Capital Group Sierra Pacific Power North Westem/PacifiCorp East NF
10 Morgan Stanley Capital Group Sierra Pacific Power NorthWestem/PacifiCorp East NF
11 Morgan Stanley Capital Group Sierra Pacific Power NorthWesternlPacifiCorp East NF
12 Morgan Stanley Capital Group Sierra Pacific Power Bonneville Power Administration NF
13 Pacificorp Power Marketing PacifiCorp East PacifiCorp West NF
14 Pacificorp Power Marketing PacifiCorp East Idaho Power Company LFP
15 Pacificorp Power Marketing PacifiCorp East Bonneville Power Administration NF
16 Pacificorp Power Marketing PacifiCorp East Sierra Pacific Power SFP
17 Pacificorp Power Marketing PacifiCorp East PacifiCorp East SFP
18 Pacificorp Power Marketing PacifiCorp East PacifiCorp East NF
19 Pacificorp Power Marketing PacifiCorp West PacifiCorp East NP
20 Pacificorp Power Marketing PacifiCorp West Bonneville Power Administration NF
21 Pacificorp Power Marketing PacifiCorp West Sierra Pacific Power NF
22 Pacificorp Power Marketing Idaho Power Company PacifiCorp East LFP
23 Pacificorp Power Marketing Idaho Power Company PacifiCorp West NP
24 Pacificorp Power Marketing Idaho Power Company Idaho Power Company LFP
25 Pacificorp Power Marketing Idaho Power Company Bonneville Power Administration NP
26 Pacificorp Power Marketing Idaho Power Company PacifiCorp West LFP
27 Pacificorp Power Marketing Bonneville Power Administration PacifiCorp East NP
28 Pacificorp Power Marketing Bonneville Power Administration PacifiCorp East SPP
29 Pacificorp Power Marketing Avista PacifiCorp East NP
30 Paciflcorp Power Marketing Avista PacifiCorp West NP
31 Portland General Electric PacifiCorp East Bonneville Power Administration NP
32 Portland General Electric North Western/PacifiCorp East Bonneville Power Administration NP
33 Portland General Electric Sierra Pacific Power Bonneville Power Administration NP
34 PPL Energy Plus PacifiCorp East Bonneville Power Administration NF
TOTAL
FERC FORM NO. 1 (ED. 12-90) Page 328.6
Name of Respondent
Idaho Power Company
This Re ott Is
(2) UAResubmission
Date of Report
04/15/2013
Year/Period of Report
End of 2012/Q4
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
(Including transactions reffered to as 'wheeling')
5.In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6.Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7.Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8.Report in column (i) and (j) the total megawatthours received and delivered.
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(f)
Point of Delivery
(Substation or Other
Designation)
(g)
Billing
Demand
(MW)
(h)
TRANSFER OF ENERGY Line
No. MegaWatt Hours
Received
(i)
aWatt Hours
Delivered
5 LAGRANDE BORA 342 342 I
5 LAGRANDE BRDY 2,355 2,35q 2
5 LAGRANDE JBSN 1,257 1,25: 3
5 LAGRANDE M345 3,412 3,41A 4
5 LOLO BORA 66 6 5
5 LOLO BRDY 15 11 6
5 LOLO JBSN 2
5 LOLO M345 375 371 8
5 M345 AVAT.NWMT 75 71 9
5 M345 BPAT.NWMT 204 201 10
5 M345 JEFF 33 3 11
5 M345 LAGRANDE 315 315 12
5 BORA ENPR 2,290 2,290 13
5 BORA KPRT 643,617 643,617 14
5 BORA LAGRANDE 794 794 15
5 BORA M345 1,921 1,921 16
5 BRDY BORA 1,939 1,931 17
5 BRDY BRDY 3,895 3,891 18
5 ENPR BORA 98,299 98,291 19
5 ENPR LAGRANDE 241 241 20
5 ENPR M345 556 55 21
5 JBWT BRDY 398,590 398,591 22
5 JBWT ENPR 11,242 11,24: 23
5 JBWT HMWY 347,275 347,27 24
5 JBWT LAGRANDE 12,820 12,82' 25
5 JBWT M500 272,299 272,291 26
5 LAGRANDE BORA 29,588 29,581 27
5 LAGRANDE BORA 6,262 6,26 28
5 LOLO BORA 33,621 33,621 29
5 LOLO ENPR 201 201 30
5 BORA LAGRANDE 50 5 31
5 JEFF LAGRANDE 105 10q 32
5 M345 LAGRANDE 50 5( 33
5 BRDY LAGRANDE 968 96 34
0 6,075,120 6,075,121
FERC FORM NO. I (ED. 12-90) Page 329.6
Name of Respondent
Idaho Power Company
I This Report Is:
AResubmission
I Date of Report L 04/15/2013
Year/Period of Report
End of 2012/04
TRANSMISSION ELECTRICITY FOR OTI-IE S (Account 456.1) (including transactions referred to as 'wheeling')
1.Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2.Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3.Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4.In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SEP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line
N0.
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
I PPL Energy Plus North WestemlPacifiCorp East PaciflCorp East NF
2 PPL Energy Plus North Western/PacifiCorp East Bonneville Power Administration NF
3 PPL Energy Plus Avista Paciflorp East NF
4 PPL Energy Plus Avista PacifiCorp West NF
5 Puget Sound Energy Bonneville Power Administration Sierra Pacific Power NF
6 Rainbow Energy Marketing North Westem/PacifiCorp East PadfiCorp East NF
7 Rainbow Energy Marketing PacifiCorp East Sierra Pacific Power NF
8 Rainbow Energy Marketing NorthWestem/PacifiCorp East PacifiCorp East NF
9 Rainbow Energy Marketing North Westem/PadfiCorp East PacifiCorp East SFP
10 Rainbow Energy Marketing PacifiCorp West PacifiCorp East NF
11 Rainbow Energy Marketing PaciflCorp West PacifiCorp East SFP
12 Rainbow Energy Marketing PacifiCorp West PacifiCorp East NF
13 Rainbow Energy Marketing PacifiCorp West North Westem/PacifiCorp East SFP
14 Rainbow Energy Marketing North Western/PadfiCorp East PacifiCorp East NF
15 Rainbow Energy Marketing North Western/PacifiCorp East PacifiCorp East NF
16 Rainbow Energy Marketing Avista PacifiCorp East NF
17 Rainbow Energy Marketing Avista PaciflCorp East SFP
18 Rainbow Energy Marketing Avista Sierra Pacific Power NF
19 Rainbow Energy Marketing Avista Sierra Pacific Power SFP
20 Shell Energy PacifiCorp East Bonneville Power Administration NF
21 Shell Energy PacifiCorp East Sierra Pacific Power NF
22 Shell Energy Idaho Power Company PacifiCorp East NF
23 Shell Energy Idaho Power Company Sierra Pacific Power NF
24 Shell Energy North Westem/PacifiCorp East Bonneville Power Administration NF
25 Shell Energy North Westem/PacifiCorp East Sierra Pacific Power NF
26 Shell Energy Bonneville Power Administration PaciflCorp East NF
27 Shell Energy Bonneville Power Administration Sierra Pacific Power NF
28 Shell Energy Bonneville Power Administration Sierra Pacific Power SFP
29 Shell Energy Avista Sierra Pacific Power NF
30 Shell Energy Sierra Pacific Power PacifiCorp East NF
31 Shell Energy Sierra Pacific Power Bonneville Power Administration NE
32 1 Shell Energy Sierra Pacific Power PacifiCorp East NF
33 Shell Energy Sierra Pacific Power Bonneville Power Administration NF
34 Shell Energy Idaho Power Company Bonneville Power Administration NF
TOTAL
FERC FORM NO. I (ED. 12-90) Page 328.7
Name of Respondent
Idaho Power Company
This RM
A
ott Is:
Resubmission
Date of Report
04/15/2013
Year/Period of Report
End of 2012/Q4
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456XContinued) (Including transactions reffered to as 'wheeling')
5.In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6.Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7.Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8.Report in column (i) and (j) the total megawatthours received and delivered.
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(f)
Point of Delivery
(Substation or Other
Designation)
(g)
Billing
Demand
(MW)
TRANSFER OF ENERGY Line
No.
(h)
MegaWatt Hours
Received
MegaWatt Hours Delivered
5 JEFF BRDY 211 211 1
5 IJEFF LAGRANDE 3,844 3,84 2
5 LOLO BROY 180 18 3
5 LOLO JBSN 280 28 4
5 LAGRANDE M345 210 2V 5
5 AVAT.NWMT BORA 301 301 6
5 BORA M345 1,515 1,51: 7
5 BPAT.NWMT BORA 553 553 8
5 BPAT.NWMT BORA 9,381 9,381 9
5 JBSN BORA 28 28 10
5 JBSN BORA 2,114 2,114 11
5 JBSN BRDY 61 61 12
5 JBSN JEFF 685 681 13
5 JEFF BORA 969 961 14
5 JEFF BRDY 21 211 15
5 LOLO BORA 46,623 46,62 16
5 LOLO BORA 19,117 19,111 17
5 LOLO M345 940 94 18
5 LOLO M345 2,527 2,527 19
5 BRDY LAGRANDE 2,723 2,723 20
5 BRDY M345 4,041 4,041 21
5 HMWY BROY 241 241 22
5 HMWY M345 4,551 4,551 23
5 JEFF LAGRANDE 544 54 24
5 JEFF M345 1,224 1,221 25
5 LAGRANDE BRDY 392 39A 26
5 LAGRANDE M345 5,417 5,41 27
5 LAGRANDE M345 2,686 2,681 28
5 LOLO M345 6 29
5 LYPK BRDY 100 101 30
5 LYPK LAGRANDE 73 7 31
5 M345 BRDY 279 27t 32
5 M345 LAGRANDE 3,602 3,60 33
5 MDSK LAGRANDE 442 444 34
0 6,075,1201 6,075,124
FERC FORM NO. I (ED. 12-90) Page 329.7
Name of Respondent
Idaho Power Company I'
I This Re ort Is: 1(1 ) X An Original
I (2) A Resubmission
I Date of Report
(Mo, Da, Yr)
j 04/15/2013
Year/Period of Report
End of 2012/Q4
TRANSMISION ELECTRICITY FOR OTHEkS (Account 456.1) (Including transactions referred to as 'wheeling')
1.Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2.Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3.Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4.In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line
No
-
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
1 Shell Energy Idaho Power Company Bonneville Power Administration NF
2 Sierra Pacific Power Marketing PaciflCorp East Sierra Pacific Power NF
3 Sierra Pacific Power Marketing PaciflCorp East Sierra Pacific Power NF
4 Sierra Pacific Power Marketing PacitlCorp East Sierra Pacific Power SFP
5 Sierra Pacific Power Marketing Idaho Power Company Sierra Pacific Power NF
6 Sierra Pacific Power Marketing PacifiCorp West Sierra Pacific Power NF
7 Sierra Pacific Power Marketing North Westem/PacifiCorp East Sierra Pacific Power NF
8 Sierra Pacific Power Marketing Bonneville Power Administration Sierra Pacific Power NF
9 Sierra Pacific Power Marketing Avista Sierra Pacific Power NF
10 Sierra Pacific Power Marketing Sierra Pacific Power PaciflCorp East NF
11 Sierra Pacific Power Marketing Sierra Pacific Power PacifiCorp East NF
12 Sierra Pacific Power Marketing Sierra Pacific Power Bonneville Power Administration NF
13 Tenaska Bonneville Power Administration PacifiCorp East NF
14 The Energy Authority Idaho Power Company PaciflCorp East NF
15 The Energy Authority Bonneville Power Administration PacifiCorp East NF
16 The Energy Authority Bonneville Power Administration PaciflCorp East NF
17 Transalta Energy Marketing PaciflCorp East Bonneville Power Administration NF
18 Transalta Energy Marketing PacifiCorp East Sierra Pacific Power NF
19 Transalta Energy Marketing North Westem/PacifiCorp East PacifiCorp East NF
20 Transalta Energy Marketing North Westem/PacifiCorp East PacifiCorp East NF
21 Transalta Energy Marketing North Westem/PacifiCorp East Sierra Pacific Power NF
22 Transalta Energy Marketing PacifiCorp East PacifiCorp East NF
23 Transalta Energy Marketing North Westem/PacifiCorp East Bonneville Power Administration NF
24 Transalta Energy Marketing Bonneville Power Administration PacifiCorp East NF
25 Transalta Energy Marketing Bonneville Power Administration Avista NF
26 Transalta Energy Marketing Bonneville Power Administration Sierra Pacific Power NF
27 Transalta Energy Marketing Avista PacifiCorp East NF
28 Transalta Energy Marketing Avista Sierra Pacific Power NF
29 Transalta Energy Marketing Sierra Pacific Power PacifiCorp East NF
30 Transalta Energy Marketing Sierra Pacific Power Bonneville Power Administration NF
31 lTransalta Energy Marketing Idaho Power Company PacifiCorp East NF
32 Utah Associated Municipal Power PacifiCorp East Sierra Pacific Power NF
33
34
TOTAL
FERC FORM NO. I (ED. 12-90) Page 328.8
Name of Respondent
Idaho Power Company
This Re ort Is:
A Resubmission
Date of Report
04/15/2013
Year/Period of Report
End of 20121Q4
TRANSMISSION OF ELECTRICrrY FOR OTHERS (Account 4s6XGontinued)
(Including transactions reffered to as 'wheeling')
5.In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6.Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7.Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8.Report in column (i) and (j) the total megawatthours received and delivered.
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(0
Point of Delivery
(Substation or Other
Designation)
(g)
Billing
Demand
(MW)
(h)
TRANSFER OF ENERGY Line
No. Ma Waft Hours
Received (I)
MegaWatt Hours
Delivered
(I)
5 MNHM LAGRANDE 16 le I
5 IBORA M345 2,085 2,08q 2
5 BRDY M345 36,131 36,131 3
5 BRDY M345 4,920 4,921 4
5 HMWY M345 3,346 3,341 5
5 JBSN M345 905 90 6
5 JEFF M345 28,490 28,48 7
5 LAGRANDE M345 4,201 4,201 8
5 LOLO M345 19,793 19,79: 9
5 M345 BORA 50 51 10
5 M345 BRDY 215 21 11
5 M345 LAGRANDE 425 42q 12
5 LAGRANDE BORA 97 9A 13
5 HMWY BORA 290 291 14
5 LAGRANDE BORA 801 801 15
5 LAGRANDE BRDY 24 24 16
5 BORA LAGRANDE 767 767 17
5 BORA M345 97 97 18
5 BPAT.NWMT BORA 15 iq 19
5 BPAT.NWMT BRDY 74 71 20
5 BPAT.NWMT M345 8 1 21
5 BRDY BORA 43 4: 22
5 GSHN LAGRANDE 180 181 23
5 LAGRANDE BORA 6,335 6,331 24
5 LAGRANDE LOLO 85 8 25
5 LAGRANDE M345 964 96 26
5 LOLO BORA 85 8 27
5 LOLO M345 16 11 28
5 M345 BORA 12 1, 29
5 M345 LAGRANDE 267 267 30
5 OBBLPR BORA 84 84 31
5 BORA M345 8,833 8,833 32
33
34
0 6,075,120 6,075,12
FERC FORM NO. I (ED. 12-90) Page 329.8
Name of Respondent
Idaho Power Company
This RM
A
ort Is
(2)Resubmission
Date of Report
04/15/2013
Year/Period of Report
End of 2012/04
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)
(Including transactions reffered to as 'wheeling')
9.In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10.The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11.Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(I)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
1JiS
No.
1,110,520 135,121 1,245,641 1
1,398,847 156,231 1,555,078 2
4,182,97 315,408 4,498,385 3
16,400 16,400 4
331,490 331,490 5
6,841 1,246 8,087 6
54,640 54,640 7
3,230 3,230 8
2,040 2,040 9
540 540 10
38 3811
166 166 12
7,887 7,887 13
1,330 1,330 14
13,032 13,032 15
8,469 8,469 16
1,549 1,549 17
149,423 149,423 18
4,544 4,544 19
15,748 15,748 20
374 374 21
4,586 4,586 22
2,538 2,538 23
7,011 7,011 24
144 144 25
1,553 1,553 26
15 1527
5,375 5,375 28
15 1529
10,520 10,520 30
4,771 4,771 31
1,411,400 1,411,400 32
132,338 132,338 33
101,714 101,714 34
6,753,825 14,300,873 0 21,054,698
FERC FORM NO. 1 (ED. 12-90) Page 330
Name of Respondent
Idaho Power Company
This Re ort Is:
(2) AResubmission
Date of Report
04/15/2013
Year/Period of Report
End of 20121Q4
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued) (Including transactions reffered to as 'wheeling)
9.In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10.The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11.Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($) (I)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+I+m)
(n)
Line
No.
-
6,860 6,860 1
865 865 2
287 287 3
9,904 9,904 4
19 195
669 6696
6,576 6,576 7
170 170 8
276,371 276,371 9
8,171 8,171 10
14,248 14,248 11
823 823 12
2,735 2,735 13
20,451 20,451 14
310 310 15
91 91 16
253 253 17
653 65318
3,181 3,181 19
53 5320
132 132 21
14,524 14,524 22
91 9123
140 140 24
37,090 37,090 25
1,027 1,027 26
1,326 1,326 27
170 170 28
181 181 29
298 298 30
349,343 349,343 31
4,537 4,537 32
206,772 206,772 33
65,338 65,338 34
6,753,825 14,300,873 0 21,054,698
FERC FORM NO. 1 (ED. 12-90) Page 330.1
Name of Respondent
Idaho Power Company
This Re oil Is:
(2) AResubmission
Date of Report
04/15/2013
Year/Period of Report
End of 2012/Q4
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued) (Including transactions reffered to as 'wheeling')
9.In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10.The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11.Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(I)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Line
No.
-
35,761 35,761 1
4,896 4,896 2
30,722 30,722 3
42,058 42,058 4
7,124 7,124 5
7,778 7,778 6
7,551 7,551 7
2,214 2,214 8
585 585 9
2,648 2,648 10
230 230 11
4,031 4,031 12
1,292 1,292 13
3,026 3,026 14
2,305 2,305 15
3,026 3,026 16
1,266 1,266 17
9,851 9,851 18
34,375 34,375 19
14,811 14,811 20
3,039 3,039 21
7,412 7,412 22
4 423
275 275 24
283 283 25
1,806 1,806 26
590 590 27
3,147 3,147 28
15,279 15,279 29
6,987 6,987 30
16,649 16,649 31
5,696 5,696 32
5,775 5,775 33
34,725 34,725 34
6,753,825 14,300,873 0 21,054,698
FERC FORM NO. I (ED. 12.90) Page 330.2
Name of Respondent
Idaho Power Company
This Re ort Is:
(1) (2)0 A Resubmission
Date of Report
04/15/2013
Year/Period of Report
End of 20121Q4
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued) -
(Including transactions reffered to as 'wheeling')
9.In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10.The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11.Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(I)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
IJIi
No.
-
236 236 1
429 429 2
31,901 31,901 3
64,364 64,364 4
787 787 5
2,140 2,140 6
98 987
1,507 1,507 8
63,085 63,085 9
14,776 14,776 10
218,858 218,858 11
103,640 103,640 12
393 393 13
1,574 1,574 14
4,312 4,312 15
850 850 16
3,777 3,777 17
4,799 4,799 18
16,145 16,145 19
421 421 20
2,640 2,640 21
42,353 42,353 22
29,847 29,847 23
4,017 4,017 24
4,382 4,382 25
39 3926
31,802 31,802 27
2,895 2,895 28
53,852 53,852 29
45,201 45,201 30
6,066 6,066 31
205,436 205,436 32
66,803 66,803 33
37,601 37,601 34
6,753,825 14,300,873 0 21,054,698
FERC FORM NO. I (ED. 12-90) Page 330.3
Name of Respondent
Idaho Power Company
This Re ort Is:
(2) Q A Resubmission
Date of Report
04/15/2013
Year/Period of Report
End of 2012/Q4
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued) (Including transactions reffered to as 'wheeling')
9.In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(ri). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10.The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11.Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($) (I)
(Other Charges)
($) (m)
Total Revenues ($)
(k+l+m)
(n)
Line
No.
-
250,043 250,043 1
2,065 2,065 2
1,058 1,058 3
1,192 1,192 4
590 590 5
665 665 6
1,003 1,003 7
17,927 17,927 8
9,815 9,815 9
201 201 10
27,518 27,518 11
80,414 80,414 12
1,028,717 1,028,717 13
59 5914
940 940 15
173 173 16
909 909 17
323 323 18
4,028 4,028 19
2,392 2,392 20
4 421
6,294 6,294 22
381 381 23
162 162 24
1,116 1,116 25
558 558 26
623 623 27
15,323 15,323 28
3,389 3,389 29
22,140 22,140 30
14,088 14,088 31
227 227 32
14,167 14,167 33
104 104 34
6,753,825 14,300,873 0 21,054,698
FERC FORM NO. I (ED. 12.90) Page 330.4
Name of Respondent
Idaho Power Company
This Re ort Is:
UAResubmission
Date of Report
04/15/2013
Year/Period of Report
End of 2012/Q4
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued) (Including transactions reffered to as 'wheeling)
9.In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10.The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11.Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(I)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Line
No.
-
522 522 1
180 180 2
3,032 3,032 3
580 580 4
24 245
938 938 6
1,161 1,161 7
20 208
1,840 1,840 9
998 998 10
179 179 11
819 819 12
5,171 5,171 13
139 139 14
10,445 10,445 15
18,123 18,123 16
107 107 17
51,055 51,055 18
29,836 29,836 19
521 52120
1,737 1,737 21
199 199 22
568 568 23
179 179 24
7,325 7,325 25
16,708 16,708 26
2,607 2,607 27
795 795 28
70,994 70,994 29
3,160 3,160 30
2,516 2,516 31
17,920 17,920 32
51,464 51,464 33
3,680 3,680 34
6,753,825 14,300,873 0 21,054,698
FERC FORM NO. I (ED. 12.90) Page 330.5
Name of Respondent
Idaho Power Company
This Re ort Is:
(2) U A Resubmission
Date of Report
04/15/2013
Year/Period of Report
End of 2012/04
TRANSMISSION OF ELECTRICITY FOR OTHERS(Account 456) (Continued)
(Including transactions reffered to as 'wheeling')
9.In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10.The total amounts in columns (I) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11.Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(I)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Line
No.
-
1,359 1,359 1
9,360 9,360 2
4,996 4,996 3
13,561 13,561 4
262 262 5
60 606
8 87
1,490 1,490 8
298 298 9
811 811 10
131 131 11
1,252 1,252 12
11,931 11,931 13
14
4,137 4,137 15
10,008 10,008 16
10,102 10,102 17
20,293 20,293 18
512,127 512,127 19
1,256 1,256 20
2,897 2,897 21
2,076,610 2,076,610 22
58,570 58,570 23
1,809,265 1,809,265 24
66,791 66,791 25
1,418,648 1,418,648 26
154,150 154,150 27
32,624 32,624 28
175,162 175,162 29
1,047 1,047 30
275 275 31
577 577 32
275 275 33
3,181 3,181 34
6,753,825 14,300,873 0 21,054,698
FERC FORM NO. I (ED. 12-90) Page 330.6
Name of Respondent
Idaho Power Company
This Re ott Is
AResubmission
Date of Report
04/15/2013
Year/Period of Report
End of 2012/Q4
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued) (Including transactions reffered to as 'wheeling')
9.In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10.The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11.Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(I)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Line
No.
-
693 693 1
12,632 12,632 2
591 591 3
920 920 4
510 510 5
916 916 6
4,611 4,611 7
1,683 1,683 8
28,553 28,553 9
85 8510
6,434 6,434 11
186 186 12
2,085 2,085 13
2,949 2,949 14
64 6415
141,905 141,905 16
58,186 58,186 17
2,861 2,861 18
7,691 7,691 19
14,753 14,753 20
21,894 21,894 21
1,306 1,306 22
24,657 24,657 23
- 2,947 2,947 24
6,631 6,631 25
2,124 21124 26
29,349 29,349 27
14,553 14,553 28
33 3329
542 542 30
396 396 31
1,512 1,512 32
19,516 19,516 33
2,395 2,395 34
6,753,825 14,300,873 0 21,054,698
FERC FORM NO. I (ED. 12-90) Page 330.7
Name of Respondent
Idaho Power Company
This Re ort Is:
2h1R Original rssion
Date of Report
04/15/2013
Year/Period of Report
End of 2012/Q4
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)
(Including transactions reffered to as 'wheeling')
9.In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10.The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11.Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(I)
- (Other Charges)
($)
(m)
Total Revenues ($)
(k+I+m)
(n)
Line
No.
-
87 87 1
6,894 6,894 2
119,462 119,462 3
16,267 16,267 4
11,063 11,063 5
2,992 2,992 6
94,197 94,197 7
13,890 13,890 8
65,442 65,442 9
165 165 10
711 711 11
1,405 1,405 12
626 626 13
792 792 14
2,187 2,187 15
66 6616
2,841 2,841 17
359 359 18
56 5619
274 274 20
30 3021
159 159 22
667 667 23
23,462 23,462 24
315 315 25
3,570 3,570 26
315 315 27
59 5928
44 4429
989 989 30
311 311 31
33,201 33,201 32
33
34
6,753,825 14,300,873 0 21,054,698
FERC FORM NO. 1 (ED. 12-90) Page 330.8
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 04/15/2013 2012/Q4
FOOTNOTE DATA

Schedule Page: 328 Line No.: I Column: e I
5, Open Access Transmission Tariff, Volume 5, first revision

chedule Page: 328 Line No.: I Column: h I
The network service agreement between Idaho Power and the Bonneville Power Administration
for the Oregon Trail Electric Cooperative expires September 30, 2028. The billing demand
for network service is the customer's demand at the time of Idaho Power Company
transmission system peak and varies by month.

ISchedule Page: 328 Line No.: 2 Column: h I
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.: 3 Column: h
The network service agreement between Idaho Power and the Bonneville Power Administration
for the Priority Firm Customers expires September 20, 2028. The billing demand for network
service is the customer's demand at the time of Idaho Power Company transmission system
peak and varies by month.
Schedule Page: 328 Line No.: 4 Column: e
Legacy, contract prior to the Open Access Transmission Tariff
Schedule Page: 328 Line No.: 4 Column: h
The contract between Idaho Power and the Milner Irrigation District expires December 31,
2017.
Schedule Page: 328 Line No.: 5 Column: h
The agreement between Idaho Power and the City of Seattle expires December 31, 2017. City
of Seattle has re-sold this transmission service request to Cargill and Cargill is now
responsible for payment.
Schedule Page: 328 Line No.: 6 Column: h
The contract between Idaho Power and PacifiCorp - Imnaha expires on March 31, 2016. The
billing demand for network service is the customer's demand at the time of Idaho Power
Company transmission system peak and varies by month.
Schedule Page: 328 Line No.: 7 Column: e
Legacy, contract prior to the Open Access Transmission Tariff
Schedule Page: 328 Line No.: 7 Column: h
The agreement between Idaho Power and the United States Department of the Interior, Bureau
of Indian Affairs is subject to termination upon 90 days written notice by the Bureau.
Schedule Page: 328.6 Line No.: 14 Column: h
Legacy agreement providing OATT-like service, but billed under 454 Facilities revenue
ERC FORM NO. I (ED. 12-87) Page 450.1 1
Name of Respondent This Report Is: Date of Report Year/Period of Report
Idaho Power Company (1)An Original (Mo, Da, Yr) n 2012/Q4
(2)j A Resubmission 04/15/2013
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
(Including transactions referred to as wheeling")
1.Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public
authorities, qualifying facilities, and others for the quarter.
2.In column (a) report each company or public authority that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3.In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.
4.Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5.Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent In column (e) report the
demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all
other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all
components of the amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no
monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement,
including the amount and type of energy or service rendered.
6.Enter "TOTAL" in column (a) as the last line.
7.Footnote entries and provide explanations following all required data.
Line TRANSFER OF ENERGY EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHER
No. Name of Company or Public
Authority Affiliations) (Footnote
Statistical
Classification
MT watt
Received
Maawatt-
Delivered Chas
($?
Chs
($?
CS ($
Total Cos of
ransission
- (a) (b) (c) (d) (e) (f) (g) (h)
1 Avista Corp-WWP Div NF 34,954 34,954 251,314 251,314
2 Avista Corp-WWP Div SEP 319,770 319,770 1,556,759 1,556,759
3 Bonneville Power Admin 268,990 268,990 1,531,616 1,531616
Bonneville Power Admin
OS 7,453 7,453
5 NF 1,127 1,127 13,345 13,345
6 Bonneville Power Admin SEP 1,997 1,997 12,539 12,539
7 OS -1,944 .1,944
8 Northwestern Energy 20,259 20,259 199,600 199,600
9 1 NorthWesern Energy NE 1,993 1,993 10,947 10,947
10 NorthWestern Energy SEP 83,567 83,567 557,646 557,646
11 PacifiGorp Inc. 52,522 52,522 922,740 922,740
12 PaciflCorp Inc. NF 23,600 23,600 249,998 249,998
13 PacifiCorp Inc. SEP 14,331 14,331 121,385 121,385
14 Portland General Ele Co SFP 93,739 93,739 333,877 333,877
15 OS -239,216 -239,216
16 PPL EnergyPlus, LLC SEP 4,032 4,032 13,859 13,859
TOTAL 1,024,12 1,024,122 1,731,216 4,796,901 -233,707 6,294,410
FERC FORM NO. 113-0 (REV. 02-04) Page 332
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Idaho Power Company End of 2012/Q4
04/15/2013
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
(Including transactions referred to as"wheeling")
1.Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public
authorities, qualifying facilities, and others for the quarter.
2.In column (a) report each company or public authority that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3.In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.
4.Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5.Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the
demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all
other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all
components of the amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no
monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement,
including the amount and type of energy or service rendered.
6.Enter TOTAL" in column (a) as the last line.
7.Footnote entries and provide explanations following all required data.
Line TRANSFER OF ENERGY EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHER
No. Name of Company or Public Statistical Maawatt- Maawatt- man0
($?
lIrg%
($? ha C ees
($?
Total Cost of
Authority (Footnote Affiliations) Classification Received Delivered
- (a) (b) (C) (d) (e) (f) (g) (h)
1 Puget Sound Energy, Inc SFP 3,736 3,736 4,870 4,870
21 Seattle City Light SFP 94,344 94,344 732,422 732,422
3 Sierra Pacific Power Co NF 769 769 6,068 6,068
4 Snohomish County PUD SFP 4,392 4,392 9,132 9,132
5
6
7
8
9
10
11
12
13
14
15
16
TOTAL 1,024,121 1,024,122 1,731,216 4,796,901 -233,707 6,294,410
FERC FORM NO. 113-Q (REV. 02-04) Page 332.1
This Page Intentionally Left Blank
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)An Original (Mo, Da, Yr)
Idaho Power Company (2)- A Resubmission 04/15/2013 2012/Q4
FOOTNOTE DATA
hedule Page: 332 Line No.: 3 Column: b I
Contract Expiration Date 09/30/2016
Schedule Page: 332 Line No.: 4 Column: a I
Reserves Provided
hedule Page: 332 Line No.: 7 Column: a
Resale Transmission
[Schedule Page: 332 Line No.: 8 Column: b
Contract can be terminated at anytime, with 30 days prior notice.
diedule Page: 332 Line No.: 11 Column: b 1
Contract Expiration Date 05/31/2014
Schedule Page: 332 Line No.: 15 Column: a I
Resale Transmission
IFERC FORM NO. I (ED. 12-87) Page 450.1 1
Name of Respondent This ReDort Is:
Idaho Power Company
Dateof Report
04/15/2013
Year/Period of Report
End of 2012/04
- MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Line
N DescilDijon
(a)
Amount
(b)
I Industry Association Dues 410,105
2 Nuclear Power Research Expenses
3 Other Experimental and General Research Expenses
4 Pub & Dist Info to Stkhldrs ... expn servicing outstanding Securities 405,305
5 0th Expn >=5,000 show purpose, recipient, amount. Group if < $5,000
6 Richard Dahl 81,888
7 Christine King 77,294
8 Gary Michael 141,582
9 Richard Reiten 26,144
10 Joan Smith 77,365
11 Jan Packwood 54,750
12 Judith Johansen 72,526
13 Thomas Wilford 69,428
14 Robert Tintsman 78,828
15 Stephen Allred 70,559
16
17 Chamber of Commerce & Other Civic Organizations 123,491
18
19 1 Association of Idaho Cities 2,300
20 Associated Taxpayers of Idaho 22,000
21 Boston College Center for Corporation 5,000
22 Corporate Executive Board 42,750
23 Idaho Association of Commerce & Industry 3,000
24 Idaho Association of Counties 350
25 Idaho Technology Council 10,000
26 National Association of Directors 5,558
27 National HydroPower Association 28,000
28 North American Energy Standard 6,500
29 1 Northwest Power Pool 131,093
30 Pacific Northwest Utilities 36,824
31 Western Electricity Coordinating Council 837,673
32 Western Energy Institute 28,110
33 Wyoming Taxpayers Association 1,500
34
35
36
37
38
39
40
41
42
43
44
45
46 TOTAL 4,026,891
FERC FORM NO. I (ED. 12-94) Page 335
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
Idaho Power Company (2)- A Resubmission 04/15/2013 2012/04
FOOTNOTE DATA
[Schedule Page: 335 Line No.: 5 Column: b
Recipient Purpose Amount
Broadridge Financial Solutions Proxy & Bulletin $ 43,589
Deutsche Bank Broker Fees 35,048
E Source Mgmt Services 35,432
Moody's Analytics Broker Services 30,285
New York Stock Exchange Listing fees 52,976
Port of Morrow Misc Expenses 5,475
PR Newswire Misc Expense 13,825
Rate Related Amortization Misc Expense 230,657
Rivel Research Group Mgmt Services 11,880
Stock Based Compensation Stock Expense 576,000
Thomson Financial/Carson Analyst Service 105,197
Misc 36,604
Total $1,176,968
I FERC FORM NO. 1 (ED. 12-87) Page 450.1 1
Name of Respondent This Report Is: Date of Report Year/Period of Report
Idaho Power Company (1)On Original (Mo, Da, Yr) End o 2012/04
(2)11A Resubmission 04/15/2013
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Account 403, 404,405)
(Except amortization of aquisition adjustments)
1.Report in section A for the year the amounts for: (b) Depreciation Expense (Account 403; (c) Depredation Expense for Asset
Retirement Costs (Account 403.1; (d) Amortization of Limited-Term Electric Plant (Account 404); and (e) Amortization of Other Electric
Plant (Account 405).
2.Report in Section 8 the rates used to compute amortization charges for electric plant (Accounts 404 and 405). State the basis used to
compute charges and whether any changes have been made in the basis or rates used from the preceding report year.
3.Report all available information called for in Section C every fifth year beginning with report year 1971, reporting annually only changes
to columns (c) through (g) from the complete report of the preceding year.
Unless composite depreciation accounting for total depreciable plant is followed, list numerically in column (a) each plant subaccount,
account or functional classification, as appropriate, to which a rate is applied. Identify at the bottom of Section C the type of plant
included in any sub-account used.
In column (b) report all depreciable plant balances to which rates are applied showing subtotals by functional Classifications and showing
composite total. Indicate at the bottom of section C the manner in which column balances are obtained. If average balances, state the
method of averaging used.
For columns (c), (d), and (e) report available information for each plant subaccount, account or functional classification Listed in column
(a). If plant mortality studies are prepared to assist in estimating average service Lives, show in column (f) the type mortality curve
selected as most appropriate for the account and in column (g), if available, the weighted average remaining life of surviving plant. If
composite depreciation accounting is used, report available information called for in columns (b) through (g) on this basis.
4.If provisions for depreciation were made during the year in addition to depreciation provided by application of reported rates, state at
the bottom of section C the amounts and nature of the provisions and the plant items to which related.
- A. Summary of Depreciation and Amortization Charges
- Depreciation Amortization of
Line Depreciation Expense for Asset Limited Term Amortization of
No. Functional Classification Expense Retirement Costs Electric Plant Other Electric Total
(Account 403) (Account 403.1) (Account 404) Plant (Ace 405) - (a) (b) (c) (d) (e) (f)
I Intangible Plant 7,483,540 7,483,540
2 Steam Production Plant 21,748,286 317,075 22,065,361
3 Nuclear Production Plant
4 Hydraulic Production Plant-Conventional 14,287,651 14,287,651
5 Hydraulic Production Plant-Pumped Storage
6 Other Production Plant 10,903,496 10,903,496
7 Transmission Plant 18,110,510 18,110,510
8 Distribution Plant 40,970,148 40,970,148
9 Regional Transmission and Market Operation
10 General Plant 10,390,099 10,390,099
11 Common Plant-Electric -296,299 -296,299
12 TOTAL 116,113,891 317,075 7,483,540 123,914,506
- B. Basis for Amortization Charges
Account 404 - Basis used to compute charges:
Balance 1/1/12 2012 Amortization Balance 12/31/12 Remaining months
(1)12,000 12,000 60,000 12
(2)11,976,335 545,446 11,430,888 -
(3)47,195 5,626,910 357
(4)18,068,415 6,582,974 15,481,590 -
(5)4,611,695 287,899 4,323,796 192
(6)225,899 8,026 217,873 -
Total 34,894,344 7,483,540 37,141,058
(1)Shoshone-Bannock Tribe License & Use Agreement (Termination date December 31, 2023).
(2)Middle Snake Relicensing Costs (Amortized over a 30 year license period).
(3)Swan Falls Relicenisng (Amortized over a 30 year license period).
(4)Computer Software packages (Amortized over a 60 month period from date of purchase).
(5)Shoshone-Bannock Right of Way (Termination date December 31, 2028).
(6)Boardman Retrofit Tech Analysis (Termination date December 31, 2040).
FERC FORM NO. I (REV. 12-03) Page 336
Name of Respondent
Idaho Power Company
This Re ort Is:
(2) M A Resubmission
Date of Report
04/15/2013
Year/Period of Report
End of 2012/Q4
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line
No
-
Account No.
(a)
Depreciable
Plant Base (In Thousands)
(b)
Estimated
Avg. Service Life
(c)
Net
Salvage
(Percent)
(d)
Applied
Depr. rates (Percent)
(e)
Mortality
Curve Type
(U
Average
Remaining Life (g)
12 310.20 633 75.00 3.71 R4.0 20.20
13 311.00 147,710 100.00 -10.00 1.70 S1.0 21.30
14 312.10 81,667 60.00 -5.00 1.52 R3.0 21.80
15 312.20 477,479 60.00 -5.00 2.53 R1.5 20.90
16 312.30 4,204 25.00 20.00 2.38 R3.0 7.90
17 314.00 147,772 45.00 -5.00 2.84 S1.0 19.40
18 315.00 68,200 60.00 6.82 S1.5 19.80
19 316.00 14,053 45.00 -5.00 6.60 R0.5 19.00
20 316.10 87 12.00 15.00 8.82 L2.0 6.30
21 316.40 240 12.00 15.00 4.37 L2.0 7.90
22 316.50 83 12.00 15.00 4.33 L2.0 5.10
23 316.60 106 20.00 15.00 4.09 L2.0 18.00
24 316.70 80 20.00 15.00 2.83 L2.0 14.40
25 316.80 1,054 20.00 30.00 8.13 01.0 16.60
26 316.90 14 35.00 15.00 2.25S1.0 34.70
27317.00 10,214
28 Subtotal Steam 953,596
29 331.00 157,518 100.00 -25.00 2.52 R2.5 33.00
30 332.10 19,460 95.00 -20.00 1.71 S4.0 39.80
31 332.20 228,211 95.00 -20.00 1.88 S4.0 35.60
32 332.30 5,472 2.03 SQUARE 49.10
33 333.00 200,844 80.00 -5.00 1.81 R3.0 32.60
34 334.00 46,647 50.00 -5.00 2.85 R1.5 26.10
35 335.00 19,686 95.00 2.19 R2.0 28.10
36 335.10 76 15.00 5.41 SQUARE 6.50
37 335.20 364 20.00 4.72 SQUARE 5.30
38 335.30 166 5.00 14.43 SQUARE 3.30
39 336.00 8,118 75.00 2.23 R3.0 21.40
40 Subtotal Hydro 686,562
41 341.00 133,026 2.89 SQUARE 27.20
42 342.00 7,988 50.00 2.90 S2.5 28.50
43 343.00 226,811 40.00 3.26 S1.5 25.90
44 344.00 73,447 45.00 2.48S2.0 26.80
45 345.00 95,558 50.00 3.21 S1.5 22.60
46 346.00 5,739 35.001 3.14 S2.5 24.50
47 Subtotal Other 542,569
48 350.20 31,171 70.00 1.39 R3.0 58.80
49 352.00 70,137 65.00 -35.00 1.84 R3.0 53.70
50 353.00 365,355 50.00 6.00 1.90 R1.5 40.70
FERC FORM NO. I (REV. 12-03) Page 337
Name of Respondent
Idaho Power Company
This Re ort Is:
2 Resubmission
Date of Report
04/15/2013
Year/Period of Report
End of 20121Q4
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line
No
-
Account No.
(a)
Depreciable
Plant Base
(In Thousands)
(b)
Estimated
Avg. Service
Life
(C)
Net
Salvage
(Percent)
(d)
Appliecl
De pr. rates
(Percent)
(e)
Mortality
Curve Type
(f)
Average
Remaining Life (q)
12 354.00 155,096 65.00 -15.00 1.70S3.0 50.80
13 355.00 120,356 60.00 -70.00 2.77 R2.0 43.60
14 356.00 182,332 65.00 40.00 2.25 R2.0 48.50
15 359.00 390 65.00 0.79 R2.5 24.00
16 Subtotal Transmission 924,83
17 360.22 32 30.00 3.33 30.00
18 361.00 31,354 65.00 40.00 2.14 R2.5 53.30
19 362.00 189,665 50.00 -5.00 2.00 R1.0 40.20
20 364.00 230,356 44.00 -45.00 3.08 R1.5 31.30
21 365.00 124,012 45.00 -35.00 2.98 R0.5 33.60
22 366.00 46,834 60.00 -20.00 1.95 R2.0 48.40
23 367.00 197,732 46.00 -15.00 2.26 R2.0 35.30
24 368.00 451,212 35.00 -3.00 2.58 R1.0 27.00
25 369.00 56,853 40.00 -40.00 2.55 R2.0 29.50
26 370.00 14,182 22.00 1.00 3.46 01.0 17.50
27 370.10 56,751 15.00 6.96 S2.5 13.10
28 370.30
29 371.10 27 12.00 -2.00 2.35 S4.0 9.00
30 371.20 2,838 17.00 -2.00 1.51 R1.5 14.70
31 373.20 4,505 30.00 -25.00 2.41 R1.0 20.60
32 374.00 644
33 Subtotal Distribution 1,406,997
34 390.11 27,395 100.00 -5.00 2.58 S0.5 28.80
35 390.12 65,695 55.00 -5.00 1.90 S0.5 44.30
36 390.20 563 35.00 2.15 S3.0 25.70
37 391.11 12,769 20.00 2.88 SQUARE 12.90
38 391.20 21,438 5.00 11.12 SQUARE 3.20
39 391.21 8,588 8.00 11.22 L2.0 5.70
40 392.10 766 12.00 15.00 7.50 L2.0 8.90
41 392.30 2,590 10.00 50.00 1.73 S2.5 3.40
42 392.40 19,800 12.00 15.00 7.36 1.2.0 6.80
43 392.50 882 12.00 15.00 3.53 L2.0 9.00
44 392.60 30,787 20.00 15.00 4.14 1.2.0 13.40
45 392.70 5,635 20.00 15.00 3.21 L2.0 12.50
46 392.90 4,431 35.00 15.00 2.10S1.0 24.30
47 393.00 1,878 25.00 3.30 SQUARE 19.40
48 394.00 6,466 20.00 4.13 SQUARE 13.30
49 395.00 12,255 20.00 4.29 SQUARE 12.10
50 396.00 11,496 20.00 30.00 1.66 01.0 17.60
FERC FORM NO. I (REV. 12-03) Page 337.1
Name of Respondent
Idaho Power Company
This Report Is:
(1)An Original (2)o Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2013
Year/Period of Report
n 0 2012/04
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line
No Account No.
(a)
Depreciable
Plant Base
(In Thousands)
(b)
s1imated
Avg. Service
Life
(c)
Net
Salvage
(Percent)
(d)
Applied
Depr. rates
(Percent)
(e)
Mortality
Curve
Type
(f)
Average
Remaining
Life
(g)
12 397.10 5,582 15.00 4.25 SQUARE 8.30
13 397.20 27,115 15.00 5.38 SQUARE 9.80
14 397.30 3,612 15.00 5.31 SQUARE 8.00
15 397.40 3,621 10.00 7.90 SQUARE 6.50
16 398.00 5,622 15.00 5.20 SQUARE 10.60
17 Subtotal General 278,986
18 Total Plant 4,793547
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
FERC FORM NO. I (REV. 12-03) Page 337.2
Name of Respondent
Idaho Power Company
This Re oil Is:
(2) AResubrnission
Date of Report
04/15/2013
Year/Period of Report
End of 2012/Q4
REGULATORY COMMISSION EXPENSES
1.Report particulars (details) of regulatory commission expenses incurred during the current year (or incurred in previous years, if
being amortized) relating to format cases before a regulatory body, or cases in which such a body was a party.
2.Report in columns (b) and (c), only the current year's expenses that are not deferred and the current year's amortization of amounts
deferred in previous years.
Line
No.
Description
(Furnish name of regulatory commission or body the docket or case number and a description of the case)
(a)
Assessed by
Regulatory Commission
(b)
Expenses
of
Utility
(c)
Total
(b) + (c)
(d)
Deferred in Account
Beginning oYear
(e)
I Federal Energy Regulatory Commission:
2 Annual admin charges assessed by FERC 3,862,917 3,862,917
3
4 Regulatory FERC fees Tru-up 381,035 381,035
5
6 General Regulatory Expenses and
7 Various other Dockets 326,544 326,544
8
9 Oregon Hydro - Fees Amortization 158,501 158,501
10
11 Regulatory Commission Expenses - Idaho
12 Intervenor funding 150,024 150,024
13 j PURPA expenses 270,004 270,004
14 Rate Case - Misc expenses 4,712 4.712
15
16 Regulatory Commission Expenses - Oregon
17 Rate Case - Misc expenses 9,755 9,755
18
19 Other - OPUC
20 UE-233 150,392 150,392
21 UE -244 39,012 39,012
22 UE -248 19,098 19,098
23 UM-1182 30,421 30,421
24 UM - 1559 26,890 26,890
25 UM-1562 50,113 50,113
26 UM-1572 52,332 52,332
27 UM - 1575 26,573 26,573
28 PURPA 32,513 32,513
29 General Regulatory 19,785 19,785
30 Other OPUC expenses 81,865 81,865
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
461 TOTAL 4,021,4181 1,671,0681 5,692,486
FERC FORM NO. I (ED. 12-98) Page 350
Name of Respondent
Idaho Power Company
This Re ort Is Date of Report
04fl5/2013
Year/Period of Report
End of 20121Q4
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.
EXPENSES INCURRED DURING YEAR AMORTIZED DURING YEAR
CURRENTLY CHARGED TO Deferred to
Account 182.3
(i)
Contra
Account
(j)
Amount
(k)
Deferred in Account 182.3 Line
No. Department
(f)
AcoUflt
(9)
Amount
(h)
Electric 928 3,862,917 2
3
Electric 928 381,035 4
5
6
Electric 928 326,544 7
8
158,501 9
10
11
Electric 928 150.024 12
Electric 928 270,004 13
Electric 928 4,712 14
15
16
Electric 928 9,755 17
18
19
Electric 928 150,392 20
Electric 928 39,012 21
Electric 928 19,098 22
Electric 928 30,421 23
Electric 928 26,890 24
Electric 928 50,113 25
Electric 928 52,332 26
Electric 928 26,573 27
Electric 928 32,513 28
Electric 928 19,785 29
Electric 928 81,865 30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
5,692,4861 46
FERC FORM NO. I (ED. 12-96) Page 351
Name of Respondent
Idaho Power Company
This Re ort Is:
(2) EJ AResubmission
Date of Report
04/15/2013
Year/Period of Report
End of 20121Q4
RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIViTIES
1.Describe and show below costs incurred and accounts charged during the year for technological research, development, and demonstration (R, D &
D) project initiated, continued or concluded during the year. Report also support given to others during the year for jointly-sponsored projects.(ldentify
recipient regardless of affiliation.) For any R, D & 0 work carried with others, show separately the respondent's cost for the year and cost chargeable to
others (See definition of research, development, and demonstration in Uniform System of Accounts).
2.Indicate in column (a) the applicable classification, as shown below:
Classifications:
A. Electric R, D & D Performed Internally: a. Overhead
(1) Generation b. Underground
a.hydroelectric (3) Distribution
I. Recreation fish and wildlife (4) Regional Transmission and Market Operation
ii Other hydroelectric (5) Environment (other than equipment)
b.Fossil-fuel steam (6) Other (Classify and include items in excess of $50,000.)
c.Internal combustion or gas turbine (7) Total Cost Incurred
d.Nuclear B. Electric, R, D & D Performed Externally:
e.Unconventional generation (1) Research Support to the electrical Research Council or the Electric
f.Siting and heat rejection Power Research Institute
(2) Transmission
Line
No.
Classification
(a)
Description
(b)
1 Idaho Power did not incur any Research and
2 Development expenditures in 2012.
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
FERC FORM NO. 1 (ED. 1247) Page 352
Name of Respondent
Idaho Power Company
This Re ort Is:
(2) E]A Resubmission
Date of Report
04/15/2013
Year/Period of Report
End of 201 2/Q4
RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES (Continued)
(2)Research Support to Edison Electric Institute
(3)Research Support to Nuclear Power Groups
(4)Research Support to Others (Classify)
(5)Total Cost Incurred
3.Include in column (c) all R, D & D items performed internally and in column (d) those items performed outside the company costing $50,000 or more,
briefly describing the specific area of R, D & 0 (such as safety, corrosion control, pollution, automation, measurement, insulation, type of appliance, etc.).
Group items under $50,000 by classifications and indicate the number of items grouped. Under Other, (A (6) and B (4)) classify items by type of R, D &
D activity.
4.Show in column (e) the account number charged with expenses during the year or the account to which amounts were capitalized during the year,
listing Account 107, Construction Work in Progress, first. Show in column (f) the amounts related to the account charged in column (e)
5.Show in column (9) the total unamortized accumulating of costs of projects. This total must equal the balance in Account 188, Research,
Development, and Demonstration Expenditures, Outstanding at the end of the year.
6.If costs have not been segregated for R, D &D activities or projects, submit estimates for columns (c), (d), and (f) with such amounts identified by
"Est."
7.Report separately research and related testing facilities operated by the respondent.
Costs Incurred Internally
Current Year
Costs Incurred Externally
Current Year
(d)
AMOUNTS CHARGED IN CURRENT YEAR Unamortized
Accumulation
(g)
Line
No. Account
(e)
Amount
(f)
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
FERC FORM NO. I (ED. 12-87) Page 353
Name of Respondent
Idaho Power Company
This Re ort Is:
(2) AResubmission
Date of Report
04/15/2013
Year/Period of Report
End of 2012/014
DISTRIBUTION OF SALARIES AND WAGES
Report below the distribution of total salaries and wages for the year. Segregate amounts originally charged to clearing accounts to
Utility Departments, Construction, Plant Removals, and Other Accounts, and enter such amounts in the appropriate lines and columns
provided. In determining this segregation of salaries and wages originally charged to clearing accounts, a method of approximation
giving substantially correct results may be used.
Line
No.
-
Classification
(a)
Direct Payroll Distribution
(b)
Alocation
P 1 Jfcr Total
Clearm Accounts c) (d)
1 Electric
2 Operation
3 Production I 20,049,754
4 Transmission 6,731,505
5 Regional Market
6 Distribution 17,301,055
7 Customer Accounts
8 Customer Service and Informational 8,412,128
9 Sales
Administrative and General
4,648,046
42,810,041 10
11 TOTAL Operation (Enter Total of lines 3 thru 10) 99,952,529
12 Maintenance
13 Production 6,116,531
14 Transmission 3,404,348
15 Regional Market
16 Distribution 9,416,231
17
18
Administrative and General
TOTAL Maintenance (Total of lines 13 thru 17)
1,164,994
20,102,104
19 Total Operation and Maintenance
Production (Enter Total of lines 3 and 13) I 26,166,285 20
21 Transmission (Enter Total of lines 4 and 14) 10,135,853
22 Regional Market (Enter Total of Lines 5 and 15)
23 Distribution (Enter Total of lines 6 and 16)
Customer Accounts (Transcribe from line 7)
26,717,286
24
25 Customer Service and Informational (Transcribe from line 8) 8,412,128
26 Sales (Transcribe from line 9)
Administrative and General (Enter Total of lines 10 and 17)
4,648,046
43,975,035 27
28 TOTAL Oper. and Maint. (Total of lines 20 thru 27) 120,054,6331 I 120,054,633 1
29 Gas
30 Operation
31 Production-Manufactured Gas I
32 Production-Nat Gas (Including Expi. and Dev.)
33 Other Gas Supply
34 Storage, LNG Terminaling and Processing
35 Transmission
36 Distribution
37 Customer Accounts
38 Customer Service and Informational
39 Sales
40 Administrative and General
41 TOTAL Operation (Enter Total of lines 31 thru 40)
42 Maintenance
43 Production-Manufactured Gas I
44 Production-Natural Gas (Including Exploration and Development)
45 Other Gas Supply
46 Storage, LNG Terminaling and Processing
47 Transmission
FERC FORM NO. I (ED. 12-88) Page 354
Name of Respondent
Idaho Power Company
This Re ort Is:
Resubmission
Date of Report
04/15/2013
Year/Period of Report
End of 20121Q4
DISTRIBUTION OF SALARIES AND WAGES (Continued)
Line Classification
(a)
Direct Payroll
Distribution
(b)
?%°Je for Total
c) (d)
48 Distribution
49 Administrative and General
50 TOTAL Maint. (Enter Total of lines 43 thru 49)
51
52
Total Operation and Maintenance
Production-Manufactured Gas (Enter Total of lines 31 and 43)
53 Production-Natural Gas (Including Expl. and Dev.) (Total lines 32, 7 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 Accounts (Line 37)
59 Customer Service and Informational (Line 38)
60 Sales (Line 39)
61 Administrative and General (Lines 40 and 49)
62 TOTAL Operation and Maint (Total of lines 52 thru 61)
63 Other Utility Departments
64 Operation and Maintenance
65 TOTAL All Utility Dept. (Total of lines 28, 62, and 64) 120,054,633 120,054,633
66 Utility Plant
I I I
67
68
Construction (By Utility Departments)
Electric Plant
69 Gas Plant
70 Other (provide details in footnote):
71 TOTAL Construction (Total of lines 68 thru 70)
72 Plant Removal (By Utility Departments)
54,744,367 54,744,367 73 Electric Plant
74 Gas Plant
75 Other (provide details In footnote):
76 TOTAL Plant Removal (Total of lines 73 thru 75) 54,744,367 54,744,367
77 Other Accounts (Specify, provide details in footnote):
78 Stores Expense 4,918,559 4,918,559
79 Other Clearing Accounts 3,064,354 3,064,354
80 Other work in progress 1,882,252 1,882,252
81 Paid absences 20,732,543 20,732,543
82 Preliminary survey and investigation 93,565 93,565
83 Other accounts 5,062,314 5,062,314
84
85
86
87
88
89
90
91
92
93
94
95 TOTAL Other Accounts 35,753,587 35,753,587
96 TOTAL SALARIES AND WAGES 210,552,587 210,552,587
FERC FORM NO. I (ED. 12-88) Page 355
Name of Respondent
Idaho Power Company
This Re ort Is: Date of Report Year/Period of Report
End of 2012/04
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 ) by month the system' monthly maximum megawatt load by statistical classifications. See General Instruction for
the definition of each statistical classification.
NAME OF SYSTEM: Idaho Power Company
Line
No.
-
Month
(a)
Monthly Peak
MW - Total
(b)
Day of
Monthly
Peak
(c)
Hour of
Monthly
Peak
(d)
Firm Network
Service for Sell
(e)
Firm Network
Service for
Others
(f)
Long-Term Firm
Point-to-point
Reservations
(g)
Other Long-
Term Firm
Service
(h)
Short-Term Firm
Point-to-point
Reservation
(i)
Other
Service
(j)
1 January 4,441 27 900 3,220 203 567 451
2 February 4,431 900 3,055 201 567 616
3 March 4,43 800 3,109 212 567 550
4 Total for Quarter 13,31 9,384 616 1,701 1,617
5 April 4,56 2 1600 3,100 216 567 681
6 4,791 1 1900 3,436 269 567 519
7 June 5,54 20 2000 4,472 337 567 168
8 Total for Quarter 2 14,89 11,008 822 1,701 1,368
9 July 5,86 1 1600 4,861 342 567 94
10 August 5,46 1800 4,482 303 567 137
111 September 4,73 2100 3,773 255 567 125
12 Total for Quarter 3 16,07 13,116 900 1,701 356
13 October 4,24 2 9001 3,367 182 567 127
14 November 4,36 t 19001 3,499 193 567 103
15 December 4,49 1 9001 3,660 200 567 72
II' Total for Quarter 4 13,10' 10,526 575 1,701 302
1 Total Year to
Date/Year 57,39' 44,034 2,913 6,804 3,643
FERC FORM NO. 113-0 (NEW 07-04) Page 400
Name of Respondent
Idaho Power Company
This Report Is:
AResubmission
Date of Report
04/15/2013
Year/Period of Report
End of 2012/04
ELECTRIC ENERGY ACCOUNT
Report below the information called for concerning the disposition of electric energy generated, purchased, exchanged and wheeled during the year.
Line
No.
Item
(a)
MegaWatt Hours
(b)
Line
No.
Item
(a)
MegaWatt Hours
(b)
1 SOURCES OF ENERGY 21 DISPOSITION OF ENERGY
2 Generation (Excluding Station Use): 22 Sales to Ultimate Consumers (Including
Interdepartmental Sales)
14,085,316
3 Steam 5,227,051
4 Nuclear 23 Requirements Sales for Resale (See
instruction 4, page 311.) 5 Hydro-Conventional 7,956,343
6 Hydro-Pumped Storage 24 Non-Requirements Sales for Resale (See
instruction 4, page 311.)
2,183,262
7 Other 675,603
8 Less Energy for Pumping 25 Energy Furnished Without Charge
9 Net Generation (Enter Total of lines 3
through 8)
13,859,001 26
-
Energy Used by the Company (Electric
Dept Only, Excluding Station Use)
10 Purchases 3,667,462 27 Total Energy Losses 1,253,953
11 Power Exchanges: 8 TOTAL (Enter Total of Lines 22 Through
27) (MUST EQUAL LINE 20)
17,522531
12 Received
13 Delivered
14 Net Exchanges (Line 12 minus line 13) ;-2,"
15 Transmission For Other (Wheeling)
16 Received
17 Delivered 6,075,121
18 Net Transmission for Other (Line 16 minus
line 17)
-98
19 Transmission By Others Losses
20 TOTAL (Enter Total of lines 9, 10, 14, 18
and 19)
17,522,531
FERC FORM NO. 1 (ED. 12-90) Page 401a
Name of Respondent
Idaho Power Company
This Re ort Is: Date of Report
04/15/2013
Year/Period of Report
End of 201 2/Q4
MONTHLY PEAKS AND OUTPUT
1.Report the monthly peak load and energy output If the respondent has two or more power which are not physically integrated, furnish the required
information for each non- integrated system.
2.Report in column (b) by month the system's output in Megawatt hours for each month.
3.Report in column (c) by month the non-requirements sales for resale. Include in the monthly amounts any energy losses associated with the sales.
4.Report in column (d) by month the system's monthly maximum megawatt load (60 minute integration) associated with the system.
5.Report in column (e) and (f) the specified information for each monthly peak load reported in column (d).
NAME OF SYSTEM: Idaho Power Company
Line
No.
-
Month
(a)
Total Monthly Energy
(b)
Monthly Non-Requirments
Sales for Resale &
Associated Losses
(c)
MONTHLY PEAK
Megawatts (See lnstr. 4)
(d)
Day of Month
(e)
Hour
(f)
29 January 1,514,978 265,515 2,130 17 8 A
30 February 1,434,240 323,075 2,021 6 8 A
31 March 1,467,239 384,924 1,949 2 8 A
32 April 1,386,222 302,871 2,073 23 4 P
33 May 1,555,433 259,416 2,296 21 6 PM
34 June 1,529,723 12,232 2,927 28 8 PM
35 July 1,785,648 8,655 3,245 12 4 P
36 August 1,649,308 14,344 3,086 7 6PM
37 September 1,294,520 85,446 2,385 5 7 PM
38 October 1,246,951 168,622 1,832 2 2 P
39 November 1,228,647 158,090 1,908 27 8 A
40 December 1,429,622 200,072 2,133 19 8 A
41 TOTAL 17,522,531 2,183,262
FERC FORM NO. 1 (ED. 12-90) Page 401b
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
Idaho Power Company (2)- A Resubmission 04/15/2013 2012/Q4
FOOTNOTE DATA
ISchedule Page: 401 Line No.: 16 Column: b I
Page 329 column I differs from Page 401 by 988 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 for
account 447 transmission.
IFERC FORM NO. I (ED. 12-87) Page 450.1 1
Name of Respondent
Idaho Power Company
This Re rt Is:
Resubmission
Date of Report
04/15/2013
Year/Period of Report
End of 2012/04
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in
this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. Indicate by a footnote any plant leased or operated
as a joint facility. 4. If net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. If any employees attend
more than one plant, report on line 11 the approximate average number of employees assignable to each plant. 6. If gas is used and purchased on a
therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 7. Quantities of fuel burned (Line 38) and average cost
per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20. 8. If more than one
fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
Line
No.
Item
(a)
Plant
Name: Jim Bridger
(b)
Plant
Name: Boardman
(c)
1 Kind of Plant (Internal Comb, Gas Turb, Nuclear Steam Steam
2
3
4
IType of Constr (Conventional, Outdoor, Boiler, etc)
Year Originally Constructed
Year Last Unit was Installed
Semi-Outdoor Boilerl
119791
Conventional
1980
5
6
Total Installed Cap (Max Gen Name Plate Ratings-MW)
Net Peak Demand on Plant - MW (60 minutes) 7171 60
7 Plant Hours Connected to Load 8784 5561
8 Net Continuous Plant Capability (Megawatts) 01 0
9
10
When Not Limited by Condenser Water
When Limited by Condenser Water 0 0
11 Average Number of Employees 0 0
12 Net Generation, Exclusive of Plant Use - KWh 4374213000 230176000
13 Cost of Plant: Land and Land Rights 106610 494358
14 Structures and Improvements 13910931 66823285
15 Equipment Costs 60588342 460074757
16 Asset Retirement Costs 0 0
17 Total Cost 74605883 527392400
18 Cost per KW of Installed Capacity (line 17/5) Including 96.8279 8214.8349
19 Production Expenses: Oper, Supv, & Engr 222901 590272
20 Fuel 103402312 4991249
21 Coolants and Water (Nuclear Plants Only) 0 0
22 Steam Expenses 5203040 424389
23 Steam From Other Sources 0 0
24 Steam Transferred (Cr) 0 0
25 Electric Expenses 0 0
26 Misc Steam (or Nuclear) Power Expenses 6278439 473728
27 Rents 285311 0
28 Allowances 0 0
29 Maintenance Supervision and Engineering 133909 197376
30 Maintenance of Structures 0 166
31 Maintenance of Boiler (or reactor) Plant 8136821 128927
32 Maintenance of Electric Plant 2261009 1817633
33 Maintenance of Misc Steam (or Nuclear) Plant 4717009 36324
34 Total Production Expenses 130640751 8660064
35 Expenses per Net KWh 0.0299 0.0376
36 Fuel: Kind (Coal, Gas, Oil, or Nuclear) Coal Oil Coal Oil
37 Unit (Coal-tons/OiI-barrel/Gas-mcf/Nuclear-indicate) Tons Barrels Tons Barrels
38 Quantity (Units) of Fuel Burned 2404401 6419 0 140346 1243 0
39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 9325 140000 0 8345 138800 0
40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 38.245 142.680 0.000 30.960 134.052 0.000
41 Average Cost of Fuel per Unit Burned 42.626 98.502 0.000 34.221 128.858 0.000
42 Average Cost of Fuel Burned per Million BTU 2.275 16.752 0.000 2.046 22.104 0.000
43 Average Cost of Fuel Burned per KWh Net Gen 0.024 0.000 0.000 0.022 0.000 0.000
44 Average BTU per KWh Net Generation 10307.000 0.000 0.000 10228.000 0.000 0.000
FERC FORM NO. 1 (REV. 12-03) Page 402
Name of Respondent
Idaho Power Company
This Re ort Is: Date of Report
04/15/2013
Year/Period of Report
End of 2012/Q4
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos.
547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants
designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear
steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined
cycle operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by
footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units
used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the
report period and other physical and operating characteristics of plant.
Plant
Name: Valmy
(d)
Plant
Name: Danskin
(e)
Plant
Name: Bennett Mountain
(f)
Line
No.
-
Steam Gas Turbine Gas Turbine 1
Outdoor Conventional Conventional 2
2001 2005 3
1985 2008 2005 4
270.90 172.80 5
261 224 178 6
7881 541 397 7
0 261 164 8
0
0 0 0 10
0 9 4 11
622666000 72685000 53194000 12
1106140 402745 0 13
66975806 5679993 1471166 14
274376410 107792021 58946771 15
0 0 0 16
342458356 113874759 60417937 17
1207.9660 420.3572 349.6408 18
589570 344837 148572 19
261 07543 5908249 3626466 20
0 0 0 _.!
2652194 0 0 22
0 0 0
0 0
1539354 294777 277326 25
1579676 103559 43651 26
O 0 0
0 0 0
71 0 0 29
758837 80801 73394 30
4339854 4922 38360 31
1060665 2087452 289155 32
243285 0 0 33
38871049 8824597 4496924 34
0.0624 0.1214 0.0845 35
Coal Oil Gas Gas 36
Tons Barrels MCF MCF 37
346327 14997 0 764057 0 0 568185 0 0 38
9853 138778 0 1027 0 0 1027 0 0 39
36.543 132.895 0.000 7.733 0.000 0.000 6.383 0.000 0.000 40
69.462 132.880 0.000 7.733 0.000 0.000 6.383 0.000 0.000 41
3.525 22.798 0.000 5.440 0.000 0.000 4.480 0.000 0.000 42
0.042 0.000 0.000 0.081 0.000 0.000 0.068 0.000 0.000 43
11101.000 0.000 0.000 10796.000 0.000 0.000 10970.000 0.000 0.000 44
FERC FORM NO. 1 (REV. 12-03) Page 403
Name of Respondent
Idaho Power Company
This Re ort Is:
Resubmission
Date of Report
04/15/2013
Year/Period of Report
End of 20121Q4
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in
this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. Indicate by a footnote any plant leased or operated
as a joint facility. 4. If net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. If any employees attend
more than one plant, report on line 11 the approximate average number of employees assignable to each plant. 6. If gas is used and purchased on a
therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 7. Quantities of fuel burned (Line 38) and average cost
per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20. 8. If more than one
fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
Line
No.
-
Item
(a)
Plant
Name: Langley Gulch
(b)
Plant
Name:
(c)
1 Kind of Plant (Internal Comb, Gas Turb, Nuclear Gas Turbine
2 IType of Constr (Conventional, Outdoor, Boiler, etc) Conventional
3 Year Originally Constructed 2012
4 Year Last Unit was Installed 2012
5 Total Installed Cap (Max Gen Name Plate Ratings-MW) 318.45 0.00
6 Net Peak Demand on Plant - MW (60 minutes) 305 0
7 Plant Hours Connected to Load 1907 0
8 Net Continuous Plant Capability (Megawatts) 300 0
9 When Not Limited by Condenser Water 0 0
10 When Limited by Condenser Water 0 0
11 Average Number of Employees 16 0
12 Net Generation, Exclusive of Plant Use - KWh 549705000 0
13 Cost of Plant: Land and Land Rights 2287261 0
14 Structures and Improvements 125862894 0
15 Equipment Costs 241906961 0
16 Asset Retirement Costs 0 0
17 Total Cost 370057116 0
18 Cost per KW of Installed Capacity (line 17/5) Including 1162.0572 0
19 Production Expenses: Oper, Supv, & Engr 727729 0
20 Fuel 16873841 0
21 Coolants and Water (Nuclear Plants Only) 0 0
22 Steam Expenses 0 0
23 Steam From Other Sources 0 0
24 Steam Transferred (Cr) 0 0
25 Electric Expenses 1597922 0
26 Misc Steam (or Nuclear) Power Expenses 226959 0
27 Rents 0 0
28 Allowances 0 0
29 Maintenance Supervision and Engineering 0 0
30 Maintenance of Structures 45424 0
31 Maintenance of Boiler (or reactor) Plant 17345 0
32 Maintenance of Electric Plant 186031 0
33 Maintenance of Misc Steam (or Nuclear) Plant 0 0
34 Total Production Expenses 19675251 0
35 Expenses per Net KWh 0.0358 0.0000
36 Fuel: Kind (Coal, Gas, Oil, or Nuclear) Gas
37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) MCF
38 Quantity (Units) of Fuel Burned 2261741 0 0 0 0 0
39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 1027 0 0 0 0 0
40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 7.461 0.000 0.000 0.000 0.000 0.000
41 Average Cost of Fuel per Unit Burned 7.461 0.000 0.000 0.000 0.000 0.000
42 Average Cost of Fuel Burned per Million BTU 5.350 0.000 0.000 0.000 0.000 0.000
43 Average Cost of Fuel Burned per KWh Net Gen 0.031 0.000 0.000 0.000 0.000 0.000
44 Average BTU per KWh Net Generation 4226.000 0.000 0.000 0.000 0.000 0.000
FERC FORM NO. I (REV. 12-03) Page 402.1
Name of Respondent
Idaho Power Company
This Re ort Is:
(2) AResubmission
Date of Report
04/15/2013
Year/Period of Report
End of 20121Q4
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos.
547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants
designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear
steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined
cycle operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by
footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units
used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the
report period and other physical and operating characteristics of plant.
Plant
Name:
(d)
Plant
Name:
(e)
Plant
Name:
(f)
Line
No.
-
2
3
4
0.00 0.00 0.00
0 0
0 0 0 7
0 0 0_.__
0 0 0 9
0 0 0 10
0 0 01_1 .
0 0 0 12
0 0 0 __.!.
0 0 0 14
0 0 oii
0 0 0 16
0 0 0 _i!
0 0 0
0 0 0
0 0 0
0 0 0 21
0 0 0
0 0 0
0 0 0
0 0 0
0 0 0 -
0 0 0 27
0 0 0 28
0 0 0 29
0 0 030
0 0 0
0 0!
0 0 33
o 0 34
0.0000 - 0.0000 0.0000
36
37
0 0 0 0 0 0 0 0 0 38
0 0 0 0 0 0 0 0 0
0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 40
0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 42
0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 43
0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 ±:
FERC FORM NO. I (REV. 12-03) Page 403.1
This Page Intentionally Left Blank
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
Idaho Power Company (2)- A Resubmission 04/15/2013 20121Q4
FOOTNOTE DATA
hedule Page: 402 Line No.: 3 Column: b
This footnote applies to lines 3 and 4. The Jim Bridger Power
Plant consists of four equal units constructed jointly by Idaho
Power Company and Pacific Power and Light Company, with Idaho
owning 1/3 and PacifiCorp owning 2/3. Unit #1 was placed in
commercial operation November 30, 1974, Unit #2 December 1, 1975,
Unit #3 September 1, 1976, and Unit #4 November 29, 1979.
Schedule Page: 402 Line No.: 3 Column: c
This footnote applies to lines 3 and 4. The Boardman plant
consists of one unit constructed jointly by Portland General
Electric Company, Idaho Power Company, and Pacific Northwest
Generating Company, with Idaho Power Company owning 10%. The
unit was placed in commercial operation August 3, 1980.
ISchedule Page: 402 Line No.: 3 Column: d
This footnote applies to lines 3 and 4. The Valmy plant consists
of two units constructed jointly by Sierra Pacific Power Company
and Idaho Power Company, with Sierra owning 1/2 and Idaho owning
1/2. Unit #1 was placed in commercial operation December 11, 1981
and Unit #2 May 21, 1985.
chedule Page: 402 Line No.: 5 Column: b
This footnote applies to line 5 and lines 12 through 43.
Information reflects Idaho Power Company's share as explained
in note for line 3 page 402 column B.
Schedule Page: 402 Line No.: 5 Column: c
This footnote applies to line 5 and lines 12 through 43.
Information reflects Idaho Power Company's share as explained
in note on line 3 page 402 column C
Schedule Page: 402 Line No.: 5 Column: d
This footnote applies to line 5 and lines 12 through 43.
Information reflects Idaho Power Company's share as explained
in note for line 3 paqe 403 column D.
This footnote applies to lines 9, 10, and 11. PacifiCorp
as operator of the plant will report this
information.
chedule Page: 402 Line No.: 9 Column: c
This footnote applies to lines 9, 10, and 11. Portland General
Electric Company, as operator will report this information.
Schedule Page: 402 Line No.: 9 Column: d
This footnote applies to lines 9, 10, and 11. Sierra Pacific
Power, as operator of the plant, will report this information.
IFERC FORM NO. I (ED. 12-87) Page 450.1
Name of Respondent
Idaho Power Company
This Re oil Is:
(2) AResubmission
Date of Report
04/15/2013
Year/Period of Report
End of 2012/Q4
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1.Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2.If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in
a footnote. If licensed project, give project number.
3.If net peak demand for 60 minutes is not available, give that which is available specifying period.
4.If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
Line
No.
-
Item
(a)
FERC Licensed Project No. 2736
Plant Name: American Falls
(b)
FERC Licensed Project No. 1975
Plant Name: Bliss
(c)
1 Kind of Plant (Run-of-River or Storage) Run-of-River
2 Plant Construction type (Conventional or Outdoor) Outdoor Outdoor
3 Year Originally Constructed 1978 1949
4 Year Last Unit was Installed 1978 1950
5 Total installed cap (Gen name plate Rating in MW) 92.30 75.00
6 Net Peak Demand on Plant-Megawatts (60 minutes) 1001 77
7 Plant Hours Connect to Load 6,8721 8,784
8 Net Plant Capability (in megawatts)
110 76 9 (a) Under Most Favorable Oper Conditions
10 (b) Under the Most Adverse Oper Conditions 0 1
11 Average Number of Employees 4 4
12 Net Generation, Exclusive of Plant Use - Kwh 352,580,000 367,568,000
13
14
Cost of Plant
Land and Land Rights 875,318 768,358
15 Structures and Improvements 11,855,142 1,085,815
16 Reservoirs, Dams, and Waterways 4,293,075 8,413,888
17 Equipment Costs 31,904,332 8,423,020
18 Roads, Railroads, and Bridges 839,276 486,477
19 Asset Retirement Costs 0 0
20 TOTAL cost (Total of 14 thru 19) 49,767,143 19,177,558
21 Cost per KW of Installed Capacity (line 20 / 5) 539.1890 255.7008
22
23
Production Expenses
Operation Supervision and Engineering 476,609 927,261
24 Water for Power 1,577,186 628,163
25 Hydraulic Expenses 97,084 597,445
26 Electric Expenses 51,463 48,134
271 Misc Hydraulic Power Generation Expenses 63,884 79,638
28 Rents 155 3,034
29 Maintenance Supervision and Engineering 13,233 23,041
30 Maintenance of Structures 124,229 72,264
31 Maintenance of Reservoirs, Dams, and Waterways 243 276,980
32 Maintenance of Electric Plant 234,659 63,965
33 Maintenance of Misc Hydraulic Plant 82,341 130,468
34 Total Production Expenses (total 23 thru 33) 2,721,086 2,850,393
35 Expenses per net KWh 0.0077 0.0078
FERC FORM NO. 1 (REV. 12-03) Page 406
Name of Respondent
Idaho Power Company
This Re ort Is: Art

Date of Report
04/15/2013
Year/Period of Report
End of 2012104
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5.The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6.Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC Licensed Project No. 1971
Plant Name: Brownlee
(d)
FERC Licensed Project No. 2848
Plant Name: Cascade
(e)
FERC Licensed Project No. 1971
Plant Name: Oxbow
(f)
Line
No.
-
Storage
Outdoor Outdoor Outdoor 2
1958 1983 1961 3
1980 1984 1961 4
585.40 12.42 190.00 5
677 14 217 6
8,784 7,530 8,784 7
747 15 221
8
9
220 1 20210
6 2 6. 11
2,299,399,000 52,931,000 1,092,370,000 12
18,089,244 82,142 1,210,187
13
14
32,265,720 7,364,154 9,979,198 15
67,073,285 3,145,630 30,435,631 16
57,797,955 12,601,622 15,814,524 17
518,444 122,668 565,842 18
0 0 0 19
175,744,648 23,316,216 58,005,382 20
300.2129 1,877.3121 305.2915 21
561,426 220,588 331,280 23
402,168 212,942 221,975 24
924,182 448,127 514,955 25
289,589 179,333 157,482 26
645,433 303,217 427,938 27
195,636 112 32,214 28
44,343 15,314 28,653 29
166,643 37,386 235,793 30
238,438 4,236 47,778 31
465,035 201,474 237,479 32
486,572 76,454 220,503 33
4,419,465 1,699,183 2,456,050 34
0.0019 0.0321 0.0022 35
FERC FORM NO. 1 (REV. 12-03) Page 407
Name of Respondent
Idaho Power Company
This Re ort Is:
(2) AResubmission
Date of Report
04/15/2013
Year/Period of Report
End of 20121Q4
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1.Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2.If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in
a footnote. If licensed project, give project number.
3.If net peak demand for 60 minutes is not available, give that which is available specifying period.
4.If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
Line
No.
-
Item
(a)
FERC Licensed Project No. 1971
Plant Name: Hells Canyon
(b)
FERC Licensed Project No. 2726
Plant Name: Malad
(c)
1
2
1 Kind of Plant (Run-of-River or Storage)
Plant Construction type (Conventional or Outdoor) Outdoor Outdoor
3 Year Originally Constructed 1967 1948
4 Year Last Unit was Installed 1967 1948
5 Total installed cap (Gen name plate Rating in MW) 391.50 21.77
6 Net Peak Demand on Plant-Megawatts (60 minutes) 441 24
7 Plant Hours Connect to Load 8,772 8,784
8
9
Net Plant Capability (in megawatts)
(a) Under Most Favorable Oper Conditions 445 25
10 (b) Under the Most Adverse Oper Conditions 137 21
11 Average Number of Employees 5 1
12 Net Generation, Exclusive of Plant Use - Kwh 2,084,203,000 167,365,000
13
14
Cost of Plant
Land and Land Rights 1,877,301 205,376
15 Structures and Improvements 2,870,863 2,794,963
16 Reservoirs, Dams, and Waterways 52,738,008 6,262,987
171 Equipment Costs 18,085,610 4,403,230
18 Roads, Railroads, and Bridges 819,192 309,805
19 Asset Retirement Costs 01 0
20 TOTAL cost (Total of 14 thru 19) 76,390,9741 13,976,361
21 Cost per KW of Installed Capacity (line 20/5) 195.12381 642.0010
22 Production Expenses
Operation Supervision and Engineering 404,945 272,806 23
24 Water for Power 271,901 686,421
25 Hydraulic Expenses 632,125 163,775
26 Electric Expenses 156,482 37,579
27 Misc Hydraulic Power Generation Expenses 534,981 32,552
28 Rents 53,355 0
29 Maintenance Supervision and Engineering 47,425 13,111
30 Maintenance of Structures 58,661 19,136
31 Maintenance of Reservoirs, Dams, and Waterways 294,579 38,130
32 Maintenance of Electric Plant 375,770 156,049
33 Maintenance of Misc Hydraulic Plant 1,002,621 106,508
34 Total Production Expenses (total 23 thru 33) 3,832,845 1,526,067
35 Expenses per net KWh 0.0018 0.0091
FERC FORM NO. I (REV. 12-03) Page 406.1
Name of Respondent
Idaho Power Company
This Re ort Is:
(1)An Original (2)EJ A Resubmissi on
Data of Report
(Mo, Da, Yr)
04/15/2013
Year/Period of Report
End of 2012/Q4
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5.The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses.'
6.Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC Licensed Project No. 2055
Plant Name: C J Strike
(d)
FERC Licensed Project No. 503
Plant Name: Swan Falls
(e)
FERC Licensed Project No. 18
Plant Name: Twin Falls
(f)
Line
No.
-
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 5274 5
93 23 511 6
8,780 8,754 6,8981 7
91 24 539
8
84 14 5010
5 4 4 11
464,505,000 127,279,000 166,426,000 12
5,476,746 51,675 255,499
13
14
9,266,487 25,469,343 10,891,616 15
10,697,169 13,856,887 7,908,870 16
12,306,266 30,416,395 20,731,334 17
248,183 835,946 1,917,603 18
0 0 019
37,994,851 70,630,246 41,704,922 20
458.8750 2,825.2098 790.7645 21
1,090,503 766,824 343,165
22
23
689,076 402,783 180,435 24
1,005,259 503,308 168,886 25
70,368 14,618 53,776 26
131,381 77,054 46,602 27
32,673 8,014 1,122 28
25,825 17,358 8,672 29
56,461 62,762 38,469 30
122,743 86,970 15,145 31
341,903 215,803 122,610 32
125,736 110,956 140,702 33
3,691,928 2,266,450 1,119,584 34
0.0079 0.0178 0.0067 35
FERC FORM NO. I (REV. 12-03) Page 407.1
Name of Respondent
Idaho Power Company
This Regort Is: Date of Report
04/15/2013
Year/Period of Report
End of 2012/Q4
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1.Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2.If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in
a footnote. If licensed project, give project number.
3.If net peak demand for 60 minutes is not available, give that which is available specifying period.
4.If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
Line
No.
-
Item
(a)
FERC Licensed Project No. 2777
Plant Name: Upper Salmon
(b)
FERC Licensed Project No. 2778
Plant Name: Shoshone Falls
(c)
11 Kind of Plant (Run-of-River or Storage) Run-of-River Run-of-River
2 Plant Construction type (Conventional or Outdoor) Outdoor Conventional
3 Year Originally Constructed 1937 1907
4 Year Last Unit was Installed 1947 1921
5 Total installed cap (Gen name plate Rating in MW) 34.50 12.50
6 Net Peak Demand on Plant-Megawatts (60 minutes) 351 14
7 Plant Hours Connect to Load 8,7841 6,035
8 Net Plant Capability (in megawatts)
(a) Under Most Favorable Oper Conditions 39 14 9
10 (b) Under the Most Adverse Oper Conditions 32 11
11 Average Number of Employees 4 2
12 Net Generation, Exclusive of Plant Use - Kwh 218,236,000 65,937,000
13 Cost of Plant
Land and Land Rights 202,399 313,328 14
15 Structures and Improvements 2,027,032 1,231,506
16 Reservoirs, Dams, and Waterways 5,569,171 512,402
17 Equipment Costs 8,693,529 4,550,600
18 Roads, Railroads, and Bridges 29,359 51,383
19 Asset Retirement Costs 0 0
20 TOTAL cost (Total of 14 thru 19) 16,521,490 6,659,219
21 Cost per KW of Installed Capacity (line 20 / 5) 478.8838 532.7375
22 Production Expenses
Operation Supervision and Engineering 547,441 286,537 23
24 Water for Power 337,882 139,168
25 Hydraulic Expenses 578,598 116,243
26 Electric Expenses 64,611 31,015
27 Misc Hydraulic Power Generation Expenses 86,664 35,336
28 Rents 0 30
29 Maintenance Supervision and Engineering 16,266 12,583
30 Maintenance of Structures 110,854 101,919
31 Maintenance of Reservoirs, Dams, and Waterways 171,031 901
32 Maintenance of Electric Plant 57,080 118,936
33 Maintenance of Misc Hydraulic Plant 96,409 69,371
34 Total Production Expenses (total 23 thru 33) 2,066,836 912,039
35 Expenses per net KWh 0.0095 0.0138
FERC FORM NO. I (REV. 12-03) Page 406.2
Name of Respondent
Idaho Power Company
This Re ort Is:
(2) E] A Resubmission
Date of Report
04/15/2013
Year/Period of Report
End of 20121Q4
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5.The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as 'Other Power Supply Expenses.'
6.Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC Licensed Project No. 1971
Plant Name: Common Facilities
(d)
FERC Licensed Project No. 2061
Plant Name: Lower Salmon
(e)
FERC Licensed Project No. 2899
Plant Name: Milner
(f)
Line
No.
-
Run-of-River Run-of-River I
Outdoor Conventional 2
1949 1992 3
1949 1992 4
0.00 60.00 59.45 5
0 60 59 6
0 8,7731 5,464 7
0 64 619
8
0 60 110
0 5 21 11
0 248,940,000 175,182,0001 12
114,367 424,428 138,100
13
14
26,681,738 2,826,153 10,354,284 15
13,556,785 6,920,148 17,114,934 16
1,792,250 8,062,473 27,720,868 17
99,051 88,693 501,877 18
0 01 01 19
42,244,191 18,321,8951 55,830,063 20
0.0000 305.36491 939.10961 21
0 681,142 395,884
22
23
0 285,885 1,716,901 24
6,559,288 240,393 79,771 25
0 95,961 34,738 26
78 78,931 65,495 27
0 1,311 1,553 28
0 22,026 12,366 29
0 60,939 115,036 30
0 5,757 7,949 31
0 336,611 118,770 32
130,569 106,936 56,008 33
6,689,935 1,915,892 2,604,471 34
0.0000 0.0077 0.0149 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)X An Original (Mo, Da, Yr)
Idaho Power Company (2)A Resubmission 04/15/2013 2012/Q4
FOOTNOTE DATA
American Falls generating capacity is dependent upon water releases controlled by the
tJSBR.
Schedule Page: 406 Line No.: I Column: e I
Cascade generating capacity is dependent upon water releases controlled by the USBR.
[Schedule Page: 406 Line No.: I Column: f 1
Upstream storage in Brownlee Reservoir
[Schedule Page: 406.1 Line No.: I Column: b I
Upstream storage in Brownlee Reservoir
[Schedule Page: 406.1 Line No.: I Column: c I
Lower Malad maximum demand 15,000 Kw, Upper Malad maximum demand 9,000 Kw non-coincident.
IFERC FORM NO. I (ED. 12-87) Page 450.1 1
Name of Respondent
Idaho Power Corn
This Report Is:
(1)JAn Original
(2) DA Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2013
Year/Period of Report
End of 2012/04
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
No.
-
Name of Plant
(a)
Year
Ong. Const.
(b)
Installed Capacity
Name Plate Ratint
(In MW)
(c)
Net Peak
Demand
' ()
•'
Net Generation
Excluding Plant Use
(e)
Cost of Plant
(f)
1 Hydro:
2 Clear Lakes 1937 2.50 2.3 16,883 1,759,923
3 Thousand Springs 1912 8.80 7.5 56,539 9,359,404
4
5
6 Internal Combustion:
7 Salmon Diesel (1) 1967 5.00 3.0 19 909,259
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
Idaho Power Company
This Re Ott Is:
(1)X An Original
(2)EA Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2013
Year/Period of Report
n 20121Q4
GENERATING PLANT STATISTICS (Small Plants) (Continued)
3. List plants appropriately under subheadings for steam, hydro, nuclear, internal combustion and gas turbine plants. For nuclear, see instruction 11,
Page 403. 4. If net peak demand for 60 minutes is not available, give the which is available, specifying period. 5. If any plant is equipped with
combinations of steam, hydro internal combustion or gas turbine equipment, report each as a separate plant. However, if the exhaust heat from the gas
turbine is utilized in a steam turbine regenerative feed water cycle, or for preheated combustion air in a boiler, report as one plant
Plant Cost (Incl Asset
Retire. Costs) Per MW
(g)
Operation
Exc'l. Fuel
(h)
Production Expenses
Kind of Fuel
(k)
Fuel Costs (in cents
(per Million Btu)
(I)
Line
Fuel
(I)
Maintenance
(j)
703,969 167,698 150,624 2
1,063,569 223,097 152,979 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
Idaho Power Company
This Re ort Is:
(2) AResubmission
Date of Report
04/15/2013
Year/Period of Report
End of 2012/Q4
TRANSMISSION LINE STATISTICS
1.Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2.Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3.Report data by individual lines for all voltages if so required by a State commission.
4.Exclude from this page any transmission lines for which plant costs are included In Account 121, Nonutility Property.
5.Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the
remainder of the line.
6.Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (1) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line
No
DESIGNATION VOLTAGE (Ky) (Indicate where
other than
60 cycle, 3 phase)
T f ype 0
Supporting
Structure
(e)
LENGTH (Pole miles) In the Cas1 of u dergroun hnes report Circuit miles)
Number
Of
Circuits
(h)
From
(a)
To
(b)
Operating
(c)
Designed
(d)
On structure
Des! of Lin? a ed
on jtructures ofiother
(g)
1 Borah Midpoint 345.0 500.00 Slower 85.17 1
2 Boardman Slatt 500.0c 500.00 Slower 1.79 1
3 Summer lake Hemingway 500.0 500.00 S Tower 0.40 1
4 Hemingway Midpoint 500.0 500.00 S Tower 0.37 1
5
6 Jim Bridger Goshen 345.0 345.00 Slower 226.16 1
7 State Line Midpoint 345.0 345.00 S Tower 76.04 2
8 Kinport Borah 3450 345.00 S Tower 27.10 1
9 Midpoint Borah #1 345.01 345.00 H Wood 79.31 1
10 Midpoint Borah #2 345.0 345.00 H Wood 77.58 2
11 Adelaide Tap Adelaide 345.01 345.00 H Wood 3.55 2
12
13 Quartz LaGrande 230.0 230.00 H Wood 46.27 1
14 Midpoint Hunt 230.04 230.00 Slower 0.70 2
15 Brady Antelope 230.04 230.00 H Wood 56.41 1
16 Brady Treasureton 230.04 230.00 H Wood 0.11 1
17 Brady #1 &#2 Kinport 230.04 230.00 STower 17.94 2
18 Jim Bridger Point of Rocks 230. 230.00 H Wood 1.40 1
19 Brownlee Ontario 230. T30-00 S Tower 72.74 1
20 More Bowmont 138. 230.00 S P Wood 9.91 1
21 More Bowmont 138.0 230.00 H Wood 8.82 1
22 Jim Bridger Point of Rocks 230.0 230.00 H Wood 2.79 1
23 Caldwell 710 Locust 230.01 230.00 SP Steel 18.59 1
24 Boise Bench Caldwell 230.0 230.00 Slower 7.58 1
25 Boise Bench Caldwell 230.0 230.00 H Wood 33.68 1
26 Boise Bench Cloverdale 230.0 230.00 S Tower 15.94 2
27 Boardman Dalreed Sub 230.0 230.00 H Wood 1.68 1
28 Brownlee 714 Oxbow 2300 230.00 SP Steel 11.05 2
29 Caldwell Ontario 230.01 230.00 H Wood 29.97 1
30 Caldwell Ontario 230.01 230.00 S Tower 3.27 1
31 Bennett Mtn PP Rattlesnake TS 230.0 230.00 SP Steel 4.44 1
32 Borah Hunt 230.0 230.00 H Steel 68.22 1
33 Danskin Hubbard 230.04 230.00 H Steel 36.25 1
34 Danskin Hubbard 230.01 230.00 SP Steel 1.90 1
35 Danskin Hubbard 230.01 230.00 SP Steel 1.30 2
36 TOTAL 4,778.911 11.02 190
FERC FORM NO. I (ED. 12-87) Page 422
Name of Respondent
Idaho Power Company
This Re ort Is:
(2) Ej A Resubmission
Date of Report
04/15/2013
Year/Period of Report
End of 2012/Q4
TRANSMISSION LINE STATISTICS (Continued)
7.Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8.Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9.Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10.Base the plant cost figures called for in columns (j) to (I) on the book cost at end of year.
Size of
Conductor
'1 Material an i
(i)
COST OF LINE (Include in Column (j) Land,
Land rights, and clearing right-of-way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES -
Line
i'0.
Land
(j)
Construction and
Other Costs (k)
Total Cost
(I)
Operation
Expenses
(m)
Maintenance
Expenses
(n)
Rents
(0)
Total
Expenses (p)
1272 ACSR 256,381 21,787333 22,043,714
XI780ACSR 446,708 446,708 2
1272 ACSR 836,006 836,006 3
1272 ACSR 4
5
1272 ACSR 483,301 16,889,111 17372,425 6
95ACSR 571,971 11,048,287 11,620,26 7
1272 ACSR 344,221 6,008,061 6,352,281 8
15.5 ACSR 283,14: 6,380,747 6,663,890 9
15.5 ACSR 64,851 12,281,414 12,346,265 10
15.5 ACSR 51,44 347,946 399,394 11
12
95ACSR 62,21 5,537,611 5,599,829 13
15.5 ACSR 9,14 998,452 1,007,597 14
1272 ACSR 108,301 3,058,249 3,166,550 15
95ACSR _ 6,186 6,186 16
15.5 ACSR 18,82 969,871 988,700 17
I272ACSR 1,191 51,525 52,715 18
X954 ACSR 1,676,83 20,541,790 22,218628 19
15.5 ACSR 413,79 2,198,731 2,612,524 20
15.5 ACSR 21
1272 ACSR 1,89 212,523 214,422 22
1590 ACSR 2,138,23' 8,775,086 10,913,322 23
1272 ACSR 1,748,21 7,009,570 8,757,784 24
715.5 ACSR 25
1272 ACSR 3,062,81 6,980,098 10,042,910 26
795 AAC 80,895 80,895 27
54 ACSR 34,17 16,026,470 16,060,644 28
X954 ACSR 236,15 9,192,894 9,429,046 29
1272 ACSR 30
1272 ACSR 81,701 1666,354 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
31,516,529 460,340,116 491,856,645 7,159,365 5,779,567 3,002,229 15,941,161 36
FERC FORM NO. I (ED. 12-87) Page 423
Name of Respondent
Idaho Power Company
This Mort Is:
(1)An Original
(2)[:]A Resubmission
Date of Report
(Mo, Da, Yr)
04115/2013
Year/Period of Report
End of 20121Q4
TRANSMISSION LINE STATISTICS
1.Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2.Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3.Report data by individual lines for all voltages if so required by a State commission.
4.Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
5.Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the
remainder of the line.
6.Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line
No
-
DESIGNATION VOLTAGE ) (Indicate where other than
60 cycle, 3 phase)
T of ype
Supporting
Structure
(e)
LENGTH (Pole Tiles) in me case ores u dergroun lin report circuit miles)
Number
Of
Circuits
(h)
From
(a)
To
(b)
Operating
(c)
Designed
(d)
on structure D of Line esinated
on sjructiires of other
(g)
I Danskin Bennett Mtn 230.0 230.00 SP Steel 5.37 1
2 Hemingway Bowmont 230.0 230.00 SP Steel 13.02 1
3 Langley Gulch Galloway Rd 138.0 230.00 SP Steel 14.19 1
4 Galloway Rd Willis Tap 138.0 230.00 SP Steel 2.09 1
5 Boise Bench Midpoint #1 230.0 230.00 S Tower 0.87 1
6 Boise Bench Midpoint #1 230.0 230.00 H Wood 108.49 1
7 Brownlee Quartz Jct 230.1 230.00 S Tower 1.51 1
8 Brownlee Quartz Jct 230.0 230.00 H Wood 41.32 1
9 Brownlee Boise Bench #1 & #2 230.0 230.00 S Tower 99.76 2
10 Oxbow Brownlee 230.0 230.00 Slower 10.40 2
11 Boise Bench Midpoint #2 230.0 230.00 Slower 3.49 1
12 Boise Bench Midpoint #2 230.1 230.00 H Wood 102.07
13 Oxbow Pallette Jct 230.04 230.00 Slower 20.08
14 Pallette Jct Imnaha 230.04 230.00 H Wood 24.43
15 Hells Canyon Palette Jct 230.04 230.00 Slower 9.04
16 Brownlee Boise Bench 230.04 230.00 Slower 102.54
17 Boise Bench Midpoint #3 230.0 230.00 H Wood 106.30
18 Palette Jct Enterprise 230.0 230.00 H Wood 29.60 1
19 Borah Brady #2 230.0 230.00 Slower 0.41 1
20 Borah Brady #2 230.0 230.00 H Wood 3.56 1
21 Borah Brady #1 230.0 230.00 H Wood 3.87 1
22
23 Goshen State Line 1610 161.00 H Wood 90.60 1
24 Don Goshen 161.0 161.00 Slower 2.37 2
25 Don Goshen 161.0 161.00 H Wood 48.43 2
26
27 American Falls Power Plant Adelaide 138.04 138.00 H Wood 11.22 2
28 American Falls Power Plant Adelaide 138.0 138.00 5 P Wood 0.12 2
29 Minidoka Loop Adelaide 138.0 138.00 Slower 1.13 2
30 Nampa Caldwell 138.0 138.00 SPWood 11.10 2
31 Upper Salmon Mountain Home Jct 138.0 138.00 H Wood 54.35 1
32 Upper Salmon Cliff 138.0 138.00 HWood 30.81 1
33 Eastgate Russet 138.0 138.00 SPWood 2.08 1
34 Brady Fremont 138.0 138.00 Slower 1.00 2
35 Brady Fremont 138.0 138.00 H Wood 24.32 2
36 ITOTAL 1 4,778.911 11.021 190
FERC FORM NO. I (ED. 12-87) Page 422.1
Name of Respondent
Idaho Power Company
This Re ort Is:
(2) [:]A Resubmission
Date of Report
04/15/2013
Year/Period of Report
End of 2012/Q4
TRANSMISSION LINE STATISTICS (Continued)
7.Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8.Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9.Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10.Base the plant cost figures called for in columns (j) to (I) on the book cost at end of year.
Size of
Conductor
an Material
(i)
COST OF LINE (Include in Column U) Land,
Land rights, and clearing right-of-way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES -
Line
i'&O.
Land
U)
Construction and
Other Costs (k)
Total Cost
(I)
Operation
Expenses
(m)
Maintenance
Expenses
(n)
Rents
(o)
Total
Expenses (p)
1590 ACSR 3528,033 3,528,033 1
1590 ACSR 1,854,99' 9,212,985 11,067,981 2
1590 ACSR 948,161 9,078,827 10,026,993 3
1272 ACSR 4
15.5 ACSR 385,28 5,595,136 5980,423 5
15.5 ACSR 6
795 ACSR 53,061 2,799,473 2,852,541 7
95ACSR 8
VARIOUS 289,93 9,016,582 9,306,516 9
272ACSR 14,811 1,241,047 1,255,857 10
15.5 ACSR 227,821 6,920,209 7,148,034 11
VARIOUS 12
272 ACSR 87,461 2,171,101 2,258,569 13
I272ACSR 171,081 1,540,515 1,711,596 14
I272ACSR 44,687 1,252,130 1,296,817 15
54 ACSR 185,106 6,269,304 6,454,410 16
715.5 ACSR 247,857 11,784,046 12031,903 17
1272 ACSR 84,01 1,881,398 1,965,412 18
1272 ACSR 3,06 416,606 419,674 19
715.5 ACSR 20
1272 ACSR 10,06' 311,349 321,413 21
22
50 COPPER 16,15 648,382 664,537 23
715.5 ACSR 76,041 1,737,526 1,813,567 24
97.5 ACSR 25
26
50 COPPER 26,50' 338,681 365,188 27
50 COPPER 28
715.5 ACSR 21,32 249,232 270,559 29
795AAC 646,11 3,152,590 3,798,702 30
795ACSR 47,68 3,545,932 3,593,619 31
95 ACSR 43,56E 913,613 957,181 32
795 AAC 270,82 557,504 828,327 33
VARIOUS 564,93 3,768,756 4,333,688 34
VARIOUS 35
31,516,529 460,340,116 491,856,6451 7,159,365 5,779,567 3,002,229 15,941,1611 36
FERC FORM NO. 1 (ED. 12-87) Page 423.1
Name of Respondent
Idaho Power Company
This Report Is:
An
' RssiOn
Date of Report Year/Period of Report
End of 20121Q4
TRANSMISSION LINE STATISTICS
1.Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2.Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3.Report data by individual lines for all voltages if so required by a State commission.
4.Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
5.Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the
remainder of the line.
6.Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line
No
DESIGNATION VOLTAGE (KV) (Indicate where other than 60 cycle, 3 phase)
T f ype 0
Supporting
Structure
(e)
LENGTH (Pole miles) In the case of u dergoui lines report circuit miles)
Number
Of
Circuits
(h)
From
(a)
To
(b)
Operating
(c)
Designed
(d)
On Structure
DIL?ed
f)
On "itrupWres of orthe
(g)
11 Brady Fremont 138.00 138.00 S P Wood 24.33 2
2 King Lower Malad 138.0 138.00 H Wood 84.78 2
3 Emmett Jct Payette 138.0q 138.00 H Wood 66,41 2
4 Mountain Home AFB Tap 138.0 138.00 H Wood 6.20 1
5 Ontario Quartz 138.0 138.00 H Wood 73.40 1
_6 King American Falls PP 138.0 138.00 Slower 1.01 2
7 King American Falls PP 138.0 138.00 H Wood 141.74 1
_8 King American Falls PP 138.0 138.00 S P Wood 3.71 1
9 Duffln Clawson 138.0 138.00 H Wood 6.22 1
10 American Falls Brady Tie 138.0 138.00 H Wood 0.33 1
11 Upper Salmon A-B King 138.0 138.00 H Wood 5.66 1
121 Upper Salmon B Wells 138.0 138.00 H Wood 125.59 1
13 King Wood River 138.0 138.00 H Wood 73.74 1
14 Boise Bench Grove 138.0 138.00 S P Wood 10.58 2
15 Quartz John Day 138.0 138.00 H Wood 67.32 1
16 Sinker Creek Tap 138.0 138.00 H Wood 2.80 1
17 Mom Cloverdale 138.0 138.00 H Wood 2.511 1
18 Mom Cloverdale 138.0 138.00 SPWood 22.28 1
19 Mom Cloverdale 138.04 138.00 5 P Steel 0.96 2
20 Stoddard Jct Stoddard Sub 138.04 138.00 S P Steel 3.80 1
21 Fossil Gulch Tap 138.0 138.00 H Wood 1.95 1
22 Wood River Midpoint 138.0 138.00 H Wood 53.08 2
23 Wood River Midpoint 138.0 138.00 S P Wood 16.69 2
24 Oxbow McCall 138.0 138.00 H Wood 37.15 1
25 Oxbow McCall 138.0 138.00 S P Wood 2.32 1
26 Lowell Jct Nampa 138.0 138.00 S P Wood 7.50 2
27 Hunt Milner 138.0 138.00 SPWood 19.40 1
28 Strike Bruneau Bridge 1380 138.00 H Wood 13.50 1
29 American Falls Kramer Sub 138.0 138.00 SPWood 18.47 2
30 Pingree Haven 138.0 138.00 SPWood 11.72 1
31 Midpoint Twin Falls 138.0 138.00 S P Wood 25.20 2
32 Twin Falls Russett 138.0 138.00 S P Wood 1.72 1
33 Blackfoot Aiken 46.0 138.00 SPWood 6.17 2
34 Peterson Tendoy 69.0 138.00 H Wood 57.23 1
35 Eastgate Tap Eastgate 138.0 138.00 S P Wood 6.36 1
36 TOTAL 4,778.91 11.02 190
FERC FORM NO. 1 (ED. 12-87) Page 422.2
Name of Respondent
Idaho Power Company
This Re ort Is:
(2) []A Resubmission
Date of Report
04/15/2013
Year/Period of Report
End of 2012/Q4
TRANSMISSION LINE STATISTICS (Continued)
7.Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8.Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses bome by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9.Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10.Base the plant cost figures called for in columns (j) to (I) on the book cost at end of year.
Size of
Conductor
and Material
(I)
COST OF LINE (include in Column (j) Land,
Land rights, and clearing right-of-way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES -
Line
No.
Land
(j)
Construction and
Other Costs (k)
Total Cost
(I)
Operation
Expenses
(m)
Maintenance
Expenses
(n)
Rents
(0)
Total
Expenses
(p)
VARIOUS T
VARIOUS 76,823 2,302,594 2,379,417 2
VARIOUS 30,91 2511,404 2,542,322 3
97.5ACSR 1,95 6,930 8,885 4
VARIOUS 34,42f 4,811,314 4,845,742 5
715.5 ACSR 216,91 8,271,471 8,488,390 6
715.5 ACSR 7
115.5 ACSR 8
4,191 309,857 314,048 9
54 ACSR 96,921 96,921 10
50 COPPER 2,741 122,591 125,332 11
ARIOUS 28,49 2,150,317 2,178,807 12
ARIOUS 173,68 3,037,531 3,211,214 13
ARIOUS 225,60 1,652,772 1,878,374 14
97.5 ACSR 92,17 2,362,416 2,454,589 15
VARIOUS 2 77,199 77,219 16
15.5 ACSR 3,123,38 8,219,053 11,342,433 17
VARIOUS 18
95AAC 19
1272 ACSR 20
50 COPPER 451 187,848 188,298 21
97.5 ACSR 349,7t 7,062,297 7,412,00t 22
97.5 ACSR 23
97.5 ACSR 109,89 2,306,969 2,416,868 24
97.5 ACSR 25
15.5 ACSR 211,131 1,448,294 1,659,421 26
15.5 ACSR 3,32 1,430,523 1,433,847 27
97.5 ACSR 14,92 587,404 602,331 28
15.5 ACSR 13,73' 1,051,324 1,065,058 29
97.5 ACSR 18,22 1,276,855 1,295,078 30
VARIOUS 54,84 3,084,397 3,139,245 31
715.5 ACSR 16,7 206,158 222,948 32
715.5 ACSR 13,611 491,359 504,975 33
97.5 ACSR 395,691 3,449,949 3,845,64 34
715.5 ACSR 343,95 2,137,516 2,481,471 35
31,516,529 460,340,116 491,856,645 7,159,365 . 5,779,5671 3,002,229 15,941,161 36
FERC FORM NO. I (ED. 12-87) Page 423.2
Name of Respondent
Idaho Power Company
This Re ort Is:
(2) AResubmission
Date of Report
04/15/2013
Year/Period of Report
End of 20121Q4
TRANSMISSION LINE STATISTICS
1.Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2.Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3.Report data by individual lines for all voltages if so required by a State commission.
4.Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
5.Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the
remainder of the line.
6.Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line
No
DESIGNATION VOLTAGE (KV) (Indicate where other than
60 cycle, 3 phase)
Type o
Supporting
LENGTH (Pole miles) me case ot u ergroufl lines report circuit miles)
Number
Of
Circuits
(h)
From To Operating Designed Structure
Ofl Structure
Deal

On triires

of er
1 Kimberly Tap Kimberly 138.0 138.00 SPSteel 1.83 2
2 Boise Bench Mora 138,0 138.00 H Wood 13.15 2
3 Bowmont-Caldwell Simplot Sub 138.00, 138.00 S P Wood 0.51 1
4 Gary Lane Eagle 138.04 138.00 SPWood 6.53 1
5 Locust Grove Blackcat Sub 138.04 138.00 S P Steel 9.24 2.98 1
6 Boise Bench Butler 138.04 138.00 S P Wood 0.14 4.02 1
71 Eagle Star 138.04 138.00 SPWood 6.37 1
8 Karcher Sub Zilog Tap 138.0 138.00 S P Steel 2.08 1
9 Cloverdale -712 712- Wye 138.0 138.00 SPSteel 0.42 4.02 1
10 Victory Jet Victory 138.0 138.00 SPSteel 1.90 1
11 Butler Wye 138.0 138.00 S P Steel 2.94 1
12 Horsefiat Starkey 138.0 138.00 H Wood 34.53 1
13 Starkey McCall 138.0 138.00 S P Steel 2.08 2
14 Starkey Mccall 138.0 138.00 H Wood 3.80 1
15 Starkey McCall 138.0 138.00 SPSteel 1.50 1
16 Starkey McCall 138.0 138.00 SPWood 17.61 1
17 Chestnut Happy Valley 138.0 138.00 SPSteel 2.79 1
18 Garnet Ward 138.00
19 McCall Lake Fork 138.0 138.00 S P Wood 8.89 1
20 McCall Lake Fork 138.0 138.00 5 Steel 2.90
21 Caldwell Willis 138.0 138.00 SPSteel 1.30 1
22 Caldwell Willis 138.0 138.00 S P Steel 1.59 1
23 Caldwell Willis 138.01 138.00 SPWood 0.87 1
24 Valivue Tap 138.01 138.00 SPSteel 0.80 2
25 Bowmont Happy Valley 138.01 138.00 S P Steel 1
26 Kinport Don #1 138.01 138.00 S Tower 1.24 2
27 Donn HOKU 138.01 138.00 S P Steel 2.68 1
28 HOKU Alamed 138.01 138.00 S P Steel 0.22 2
29 HOKU Alamed 138.01 138.00 SPSteel 0.23 2
30 HOKU Alamed 138.01 138.00 S P Steel 2.85 1
31 Rockland Jet Rockland Wind Farm 138.01 138.00 5 P Steel 5.29 1
32 King Justice 138.01 138.00 SPWood 0.11 1
33 Twin Falls PP Tap 138.01 138.00 H Wood 0.82 1
34 American Falls PP Amerdan Falls Trans ST 138.01 138.00 S P Steel 0.37 1
35 Lower Salmon King Tie 138.01 138.00 H Wood 0.11 1
36 1 ITOTAL 1 47778.91 11.02 190
FERC FORM NO. I (ED. 12-87) Page 422.3
Name of Respondent
Idaho Power Company
This Re ort Is: Date of Report
04/15/2013
Year/Period of Report
End of 2012/Q4
TRANSMISSION LINE STATISTICS (Continued)
7.Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8.Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses bome by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9.Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10.Base the plant cost figures celled for in columns (j) to (I) on the book cost at end of year.
Size of
Conductor
COST OF LINE (include in Column (j) Land,
Land rights, and clearing right-of-way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES -
and Material
(I)
Land
(j)
Construction and
Other Costs (k)
Total Cost
(I)
Operation
Expenses (m)
Maintenance
Expenses
(n)
Rents
(°)
Total
Expenses
(p)
Line
'4O.
'95 ACSR I
15.5 ACSR 14,69 637,273 651,970 2
95 AAC 49,642 49,642 3
795AAC 489,03 2,177,222 2,666,259 4
1272 ACSR 935,72 3605,765 4,541,490 5
1272 ACSR 34,68 838,605 873,292 6
715.5 ACSR 179,81 2,909,434 3,089,251 7
795AAC 43,03 434,341 477,376 8
1272 ACSR 140,41 2,577,075 2,717,487 9
I272ACSR 10
795 ACSR 134,471 1,405,436 1,539,907 11
715.5 ACSR 2,473,83 18,402,119 20,875,952 12
715,5 ACSR 13
715.5 ACSR 14
715.5 ACSR 15
715.5 ACSR 16
1272 ACSR 78,57 1,821,921 1,900,500 17
40,58 40,580 18
715.5 ACSR 331,53 4,682,879 5,014,418 19
20
1272 ACSR 272,231 2,141,218 2,413,449 21
795ACSR 22
795ACSR 23
795ACSR 351,497 351,497 24
1272 ACSR 377,29 377,296 25
715.5 ACSR 1,17 212,777 213,951 26
1272 ACSR 19 398 588 27
1272ACSR 28
'95ACSR 29
'95ACSR 30
195 ACSR -11,446 -11,446 31
1590 ACSR 70,224 70,224 32
250 COPPER 5 64,441 64,499 33
115.5 ACSR 76,560 76,560 34
497.5 ACSR 4,406 4,406 35
31,516,5291 460,340,1161 491,856,6451 7,159,365 5,779,567 3,002,229 15,941,1611 36
FERC FORM NO. 1 (ED. 12-87) Page 423.3
Name of Respondent
Idaho Power Company
This Report Is:
(2) AResubrnission
Date of Report
04/15/2013
Year/Period of Report
End of 2012/Q4
TRANSMISSION LINE STATISTICS
1.Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2.Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3.Report data by individual lines for all voltages if so required by a State commission.
4.Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
5.Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction It a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the
remainder of the line.
6.Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line
No.
DESIGNATION VOLTAGE (KV)
(Indicate where other than
60 cycle, 3 phase)
Type o
Supporting
Structure
(e)
LENGTH (Pole riles) n the case ot u dergroun lines
report circuit miles)
Number
Of
Circuits
(h)
From
(a)
To
(b)
Operating
(c)
Designed
(d)
On Structure
D Lin?ed
On tniures of
(g)
1 C J Strike Strike Jct 138.00 138.00 S Tower 4.32 2
2 Strike Jot Mountain Home Jot 138.00 138.00 H Wood 23.44 1
3 Strike Jct Bowmont 138.00 H Wood 0.05 1
4 Strike Jot Bowmont 138.0 138.00 S Tower 0.36 1
5 Strike Jot Bowmont 138.0 138.00 H Wood 68.24 1
6 Lucky Peak Lucky Peak Jot 138.0 138.00 H Wood 4.48 2
71 Bliss King 138.0 138.00 H Wood 10.48 1
8 Milner Deadend Milner PP 138.0 138.00 S p Wood 1.31 1
9 Swan Falls Tap 138.0 138.00 H Wood 1.00 1
10
11
12
13 Hines BPA(Hamey) 115.0 115.00 HWood 3.35 1
14
15
16 69 Ky Lines 69.0 69.00 H Wood 167.03 1
17 69 Ky Lines 69.0 69.00 S P Wood 938.98 1
18
19
20 46 Ky Lines 46.00 46.00 S p Wood 407.98 1
21
22 Total all lines 4,778.91 11,02 190
23
24
25
26
27
28
29
30
31
32
33
34
35
36 ITOTAL 1 4,778.911 11.02 190
FERC FORM NO. I (ED. 12-87) Page 422.4
Name of Respondent
Idaho Power Company
This Re ort Is:
Resubmission
Date of Report
//213
Year/Period of Report
End of 2012/Q4
TRANSMISSION LINE STATISTICS (Continued)
7.Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8.Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses bome by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9.Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10.Base the plant cost figures called for in columns (j) to (I) on the book cost at end of year.
Size of
Conductor
and Material
(i)
COST OF LINE (Include in Column U) Land,
Land rights, and clearing right-of-way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES -
Line
No.
Land
U)
Construction and
Other Costs
(k)
Total Cost
(I)
Operation
Expenses
(m)
Maintenance
Expenses
(n)
Rents
(0)
Total
Expenses
(p)
15.5 ACSR 1,07 398,891 399,965 1
97.5 ACSR 4,35 2,259,099 2,263,454 2
15.5 ACSR 86,651 1,866,338 1,952,989 3
15.5 ACSR 4
5
15.5 ACSR 279,481 279,488 6
15.5 ACSR 5,62 997,718 1,003338 7
15.5 ACSR 2,814 183,606 186,420 8
97.5ACSR 12,88 261,5 1 1 274,396 9
10
11
12
97.5 ACSR 1,97 63,404 65,382 13
14
15
VARIOUS 1,507,28 51,235,189 52,742,476 16
VARIOUS 17
18
19
VARIOUS 194,53 14,758,767 14,953,303 20
21
7,159,365 5,779,567 3,002,229 15,941,161 22
23
24
25
26
27
28
29
30
31
32
33
34
35
31,516,529 460,340,116 491,856,645 7,159,365 5,779,5671 3,002,2291 15,941,161 36
FERC FORM NO. 1 (ED. 12-87) Page 423.4
Name of Respondent
Idaho Power Company
This Report Is:
(1)jAn Original
(2)flA Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2013
Year/Period of Report ° 20121Q4
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 (o), it is permissible to report in these columns the
Line
No.
-
LINE DESIGNATION Llh eng
Miles
(c)
SUPPORTING STRUCTURE CIRCUITS PER STRUCTUR
From
(a)
To
(b)
Type
(d)
Number per
Miles
(e)
Present
(f)
Ultimate
(g)
I Langley Gulch Galloway Rd (str. #117) 14.26 s pole 8.13 1
2 Galloway Rd Willis Tap 2.09 s pole 15.70 1
3
4 King Justice 0.11 w pole 36.03 1
5
6 Bowmont Happy Valley 8.60 s pole 1
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44 TOTAL 25.06 59.86 4
FERC FORM NO. I (REV. 12-03) Page 424
Name of Respondent
Idaho Power Company
This Re ort Is:
(2) A Resubmission
Date of Report
04/15/2013
Year/Period of Report
End of 201 2/Q4
TRANSMISSION LINES ADDED DURING YEAR (Continued)
costs. Designate, however, if estimated amounts are reported. Include costs of Clearing Land and Rights-of-Way, and Roads and
Trails, in column (I) with appropriate footnote, and costs of Underground Conduit in column (m).
3. If design voltage differs from operating voltage, indicate such fact by footnote; also where line is other than 60 cycle, 3 phase,
indicate such other characteristic.
CONDUCTORS voltage
KV
(Operating) (k)
LINE COST Line
No.
-
Size
(h)
Specification
(i)
Configuration
and Spacing
(j)
____________________
Land and
Land Rights
(I)
Poles, Towers
and Fixtures
(m)
Conductors
and Devices
(n)
Asset
Retire. Costs
(0)
Total
(p)
1590 ACSR TAS-BP&H-FRA 138 948,166 5,447,29E 3,631,531 10,026,993 1
1272 ACSR TAS 138 2
3
1590 ACSR TVS-BP 138 24,53 45,694 70,224 4
5
1272 ACSR TVS 138 377,29 377,296 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
948,166 5,849,122 3,677,225 10,474,513 44
FERC FORM NO. 1 (REV. 12-03) Page 425
Name of Respondent
Idaho Power Company
This Re ort Is:
(2) EJ AResubmission
Date of Report
04115/2013
Year/Period of Report
End of 20121Q4
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3.Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4.Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line
No
-
Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (In MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
I Adelaide transmission 345.00 138.00 13.80
2 Aiken distribution 46.00 13.00
3 Alameda distribution 46.00 13.00
4 Alameda distribution 138.00 13.09
5 American Falls PP - attended transmission 138.00 13.80
6 American Falls transmission 138.00 46.00 12.47
7 Artesian distribution 46.00 13.00
8 Bannock Creek distribution 46.00 13.00
9 Bennett Mountain Power Plant- attended transmission 230.00 18.00
IC) Bennett Mountain Power Plant- attended distribution 18.00 4.16
11 Bethel Court distribution 138.00 13.00
12 Black Cat distribution 138.00 13.09
13 Blackfoot distribution 46.00 13.00
14 Blackfoot transmission 161.00 46.00 12.47
15 Blackfoot distribution 161.00 138.00 12.98
16 Bliss -attended transmission 138.00 13.80
17 Blue Gulch distribution 138.00 35.00
18 Boise Bench - attended transmission 230.00 138.00 13.20
19 Boise Bench - attended distribution 138.00 35.00
20 Boise Bench - attended transmission 138.00 69.00 12.98
21 Boise Bench - attended transmission 230.00 138.00 13.80
22 Boise distribution 138.00 13.00
23 Borah transmission 345.00 230.00 13.80
24 Bowmont distribution 69.00 46.00 6.90
25 Bowmont distribution 138.00 35.00
26 Bowmont transmission 138.00 69.00 12.98
27 Bowmont transmission 138.00 69.00 12.47
28 Bowmont transmission 230.00 138.00 13.80
29 Brady distribution 46.00 13.00
30 Brady transmission 230.00 138.00 13.80
31 Brady transmission 138.00 46.00 12.47
32 Brady distribution 69.00 13.00
33 Brownlee - attended transmission 230.00 13.80
34 Bruneau Bridge distribution 138.00 35.00
35 Buckhom distribution 69.00 35.00
36 Bucyrus distribution 46.00 7.20
37 Buhl distribution 46.00 13.00
38 Burley Rural distribution 69.00 13.00
39 Butler distribution 138.00 13.09
40 Caldwell distribution 138.00 13.00
FERC FORM NO. 1 (ED. 12-96) Page 426
Name of Respondent
Idaho Power Company
This Re ort Is:
(2) n A Resubmission
Date of Report
04/15/2013
Year/Period of Report
End of 20121Q4
SUBSTATIONS (Continued)
5.Show in columns (I), U) and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6.Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(In Service) (In MVa)
(f
Number of
Transformers
In Service
(g)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No. - Type of Equipment
(i)
Number of Units
a)
Total Capacity
(k)
300 2 1
20 2 2
15 1 3
18 1
72 1
25 1 6
10 1 7
10 1 8
135 1 9
5 1
15 1
24 1 12
30 2
50 3 1 14
80 1 15
69 3
15 1
254 2 18
42 2 ig
75 3 20
240 2
67 3
450 3 1
8 3 _ 18 1
25 1 26
25 1
180 1 28
5 29
312 3
1 32
721 _ 5 1
30 2 34
20 1 35
6 1 1 36
20 2
12 1 38
48 2 39
15 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427
Name of Respondent
Idaho Power Company
This Re ort Is:
2iIO fl T Date of Report
04/15/2013
Year/Period of Report
End of 20121Q4
SUBSTATIONS
I. Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3.Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4.Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line
No
-
Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (In MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
I Caldwell transmission 230.00 138.00
2 Caldwell distribution 138.00 13.09
3 Caldwell transmission 138.00 69.00 12.47
4 Caldwell transmission 230.00 138.00 12.47
5 Caldwell distribution 13.00 4.16
6 Canyon Creek distribution 138.00 35.00
7 Canyon Creek transmission 138.00 69.00 12.98
8 Cascade Power Plant - attended transmission 69.00 4.60
9 Cascade distribution 69.00 13.10
10 Chestnut distribution 138.00 13.00
11 Clear Lake - attended transmission 46.00 2.40
12 Cliff transmission 138.00 46.00 12.50
13 Cliff transmission 138.00 46.00 12.95
14 Cloverdale distribution 138.00 13.00
15 Dale distribution 46.00 4.60
16 Dale distribution 46.00 13.00
17 Dale distribution 69.00 13.00
18 Dale distribution 138.00 36.20
19 Dale transmission 138.00 46.00 12.47
20 Danskin- attended transmission 230.00 18.00
21 Danskin- attended transmission 230.00 138.00 13.80
22 Danskin- attended distribution 18.00 4.16
23 Danskin- attended transmission 138.00 12.00
24 Danskin- attended distribution 35.00 13.80
25 Don distribution 138.00 7.60
26 Don distribution 138.00 13.20
27 Don distribution 138.00 13.00
28 Don distribution 14.00
29 DRAM distribution 138.00 13.09
30 DRAM transmission 230.00 138.00 13.80
31 DRAM distribution 138.00 12.47
32 Duffin distribution 138.00 35.00
33 Eagle distribution 138.00 13.09
34 Eastgate distribution 138.00
35 Eastgate distribution 138.00 13.00
36 Eckert distribution 138.00 36.20
37 Eden distribution 138.00 36.20
38 Eden transmission 138.00 46.00 12.98
39 Elkhom distribution 138.00 12.47
40 Elkhorn distribution 138.00 13.00
FERC FORM NO. I (ED. 12-96) Page 426.1
Name of Respondent
Idaho Power Company
This Re ort is:
(2) M A Resubmission
Date of Report
04/15/2013
Year/Period of Report
End of 2012/Q4
SUBSTATIONS (Continued)
5.Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6.Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(In Service) (In MVa)
Number of
Transformers
In Service
Number of
Spare
Transformers
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Ui,e
No. Type of Equipment Number of Units Total Capacity
120 1 1
24 1 2
75 3 3
120 1 4
-
15 1 6
15 1 7
12 1 8
10 1
48 2
4 1 11
12 2 1
4 1
48 2 14
1 - 15
6
1 -
27 1 18
25 1 19
140 1 20
180 1
6 1 22
96 2 23
5 1 24
1 25
108 6 3
26 1 1
80 6
118 7 29
160 2
17 1 31
36 2 32
38 2 33
24 1 34
18 1 35
18 1 36
24 1
15 1 38
8 1 39
8 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.1
Name of Respondent
Idaho Power Company
This Re ort Is:
(2) M A Resubmission T Date of Report
04/15/2013
Year/Period of Report
End of 2012/04
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3.Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4.Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line
N0.
-
Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (In MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
I Elmore distribution 138.00 35.00
2 Elmore transmission 138.00 69.00 12.50
3 Elmore transmission 138.00 69.00 12.98
4 Emmett distribution 138.00
5 Emmett transmission 138.00 69.00 12.47
6 Falls distribution 46.00 13.00
7 Filer distribution 46.00 13.00
8 Flying H distribution 69.00 2.40
9 Fort Hall distribution 46.00 13.00
10 Fossil Gulch distribution 138.00 35.00
11 Fremont transmission 138.00 46.00 12.50
12 Gary distribution 138.00 13.09
13 Gary distribution 138.00 13.00
14 Gem distribution 69.00 13.00
15 Gem distribution 69.00
16 Goodng Rural distribution 46.00 13.00
17 Golden Valley distribution 69.00 13.00
18 Gowen Substation distribution 138.00 35.00
19 Grindstone distribution 35.00
20 Grove distribution 138.00 13.09
21 Grove distribution 138.00 13.00
22 Hagerman distribution 46.00 13.00
23 Hagerman distribution 46.00 13.00 32.00
24 Halley distribution 138.00 13.00
25 Happy Valley distribution 138.00 13.09
26 Haven distribution 138.00 35.00
27 Haven transmission 138.00 46.00
2 transmission 500.00 230.00 34.50
29 Hewlett Packard distribution 138.00 13.00
30 Hidden Springs distribution 138.00 13.00
31 Highland distribution 138.00 13.00
32 Hill distribution 138.00 13.00
33 Hillsdale distribution 138.00
34 Hoku distribution 138.00 13.80
35 Homedale distribution 69.00 13.00
36 Horse Flat transmission 230.00 138.00 13.80
37 Horseshoe Bend distribution 35.00
38 Horseshoe Bend distribution 69.00 36.20
39 Horseshoe Bend distribution 69.00 25.00
40 Huston distribution 69.00 13.00
FERC FORM NO. 1 (ED. 12-96) Page 426.2
Name of Respondent
Idaho Power Company
This Re oct Is:
(2) AResubmission
Date of Report
04/15/2013
Year/Period of Report
End of 2012/Q4
SUBSTATIONS (Continued)
5.Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6.Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(In Service) (In MVa)
(f)
Number of
Transformers
In Service
(g)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No. - Type of Equipment
(i)
Number of Units
(I)
Total Capacity
(k)
17 1 1
15 1 2
15 1
24 1 4
25 1
18 2 6
10 1 7
15 2 8
10 1 1
15 1 —To.
50 3 1
20 1 12
17 1
8 1
10 1
15 2 16
10 1 1
24 1 18
5 2
48 2 20
24 1
10 1 22
5 1
20
_
1 24
18 1 25
12 1
25 1 27
600 3 1
20 1
8 1 30
18 1 31
39 2
24 1 33
2
22 2 35
100 1
5 1 __—ay
12
_
1 38
5 1
10 1 -
FERC FORM NO. I (ED. 12-96) Page 427.2
Name of Respondent
Idaho Power Company
This Re ort Is:
2SSIon
Date of Report Year/Period of Report
End of 2012/04
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3.Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4.Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line
N
-
Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (In MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 Hulen distribution 46.00 13.00
2 Hunt transmission 230.00 138.00 13.80
3 Hydra distribution 138.00 36.20
4 Island distribution 69.00 13.00
5 Jerome distribution 138.00 13.00
6 Jerome distribution 138.00 13.09
7 Julion Clawson distribution 138.00 35.00
8 Joplin distribution 138.00 13.00
9 Joplin distribution 138.00 35.00
10 Justice transmission 230.00 138.00 13.80
11 Karcher distribution 138.00 13.00
12 Kenyon distribution 69.00 13.00
13 Ketchum distribution 138.00 13.00
14 Kimberly distribution 138.00 13.00
15 Kinport transmission 161.00 46.00 13.20
16 Kinport transmission 230.00 138.00 12.47
17 Kinport transmission 230.00 138.00 13.80
18 Kinport transmission 345.00 230.00 13.80
19 Kramer distribution 138.00 35.00
20 Kramer distribution 138.00 36.20
21 Kuna distribution 138.00 13.00
22 Lake Fork distribution 138.00 36.20
23 Lake Fork transmission 138.00 69.00 12.50
24 Lamb distribution 138.00 13.00
25 Langley Gulch- attended transmission 230.00 138.00 13.80
26 Langley Gulch- attended transmission 230.00
27 Langley Gulch- attended distribution 4.16
28 Langley Gulch- attended distribution 13.00 4.16
29 Lansing distribution 69.00 13.00
30 Lincoln distribution 138.00 13.09
31 Linden distribution 138.00 13.00
32 Locust distribution 138.00 36.20
33 Locust transmission 230.00 138.00 13.80
34 Lower Malad - attended transmission 138.00 7.20
35 Lower Salmon - attended transmission 138.00 13.80
36 Map Rock distribution 69.00 13.00
37 McCall distribution 13.00 13.09
38 McCall distribution 138.00 36.20
39 Meridian distribution 138.00 13.00
40 Micron distribution 138.00 13.09
FERC FORM NO. I (ED. 12-96) Page 426.3
Name of Respondent
Idaho Power Company
This Re ort Is:
ARubmiion
Date of Report
04/15/2013
Year/Period of Report
End of 2012/Q4
SUBSTATIONS (Continued)
5.Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6.Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(In Service) (In MVa)
(f)
Number of
Transformers
In Service
(g)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.
-
Type of Equipment
(i)
Number of Units
(j)
Total Capacity
(k)
10 1 1
300 3 2
48 2 3
12 1 4
20 1 5
20 1 6
30 2
15 1 8
18 1 9
180 1
12 1 11
20 2 12
42 2
18 1 14
7 15
180 1 16
180 1
600 3 1 18
12 1 19
18 1
15 1
18 1 22
15 1 23
18 1 24
180 1 25
246 2
12 1 27
12 1 28
12 1
10 1
33 2 31
48 2 32
360 2 33
16 1
70 4 35
10 1
12 1
18 1
36 2
24 2 40
FERC FORM NO. I (ED. 12-96) Page 427.3
Name of Respondent
Idaho Power Company
This Re ort Is: Date of Report
04/15/2013
Year/Period of Report
End of 2012/Q4
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3.Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4.Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (U.
Line
N 0.
-
Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (In MVa)
Primary
(C)
Secondary
(d)
Tertiary
(e)
1 Micron distribution 138.00 13.00
2 Midpoint transmission 230.00 138.00 13.80
3 Midpoint transmission 345.00 230.00 13.80
4 Midpoint transmission 500.00 345.00
5 Midrose distribution 138.00 13.09
6 Milner transmission 138.00 69.00 12.47
7 Milner dIstribution 69.00 46.00 6.90
8 Milner distribution 138.00 35.00
9 Milner PP - attended transmission 138.00 13.80
10 Moonstone distribution 138.00 35.00
11 Mora distribution 138.00 35.00
12 Mora distribution 138.00 36.20
13 Moreland distribution 35.00 13.00
14 Moreland distribution 46.00 13.00
15 Moreland distribution 46.00 35.00 12.47
16 Mountain Home distribution 69.00 13.00
17 Mountain Home Air Force Base distribution 69.00 13.00
18 Mountain Home Air Force Base distribution 138.00 13.00
19 Nampa transmission 230.00 138.00 13.80
20 Nampa distribution 138.00 13.00
21 New Meadows distribution 138.00 36.20
22 New Plymouth distribution 69.00 13.00
23 1 N Butte distribution 138.00 13.09
24 1 Orchard distribution 69.00 36.20
25 Orchard distribution 69.00 35.00 12.47
26 Parma distribution 69.00 13.00
27 Parma distribution 69.00 35.00
28 Paul distribution 138.00 35.00
29 Payette distribution 138.00 13.00
30 Pingree transmission 138.00 46.00 12.50
31 Plngree distribution 138.00 35.00
32 Pleasant Valley distribution 138.00 35.00
33 Pocatello distribution 46.00 13.00
34 Poleline distribution 138.00 13.09
35 transmission 345.00
36 Portneuf distribution 138.00 35.00
37 Portneuf distribution 46.00 35.00
38 Rockford distribution 46.00 13.00
39 Russell distribution 138.00 13.00
40 Sailor Creek distribution 138.00 2.40
FERC FORM NO. 1 (ED. 12-96) Page 426.4
Name of Respondent
Idaho Power Company
This Report Is:
(2) gAResubmission
Date of Report
04/15/2013
Year/Period of Report
End of 2012/04
SUBSTATIONS (Continued)
5.Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6.Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(In Service) (In MVa)
(f)
Number of
Transformers
In Service
(g)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.
-
Type of Equipment
(I)
Number of Units
(j)
Total Capacity
(k)
24 2 1
120 1 2
840 2 1 3
750 3 1 4
24 1
100 4 6
8 3 1
29 2 8
36 1 9
12 1
15 1 11
24 1 12
6 1
8 1
8 4
15 1 16
1 17
18 1 18
180 1
50 3
12 1 21
10 1 22
10 1 23
6 1 24
10 3
10 1
12 1 27
36 2 28
23 3
50 3
22 2 31
42 2 32
36 2 33
18 1
35
18 1 36
14 2 38
18 1
15 2 40
FERC FORM NO. I (ED. 12-96) Page 427.4
Name of Respondent
Idaho Power Company
This Re art Is:
ARSLWflission
Date of Report
04/15/2013
Year/Period of Report
End of 20121Q4
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3.Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4.Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line
No.
-
Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (In MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
I Sailor Creek distribution 138.00 35.00
2 Salmon distribution 69.00 13.00
3 Salmon distribution 69.00 34.501 12.47
4 Salmon distribution 69.00 12.47
5 Salmon transmission 13.00 2.40
6 Shoshone distribution 46.00 13.00
7 Shoshone distribution 46.00 7.20
8 Shoshone Falls -attended transmission 46.00 2.30
9 Shoshone Falls - attended transmission 46.00 6.60
10 Silver distribution 138.00 35.00
11 Simplot distribution 138.00 13.00
12 Sinker Creek distribution 138.00 35.00
13 Siphon distribution 138.00 35.00
14 South Park distribution 46.00 13.00
15 Star distribution 138.00 13.09
16 Starkey transmission 138.00 69.00 12.47
17 State distribution 69.00 13.00
18 Stoddard distribution 138.00 13.00
19 Strike Power Plant - attended transmission 138.00 13.80
20 Sugar distribution 138.00 35.00
21 Swan Falls - attended transmission 138.00 6.90
22 Taber distribution 46.00 13.00
23 Ten Mile distribution 138.00 13.09
24 Terry distribution 138.00 13.09
25 Terry distribution 138.00 13.00
26 Thousand Springs - attended transmission 46.00 7.20
27 Fhousand Springs - attended transmission 7.00 2.40
28 Toponis distribution 138.00 33.00
29 Twin Falls distribution 138.00 13.09
30 Twin Falls transmission 138.00 46.00 12.98
31 Twin Falls PP - attended transmission 138.00 7.20
32 Twin Falls PP - attended transmission 138.00 13.20
33 Upper Malad - attended transmission 45.00 7.20
34 Upper Salmon- attended transmission 138.00 7.20
35 Ustick distribution 138.00 13.00
36 Vallivue distribution 138.00 13.09
37 Victory distribution 138.00 13.00
38 Victory distribution 138.00 13.09
39 Ware distribution 69.00 13.00
40 Weiser distribution 69.00 13.00
FERC FORM NO. I (ED. 12-96) Page 426.5
Name of Respondent
Idaho Power Company
This Re ort Is:
2nR0n9S.fl
Date of Report
04/15/2013
Year/Period of Report
End of 2012/Q4
SUBSTATIONS (Continued)
5.Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6.Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(In Service) (In MVa)
Number of
Transformers
In Service
Number of
Spare
Transformers
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No. Type of Equipment Number of Units Total Capacity
15 1 1
10 1 3 2
10 3 3
2
5 2
10 1 6
2 3 7
3 1 8
10 1
12 1 10
15 1
12 1
33 2
10 1
18 1 15
18 1
33 2
15 1 18
83 3 19
20 2 20
18 1 —T
5 1
24 1 23
12 1 24
30 2 25
8 1 26
3 1 27
18 1
44 2
33 2 30
9 1
72 1
8 1 33
36 4
44 2
18 1
24 _ 1
18 1
12 1 1
20 2
FERC FORM NO. I (ED. 12-96) Page 427.5
Name of Respondent
Idaho Power Company
This Re ort Is:
(2) [:]AResubmission
Date of Report
04/15/2013
Year/Period of Report
End of 2012/04
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3.Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4.Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line
No
-
Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (In MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
I Weiser transmission 138.00 69.00 12.47
2 Wilder distribution 69.00 13.00
3 Willis distribution 138.00 13.09
4 Wye distribution 138.00 13.00
5 Wye distribution 138.00 13.09
6 Zilog distribution 138.00 13.09
7
8
9 The above are all State of Idaho
10
11 Montana:
12 Peterson transmission 230.00 69.00 13.20
13
14 Nevada:
15 transmission 345.00 125.00 24.90
16 transmission 345.00 125.00 24.90
17 transmission 120.00 24.90 7.20
18 transmission 345.00
19 transmission 345.00
20 transmission 345.00
21 transmission 345.00
22 transmission 345.00
23 Wells transmission 138.00 69.00 13.00
24
25 Oregon:
26 transmission 500.00 24.00
27 transmission 230.00 7.20
28 transmission 24.00 7.20
291 Cairo distribution 69.00 13.00
30 Hells Canyon - attended transmission 230.00 13.80
31 Hells Canyon - attended distribution 69.00 0.50
32 Hines transmission 138.00 115.00 12.47
33 Malheur Butte distribution 69.00 34.50
34 Nyssa distribution 69.00 13.00
35 Ontario distribution 138.00 13.00
36 Ontario transmission 138.00 69.00 12.47
37 Ontario transmission 230.00 138.00 13.80
38 Ontario transmission 138.00 69.00 12.98
39 Ontario transmission 138.00 69.00 13.09
40 Ore-Ida distribution 69.00 13.00
FERC FORM NO. I (ED. 12-96) Page 426.6
Name of Respondent This Report Is: Date of Report Year/Period of Report
End of 2012/Q4 Idaho Power Company 04/15/2013
SUBSTATIONS (Continued)
5.Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6.Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa) Transformers
In Service
Spare
Transformers No. Type of Equipment Number of Units Total Capacity
25 1 1
10 1 2
18 1
36 2 4
20 1 5
24 1 6
7
8
9
10
11
30 3 1
13
14
1 - 15
1 16
-v
Line Reactor 1 48 18
Une Reactor 1 35 19
Line Reactor 1 35 20
Line Reactor 1 35 21
Line Reactor 1 35 22
20 3 1 23
24
25
685 3 1
55 1 27
55 1 28
12 1
500 3 30
1 1 __-
40 1 32
8 3 1 33
20 2
38 2
25 1 1
240 2
50 2
-
15 1
FERC FORM NO. I (ED. 12-96) Page 427.6
Name of Respondent
Idaho Power Company
This Re ort Is:
(2) F] A Resubmission
Date of Report
04/15/2013
Year/Period of Report
End of 2012/Q4
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3.Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4.Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line
NO
-
Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (In MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 Oxbow -attended transmission 138.00 69.00 13.00
2 Oxbow -attended transmission 230.00 13.80
3 Oxbow -attended transmission 230.00 138.00 13.80
4 Quartz transmission 138.00 69.00 12.50
5 Quartz transmission 230.00 138.00 12.98
6 Quartz transmission 138.00 69.00 12.98
7 Vale distribution 69.00 13.00
8
9 Wyoming:
10 transmission 345.00 22.00
11 transmission 345.00 230.00 34.50
12'
13
14
15
16
17 Transformers-distribution substations under 10,000
18 KVA 85 unattended.
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO. I (ED. 12-96) Page 426.7
Name of Respondent
Idaho Power Company
This Re ort Is:
Resubmi
Date of Report
04/15/2013
Year/Period of Report
End of 20121Q4
SUBSTATIONS (Continued)
5.Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6.Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(In Service) (In MVa)
(f)
Number of
Transformers
In Service
(9)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No. Type of Equipment
(i)
Number of Units
(j)
Total Capacity
(k)
10 3 1 1
244 2 2
100 1 3
15 1 4
100 3 1
15 1 6
10 1 7
8
9
1122 2
1084 22
12
13
14
15
16
17
350 18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO. I (ED. 12-96) Page 427.7
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 04/15/2013 2012104
FOOTNOTE DATA
Schedule Page: 426.2 Line No.: 28 Column: a
PacifiCorp has a 59% interest in certain high-voltage transmission related and
interconnection equipment located at Idaho Power's Hemingway Station.
~Schedule Page: 426.4 Line No.: 35 Column: a
Idaho Power has a 20.8% interest in certain high-voltage transmission related and
interconnection equipment located at PacifiCorp's Populus station.
Schedule Page: 426.6 Line No.: 15 Column: a
Jointly owned with Sierra Pacific Power Company, dlb/a NV Energy. Idaho Power has a 50%
share of ownership.
Schedule Page: 426.6 Line No.: 16 Column: a
Jointly owned with Sierra Pacific Power Company, d/bla NV Energy. Idaho Power has a 50%
share of ownership.
Schedule Page: 426.6 Line No.: 17 Column: a
Jointly owned with Sierra Pacific Power Company, d/b/a NV Energy. Idaho Power has a 50%
share of ownership.
Schedule Page: 426.6 Line No.: 18 Column: a
Jointly owned with Sierra Pacific Power Company, d/b/a NV Energy. Idaho Power has a 50%
share of ownership.
Schedule Page: 426.6 Line No.: 19 Column: a
Jointly owned with Sierra Pacific Power Company, d/b/a NV Energy. Idaho Power has a 50%
share of ownership.
ISchedule Page: 426.6 Line No.: 20 Column: a
Jointly owned with Sierra Pacific Power Company, d/b/a NV Energy. Idaho Power has a 50%
share of ownership.
Schedule Page: 426.6 Line No.: 21 Column: a
Jointly owned with Sierra Pacific Power Company, d/b/a NV Energy. Idaho Power has a 50%
share of ownership.
Schedule Page: 426.6 Line No.: 22 Column: a
Jointly owned with Sierra Pacific Power Company, d/b/a NV Energy. Idaho Power has a 50%
share of ownership.
Schedule Page: 426.6 Line No.: 26 Column: a
Jointly owned with Portland General Electric, Power Resources Cooperative and BA Leasing
BCS, LLC. Idaho Power has a 10% share of the jointly owned capacity. 100% of the capacity
is reported.
Schedule Page: 426.6 Line No.: 27 Column: a
Jointly owned with Portland General Electric, Power Resources Cooperative and BA Leasing
BCS, LLC. Idaho Power has a 10% share of the jointly owned capacity. 100% of the capacity
is reported.
Schedule Page: 426.6 Line No.: 28 Column: a
Jointly owned with Portland General Electric, Power Resources Cooperative and BA Leasing
BCS, LLC. Idaho Power has a 10% share of the jointly owned capacity. 100% of the capacity
is reported.
Schedule Page: 426.7 Line No.: 10 Column: a I
Jointly owned with PacificCorp. Idaho Power has a 33.3% share of ownership.
hedule Page: 426.7 Line No.: 11 Column: a
Jointly owned with PacificCorp. Idaho Power has a 33.3% share of ownership.
I FERC FORM NO. I (ED. 12-87) Page 450.1 I
Name of Respondent
Idaho Power Company
This Re ort Is:
2n RSSIOfl
Date of Report
04/15/2013
Year/Period of Report
End of 20121Q4
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 (affiliated) companies.
2.The reporting threshold for reporting purposes is $250,000. The threshold applies to the annual amount billed to the respondent or billed to
an associated/affiliated company for non-power goods and services. The good or service must be specific in nature. Respondents should not
attempt to include or aggregate amounts in a nonspecific category such as general".
3.Where amounts billed to or received from the associated (affiliated) company are based on an allocation process, explain in a footnote.
Line
No.
-
Description of the Non-Power Good or Service
(a)
Name of
Associated/Affiliated
Company
(b)
Account
Charged or
Credited
(c)
Amount
Charged or
Credited
(d)
I Non-power Goods or Services Provided by Affiliated
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20 Non-power Goods or Services Provided for Affiliate
Managerial Expense IDA 417420 257,667
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
FERC FORM NO. I (New) Page 429
FERC FORM NO. I-F (New)
December 31, 2012
ANNUAL REPORT
IDAHO SUPPLEMENT TO FERC FORM I
MULTI-STATE ELECTRIC COMPANIES
INDEX
Page
Number
1
2
3
3
4
5
6
7-10
11
12-15
15
Title
Statement of Income for the Year
Taxes Allocated to Idaho
Notes and Accounts Receivable
Accumulated Provision for Uncollectible Accounts
Receivables from Associated Companies
Gain or Loss on Disposition of Property
Professional or Consultative Services
Electric Plant in Service
Electric Operating Revenues
Electric Operation and Maintenance Expenses
Number of Electric Department Employees
IDAHO SUPPLEMENT
This Page Intentionally Left Blank
STATE OF IDAHO - ALLOCATED
Idaho Power Company An Original December 31, 2012
STATEMENT OF INCOME FOR THE YEAR
1.Report amounts for accounts 412 and 413, Revenue and Expenses from Utility Plant Leased to Others, in another utility
column (i,k,m,o) in a similar manner to a utility department Spread the amount(s) over lines 01 thru 24 as appropriate.
Include these amounts in columns (c) and (d) totals.
2.Report amounts in account 414, Other Utility Operating Income, in the same manner as accounts 412 and 413 above.
3.Report data for lines 7, 9, and 10 for Natural Gas companies using accounts 404.1, 404.2, 404.3, 407. 1, and 407.2.
4.Use page 122 for important notes regarding the state ment of income or any account thereof.
5.Give concise explanations concerning unsettled rate proceedings where a contingency exists such that refunds of a
material amount may need to be made to the utility's customers or which may result in a material refund to the utility
with respect to power or gas purchases. State for each year affected the gross revenues or costs to which the contingency
relates and the tax effects together with an explanation of retain such revenues or recover amounts paid with respect
to power and gas purchases.
6.Give concise explanations concerning significant amounts of any refunds made or received during the year.
(Ref.)
Line Account Page TOTAL
No No Current Year Previous Year
- (a) (b) (c) (d)
1 UTILITY OPERATING INCOME
2 11 $1,024,679,001 $ 969,760,290
3 Operating Expenses
4 15 565,759,812 600,989,160
5 15 70,598,724 72,381,449
6 Depreciation Expense (403) ................................................................... 111,567,695 108,248,039
7 Amort. & DepI. of Utility Plant (404-405) ................................................ 6,972,931 6,087,113
8
Operating Revenues (400)........................................................................
Amort. of Utility Plant Acq. Adj. (406).....................................................
9 Amort. of Property Losses, Unrecovered Plant and
10 Accretion Expense (411) ......................................................................... 176,276 -
11 Regulatory Study Costs (407)..............................................................
12 Amort. of Conversion Expenses (407)....................................................
13 Regulatory Debits/Credits (407.3 & 407.4) - -
14 2 28,446,377 26,932,746
15 2 (13,715,294) (54,366,437)
16
Taxes Other Than Income Taxes (408.1)................................................
2 971,298 (731,383)
17
Operation Expenses (401)......................................................................
Maintenance Expenses (402)..................................................................
2 37,421,156 16,500,157
18 2 8,684,157 (1,083,203)
19 (Less) Gains from Disp. of Utility Plant (411.6)......................................
20 Losses from Disp. of Utility Plant (411.7)...............................................
21 (Less) Gains from Disposition of Allowances (411.8).............................
22
Income Taxes - Federal (409.1)..............................................................
Losses from Disposition of Allowances (411.9)......................................
.
.
23
- Other (409.1)...........................................................................
Provision for Deferred Income Taxes (410.1 & 411.1) Net ...................
24
Investment Tax Credit Adj. - Net (411.4).................................................
TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 22) 816,883,133 774,957,641
25
26
27 Net Utility Operating Income (Enter Total of line 2 less 24) $ 207,795,868 $ 194,802,649
IDAHO SUPPLEMENT Page 1
STATE OF IDAHO - ALLOCATED
Idaho Power Company An Original December 31, 2012
TAXES ALLOCATED TO IDAHO
Taxes Charged
Kind of Tax During Year
Taxes Other Than Income Taxes:
Labor Related:
FICA............................................................ $ 13,083,633
FUTA........................................................... $ 89,321
State Unemployment.................................. 693,464
Payroll Deduction & Loading...................... (13,866,418)
Total Labor Related 0
Property Taxes............................................... 24,562,103
Kilowatt-hour Tax........................................... 1,576,439
Licenses......................................................... 4,798
Regulatory Commission Fees........................ 2,042,319
Irrigation PlC .................................................. 260,718
Total Taxes Other Than Income Taxes 28,446,377
Federal Income Taxes..................................... (13,715,294)
State Income Taxes ......... ................................ 971,298
Deferred Income Taxes................................... 37,421,156
Investment Tax Credit Adjustment - Net 8,684,157
Total Taxes Allocated to Idaho........................ $ 61,807,694
IDAHO SUPPLEMENT Page 2
STATE OF IDAHO
Idaho Power Company An Original December 31, 2012
NOTES AND ACCOUNTS RECEIVABLE
Summary for Balance Sheet
Show separately by footnote the total amount of notes and accounts receivable
from directors, officers, and employees included in Notes Receivable (Account
141) and Other Accounts Receivable (Account 143) -
Balance Balance
Line Accounts Beginning of End of
Year Year
No. (a) (b) (c)
1 $ 94,776 $ 72,492
2 Customer Accounts Receivable (Account 142) .............................................................. 67,534,733 67,661,588
3
Notes Receivable (Account 141)....................................................................................
Other Accounts Receivable (Account 143)....................................................................8,206,727 20,876,001
4 (Disclose any capital stock subscription received)
.
5 $ 75,836,237 $ 88,610,081
6
7 Less: Accumulated Provision for Uncollectible
8 Accounts-Cr. (Account 144) 1,435,434 1,872,855
9
10 Total, Less Accumulated Provision for
11 $ 74,400,803 $ 86,737,226
12
13
Total .........................................................................................................................
14 Notes Receivable - Account 141: (at 12-31-12)
15 Directors, officers, and employees - if -
16
Uncollectible Accounts ............................................................................................
17
18 Other Accounts Receivable - Account 143: (at 12-31-12)
19 Directors, officers, and employees - if -
20 1
ACCUMULATED PROVISION FOR UNCOLLECTIBLE ACCOUNTS - CR. (Account 144)
1.Report below the information called for concerning this accumulated provision.
2.Explain any important adjustments of subaccounts.
3.Entries with respect to officers and employees shall not include items for utility services. -
Mdse,
Line Item Utility Jobbing & Officers Other Total
Customers Contract and
No. (a) Work Employees
(b) (c) (d) (e) (f)
21
22 Bal. beginning of year $ 1,435,434 $ $ $ 437,421 $ 1,872,855
23 Prov. for uncollectibles
24 for year.............................................
25 Accounts written off ............................
26 CoIl, of accounts
27 written off..........................................
28 Adjustments (explain).........................
29
30
31
32 Balance end of year ............................ $ 1,435,434 $ - $ - $ 437,421 $ 1,872,855
_____________
.
_____________ ___________ ______________ 33
IDAHO SUPPLEMENT Page 3
STATE OF IDAHO
Idaho Power Company An Original December 31, 2012
RECEIVABLES FROM ASSOCIATED COMPANIES (Accounts 145, 146)
1.Report particulars of notes and accounts receivable from associated companies at end of year.
2.Provide separate headings and totals for accounts 145, Notes Receivable from Associated Companies, and 146,
Accounts Receivable from Associated Companies, in addition to a total for the combined accounts.
3.Fornotes receivable list each note separately and state purpose for which received. Show also in column
(a) date of note, date of maturity and interest rate.
4.If any note was received in satisfaction of an open account, state the period covered by such open account
5.Include in column (f) interest recorded as income during the year, including interest on accounts and notes
held at any time during the year.
6.Give particulars of any notes pledged or discounted, also of any collateral held as guarantee of payment
of any note or account.
Balance
Line Particulars Beginning Totals for Year Balance Interest
of Year End of Year For Year Debits Credits
No. (a) (b) (c) (d) (e) (f)
1 Account 145:
2
3 IERCO ................................ $ 17,335,019 $ 11,042,047 $ 27,368,817 $ 1,008,249
4
5
6
7
8
9
.
10 Total Account 145 ................. 17,335,019 11,042,047 27,368,817 1,008,249
11
12 Account 146:
13
14
15
16 - $ 3,539,671 $ 3,475,824 $ 63,847
17
18
19
20
21
..
22
IDACORP, Inc.......................
23
24
25
26
27
28
29
30
31 $ - $ 3,539,671 $ 3,475,824 $ 63,847
32
Total Account 146....................
IDAHO SUPPLEMENT Page 4
STATE OF IDAHO
Idaho Power Company An Original December 31, 2012
STATE OF IDAHO - TOTAL SYSTEM DATA
GAIN OR LOSS ON DISPOSITION OF PROPERTY (Account 421.1 and 421.2)
1.Give a brief description of property creating the gain or loss. Include name of party acquiring the property (when
acquired by another utility or associated company) and the date transaction was completed. Identify property
by type; Leased, Held for Future Use, or Nonutility.
2.Individual gains or losses relating to property with an original cost of less than $50,000 may be grouped, with the
number of such transactions disclosed in column (a).
3.Give the date of Commission approval of journal entries in column (b), when approval is required. Where approval
is required but has not been received, give explanation following the item in column (a). (See account 102, Utility
Plant Purchased or Sold.)
- Original Cost Date Journal
Line Description of Property of Related Entry Approved Acct 421.1 Acct 421.2
(When Required)
No. (a) (b) (c) (d) (e)
I Gain on disposition of
2 property:
3
4 No gain to report for 2012
5
6
7
8
9
10
11
12
13
14 Total gain ...................................................... $ 01 0
15
16
17
18 No loss to report for 2012
19
20
21
.
22
23
24
25
26
27
28
29
30
31 iTotal loss ................................................. .$ 01 Is 0
IDAHO SUPPLEMENT Page 5
STATE OF IDAHO
Idaho Power Company An Original December 31, 2012
STATE OF IDAHO - TOTAL SYSTEM DATA
PROFESSIONAL OR CONSULTATIVE SERVICES - ITEMS $10,000 AND OVER
Line PAYEE SERVICE TYPE Amount
No. (a) (b) (c)
T ADECCO Management Services 38,594
2 ADM ASSOCIATES INC Energy Efficiency Services 184,830
3 AGREE TECHNOLOGIES AND SOLUTIO Energy Efficiency Services 246,868
4 BANDUCCI WOODARD SCHWARTZMAN P Legal Services 87,486
5 BARKER, ROSHOLT & SIMPSON LLP Legal Services 613,119
6 BERGLES LAW LLC Legal Services 86,359
7 BETHKE LAW PLLC Legal Services 37,317
8 BRENNEMAN, JOHN Lobbying Services 35,086
9 BROADRIDGE FINANCIAL SOLUTIONS Management Services 44,174
10 BROWNE CONSULTING Management Services 37,808
11 BROWNSTEIN HYATT FARBER SCHREC Legal Services 105,441
12 BULLARD SMITH JERNSTEDT WILSON Legal Services 104,890
13 BURKE INCORPORATED Management Services 175,400
14 CHARLES RIVER ASSOCIATES INCOR Rate Case Services 270,004
15 CLEAREDGE PARTNERS INC Management Services 75,000
16 CORPORATE OFFICE INSTALLATIONS Office Equipment Services 70,434
17 CRAPO SMITH PLLC Legal Services 31,549
18 0 & R INTERNATIONAL, LTD Environmental Services 22,904
19 DAVID EVANS AND ASSOCIATES Consulting Services 73,076
20 DAVIS WRIGHT TREMAINE LLP Legal Services 995,997
21 DC ENGINEERING, PC Engineering Services 57,020
22 DELOITTE TAX LLP Accounting Services 34,026
23 DESERT RESEARCH INSTITUTE Environmental Services 57,865
24 DHI INC Environmental Services 12,000
25 EMC CORPORATION Environmental Services 13,500
26 ENERNOC INC Energy Efficiency Services 117,508
27 EPICOR SOFTWARE CORPORATION Software Consultant Services 11,950
28 ERISA LAW GROUP PA Legal Services 15,973
29 EVANS KEANE Legal Services 12,421
30 EVERGREEN CONSULTING GROUP, LL Management Services 208,586
31 EXPERIS IT SERVICES US, LLC Computer Support Services 109,280
32 FLUID MARKET STRATEGIES INC Management Services 13,235
33 GALE ENERGY CONSULTING LLC Management Services 36,000
34 GANNETT FLEMING INC Management Services 44,971
35 GARTNER GROUP Management Services 95,808
36 GIVENS PURSLEY LLP Legal Services 86,484
37 GJORDING & FOUSER, PLLC Legal Services 101,793
38 GLAHE & ASSOCIATES INC Environmental Services 35,847
39 GREENBERG TRAURIG LLP Legal Services 110,644
40 HARDESTY, REBECCA Environmental Services 19,005
41 HYQUAL Environmental Services 192,246
42 INTER-FLUVE, INC. Environmental Services 85,532
43 IOWA INSTITUTE OF HYDRAULICS Engineering Services 162,348
44 ISS CORPORATE SERVICES, INC Management Services 34,000
45 1
rage b
IDAHO SUPPLEMENT
STATE OF IDAHO
Idaho Power Company An Original December 31, 2012
STATE OF IDAHO - TOTAL SYSTEM DATA
PROFESSIONAL OR CONSULTATIVE SERVICES - ITEMS $10,000 AND OVER
Line PAYEE SERVICE TYPE Amount
No. (a) (b) (c)
JACO ENVIRONMENTAL INC Environmental Services 35,737
47 JONES AND SWARTZ PLLC Legal Services 200,336
48 KLINE, BARTON L Rate Case Services 13,375
49 L CONWAY CONSULTING, INC Management Services 14,254
50 LOVINGER KAUFMANN LLP Legal Services 222,759
51 MARKET STRATEGIES INTERNATIONA Energy Efficiency Services 40,000
52 MCDOWELL RACKNER & GIBSON PC Legal Services 1,447,999
53 MCMILLEN ENGINEERING, LLC Engineering Services 22,299
54 MERITO SOLUTIONS INC Management Services 19,975
55 MICROSOFT CORP Management Services 13,180
56 MIRANDE, MICHAEL Legal Services 41,233
57 NIELSEN GROUP INC, THE Consulting Services 263,301
58 PAINE HAMBLEN LLP Legal Services 167,000
59 PARR BROWN GEE & LOVELESS INC Legal Services 32,733
60 PERKINS COlE LLP Legal Services 402,012
61 PLATEAU ARCHAEOLOGICAL INVESTI Environmental Services 29,875
62 PORTLAND ENERGY CONSERVATION, Environmental Services 123,392
63 PROFESSIONAL TRAINING SYSTEMS Management Services 11,348
64 PROVEN COMPLIANCE SOLUTIONS IN Management Services 42,852
65 RIVERSIDE TECHNOLOGY INC Management Services 46,904
66 SALLADAY, G LANCE Legal Services 38,282
67 SCHWABE WILLIAMSON & WYATT Legal Services 79,263
68 SHARP & SMITH INC. Legal Services 16,142
69 STOEL RIVES LLP Legal Services 144,986
70 STRUCTURED COMMUNICATION SYS. Management Services 10,683
71 SULLIVAN & CROMWELL Legal Services 157,975
72 SUNRISE ENGINEERING INC Engineering Services 14,439
73 SYMANTEC CORPORATION Legal Services 84,736
74 TEKSYSTEMS Management Services 79,246
75 TETRA TECH INC Environmental Services 78,858
76 TUERI LLC Management Services 35,657
77 U S GEOLOGICAL SURVEY Environmental Services 130,210
78 UNIVERSITY CORPORATION FOR Cloud Seeding Modeling Services 193,132
79 UNIVERSITY OF ARIZONA Weather Research & Forecast Service 61,468
80 UNIVERSITY OF IDAHO Environmental Services 293,563
81 UNIVERSITY OF TENNESSEE Environmental Services 51,750
82 UTILMARC INC Management Services 12,000
83 VAN NESS FELDMAN Rate Case Services 304,982
84 WALDNER LAW OFFICES LLC Legal Services 11,925
85 WATERSHED SCIENCES INC Environmental Services 30,351
86 WEATHER MODIFICATION INC Environmental Services 343,404
87 YTURRI& ROSE& BURNHAM& BENTZ Legal Services 66,548
88
89
TOTAL I Is 10,434,539
Page 6A
IDAHO SUPPLEMENT
STATE OF IDAHO
Idaho Power Company An Original December 31, 2012
Line
No.
PROFESSIONAL OR CONSULTATIVE SERVICES
ITEMS $5.000 OR MORE BUT LESS THAN $10,000
PREDOMINANT
PAYEE NATURE OF SERVICE AMOUNT
T JUB ENGINEERS Engineering Services 5,170
2 INTERPRETIVE GRAPHICS SIGNS & Management Services 5,216
3 DATA ONE LLC Legal Services 5,717
4 RIDDELL WILLIAMS P.S. Management Services 6,651
5 CTA ARCHITECTS Architectural Services 7,500
6 EPDXY SYSTEMS, INC Management Services 7,898
7 TROUT, JONES GLEDHILL FUHRMAN Legal Services 8,118
8 RIPLEY, LARRY D Management Services 8,175
9 RATIONAL TECHNOLOGY OF IDAHO Management Services 9,345
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
40
41
42
43
44
5 ITOTAL 63,790
IDAHO SUPPLEMENT Page 6B
This Page Intentionally Left Blank
STATE OF IDAHO - ALLOCATED
Idaho Power Company An Original December 31, 2012
ELECTRIC PLANT IN SERVICE (Accounts 101, 102,103 and 106)
1.Report below the original cost of electric plant in service according to the prescribed accounts.
2.In addition to Account 101, Electric Plant in Service (Classified), this page and the next include Account 102, Electric Plant
Purchased or Sold; Account 103, Experimental Electric Plant Unclassified; and Account 106, Completed Construction
Not Classified - Electric.
3.Include in column (C) or (d), as appropriate, corrections of adlitions and retirements for the current or preceding year.
4.Enclose in parentheses credit adjustments of plant accounts to indicate the negative effect of such accounts.
5.Classify Account 106 according to prescribed accounts, on an estimated basis if necessary, and include the entries in
column (c) . Also to be included in column (c) are entries for reversals of tentative distributions of prior year reported in
column (b). Likewise, if the respondent has a significant amount of plant retirements the end of the year, include in
column (d) a tentative distribution of such retirements, on an estimated basis, with appropriate contra entry to the account
for accumulated depreciation provision. Include also in column (d) reversals of tentative distributions of prior year of un-
classified retirements. Attach supplemental statement showing the account distributions of these tentative classifications in
columns (c) and (d), including the reversals of the prior years tentative account distributions of these amounts. Careful ob-
servance of the above instructions and the texts of Accounts 101 and 106 will avoid serious omissions of the reported amount
of respondent's plant actually in service at end of year.
Line Account Beginning of year Additions
No. (a) (b) (c)
2
1. INTANGIBLE PLANT
(301) Organization ................................................................................................... $ 5,457
3 (302) Franchises and Consents ............................................................................... 22,172,205
4 (303) Miscellaneous Intangible Plant .......................................................................
.
32,839,705
5 TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4) ........................................ .55,017,367
6 2. PRODUCTION PLANT
7 A. Steam Production Plant
8 (310) Land and Land Rights....................................................................................
9 (311) Structures and Improvements ........................................................................
10 (312) Boiler Plant Equipment...................................................................................
11 (313) Engines and Engine Driven Generators .........................................................
12 (314) Turbogenerator Units.....................................................................................
13 (315) Accessory Electric Equipment........................................................................
14 (316) Misc. Power Plant Equipment........................................................................
15 (317) Asset Retirement Costs for Steam Production .................. ....................... 8,275,911
16 TOTAL Steam Production Plant (Enter Total of lines 8 thru 15) .............................. 908,609,888
17 B. Nuclear Production Plant
18 (320) Land and Land Rights....................................................................................
19 (321) Structures and Improvements ........................................................................
20 (322) Reactor Plant Equipment ...............................................................................
21 (323) Turbogenerator Units.....................................................................................
22 (324) Accessory Electric Equipment........................................................................
23 (325) Misc. Power Plant Equipment........................................................................
24 (326) Asset Retirement Costs for Nuclear Production ........................................
25 TOTAL Nuclear Production Plant (Enter Total of lines 17 thru 24)..........................
26 C. Hydraulic Production Plant
27 (330) Land and Land Rights ....................................................................................
28
29 (332) Reservoirs, Dams, and Waterways................................................................
30 (333) Water Wheels, Turbines, and Generators ......................................................
.
31 (334) Accessory Electric Equipment ........................................................................
32 (335) Misc. Power Plant Equipment.........................................................................
33 (336) Roads, Railroads, and Bridges .......................................................................
34 (337) Asset Retirement Costs for Hydraulic Production ......................................
35 TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34) ........................ 679,593,365
36 D. Other Production Plant
37 (340) Land and Land Rights ....................................................................................
38 (341) Structures and Improvements ........................................................................
39 (342) Fuel Holders, Products and Accessories ........................................................
.
40 (343) Prime Movers.................................................................................................
41 (344) Generators .....................................................................................................
42 (345) Accessory Electric Equipment ........................................................................
43 (346) Misc Power Plant Equipment..........................................................................
Page 7
IDAHO SUPPLEMENT
STATE OF IDAHO - ALLOCATED
Idaho Power Company An Original December 31, 2012
ELECTRIC PLANT IN SERVICE (Accounts 101, 102,103 and 106) (Continued)
Show in column (f) reclassifications or transfers within utility plant accounts. Include also in column
(f) the additions or reductions of primary account classifications arising from distribution of amounts
initially recorded in Account 102. In showing the clearance of Account 102, include in column (e) the
amounts with respect to accumulated provision for depreciation, acquisition adjustments, etc., and show
in column (f) only the offset to the debits or credits distributed in column (f) to primary account classifications.
For Account 399, state the nature and use of plant included in this account and if substantial in amount
submit a supplementary statement showing subaccount classification of such plant conforming to the
requirements of these pages.
For each amount comprising the reported balance and changes in Account 102, state the property purchased
or sold, name of vendor or purchaser, and date of transaction. If proposed journal entries have been filed
with the Commission as required by the Uniform System of Accounts, give also date of such filing.
Retirements Adjustments Transfers End of Year Line
(d) (e) (f) (9) No.
$ 5,469 (301) 2
27,768,043 (302) 3
29,967,161 (303) 4
57,740,673 5
6
7
(310) 8
(311) 9
(312) 10
(313) 11
(314) 12
(315) 13
(316) 14
10,420,185 (317) 15
916,865,363 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
686,531,172 35
36
(340) 37
(341) 38
(342) 39
(343) 40
(344) 41
(345) 42
(345) 43
Page
IDAHO SUPPLEMENT
STATE OF IDAHO - ALLOCATED
Idaho Power Company An Original December 31, 2012
ELECTRIC PLANT IN SERVICE (Accounts 101, 102,103 and 106) (Continued)
1ji • Balance at
Account Beginning of year Additions
No. (a) (b) (c)
(346) Misc. Power Plant Equipment........
45 TOTAL Other Production Plant (Enter Total of lines 37 thru 44)............................ $ 165,688,363
46 TOTAL Production Plant (Enter Total of lines 16, 25, 35, and 45) ......................... 1,753,891,616
47 3. TRANSMISSION PLANT
.
48 (350) Land and Land Rights ..................................................................................... 33,615,717
49 (352) Structures and Improvements ......................................................................... 55,493,339
50 (353) Station Equipment ........................................................................................... 336,717,516
51 (354) Towers and Fixtures ......................................... . .............................................. 141131,353
52 (355) Poles and Fixtures .......................................................................................... 102,379,364
53 (356) Overhead Conductors and Devices ................................................................. 164,369,428
54 (357) Underground Conduit......................................................................................
55 (358) Underground Conductors and Devices............................................................
56 (359) Roads and Trails ............................................................................................. 395,522
57 (359.1) Asset Retirement Costs for Transmission Plant......................................
58 TOTAL Transmission Plant (Enter Total of lines 48 thru 57) .................................
.
.
.
.
.
.
834,102,239
59 4. DISTRIBUTION PLANT
.
60 (360) Land and Land Rights ..................................................................................... 5,288,037
61 (361) Structures and Improvements .........................................................................
.
62 (362) Station Equipment...........................................................................................
..31,149,311
187,486,045
63 63 (363) Storage Battery Equipment.............................................................................
64 (364) Poles, Towers, and Fixtures ............................................................................ 211,409,134
65 (365) Overhead Conductors and Devices ................................................................. 114,428,352
66 (366) Underground Conduit ...................................................................................... 47,290,854
67 (367) Underground Conductors and Devices ............................................................ 193,507,656
68 (368) Line Transformers ........................................................................................... 411,389,958
69 (369) Services .......................................................................................................... 54,323,982
70 (370) Meters ............................................................................................................. 109,827,388
71 (371) Installations on Customer Premises ................................................................ 2,529,769
72 (372) Leased Property on Customer Premises.........................................................
73 (373) Street Lighting and Signal Systems ................................................................. 4,181,704
74 (374) Asset Retirement Costs for Distribution Plant.........................................
75 TOTAL Distribution Plant (Enter Total of lines 60 thru 74) ....................................
.
.
.
.
.
.
.
.
1,372,812,190
76 5. GENERAL PLANT
.
77 (389) Land and Land Rights ..................................................................................... 15,434,298
78 (390) Structures and Improvements ......................................................................... 81,326,079
79 (391) Office Furniture and Equipment ....................................................................... 38,812,265
80 (392) Transportation Equipment ............................................................................... 58,352,942
81 (393) Stores Equipment ............................................................................................ 1,531,151
82 (394) Tools, Shop, and Garage Equipment ...............................................................
.
.
.
.
.5,794,321
83 (395) Laboratory Equipment ..................................................................................... .11,355,461
84 (396) Power Operated Equipment. ........................................................................... 10,235,988
85 (397) Communication Equipment ............................................................................. 31,305,950
86 (398) Miscellaneous Equipment ............................................................................... 5,028,782
87 SUBTOTAL (Enter Total of lines 77 thru 86) .........................................................
.
.
.
.259,177,237
88 (399) Other Tangible Property..................................................................................
89 (399.1) Asset Retirement Costs for General Plant.........................................
90 TOTAL General Plant (Enter Total of lines 87, 88 and 89) ................................... .259,177,237
91 TOTAL (Accounts 101 and 106) ..................................................................... .4,275,000,649
92 (102) Electric Plant Purchased ................................................................................
93 (Less) (102) Electric Plant Sold................................................................................
94 (103) Experimental Plant Unclassified......................................................................
95
96 TOTAL Electric Plant in Service ........................................................................... .$ 4,275,000,649
i'age
IDAHO SUPPLEMENT
STATE OF IDAHO - ALLOCATED
Idaho Power Company An Original December 31, 2012
ELECTRIC PLANT IN SERVICE (Accounts 101, 102,103 and 106) (Continued)
Balance at Line
Retirements Adjustments Transfers End of Year
(d) (e) (f) (9) No.
_ (346) 44
$ 523,314,060 45
2,126,710,614 46
47
34,144,330 (350) 48
67,313,466 (352) 49
350,618,551 (353) 50
148,853,601 (354) 51
115,480,123 (355) 52
177,042,541 (356) 53
(357) 54
(358) 55
374,559 (359) 56
(359.1) 57
893,627,171 58
59
4,640,145 (360) 60
30,231,294 (361) 61
183,519,214 (362) 62
(363) 63
212,624,115 (364) 64
115,863,070 (365) 65
46,149,139 (366) 66
194,586,898 (367) 67
433,676,693 (368) 68
53,989,312 (369) 69
68,386,405 (370) 70
2,636,455 (371) 71
(372) 72
4,292,528 (373) 73
(374) 74
1,350,595,269 75
76
15,457,958 (389) 77
89,805,998 (390) 78
41,036,641 (391) 79
62,224,617 (392) 80
1,800,676 (393) 81
6,200,087 (394) 82
11,751,632 (395) 83
11,023,650 (396) 84
38,289,785 (397) 85
5,391,308 (398) 86
282,982,352 87
(399) 88
_______________ (399.1) 89
282,982,352 90
4,713,856,080 91
(102) 92
(102) 93
(371) 94
95
$ 4,713,856,080 96
rage iu
IDAHO SUPPLEMENT
STATE OF IDAHO - ALLOCATED
Idaho Power Company An Original December 31, 2012
ELECTRIC OPERATING REVENUES (Account 400)
1.Report below operating revenues for each prescribed account, and manufactured gas revenues in total.
2.Report number of customers, columns (f) and (g), on the basis of meters, in addition to the number of flat rate
accounts; except that where separate meter readings are added for billing purposes, one customer should be counted
for each group of meters added. The average number of customers means the average of twelve figures at the 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)
I Sales of Electricity
2 (440) Residential Sales ........................................................ $ 415,210,872 389,903,113
3 (442) Commercial and Industrial Sales
4 Small (or Commerctal)(See lnstr. 4) (1) ............................. 360,405,504 308,079,555
5 Large (or lndustrialXSee lnstr. 4) (2) .................................. 132,393,331 128,669,701
6 (444) Public Street and Highway Lighting 3,450,987 3,160,616
7 (445) Other Sales to Public Authorities................................
8 (446) Sales to Railroads and Railways .................................
9 (448) Interdepartmental Sales
10 TOTAL Sales to Ultimate Consumers ............................. 911,460,695 * 829,812,986
11 (447) Sales for Resale - Opportunity.... Non-Firm Only 58,842,171 96,933,214
970,302,866 926,746,200 12 TOTAL Sales of Electricity ..............................................
13 (449) Provision for Rate Refunds ........................................ (17,787,033) (37,734,708)
.
952,515,833
.
889,011,492 14 TOTAL Revenue Net of Provision for Refunds
15 Other Operating Revenues
16 (450) Forfeited Discounts .....................................................
17 (451) Miscellaneous Service Revenues 3,556,088 3,477,021
18 (453) Sales of Water and Water Power................................
19 (454) Rent from Electric Property ......................................... 22,113,462 23,065,731
20 (455) Interdepartmental Rents .............................................
21 46,493,618 54,206,045
22
23
.
24
(456) Other Electric Revenues ..............................................
25 72,163,168 80,748,797
$ 1,024,679,001 $ 969,760,289 26
TOTAL Other Operating Revenues ..................................
TOTAL Electric Operating Revenues ...............................
(1)Commercial and Industrial sales - Small - under 1,000 KW and includes all irrigation customers.
(2)Commercial and Industrial sales - Large - 1,000 KW and over.
Page 11
IDAHO SUPPLEMENT
STATE OF IDAHO - ALLOCATED
Idaho Power Company An Original December 31, 2012
ELECTRIC OPERATING REVENUES (Account 400) (Continued)
4.Commercial and Industrial Sales, Account 442, may be classified according to the basis of classification
(Small or Commercial, and Large or Industrial) regularly used by the respondent if such basis of classification
is not generally greater than 1000 Kw of demand. (See Account 442 of the Uniform System of Accounts. Explain
5.See page 108, Important Changes During Year, for important new territory added and important rate increases or
decreases.
6.For lines 2, 4, 5, and 6, see page 304 for amounts relating to unbilled revenue by accounts.
7.Include unmetered sales. Provide details of such sales in a footnote.
KILOWATT HOURS SOLD AVERAGE NUMBER OF CUSTOMERS PER MONTH -
Amount for Amount for Amount for Number for Line
Current Year Previous Year Current Year Previous Year No.
(d) (e) (f) (g) -
4,854,235,929 4,950,935,597 400,291 396,435 2
3
5,684,621,245 5,259,299,071 77,437 77,038 4
2,894,339,717 2,858,414,142 112 117 5
30,944,414 28,922,261 2,044 1,557 6
7
8
9
13,464,141,305 ** 13,097,571,071 479,884 475,147 10
2,087,746,748 3,467,888,272 N/A N/A 11
15,551,888,053 16,565,459,343 479,884 475,147 12
13
* Includes $3,931,000 unbilled revenues.
-Includes -17,472,593 KWH relating to unbilled revenues.
Lines 11 through 21 are on an "allocated" basis.
Page ha
IDAHO SUPPLEMENT
STATE OF IDAHO - ALLOCATED
Idaho Power Company An Original December 31, 2012
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnotes.
Line Amount for Amount for
No. Account Current Year Previous Year
- (a) (b) (c)
1 1. POWER PRODUCTION EXPENSES
A. Steam Power Generation
3 Operation
4 (500) Operation Supervision and Engineering ............................................................ $ 1,346,287 $ 1,617,279
5 (501) Fuel ................................................................................................................... 128,616,832 114,337,716
6 (502) Steam Expenses ............................................................................................... 7,917,399 6,631,018
7 (503) Steam from Other Sources ................................................................................
8 (Less) (504) Steam Transferred-Cr .............................................................................
.
.
9 1,472,009 2,128,774
10 7,996,512 9,314,506
11
(505)Electric Expenses ..............................................................................................
(506)Miscellaneous Steam Power Expenses ..............................................................
273,828 476,607
12
(507) Rents .................................................................................................................
_____________________
13 TOTAL Operation (Enter Total of lines 4 thru 12) ................................................. 147,622,867 134,505,900
14 Maintenance
15 318,019 1,986,056
16
(510)Maintenance Supervision and Engineering ........................................................
(511)Maintenance of Structures ................................................................................. 728,455 880,911
17 (512) Maintenance of Boiler Plant .............................................................................. 12,054,121 14,645,611
18 (513) Maintenance of Electric Plant ............................................................................ 4,914,467 6,513,885
19 (514) Miscellaneous Steam Plant ............................................................................... 4,795,520 6,206,375
20 TOTAL Maintenance (Enter Total of Lines 15 thw 19) .......................................... 22,810,582 30,232,838
21 TOTAL Power Production Expenses-Steam Power (Enter Total of lines 13 and 170,433,450 164,738,738
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
(509) Allowances .........................................................................................................
(524) Miscellaneous Nuclear Power Expenses...........................................................
32 (525) Rents ................................................................................................................
.
_____________________
33 TOTAL Operation (Enter Total of lines 24 thru 32) .............................................. ____________________
34 Maintenance
35 (528) Maintenance Supervision and Engineering.......................................................
36 (529) Maintenance of Structures ................................................................................
37 (530) Maintenance of Reactor Plant Equipment.........................................................
38 (531) Maintenance of Electric Plant ............................................................................
.
39 (532) Maintenance of Miscellaneous Nuclear Plant
40
41 TOTAL Power Production Expenses-Nuclear Power (Enter Total of lines 33 and
.
42 C. Hydraulic Power Generation
43 Operation
44 (535) Operation Supervision and Engineering ............................................................. 7,136,805 5,147,250
45 (536) Water for Power ................................................................................................. 7,496,203 8,393,843
46 12,203,305 11,973,604
47 1,319,589 1,540,819
48
(537) Hydraulic Expenses ...........................................................................................
2,528,231 2,948,258
49
(538)Electric Expenses ..............................................................................................
(539)Miscellaneous Hydraulic Power Generation Expenses .......................................
315,959 200,191
50
(540) Rents .................................................................................................................
TOTAL Operation (Enter Total of lines 44 thru 49) .............................................. .31,000,092 1 30,203,965
Page 12
IDAHO SUPPLEMENT
STATE OF IDAHO - ALLOCATED
Idaho Power Company An Original December 31, 2012
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnotes.
Line Amount for Amount for
No. Account Current Year Previous Year
- (a) (b) (C)
51 C. Hydraulic Power Generation (Continued)
52 Maintenance
53 (541) Maintenance Supervision and Engineering ....................................................... $ 292,792 $ 1,687,621
54 (542) Maintenance of Structures ................................................................................ 1,275,663 1,648,569
55 (543) Maintenance of Reservoirs, Dams, and Waterways .......................................... 1,289,334 1,495,873
56 (544) Maintenance of Electric Plant ............................................................................ 2,985,623 1,711,088
57 (545) Maintenance of Miscellaneous Hydraulic Plant .................................................. 2,947,769 2,602,021
58 TOTAL Maintenance (Enter Total of lines 53 thru 57) ............................................
.
.
.
.
8,791,181 9,145,172
59 TOTAL Power Production Expenses-Hydraulic Power (Enter Total of lines 50 and
.
39,791,273 39,349,137
60 D. Other Power Generation
61 Operation
62 (546) Operation Supervision and Engineering ............................................................ 1,288,599 784,824
63 (547) Fuel ................................................................................................................... 2
.
3,822,329 11,159,409
64 (548) Generation Expenses ........................................................................................ 2,078,479 717,006
65 (549) Miscellaneous Other Power Generation Expenses ............................................ 387,151 745,729
66 (550) Rents ................................................................................................................ 0 0
67 TOTAL Operation (Enter Total of lines 62 thru 66) ................................................
.
.
.
27,576,558 13,406,968
68 Maintenance
.
69 (551) Maintenance Supervision and Engineenng ....................................................... 0 0
70 (552) Maintenance of Structures ................................................................................ 199,656 171,779
71 (553) Maintenance of Generating and Electric Plant ................................................... 95,543 110,002
72 (554) Maintenance of Miscellaneous Other Power Generation Plant
.
.
.
2,435,555 1,781,101
73 TOTAL Maintenance (Enter Total of lines 69 thru 72) ........................................... 2,730,753 2,062,882
74 TOTAL Power Production Expenses-Other Power (Enter Total of lines 67 and 73:
.
30,307,311 15,469,850
75 E. Other Power Supply Expenses
76 (555) Purchased Power .............................................................................................. .182,310,250 149,672,898
77 (556) System Control and Load Dispatching .............................................................. 2,159 1,166
78 (557) Other Expenses .................................................................................................
.
(58,406,670)
.
37,451,652
79 TOTAL Other Power Supply Expenses (Enter Total of lines 76 thru 78) 123,905,739 187,125,716
80 TOTAL Power Production Expenses (Enter Total of lines 21, 41, 59, 74, and 79) 364,437,773 406,683,441
81 2. TRANSMISSION EXPENSES
82 Operation
83 (560) Operation Supervision and Engineering ............................................................ 3,436,111 3,183,091
84 (561) Load Dispatching .............................................................................................. 2,633,413 2,781,432
85 (562) Station Expenses .............................................................................................. 2,264,325 2,155,024
86 (563) Overhead Line Expenses .................................................................................. 632,645 713,799
87 (564) Underground Line Expenses.............................................................................
88 (565) Transmission of Electricity by Others ................................................................ 6,019,037 6,165,151
89 (566) Miscellaneous Transmission Expenses ............................................................. 168,613 294,591
90 (567) Rents ................................................................................................................2,881,111
.
3,141,691
91 TOTAL Operation (Enter Total of lines 83 thru 90) ................................................ 18,035,253 18,434,779
92 Maintenance
93 (568) Maintenance Supervision and Engineering ....................................................... 465,258
.
211,076
94 (569) Maintenance of Structures ................................................................................ 735,819 409,517
95 3,540,656 2,846,962
96 5,079,531 3,516,386
97 (572) Maintenance of Underground Lines...................................................................
98 (573) Maintenance of Miscellaneous Transmission Plant ............................................ 1,468 5,237
99
(570) Maintenance of Station Equipment .....................................................................
TOTAL Maintenance (Enter Total of lines 93 thru 98) ............................................ 9,822,733 6,989,178
100
(571) Maintenance of Overhead Lines .......................... ................................................
TOTAL Transmission Expenses (Enter Total of lines 91 and 99) 27,857,987 25,423,957
101 3. DISTRIBUTION EXPENSES
.
102 Operation
103 (580) Operation Supervision and Engineering ............................................................ .3,942,246 3,585,869
Page 13
IDAHO SUPPLEMENT
STATE OF IDAHO - ALLOCATED
Idaho Power Company An Original December 31, 2012
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnotes.
Line Amount for Amount for
No. Account Current Year Previous Year
- (a) (b) (c)
104 3. DISTRIBUTION EXPENSES (Continued)
105 (581) Load Dispatching .............................................................................................. $ 3,411,958 $ 3,335,858
106 (582) Station Expenses .............................................................................................. 1,120,001 1,151,687
107 (583) Overhead Line Expenses .................................................................................. 3,510,192 2,817,997
108 (584) Underground Line Expenses ............................................................................. 1,841,055 1,796,817
109 (585) Street Lighting and Signal System Expenses .................................................... 104,460 116,145
110 (586) Meter Expenses ................................................................................................ 3,984,472 4,035,316
111 (587) Customer Installations Expenses ...................................................................... 590,811 1,002,934
112 (588) Miscellaneous Distribution Expenses ................................................................ 5,381,804 5,259,071
113 (589) Rents ................................................................................................................ 472,027 795,328
.
.
.
.
.
.
.
.
.
24,359,026 23,897,022 114 TOTAL Operation (Enter Total of lines 103 thru 113) ............................................
115 Maintenance
116 (590) Maintenance Supervision and Engineering ....................................................... 214,565 385,136
117 (591) Maintenance of Structures ................................................................................ 0 5,501
118
.
3,696,105 3,119,318
119 (593) Maintenance of Overhead Lines ........................................................................ 14,418,317 13,440,348
120 (594) Maintenance of Underground Lines ................................................................... 1,030,138 1,037,269
121
(592) Maintenance of Station Equipment .....................................................................
(595) Maintenance of Line Transformers .................................................................... 406,160 415,626
122 (596) Maintenance of Street Lighting and Signal Systems .......................................... 541,867 527,171
123 (597) Maintenance of Meters ...................................................................................... 699,899 461,660
124 (598) Maintenance of Miscellaneous Distribution Plant .............................................. .. 487,673 231,921
.
.
.
.
21,494,724 19,623,950 125 TOTAL Maintenance (Enter Total of lines 116 thru 124) ........................................
126 TOTAL Distribution Expenses (Enter Total of lines 114 and 125)
.
45,853,750 43,520,972
127 4. CUSTOMER ACCOUNTS EXPENSES
128 Operation
129 (901) Supervision ....................................................................................................... 420,669 411,109
130 (902) Meter Reading Expenses .................................................................................. 1,185,721 2,348,997
131 (903) Customer Records and Collection Expenses ..................................................... 12,704,355 12,464,340
132 (904) Uncollectible Accounts ...................................................................................... 4,234,006 4,016,095
133 (905) Miscellaneous Customer Accounts Expenses ................................................... 241
24
392
.
.
.
.
18,545,143 19,0,782 134 TOTAL Customer Accounts Expenses (Enter Total of lines 129 thru 133)
135 5. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
136 Operation
137 (907) Supervision ....................................................................................................... 506,730 494,702
138 (908) Customer Assistance Expenses ........................................................................ 31,912,362 41,237,965
139 (909) Informational and Instructional Expenses .......................................................... 284,730 79,709
140 (910) Miscellaneous Customer Service and Informational Expenses 524,139
.
498,074
33,227,961 42,310,450 141 TOTAL Cust. Service and Informational Expenses (Enter Total of lines 137 thru 1
142 6. SALES EXPENSES
143 Operation
144 (911) Supervision .......................................................................................................
145 (912) Demonstrating and Selling Expenses................................................................
146 (913) Advertising Expenses........................................................................................
147 (916) Miscellaneous Sales Expenses .......................................................................... _____________________
.____________________ 148 TOTAL Sales Expenses (Enter Total of lines 144 thru 147) ...................................
149 7. ADMINISTRATIVE AND GENERAL EXPENSES
150 Operation
151 (920) Administrative and General Salaries ................................................................. 67201,422 64,079,786
152 18,085,517
.
15,024,667
153
(921) Office Supplies and Expenses ............................................................................
(Less) (922) Administrative Expenses Transferred-Credit ........................................... (26,962,038) (24,823,165)
Page 14
IDAHO SUPPLEMENT
STATE OF IDAHO-ALLOCATED
Idaho Power Company An Original December 31, 2012
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnotes.
Line Amount for Amount for
No. Account Current Year Previous Year
- (a) (b) (c)
154 7. ADMINISTRATIVE AND GENERAL EXPENSES (Continued)
155 (923) Outside Services Employed ................................................................ . ............. $ 4,943,764 $ 4,701,113
156 (924) Property Insurance ............................................................................................ 3,367,186 3,071,478
157 (925) Injuries and Damages ....................................................................................... 6,828,251 5,541,210
158
.
58,734,533 57,109,122
159 (927) Franchise Requirements ................................................................................... 9 0
160 (928) Regulatory Commission Expenses .................................................................... 4,955,643 3,046,603
161
(926) Employee Pensions and Benefits.......................................................................
(929) Duplicate Charges-Cr........................................................................................
162 (930.1) General Advertising Expenses ....................................................................... 470,811
.
526,939
163
.
3,845,202 3,579,030
164
(930.2) Miscellaneous General Expenses ...................................................................
(931) Rents ................................................................................................................ 16,875 6,796
165 TOTAL Operation (Enter Total of lines 151 thru 164) .............................................
.
141,487,174 131,863,579
166 Maintenance
167 (935) Maintenance of General Plant ........................................................................... 4,948,750 4,327,428
168 TOTAL Admin and General Expenses (Enter Total of lines 165-167) 146,435,924 136,191,007
169 TOTAL Elec Op and Maint Exp (Total of 80, 100, 126, 134, 141, 148,168) ......... $ 636,358,536 $ 673,370,609
IDAHO ONLY
NUMBER OF ELECTRIC DEPARTMENT EMPLOYEES
1.The data on number of employees should be reported for the payroll period ending nearest to October 31,
or any payroll period ending 60 days before or after October 31.
2.If the respondent's payroll for the reporting period includes any special construction personnel, include
such employees on line 3, and show the number of such special construction employees in a footnote.
3.The number of employees assignable to the electric department from joint functions of combination utilities
may be determined by estimate, on the basis of employee equivalents. Show the estimated number of equiv-
alent employees attributed to the electric department from joint functions.
I Payroll Period Ended (Date) ....................................................................................... December 31, 2012 December 31 ,2011
2 Total Regular Full-Time Employees............................................................................2,010 1,929
3 Total Part-Time and Temporary Employees ............................................................... 18 65
4 Total Employees ........................................................................................................ 2,028 1,994
Page 15
IDAHO SUPPLEMENT