2014Annual Report.pdf

THIS FILING IS
Item 1: An Initial (Original)
Submission
OR Resubmission No. ____X
FERC FINANCIAL REPORT
FERC FORM No. 1: Annual Report of
Major Electric Utilities, Licensees
and Others and Supplemental
Form 3-Q: Quarterly Financial Report
These reports are mandatory under the Federal Power Act, Sections 3, 4(a), 304 and 309, and
18 CFR 141.1 and 141.400. Failure to report may result in criminal fines, civil penalties and
other sanctions as provided by law. The Federal Energy Regulatory Commission does not
consider these reports to be of confidential nature
OMB No.1902-0021
OMB No.1902-0029
OMB No.1902-0205
(Expires 11/30/2016)
(Expires 11/30/2016)
(Expires 11/30/2016)
Form 1 Approved
Form 1-F Approved
Form 3-Q Approved
FERC FORM No.1/3-Q (REV. 02-04)
Exact Legal Name of Respondent (Company) Year/Period of Report
End of 2014/Q4Idaho Power Company
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
LIST OF SCHEDULES (Electric Utility)
Idaho Power Company X
04/15/2015
2014/Q4
Line
No.
Title of Schedule Reference
Page No.
Remarks
(c)(b)(a)
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
101General Information 1
102Control Over Respondent 2
103Corporations Controlled by Respondent 3
104Officers 4
105Directors 5
106(a)(b)Information on Formula Rates 6
108-109Important Changes During the Year 7
110-113Comparative Balance Sheet 8
114-117Statement of Income for the Year 9
118-119Statement of Retained Earnings for the Year 10
120-121Statement of Cash Flows 11
122-123Notes to Financial Statements 12
122(a)(b)Statement of Accum Comp Income, Comp Income, and Hedging Activities 13
200-201Summary of Utility Plant & Accumulated Provisions for Dep, Amort & Dep 14
N/A202-203Nuclear Fuel Materials 15
204-207Electric Plant in Service 16
213Electric Plant Leased to Others 17
214Electric Plant Held for Future Use 18
216Construction Work in Progress-Electric 19
219Accumulated Provision for Depreciation of Electric Utility Plant 20
224-225Investment of Subsidiary Companies 21
227Materials and Supplies 22
N/A228(ab)-229(ab)Allowances 23
N/A230Extraordinary Property Losses 24
N/A230Unrecovered Plant and Regulatory Study Costs 25
231Transmission Service and Generation Interconnection Study Costs 26
232Other Regulatory Assets 27
233Miscellaneous Deferred Debits 28
234Accumulated Deferred Income Taxes 29
250-251Capital Stock 30
253Other Paid-in Capital 31
254Capital Stock Expense 32
256-257Long-Term Debt 33
261Reconciliation of Reported Net Income with Taxable Inc for Fed Inc Tax 34
262-263Taxes Accrued, Prepaid and Charged During the Year 35
266-267Accumulated Deferred Investment Tax Credits 36
FERC FORM NO. 1 (ED. 12-96) Page 2
LIST OF SCHEDULES (Electric Utility) (continued)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofIdaho Power Company X
04/15/2015
2014/Q4
Line
No.
Title of Schedule Reference
Page No.
Remarks
(c)(b)(a)
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
269Other Deferred Credits 37
N/A272-273Accumulated Deferred Income Taxes-Accelerated Amortization Property 38
274-275Accumulated Deferred Income Taxes-Other Property 39
276-277Accumulated Deferred Income Taxes-Other 40
278Other Regulatory Liabilities 41
300-301Electric Operating Revenues 42
N/A302Regional Transmission Service Revenues (Account 457.1) 43
304Sales of Electricity by Rate Schedules 44
310-311Sales for Resale 45
320-323Electric Operation and Maintenance Expenses 46
326-327Purchased Power 47
328-330Transmission of Electricity for Others 48
N/A331Transmission of Electricity by ISO/RTOs 49
332Transmission of Electricity by Others 50
335Miscellaneous General Expenses-Electric 51
336-337Depreciation and Amortization of Electric Plant 52
350-351Regulatory Commission Expenses 53
352-353Research, Development and Demonstration Activities 54
354-355Distribution of Salaries and Wages 55
N/A356Common Utility Plant and Expenses 56
N/A397Amounts included in ISO/RTO Settlement Statements 57
N/A398Purchase and Sale of Ancillary Services 58
400Monthly Transmission System Peak Load 59
N/A400aMonthly ISO/RTO Transmission System Peak Load 60
401Electric Energy Account 61
401Monthly Peaks and Output 62
402-403Steam Electric Generating Plant Statistics 63
406-407Hydroelectric Generating Plant Statistics 64
N/A408-409Pumped Storage Generating Plant Statistics 65
410-411Generating Plant Statistics Pages 66
FERC FORM NO. 1 (ED. 12-96) Page 3
LIST OF SCHEDULES (Electric Utility) (continued)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofIdaho Power Company X
04/15/2015
2014/Q4
Line
No.
Title of Schedule Reference
Page No.
Remarks
(c)(b)(a)
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
422-423Transmission Line Statistics Pages 67
424-425Transmission Lines Added During the Year 68
426-427Substations 69
429Transactions with Associated (Affiliated) Companies 70
450Footnote Data 71
Stockholders' Reports Check appropriate box:
X Two copies will be submitted
No annual report to stockholders is prepared
FERC FORM NO. 1 (ED. 12-96) Page 4
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
GENERAL INFORMATION
Idaho Power Company X
04/15/2015 2014/Q4
Idaho, June 30, 1989
Ken Petersen Vice President,Controller and CAO, Idaho Power Company
1221 W. Idaho Street, P.O. Box 70, Boise, Idaho 83707-0070
1. Provide name and title of officer having custody of the general corporate books of account and address 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.
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.
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.
4. State the classes or utility and other services furnished by respondent during the year in each State in which
the respondent operated.
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) Yes...Enter the date when such independent accountant was initially engaged:
(2) NoX
Not Applicable
Class of Utility Service State
Electric Idaho
Electric Oregon
FERC FORM No.1 (ED. 12-87) PAGE 101
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
CORPORATIONS CONTROLLED BY RESPONDENT
Idaho Power Company X
04/15/2015
2014/Q4
Line
No.
Name of Company Controlled Kind of Business Percent Voting
Stock Owned(c)(b)(a)
Footnote
Ref.(d)
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.
1 Direct Control
Coal mining and mineral 100% 2 Idaho Energy Resources Company
development 3
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FERC FORM NO. 1 (ED. 12-96) Page 103
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
OFFICERS
Idaho Power Company X
04/15/2015
2014/Q4
Line
No.
Title Name of Officer Salaryfor Year(c)(b)(a)
1. Report below the name, title and salary for each executive officer whose salary is $50,000 or more. An "executive officer" of 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.
1
President & Chief Executive Officer 575,000Darrel T. Anderson 2
3
Executive Vice President & Chief Operating Officer 430,000Dan Minor 4
5
Senior Vice President & General Counsel 335,000Rex Blackburn 6
7
Senior Vice President, Power Supply 300,000Lisa Grow 8
9
Senior Vice President, CFO & Treasurer 315,000Steven Keen 10
11
Vice President, Human Resources & Corporate Services 265,000Luci McDonald 12
13
Vice President, Customer Operations 260,000Warren Kline 14
15
Vice President, Public Affairs 245,000Jeffrey Malmen 16
17
Vice President, & Chief Risk Officer 233,000Lori Smith 18
19
Vice President Delivery, Engineering & Construction 235,000Vern Porter 20
21
Vice President,Controller & Chief Accounting Officer 215,000Ken Petersen 22
23
Vice President & Chief Information Officer 208,000Lonnie Krawl 24
25
Vice President, Regulatory Affairs 210,000Gregory Said 26
27
Corporate Secretary 182,000Patrick Harrington 28
29
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40
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42
43
44
FERC FORM NO. 1 (ED. 12-96) Page 104
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DIRECTORS
Idaho Power Company X
04/15/2015
2014/Q4
Line Name (and Title) of Director Principal Business Address(b)(a)No.
1. Report below the information called for concerning each director of the respondent who held office at any time during the year. Include in column (a), 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.
1
1809 Headlee Lane, Lake Oswego, Oregon 97034Judith A. Johansen 2
3
8527 East old Field RdChristine King*** 4
Scottsdale, Azizona 85266 5
6
4642 W Dawson Dr., Meridian, Idaho 83646Stephen Allred (1) 7
8
900 W. Bogus View Drive, Eagle, Idaho 83616Jan B. Packwood 9
10
Idaho Power Company, 1221 W. Idaho Street,Darrel T. Anderson President & Chief Executive Office 11
P.O. Box 70, Boise, Idaho 83707-0070 12
13
481 North Strata Via Way, Boise Idaho 83712J. LaMont Keen, ** *** 14
15
16
2309 S.W. First Avenue, No. 1141, Portland, Oregon 97201Joan Smith 17
18
4433 W. Quail Point Court, Boise, Idaho 83703Robert A. Tinstman *** 19
20
1504 Warm Springs AvenueThomas Wilford 21
Boise, Idaho 83712 22
23
60 Laiki Pl.Richard Dahl *** 24
Kailua, Hawaill 96734 25
26
United Heritage Life InsuranceDennis L. Johnson 27
707 E. United Heritage Ct., Ste 130, Meridian, Idaho 83642 28
29
Questar CorporationRonald W. Jibson 30
333 South State Street, Salt Lake City, Utah 84145-0433 31
32
2719 North Woodview place, Boise Idaho 83702Thomas Carlile (2) 33
34
35
36
(1) Retired on May 15, 2014 37
(2) Appointed to Board March 19, 2014 38
39
40
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46
47
48
FERC FORM NO. 1 (ED. 12-95) Page 105
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
INFORMATION ON FORMULA RATES
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.FERC Rate Schedule or Tariff Number FERC Proceeding
Does the respondent have formula rates?Yes
No
X
1. Please list the Commission accepted formula rates including FERC Rate Schedule or Tariff Number and FERC proceeding (i.e. Docket No)
accepting the rate(s) or changes in the accepted rate.
FERC Rate Schedule/Tariff Number FERC Proceeding
FERC Electric Tariff 1
2
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FERC FORM NO. 1 (NEW. 12-08) Page 106
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofIdaho Power Company X
04/15/2015 2014/Q4
Line
No.\ Filed DateAccession No.
Date
Docket No. Description
Formula Rate FERC Rate
Schedule Number or
Tariff Number
INFORMATION ON FORMULA RATES
Does the respondent file with the Commission annual (or more frequent)Yes
No
X
2. If yes, provide a listing of such filings as contained on the Commission's eLibrary website
FERC Rate Schedule/Tariff Number FERC Proceeding
filings containing the inputs to the formula rate(s)?
Document
08/28/2014201408285251 ER09-1641-000 Idaho Power CompanyFERC Electric Tariff 1
2014 Annual 2
informational filing 3
under ER-09-1641-000 4
5
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FERC FORM NO. 1 (NEW. 12-08) Page 106a
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofIdaho Power Company X
04/15/2015 2014/Q4
Line
No.Page No(s). Schedule Column Line No
INFORMATION ON FORMULA RATES
1. If a respondent does not submit such filings then indicate in a footnote to the applicable Form 1 schedule where formula rate inputs differ from
Formula Rate Variances
amounts reported in the Form 1.
2. The footnote should provide a narrative description explaining how the "rate" (or billing) was derived if different from the reported amount in the
Form 1.
3. The footnote should explain amounts excluded from the ratebase or where labor or other allocation factors, operating expenses, or other items
impacting formula rate inputs differ from amounts reported in Form 1 schedule amounts.4. Where the Commission has provided guidance on formula rate inputs, the specific proceeding should be noted in the footnote.
None 1
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FERC FORM NO. 1 (NEW. 12-08) Page 106b
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report Year/Period of Report
End of
IMPORTANT CHANGES DURING THE QUARTER/YEAR
Idaho Power Company X 04/15/2015 2014/Q4
PAGE 108 INTENTIONALLY LEFT BLANK
SEE PAGE 109 FOR REQUIRED INFORMATION.
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 1 to 11 above, such notes may be included on this page.
13. Describe fully any changes in officers, directors, major security holders and voting powers of the respondent that may have 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.
FERC FORM NO. 1 (ED. 12-96) Page 108
1. None
2. None
3. None
4. None
5. Line #134 Line was rerouted into Bowmont substation. A portion was removed from
underbuild on line 248 and given its own alignment farther South.
Line #248 Removed de-energized line around Chestnut substation.
Line #464 Added .36 miles to reroute around the new hwy 16/44 intersection.
Line #479 A new 138kv line was placed in service between Bowmont and Happy Valley
substations. 8.64 miles

There continues to be realignment using LiDar data and Aerial photos. This realignment
will result in small additions or deletions to line lenghts. There were several other
lines where data errors or omissions have also been corrected.

6. As of December 31,2014 Idaho Power had not sold any first mortgage bonds, including
Series J notes, or debt securities under the selling agency agreement.
7. None
8. Effective 1/04/2014 a 3.0 general wage adjustment was implemented.
9. See pages 123.19 to 123.20
10. None
11. None
12. None
13. Idaho Power has added Thomas Carlile as a director effective 3/19/2014. Stephen Allred
retired effective 5/15/2014.
14. Idaho Power and its unregulated parent, IDACORP have seperate cash management
programs, (seperate bank accounts, liquidity facilities, short-term debt and investment
programs). No money has been loaned or advance from Idaho Power to IDACORP through a cash
management program.
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
FERC FORM NO. 1 (ED. 12-96)Page 109.1
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
X
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
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)
Idaho Power Company 04/15/2015 2014/Q4
UTILITY PLANT 1
5,255,302,762 5,087,492,230200-201Utility Plant (101-106, 114) 2
401,929,509 327,000,038200-201Construction Work in Progress (107) 3
5,657,232,271 5,414,492,268TOTAL Utility Plant (Enter Total of lines 2 and 3) 4
2,021,073,827 1,940,654,182200-201(Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115) 5
3,636,158,444 3,473,838,086Net Utility Plant (Enter Total of line 4 less 5) 6
0 0202-203Nuclear Fuel in Process of Ref., Conv.,Enrich., and Fab. (120.1) 7
0 0Nuclear Fuel Materials and Assemblies-Stock Account (120.2) 8
0 0Nuclear Fuel Assemblies in Reactor (120.3) 9
0 0Spent Nuclear Fuel (120.4) 10
0 0Nuclear Fuel Under Capital Leases (120.6) 11
0 0202-203(Less) Accum. Prov. for Amort. of Nucl. Fuel Assemblies (120.5) 12
0 0Net Nuclear Fuel (Enter Total of lines 7-11 less 12) 13
3,636,158,444 3,473,838,086Net Utility Plant (Enter Total of lines 6 and 13) 14
0 0Utility Plant Adjustments (116) 15
0 0Gas Stored Underground - Noncurrent (117) 16
OTHER PROPERTY AND INVESTMENTS 17
1,555,480 1,274,121Nonutility Property (121) 18
0 0(Less) Accum. Prov. for Depr. and Amort. (122) 19
0 0Investments in Associated Companies (123) 20
83,477,460 91,384,573224-225Investment in Subsidiary Companies (123.1) 21
(For Cost of Account 123.1, See Footnote Page 224, line 42) 22
0 0228-229Noncurrent Portion of Allowances 23
647 824Other Investments (124) 24
0 0Sinking Funds (125) 25
0 0Depreciation Fund (126) 26
0 0Amortization Fund - Federal (127) 27
45,082,335 42,271,755Other Special Funds (128) 28
0 0Special Funds (Non Major Only) (129) 29
63,323 288,132Long-Term Portion of Derivative Assets (175) 30
0 0Long-Term Portion of Derivative Assets – Hedges (176) 31
130,179,245 135,219,405TOTAL Other Property and Investments (Lines 18-21 and 23-31) 32
CURRENT AND ACCRUED ASSETS 33
0 0Cash and Working Funds (Non-major Only) (130) 34
46,581,578 66,420,846Cash (131) 35
1,079,260 3,106,514Special Deposits (132-134) 36
13,600 14,100Working Fund (135) 37
100,000 100,000Temporary Cash Investments (136) 38
0 50,208Notes Receivable (141) 39
85,040,915 100,221,798Customer Accounts Receivable (142) 40
14,677,441 11,336,452Other Accounts Receivable (143) 41
4,650,829 2,501,686(Less) Accum. Prov. for Uncollectible Acct.-Credit (144) 42
2,053,197 0Notes Receivable from Associated Companies (145) 43
0 0Accounts Receivable from Assoc. Companies (146) 44
55,170,482 41,546,323227Fuel Stock (151) 45
599 0227Fuel Stock Expenses Undistributed (152) 46
0 0227Residuals (Elec) and Extracted Products (153) 47
50,305,479 49,267,705227Plant Materials and Operating Supplies (154) 48
0 0227Merchandise (155) 49
0 0227Other Materials and Supplies (156) 50
0 0202-203/227Nuclear Materials Held for Sale (157) 51
0 0228-229Allowances (158.1 and 158.2) 52
FERC FORM NO. 1 (REV. 12-03) Page 110
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
X
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
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)
Idaho Power Company 04/15/2015 2014/Q4
(Continued)
0 0(Less) Noncurrent Portion of Allowances 53
5,098,760 4,375,589227Stores Expense Undistributed (163) 54
0 0Gas Stored Underground - Current (164.1) 55
0 0Liquefied Natural Gas Stored and Held for Processing (164.2-164.3) 56
18,355,589 15,204,045Prepayments (165) 57
0 0Advances for Gas (166-167) 58
0 0Interest and Dividends Receivable (171) 59
0 0Rents Receivable (172) 60
56,269,642 63,506,686Accrued Utility Revenues (173) 61
0 0Miscellaneous Current and Accrued Assets (174) 62
634,183 1,672,362Derivative Instrument Assets (175) 63
63,323 288,132(Less) Long-Term Portion of Derivative Instrument Assets (175) 64
0 0Derivative Instrument Assets - Hedges (176) 65
0 0(Less) Long-Term Portion of Derivative Instrument Assets - Hedges (176 66
330,666,573 354,032,810Total Current and Accrued Assets (Lines 34 through 66) 67
DEFERRED DEBITS 68
15,815,910 17,183,115Unamortized Debt Expenses (181) 69
0 0230aExtraordinary Property Losses (182.1) 70
0 0230bUnrecovered Plant and Regulatory Study Costs (182.2) 71
1,237,823,724 1,036,375,119232Other Regulatory Assets (182.3) 72
873,939 883,871Prelim. Survey and Investigation Charges (Electric) (183) 73
0 0Preliminary Natural Gas Survey and Investigation Charges 183.1) 74
0 0Other Preliminary Survey and Investigation Charges (183.2) 75
1,053,324 2,147,654Clearing Accounts (184) 76
0 0Temporary Facilities (185) 77
45,564,713 45,208,766233Miscellaneous Deferred Debits (186) 78
0 0Def. Losses from Disposition of Utility Plt. (187) 79
0 0352-353Research, Devel. and Demonstration Expend. (188) 80
12,799,888 13,860,473Unamortized Loss on Reaquired Debt (189) 81
289,103,584 246,774,821234Accumulated Deferred Income Taxes (190) 82
0 0Unrecovered Purchased Gas Costs (191) 83
1,603,035,082 1,362,433,819Total Deferred Debits (lines 69 through 83) 84
5,700,039,344 5,325,524,120TOTAL ASSETS (lines 14-16, 32, 67, and 84) 85
FERC FORM NO. 1 (REV. 12-03) Page 111
Year/Period of ReportName of Respondent This Report is:
(1) An Original
(2) A Resubmission
x
Date of Report
(mo, da, yr)
end of
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)
Idaho Power Company 04/15/2015 2014/Q4
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
PROPRIETARY CAPITAL 1
97,877,03097,877,030Common Stock Issued (201) 2 250-251
00Preferred Stock Issued (204) 3 250-251
00Capital Stock Subscribed (202, 205) 4
00Stock Liability for Conversion (203, 206) 5
712,257,435712,257,435Premium on Capital Stock (207) 6
00Other Paid-In Capital (208-211) 7 253
00Installments Received on Capital Stock (212) 8 252
00(Less) Discount on Capital Stock (213) 9 254
2,096,9252,096,925(Less) Capital Stock Expense (214) 10 254b
843,625,028952,335,875Retained Earnings (215, 215.1, 216) 11 118-119
88,921,47981,014,366Unappropriated Undistributed Subsidiary Earnings (216.1) 12 118-119
00(Less) Reaquired Capital Stock (217) 13 250-251
00 Noncorporate Proprietorship (Non-major only) (218) 14
-16,553,375-24,157,999Accumulated Other Comprehensive Income (219) 15 122(a)(b)
1,724,030,6721,817,229,782Total Proprietary Capital (lines 2 through 15) 16
LONG-TERM DEBT 17
1,595,460,0001,595,460,000Bonds (221) 18 256-257
00(Less) Reaquired Bonds (222) 19 256-257
00Advances from Associated Companies (223) 20 256-257
24,139,54523,075,909Other Long-Term Debt (224) 21 256-257
00Unamortized Premium on Long-Term Debt (225) 22
3,277,5913,034,022(Less) Unamortized Discount on Long-Term Debt-Debit (226) 23
1,616,321,9541,615,501,887Total Long-Term Debt (lines 18 through 23) 24
OTHER NONCURRENT LIABILITIES 25
00Obligations Under Capital Leases - Noncurrent (227) 26
00Accumulated Provision for Property Insurance (228.1) 27
1,670,6951,994,972Accumulated Provision for Injuries and Damages (228.2) 28
245,780,272403,474,921Accumulated Provision for Pensions and Benefits (228.3) 29
2,771,3563,865,254Accumulated Miscellaneous Operating Provisions (228.4) 30
59,388,81672,974,757Accumulated Provision for Rate Refunds (229) 31
00Long-Term Portion of Derivative Instrument Liabilities 32
00Long-Term Portion of Derivative Instrument Liabilities - Hedges 33
25,765,36421,930,049Asset Retirement Obligations (230) 34
335,376,503504,239,953Total Other Noncurrent Liabilities (lines 26 through 34) 35
CURRENT AND ACCRUED LIABILITIES 36
00Notes Payable (231) 37
105,671,106113,979,552Accounts Payable (232) 38
13,264,1810Notes Payable to Associated Companies (233) 39
1,158,0632,027,220Accounts Payable to Associated Companies (234) 40
1,428,2211,568,822Customer Deposits (235) 41
15,104,410-10,635,253Taxes Accrued (236) 42 262-263
22,834,80422,670,165Interest Accrued (237) 43
00Dividends Declared (238) 44
00Matured Long-Term Debt (239) 45
FERC FORM NO. 1 (rev. 12-03) Page 112
Year/Period of ReportName of Respondent This Report is:
(1) An Original
(2) A Resubmission
x
Date of Report
(mo, da, yr)
end of
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)
Idaho Power Company 04/15/2015 2014/Q4
(continued)COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
00Matured Interest (240) 46
1,444,6492,599,099Tax Collections Payable (241) 47
35,788,24340,889,480Miscellaneous Current and Accrued Liabilities (242) 48
00Obligations Under Capital Leases-Current (243) 49
571,7473,960,704Derivative Instrument Liabilities (244) 50
00(Less) Long-Term Portion of Derivative Instrument Liabilities 51
00Derivative Instrument Liabilities - Hedges (245) 52
00(Less) Long-Term Portion of Derivative Instrument Liabilities-Hedges 53
197,265,424177,059,789Total Current and Accrued Liabilities (lines 37 through 53) 54
DEFERRED CREDITS 55
9,465,2173,303,553Customer Advances for Construction (252) 56
79,121,29079,162,831Accumulated Deferred Investment Tax Credits (255) 57 266-267
00Deferred Gains from Disposition of Utility Plant (256) 58
12,386,72111,635,642Other Deferred Credits (253) 59 269
70,377,00064,843,269Other Regulatory Liabilities (254) 60 278
00Unamortized Gain on Reaquired Debt (257) 61
00Accum. Deferred Income Taxes-Accel. Amort.(281) 62 272-277
1,143,090,4661,248,630,361Accum. Deferred Income Taxes-Other Property (282) 63
138,088,873178,432,277Accum. Deferred Income Taxes-Other (283) 64
1,452,529,5671,586,007,933Total Deferred Credits (lines 56 through 64) 65
5,325,524,1205,700,039,344TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65) 66
FERC FORM NO. 1 (rev. 12-03) Page 113
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STATEMENT OF INCOME
Idaho Power Company X
04/15/2015 2014/Q4
Line
(c)(b)(a)
Title of Account
No.
Total
Current Year to
Date Balance for
Quarter/Year
(d)
(Ref.)
Page No.
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 (l) 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.
Current 3 Months
Ended
Quarterly Only
No 4th Quarter
(e)
Prior 3 Months
Ended
Quarterly Only
No 4th Quarter
(f)
Total
Prior Year to
Date Balance for
Quarter/Year
UTILITY OPERATING INCOME 1
1,277,640,977 1,242,150,868300-301Operating Revenues (400) 2
Operating Expenses 3
780,281,536 710,931,086320-323Operation Expenses (401) 4
68,283,304 67,728,722320-323Maintenance Expenses (402) 5
125,245,540 121,486,191336-337Depreciation Expense (403) 6
495,029 587,012336-337Depreciation Expense for Asset Retirement Costs (403.1) 7
7,172,382 7,611,634336-337Amort. & Depl. of Utility Plant (404-405) 8
336-337Amort. of Utility Plant Acq. Adj. (406) 9
Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407) 10
Amort. of Conversion Expenses (407) 11
73,650 56,176Regulatory Debits (407.3) 12
(Less) Regulatory Credits (407.4) 13
31,748,230 30,560,823262-263Taxes Other Than Income Taxes (408.1) 14
-7,413,733 9,918,700262-263Income Taxes - Federal (409.1) 15
6,908,583 5,499,764262-263 - Other (409.1) 16
152,963,217 138,292,290234, 272-277Provision for Deferred Income Taxes (410.1) 17
134,837,097 82,501,409234, 272-277(Less) Provision for Deferred Income Taxes-Cr. (411.1) 18
41,541 -775,313266Investment Tax Credit Adj. - Net (411.4) 19
6,043(Less) Gains from Disp. of Utility Plant (411.6) 20
6,766Losses from Disp. of Utility Plant (411.7) 21
186,382 41,307(Less) Gains from Disposition of Allowances (411.8) 22
Losses from Disposition of Allowances (411.9) 23
309,716 322,348Accretion Expense (411.10) 24
1,031,085,516 1,009,677,440TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24) 25
246,555,461 232,473,428Net Util Oper Inc (Enter Tot line 2 less 25) Carry to Pg117,line 27 26
FERC FORM NO. 1/3-Q (REV. 02-04) Page 114
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STATEMENT OF INCOME FOR THE YEAR (Continued)
Idaho Power Company X
04/15/2015 2014/Q4
Line Previous Year to Date
(in dollars)
(k)(j)(g)
ELECTRIC UTILITY
No.Current Year to Date
(in dollars)
OTHER UTILITY
(l)
GAS UTILITY
Previous Year to Date
(in dollars)
Current Year to Date
(in dollars)
Previous Year to Date
(in dollars)
Current Year to Date
(in dollars)
(h) (i)
9. Use page 122 for important notes regarding the statement of income for any account thereof.
10. Give concise explanations concerning unsettled rate proceedings where a contingency exists such that refunds of a material amount may need to 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/quarter's figures are different from that reported in prior reports.
15. If the columns are insufficient for reporting additional utility departments, supply the appropriate account titles report the information in a footnote to
this schedule.
1
1,277,640,977 1,242,150,868 2
3
780,281,536 710,931,086 4
68,283,304 67,728,722 5
125,245,540 121,486,191 6
495,029 587,012 7
7,172,382 7,611,634 8
9
10
11
73,650 56,176 12
13
31,748,230 30,560,823 14
-7,413,733 9,918,700 15
6,908,583 5,499,764 16
152,963,217 138,292,290 17
134,837,097 82,501,409 18
41,541 -775,313 19
6,043 20
6,766 21
186,382 41,307 22
23
309,716 322,348 24
1,031,085,516 1,009,677,440 25
246,555,461 232,473,428 26
FERC FORM NO. 1 (ED. 12-96) Page 115
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STATEMENT OF INCOME FOR THE YEAR (continued)
Idaho Power Company X
04/15/2015 2014/Q4
Line
Previous Year
(c)(b)(a)
Title of Account
No.
Current Year
TOTAL
(d)
(Ref.)
Page No.
Current 3 Months
Ended
Quarterly Only
No 4th Quarter
(e)
Prior 3 Months
Ended
Quarterly Only
No 4th Quarter
(f)
246,555,461 232,473,428Net Utility Operating Income (Carried forward from page 114) 27
Other Income and Deductions 28
Other Income 29
Nonutilty Operating Income 30
1,009,910 946,897Revenues From Merchandising, Jobbing and Contract Work (415) 31
1,136,669 1,079,771(Less) Costs and Exp. of Merchandising, Job. & Contract Work (416) 32
37,547 41,993Revenues From Nonutility Operations (417) 33
22,828 60,482(Less) Expenses of Nonutility Operations (417.1) 34
-527 -2,844Nonoperating Rental Income (418) 35
7,092,887 6,704,329119Equity in Earnings of Subsidiary Companies (418.1) 36
2,704,620 2,426,000Interest and Dividend Income (419) 37
17,930,898 14,857,580Allowance for Other Funds Used During Construction (419.1) 38
2,453,947 14,488,869Miscellaneous Nonoperating Income (421) 39
-4,240 -2,442Gain on Disposition of Property (421.1) 40
30,065,545 38,320,129TOTAL Other Income (Enter Total of lines 31 thru 40) 41
Other Income Deductions 42
2,156 1,917Loss on Disposition of Property (421.2) 43
Miscellaneous Amortization (425) 44
747,094 744,976 Donations (426.1) 45
-1,164,064 -18,319 Life Insurance (426.2) 46
27,106 428,042 Penalties (426.3) 47
1,561,921 1,282,131 Exp. for Certain Civic, Political & Related Activities (426.4) 48
8,332,431 8,655,953 Other Deductions (426.5) 49
9,506,644 11,094,700TOTAL Other Income Deductions (Total of lines 43 thru 49) 50
Taxes Applic. to Other Income and Deductions 51
24,797 22,991262-263Taxes Other Than Income Taxes (408.2) 52
-914,126 1,540,870262-263Income Taxes-Federal (409.2) 53
-41,215 417,095262-263Income Taxes-Other (409.2) 54
1,085,673 2,496,132234, 272-277Provision for Deferred Inc. Taxes (410.2) 55
2,008,392 2,173,220234, 272-277(Less) Provision for Deferred Income Taxes-Cr. (411.2) 56
Investment Tax Credit Adj.-Net (411.5) 57
(Less) Investment Tax Credits (420) 58
-1,853,263 2,303,868TOTAL Taxes on Other Income and Deductions (Total of lines 52-58) 59
22,412,164 24,921,561Net Other Income and Deductions (Total of lines 41, 50, 59) 60
Interest Charges 61
80,561,920 81,492,149Interest on Long-Term Debt (427) 62
1,610,773 1,609,364Amort. of Debt Disc. and Expense (428) 63
1,060,585 1,060,585Amortization of Loss on Reaquired Debt (428.1) 64
(Less) Amort. of Premium on Debt-Credit (429) 65
(Less) Amortization of Gain on Reaquired Debt-Credit (429.1) 66
10,524 7,955Interest on Debt to Assoc. Companies (430) 67
4,800,939 4,146,983Other Interest Expense (431) 68
8,464,109 7,663,190(Less) Allowance for Borrowed Funds Used During Construction-Cr. (432) 69
79,580,632 80,653,846Net Interest Charges (Total of lines 62 thru 69) 70
189,386,993 176,741,143Income Before Extraordinary Items (Total of lines 27, 60 and 70) 71
Extraordinary Items 72
Extraordinary Income (434) 73
(Less) Extraordinary Deductions (435) 74
Net Extraordinary Items (Total of line 73 less line 74) 75
262-263Income Taxes-Federal and Other (409.3) 76
Extraordinary Items After Taxes (line 75 less line 76) 77
189,386,993 176,741,143Net Income (Total of line 71 and 77) 78
FERC FORM NO. 1/3-Q (REV. 02-04) Page 117
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STATEMENT OF RETAINED EARNINGS
Idaho Power Company X
04/15/2015
2014/Q4
Line
Current
Quarter/Year
Year to Date
Balance
(c)(b)(a)
Item
Contra Primary
No.
Account Affected
1. Do not report Lines 49-53 on the quarterly version.
2. Report all changes in appropriated retained earnings, unappropriated retained earnings, year to date, and 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.
Previous
Quarter/Year
Year to Date
Balance
(d)
UNAPPROPRIATED RETAINED EARNINGS (Account 216)
749,111,203 836,965,502 1 Balance-Beginning of Period
2 Changes
3 Adjustments to Retained Earnings (Account 439)
4
5
6
7
8
9 TOTAL Credits to Retained Earnings (Acct. 439)
10
11
12
13
14
15 TOTAL Debits to Retained Earnings (Acct. 439)
170,036,814 182,294,106 16 Balance Transferred from Income (Account 433 less Account 418.1)
17 Appropriations of Retained Earnings (Acct. 436)
( 3,256,123) -6,613,580215.1 18
19
20
21
( 3,256,123) -6,613,580 22 TOTAL Appropriations of Retained Earnings (Acct. 436)
23 Dividends Declared-Preferred Stock (Account 437)
24
25
26
27
28
29 TOTAL Dividends Declared-Preferred Stock (Acct. 437)
30 Dividends Declared-Common Stock (Account 438)
( 78,926,392) -88,583,259 31
32
33
34
35
( 78,926,392) -88,583,259 36 TOTAL Dividends Declared-Common Stock (Acct. 438)
15,000,000216 37 Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings
836,965,502 939,062,769 38 Balance - End of Period (Total 1,9,15,16,22,29,36,37)
APPROPRIATED RETAINED EARNINGS (Account 215)
39
40
FERC FORM NO. 1/3-Q (REV. 02-04)Page 118
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STATEMENT OF RETAINED EARNINGS
Idaho Power Company X
04/15/2015
2014/Q4
Line
Current
Quarter/Year
Year to Date
Balance
(c)(b)(a)
Item
Contra Primary
No.
Account Affected
1. Do not report Lines 49-53 on the quarterly version.
2. Report all changes in appropriated retained earnings, unappropriated retained earnings, year to date, and 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.
Previous
Quarter/Year
Year to Date
Balance
(d)
41
42
43
44
45 TOTAL Appropriated Retained Earnings (Account 215)
APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Account 215.1)
6,659,526 13,273,106 46 TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Acct. 215.1)
6,659,526 13,273,106 47 TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46)
843,625,028 952,335,875 48 TOTAL Retained Earnings (Acct. 215, 215.1, 216) (Total 38, 47) (216.1)
UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account
Report only on an Annual Basis, no Quarterly
82,217,150 88,921,479 49 Balance-Beginning of Year (Debit or Credit)
6,704,329 7,092,887 50 Equity in Earnings for Year (Credit) (Account 418.1)
15,000,000 51 (Less) Dividends Received (Debit)
52
88,921,479 81,014,366 53 Balance-End of Year (Total lines 49 thru 52)
FERC FORM NO. 1/3-Q (REV. 02-04)Page 119
(1) Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial paper; and (d) Identify separately such items as
investments, fixed assets, intangibles, etc.
(2) Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliation between "Cash and
Cash Equivalents at End of Period" with related amounts on the Balance Sheet.
(3) Operating Activities - Other: Include gains and losses pertaining to operating activities only. Gains and losses pertaining to investing and financing activities should be
reported in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid.
(4) Investing Activities: Include at Other (line 31) net cash outflow to acquire other companies. Provide a reconciliation of assets acquired with liabilities assumed in the Notes
to the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General Instruction 20; instead provide a reconciliation of
the dollar amount of leases capitalized with the plant cost.
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STATEMENT OF CASH FLOWS
Idaho Power Company X
04/15/2015 2014/Q4
Line Description (See Instruction No. 1 for Explanation of Codes)Current Year to Date
Quarter/Year
(b)(a)No.
Previous Year to Date
Quarter/Year
(c)
1 Net Cash Flow from Operating Activities:
176,741,143 189,386,993 2 Net Income (Line 78(c) on page 117)
3 Noncash Charges (Credits) to Income:
121,486,191 125,245,540 4 Depreciation and Depletion
11,648,544 11,250,901 5 Amortization of Note 1
6
7
55,836,153 17,218,276 8 Deferred Income Taxes (Net)
-497,674 26,665 9 Investment Tax Credit Adjustment (Net)
-30,953,272 22,570,540 10 Net (Increase) Decrease in Receivables
-1,213,152 -15,385,702 11 Net (Increase) Decrease in Inventory
12 Net (Increase) Decrease in Allowances Inventory
7,503,331 -18,687,818 13 Net Increase (Decrease) in Payables and Accrued Expenses
-40,694,556 16,794,041 14 Net (Increase) Decrease in Other Regulatory Assets
15,112,871 15,341,861 15 Net Increase (Decrease) in Other Regulatory Liabilities
14,857,580 17,930,898 16 (Less) Allowance for Other Funds Used During Construction
6,704,329 -7,907,113 17 (Less) Undistributed Earnings from Subsidiary Companies
-17,772,390 4,789,855 18 Other (provide details in footnote): Note 2
19
20
21
275,635,280 358,527,367 22 Net Cash Provided by (Used in) Operating Activities (Total 2 thru 21)
23
24 Cash Flows from Investment Activities:
25 Construction and Acquisition of Plant (including land):
-250,164,015 -291,841,495 26 Gross Additions to Utility Plant (less nuclear fuel)
27 Gross Additions to Nuclear Fuel
28 Gross Additions to Common Utility Plant
29 Gross Additions to Nonutility Plant
-14,857,580 -17,930,898 30 (Less) Allowance for Other Funds Used During Construction
498,473 3,551,443 31 Other (provide details in footnote): Note 3
32
33
-234,807,962 -270,359,154 34 Cash Outflows for Plant (Total of lines 26 thru 33)
35
36 Acquisition of Other Noncurrent Assets (d)
37 Proceeds from Disposal of Noncurrent Assets (d)
38
14,272,430 -15,317,379 39 Investments in and Advances to Assoc. and Subsidiary Companies
40 Contributions and Advances from Assoc. and Subsidiary Companies
41 Disposition of Investments in (and Advances to)
42 Associated and Subsidiary Companies
43
-32,660,820 -8,000,000 44 Purchase of Investment Securities (a)
25,660,820 45 Proceeds from Sales of Investment Securities (a)
FERC FORM NO. 1 (ED. 12-96) Page 120
(1) Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial paper; and (d) Identify separately such items as
investments, fixed assets, intangibles, etc.
(2) Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliation between "Cash and
Cash Equivalents at End of Period" with related amounts on the Balance Sheet.
(3) Operating Activities - Other: Include gains and losses pertaining to operating activities only. Gains and losses pertaining to investing and financing activities should be
reported in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid.
(4) Investing Activities: Include at Other (line 31) net cash outflow to acquire other companies. Provide a reconciliation of assets acquired with liabilities assumed in the Notes
to the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General Instruction 20; instead provide a reconciliation of
the dollar amount of leases capitalized with the plant cost.
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STATEMENT OF CASH FLOWS
Idaho Power Company X
04/15/2015 2014/Q4
Line Description (See Instruction No. 1 for Explanation of Codes)Current Year to Date
Quarter/Year
(b)(a)No.
Previous Year to Date
Quarter/Year
(c)
46 Loans Made or Purchased
47 Collections on Loans
48
22,284 50,208 49 Net (Increase) Decrease in Receivables
50 Net (Increase ) Decrease in Inventory
51 Net (Increase) Decrease in Allowances Held for Speculation
52 Net Increase (Decrease) in Payables and Accrued Expenses
3,450,425 4,906,085 53 Other (provide details in footnote): Note 4
54
55
56 Net Cash Provided by (Used in) Investing Activities
-224,062,823 -288,720,240 57 Total of lines 34 thru 55)
58
59 Cash Flows from Financing Activities:
60 Proceeds from Issuance of:
150,000,000 61 Long-Term Debt (b)
62 Preferred Stock
63 Common Stock
64 Other (provide details in footnote):
65
66 Net Increase in Short-Term Debt (c)
67 Other (provide details in footnote):
68
69
150,000,000 70 Cash Provided by Outside Sources (Total 61 thru 69)
71
72 Payments for Retirement of:
-71,063,636 -1,063,636 73 Long-term Debt (b)
74 Preferred Stock
75 Common Stock
-2,298,726 76 Other (provide details in footnote):
77
78 Net Decrease in Short-Term Debt (c)
79
80 Dividends on Preferred Stock
-78,926,392 -88,583,259 81 Dividends on Common Stock
82 Net Cash Provided by (Used in) Financing Activities
-2,288,754 -89,646,895 83 (Total of lines 70 thru 81)
84
85 Net Increase (Decrease) in Cash and Cash Equivalents
49,283,703 -19,839,768 86 (Total of lines 22,57 and 83)
87
17,251,243 66,534,946 88 Cash and Cash Equivalents at Beginning of Period
89
66,534,946 46,695,178 90 Cash and Cash Equivalents at End of period
FERC FORM NO. 1 (ED. 12-96) Page 121
Schedule Page: 120 Line No.: 5 Column: b

Plant 7,172,382
Unamortized debt expense 2,728,016
Unamortized discount 243,569
Water rights 1,042,009
Other 64,925
11,250,901
Schedule Page: 120 Line No.: 13 Column: b

Cash paid during the period for:
Income taxes 22,202,480
Interest (net of amount capitalized) 77,063,389
Schedule Page: 120 Line No.: 18 Column: b

Cash Flow from Operating Activities (Other)
Pension and postretirement benefit plan expense 44,578,826
Contributions to pension and postretirement benefit plans (33,672,415)
Unbilled revenues 7,237,044
Prepayments (4,988,374)
Company owned life insurance (1,856,230)
Customer deposits (5,746,063)
Other (762,933)
4,789,855
Schedule Page: 120 Line No.: 26 Column: b

Non-cash investing activities:
Additions to PP&E in accounts payable 28,438,385
Schedule Page: 120 Line No.: 31 Column: b
Other Cash Flows from Plant
Sale of utility property 620,205
Sale of emission allowances and renewable energy certificates 2,931,238
3,551,443
Schedule Page: 120 Line No.: 53 Column: b
Other Investing Cash Flows
Disbursements from rabbi trust & EDC plan 4,905,908
Miscellaneous other investing activities 177
----------
4,906,085

Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report Year/Period of Report
End of
NOTES TO FINANCIAL STATEMENTS
Idaho Power Company X 04/15/2015 2014/Q4
PAGE 122 INTENTIONALLY LEFT BLANK
SEE PAGE 123 FOR REQUIRED INFORMATION.
1. Use the space below for important notes regarding the Balance Sheet, Statement of Income for the year, Statement of 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.
FERC FORM NO. 1 (ED. 12-96) Page 122
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 area 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 , (6) non-utility revenues and (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
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.
Idaho Power’s financial statements reflect the effects of the different ratemaking principles followed by the jurisdictions regulating
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.1
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 record such expenses and revenues. 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 that are expected to be refunded. The effects of applying these regulatory
accounting principles to Idaho Power’s operations are discussed in more detail in Note 3.
Cash and Cash Equivalents
Cash and cash equivalents include cash on-hand and highly liquid temporary investments that mature within 90 days of the date of
acquisition.
Receivables and Allowance for Uncollectible Accounts
Customer receivables are recorded at the invoiced amounts and do not bear interest. A late payment fee of one percent may be
assessed on account balances after 30 days. An allowance is recorded for potential uncollectible accounts. The allowance is reviewed
periodically and adjusted based upon a combination of historical write-off experience, aging of accounts receivable, and an analysis
of specific customer accounts. Adjustments are charged to income. Customer accounts receivable balances that remain outstanding
after reasonable collection efforts are written off through a charge to the allowance and a credit to accounts receivable.
Other receivables 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, 2014 and 2013. 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. With the exception of forward contracts for the
purchase of natural gas for use at Idaho Power's natural gas generation facilities and a nominal number of power transactions, Idaho
Power’s physical forward contracts are designated as normal purchases and normal sales. 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
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.2
Operating revenues related to Idaho Power’s sale of energy are recorded when service is rendered or energy is delivered to
customers. Idaho Power accrues estimated unbilled revenues for electric services delivered to customers but not yet billed at
year-end. Idaho Power collects franchise fees and similar taxes related to energy consumption. None of these collections are reported
on the income statement. Beginning in February 2009, Idaho Power is collecting in base rates a portion of the allowance for funds
used during construction (AFUDC) related to its Hells Canyon Complex (HCC) 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 2.68 percent in 2014 and 2.69 percent
in 2013.
During the period of construction, costs expected to be included in the final value of the constructed asset, and depreciated once the
asset is complete and placed in service, are classified as construction work in progress on the consolidated balance sheets. If the
project becomes probable of being abandoned, such costs are expensed in the period such determination is made. If any costs are
expensed, Idaho Power may seek recovery of such costs in customer rates, although there can be no guarantee such recovery would be
granted.
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 is recognized in the financial statements. There were no material impairments of these assets
in 2014 or 2013.
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 HCC 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 rate was 7.7 percent for 2014 and 2013.
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
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.3
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 from the beginning to the 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.
Other Accounting Policies
Debt discount, expense, and premium are deferred and are being amortized over the terms of the respective debt issues.
Recently Issued Accounting Pronouncements
In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update (ASU) 2014-09, Revenue from
Contracts with Customers (Topic 606). ASU 2014-09 is intended to enable users of financial statements to better understand and
consistently analyze an entity's revenue across industries, transactions, and geographies. Under the ASU, recognition of revenue
occurs when a customer obtains control of promised goods or services. In addition, the ASU requires disclosure of the nature,
amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The amendments in ASU 2014-09
are effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period.
Early adoption is not permitted. The guidance permits two implementation approaches, one requiring retrospective application of the
new standard with restatement of prior years and one requiring prospective application of the new standard including a
cumulative-effect adjustment with disclosure of results under old standards. As such, at Idaho Power's required adoption date of
January 1, 2017, amounts in 2015 and 2016 may have to be revised. Idaho Power is currently evaluating the impact of ASU 2014-09
on its financial statements.
Subsequent Events
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.4
Management has evaluated the impact of events occurring after December 31, 2014 up to February 19, 2015, the date that Idaho
Power Company’s U.S. GAAP financial statements were issued and has updated such evaluation for disclosure purposes through
April 15, 2015. These financial statements include all necessary adjustments and disclosures resulting from these evaluations.
2. INCOME TAXES
A reconciliation between the statutory federal income tax rate and the effective tax rate is as follows (in thousands of dollars):
2014 2013
Federal income tax expense at 35% statutory rate $ 71,810 $ 87,310
Change in taxes resulting from:
Equity Earnings of subsidiary companies (2,483) (2,347)
AFUDC (9,238) (7,882)
Capitalized interest 2,278 1,832
Investment tax credits (3,002) (3,120)
Removal costs (3,656) (3,527)
Capitalized overhead costs (8,750) (8,750)
Capitalized repair costs (26,250) (19,250)
Tax method change – capitalized repairs (24,516) 4,583
State income taxes, net of federal benefit 5,334 6,970
Depreciation 16,040 14,820
Other, net (1,783) 2,076
Total income tax expense $ 15,784 $ 72,715
Effective tax rate 7.7 % 29.1 %
The items comprising income tax expense are as follows (in thousands of dollars):
2014 2013
Income taxes current:
Federal $ (8,328) $ 11,460
State 6,867 5,917
Total (1,461) 17,377
Income taxes deferred:
Federal 23,624 56,918
State (6,421) (804)
Total 17,203 56,114
Investment tax credits:
Deferred 3,044 2,344
Restored (3,002) (3,120)
Total 42 (776)
Total income tax expense $ 15,784 $ 72,715
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.5
The components of the net deferred tax liability are as follows (in thousands of dollars):
2014 2013
Deferred tax assets:
Regulatory liabilities $ 55,490 $ 55,017
Deferred compensation 25,240 23,647
Deferred revenue 28,529 23,062
Tax credits 26,768 23,642
Net operating losses — 29,628
Retirement benefits 132,571 69,033
Other 14,553 10,359
Total 283,151 234,388
Deferred tax liabilities:
Property, plant and equipment 451,118 436,837
Regulatory assets 802,188 710,482
Power cost adjustments 23,192 35,763
Retirement benefits 122,360 65,810
Other 22,252 19,901
Total 1,421,110 1,268,793
Net deferred tax liabilities $ 1,137,959 $ 1,034,405
IDACORP's tax allocation agreement provides that each member of its consolidated group compute its income taxes on a separate
company basis. Amounts payable or refundable are settled through IDACORP. See Note 1 for further discussion of accounting
policies related to income taxes.
Uncertain Tax Positions
Idaho Power believes that it has no material income tax uncertainties for 2014 and prior tax years. The company recognizes interest
accrued related to unrecognized tax benefits as interest expense and penalties as other expense.
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 2014 for federal and 2011-2014 for Idaho. In May 2009, IDACORP formally entered the U.S. Internal Revenue
Service (IRS) Compliance Assurance Process (CAP) program for its 2009 tax year and has remained in the CAP program for all
subsequent years. The CAP program provides for IRS examination and issue resolution throughout the current year with the
objective of return filings containing no contested items. In 2014, the IRS completed its examination of IDACORP's 2013 tax year
with no unresolved income tax issues.
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.6
Tax Accounting Method Changes for Repair-Related Expenditures
In the fourth quarter of 2014, Idaho Power finalized an income tax accounting method change for its 2014 tax year associated with the
electric generation property portion of its capitalized repairs tax method it adopted in fiscal year 2010. As a result of the change,
Idaho Power recorded an $8.8 million tax benefit related to the cumulative method change adjustment for years prior to 2014 and
reversed a related $4.6 million tax expense estimate it had recorded in 2013 (discussed below), for a total adjustment of $13.4 million.

The method change is pursuant to Revenue Procedure 2013-24 and will bring Idaho Power's existing method into alignment with the
Revenue Procedure's safe harbor unit-of-property definitions for electric generation property. The change also incorporates
provisions of the final tangible property regulations issued by the U.S. Treasury Department (Treasury) and IRS in the third quarter of
2013 that address the deduction or capitalization of expenditures related to tangible property. Following the automatic consent
procedures provided for in the Revenue Procedure, Idaho Power expects to adopt this method with the filing of IDACORP’s 2014
consolidated federal income tax return in September 2015. The method change will be subject to IRS review as part of IDACORP’s
CAP examination.
In the third quarter of 2014, Idaho Power, in coordination with the IRS through IDACORP’s CAP examination process, implemented
aspects of the final tangible property regulations and other technical interpretations of these rules into its existing capitalized repairs
tax accounting method for generation, transmission and distribution assets. These technical interpretations were received from the
IRS in 2014. An $11.1 million tax benefit related to the portion of the 2013 capitalized repairs deduction based on these
modifications was recorded in the third quarter. Idaho Power finalized these changes with the filing of IDACORP’s 2013
consolidated federal income tax return in September 2014. The IRS approved the repairs method modifications prior to the filing of
the return as part of IDACORP’s 2013 CAP examination.
In connection with the issuance of the tangible property regulations and following the provisions of Revenue Procedure 2013-24
(discussed above), in the third quarter of 2013 Idaho Power assessed and estimated the impact of a method change associated with the
electric generation property portion of its capitalized repairs method. Based upon this assessment, in 2013 Idaho Power recorded $4.6
million of income tax expense related to the estimated cumulative method change adjustment for years prior to 2013.
The amount of the capitalized repairs annual tax deduction will vary depending on a number of factors, but most directly by the
amount and type of Idaho Power’s annual capital additions. The reversal of this temporary difference from prior years will offset a
portion of the ongoing annual benefit. Idaho Power’s prescribed regulatory accounting treatment requires immediate income
recognition for temporary tax differences of this type, commonly referred to as “flow-through.” A net regulatory asset is established
to reflect Idaho Power’s ability to recover the net increased income tax expense when such temporary differences reverse. Idaho
Power’s 2014 capitalized repairs deduction estimate incorporates the provisions of both method changes.
3. REGULATORY MATTERS
Included below is information on Idaho Power's regulatory assets and liabilities, as well as a summary of Idaho Power's most recent
general rate changes and other notable recent or pending regulatory matters and proceedings.
Regulatory Assets and Liabilities
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.7
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 record such expenses and revenues. Regulatory assets
represent incurred costs that have been deferred because it is probable they will be recovered from customers through future rates.
Regulatory liabilities represent obligations to make refunds to customers for previous collections, or represent amounts collected in
advance of incurring an expense. The following table presents a summary of Idaho Power’s regulatory assets and liabilities (in
thousands of dollars):
Remaining
Amortization
Period
As of
December 31,
2014 Earning
a Return(1)
As of
December 31,
2014 Not
Earning a
Return
Total as of
December 31,
2014
Total as of
December 31,
2013
Regulatory Assets:
Income taxes $ — $ 802,188 $ 802,188 $ 710,482
Unfunded postretirement benefits(2) — 264,548 264,548 116,583
Pension expense deferrals 40,816 22,828 63,644 75,108
Energy efficiency program costs(3) 4,690 — 4,690 3,694
Power supply costs(3) Varies 59,189 — 59,189 91,477
Fixed cost adjustment(3) 2015-2016 23,737 — 23,737 19,526
Asset retirement obligations(4) — 17,309 17,309 18,026
Mark-to-market liabilities(5) — 3,961 3,961 1,629
Other 2015-2021 1,215 1,906 3,121 3,546
Total $ 129,647 $ 1,112,740 $ 1,242,387 $ 1,040,071
Regulatory Liabilities:
Income taxes $ — $ 55,490 $ 55,490 $ 55,017
Energy efficiency program costs(3) — — — 6,686
Power supply costs(3) Varies 1 — 1 24
Settlement agreement sharing mechanism(3) 2015-2016 7,999 — 7,999 7,602
Mark-to-market assets(5) — 1,880 1,880 1,672
Other 3,114 922 4,036 3,470
Total $ 11,114 $ 58,292 $ 69,406 $ 74,471
(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 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 typically 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 materially adverse
financial impact.
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.8
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 contracted
power purchase prices and volumes, changes in wholesale market prices and transaction volumes, fuel prices, and the levels of Idaho
Power's own generation.
Idaho Jurisdiction Power Cost Adjustment Mechanism: In the Idaho jurisdiction, the annual PCA adjustment consists of (a) a
forecast component, based on a forecast of net power supply costs in the coming year as compared with net power supply costs
included in base rates; and (b) a true-up component, based on the difference between the previous year’s actual net power supply
costs and the previous year’s forecast. The latter component also includes a balancing mechanism so that, over time, the actual
collection or refund of authorized true-up dollars matches the amounts authorized. The Idaho PCA mechanism also includes:
•a cost or benefit sharing ratio that allocates the deviations in net power supply expenses between customers (95 percent) and
shareholders (5 percent), with the exceptions of expenses associated with PURPA power purchases and demand response
incentive payments, which are allocated 100 percent to customers; and
•a load change adjustment rate, which is intended to ensure that power supply expense fluctuations resulting solely from load
changes do not distort the results of the mechanism.
The table below summarizes the two most recent Idaho PCA rate adjustments, all of which also include non-PCA-related rate
adjustments as ordered by the IPUC:
Effective Date $ Change (millions)Notes
June 1, 2014 $ (88.2)2014 PCA rates are net of (a) $20.0 million of surplus Idaho energy efficiency
rider funds, and (b) $7.6 million of customer revenue sharing under a regulatory
settlement stipulation. In addition, on June 1, 2014, there was an increase in
base net power supply costs that shifted $99.3 million in power supply expenses
from recovery via the PCA mechanism to recovery via base rates. See further
discussion of the change in base net power supply costs below.
June 1, 2013 $ 140.4 The 2013 PCA rate increase was net of $7.2 million of customer revenue sharing
under regulatory settlement stipulations.
On November 1, 2013, Idaho Power filed an application with the IPUC requesting an increase of approximately $106 million in the
normalized or "base level" net power supply expense on a total-system basis to be used to update base rates and in the determination
of the PCA rate that would become effective June 1, 2014. Idaho Power's request was intended to remove the Idaho-jurisdictional
portion of those expenses (approximately $99 million) from collection via the Idaho PCA mechanism and instead collect that portion
through base rates. On March 21, 2014, the IPUC issued an order approving Idaho Power's application, with the change in collection
methodology effective June 1, 2014.
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.9
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 Oregon-jurisdictional 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 2014 and 2013 are summarized in the table that follows:
Year and
Mechanism APCU or PCAM Adjustment
2014 PCAM Idaho Power estimates that actual net power supply costs were within the deadband, which would result in
no deferral.
2014 APCU A rate increase of $0.4 million annually took effect June 1, 2014.
2013 PCAM Actual net power supply costs were within the deadband, resulting in no deferral.
2013 APCU A rate increase of $2.9 million annually took effect June 1, 2013.
Idaho Regulatory Matters
Idaho Base Rate Changes: Effective January 1, 2012, Idaho Power implemented new Idaho base rates resulting from IPUC approval
of a settlement stipulation that provided for a 7.86 percent authorized overall rate of return on an Idaho-jurisdiction rate base of
approximately $2.36 billion. The settlement stipulation resulted in a 4.07 percent, or $34.0 million, overall increase in Idaho Power's
annual Idaho-jurisdiction base rate revenues. Idaho base rates were subsequently adjusted again in 2012, in connection with Idaho
Power's completion of the Langley Gulch power plant. 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. Neither the settlement stipulation nor the IPUC orders adjusting base rates specified an authorized rate of return on equity
or imposed a moratorium on Idaho Power filing a general rate case at a future date.
As noted above in this Note 3, the IPUC also issued a March 2014 order approving Idaho Power's request for an increase in the
normalized or "base level" net power supply expense to be used to update base rates and in the determination of the Idaho PCA rate
that would become effective June 1, 2014.
December 2011 Idaho Settlement Stipulation: On December 27, 2011, the IPUC issued an order, separate from the general rate case
proceeding, approving a settlement stipulation that provided as follows:
•If Idaho Power's actual Idaho-jurisdiction return on year-end equity (Idaho ROE) for 2012, 2013, or 2014 is less than 9.5
percent, then Idaho Power may amortize up to a total of $45 million of additional ADITC to help achieve a minimum 9.5
percent Idaho ROE in the applicable year.
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.10
•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 mechanism adjustment.
•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.
As Idaho Power's Idaho ROE exceeded 10.5 percent for 2013 and 2014, Idaho Power did not amortize additional ADITC for those
years, but instead shared a portion of its Idaho-jurisdiction earnings with Idaho customers. The amounts Idaho Power recorded in
2013 and 2014 for sharing with customers under the December 2011 Idaho regulatory settlement stipulation were as follows (in
millions):
Year
Recorded as Refunds
to Customers
Recorded as a Pre-tax
Charge to Pension Expense
2014 $8.0 $16.7
2013 $7.6 $16.5
October 2014 Idaho Settlement Stipulation: In October 2014, the IPUC issued an order approving an extension, with modifications,
of the terms of the December 2011 Idaho settlement stipulation for the period from 2015 through 2019, or until the terms are
otherwise modified or terminated by order of the IPUC or the full $45 million of additional ADITC contemplated by the settlement
stipulation has been amortized. The provisions of the new settlement stipulation are as follows:
•If Idaho Power's annual Idaho ROE in any year is less than 9.5 percent, then Idaho Power may amortize up to $25 million of
additional ADITC to help achieve a 9.5 percent Idaho ROE for that year, and may amortize up to a total of $45 million of
additional ADITC over the 2015 through 2019 period.
•If Idaho Power's annual Idaho ROE in any year exceeds 10.0 percent, the amount of earnings exceeding a 10.0 percent Idaho
ROE and up to and including a 10.5 percent Idaho ROE will be allocated 75 percent to Idaho Power's Idaho customers as a
rate reduction to be effective at the time of the subsequent year's power cost adjustment and 25 percent to Idaho Power.
•If Idaho Power's annual Idaho ROE in any year exceeds 10.5 percent, the amount of earnings exceeding a 10.5 percent Idaho
ROE will be allocated 50 percent to Idaho Power's Idaho customers as a rate reduction to be effective at the time of the
subsequent year's power cost adjustment, 25 percent to Idaho Power's Idaho customers in the form of a reduction to the
pension regulatory asset balancing account (to reduce the amount to be collected in the future from Idaho customers), and 25
percent to Idaho Power.
•If the full $45 million of additional ADITC contemplated by the settlement stipulation has been amortized the sharing
provisions would terminate.
•In the event the IPUC approves a change to Idaho Power's Idaho-jurisdictional allowed return on equity as part of a general
rate case proceeding seeking a rate change effective prior to January 1, 2020, the Idaho ROE thresholds (9.5 percent, 10.0
percent, and 10.5 percent) will be adjusted prospectively.
Neither the settlement stipulation nor the associated IPUC order impose a moratorium on Idaho Power filing a general rate case or
other form of rate proceeding during the term of the settlement stipulation.
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.11
Fixed Cost Adjustment: The Idaho jurisdiction fixed cost adjustment (FCA) mechanism is designed to remove Idaho Power’s
financial 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 mechanism is adjusted each year to
collect, or refund, the difference between the allowed fixed-cost recovery amount and the actual (weather-normalized) fixed costs
recovered by Idaho Power during the year. The amount of the FCA recovery is capped at no more than 3 percent of base revenue,
with any excess deferred for collection in a subsequent year. The following table summarizes FCA amounts approved for collection
in the prior two FCA years:
FCA Year Period Rates in Effect
Annual Amount
(in millions)
2013 June 1, 2014-May 31, 2015 $14.9
2012 June 1, 2013-May 31, 2014 $8.9
On July 1, 2014, the IPUC opened a docket to allow Idaho Power, the IPUC Staff, and other interested parties to further evaluate the
IPUC Staff's concerns regarding the application of the FCA mechanism. Concerns cited by interested parties included the application
of weather-normalization, the customer count methodology, the rate adjustment cap, cross-subsidization issues, and whether the FCA
mechanism is in fact effectively removing Idaho Power's disincentive to aggressively pursue energy efficiency programs.
Proceedings in the FCA mechanism docket, which remains open, could result in significant changes to the FCA mechanism.
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 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. The December 2011 IPUC general rate case settlement order described above 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. As of December 31, 2014, the Idaho energy efficiency rider balance was a regulatory
asset of $0.8 million.
On June 12, 2013, the IPUC issued an order authorizing Idaho Power to recover custom efficiency program incentive payments,
including the then-current regulatory asset balance of approximately $14 million, as well as subsequent custom efficiency program
incentive payments, through the Idaho energy efficiency rider mechanism. As a result of the order, Idaho Power recognized the
balance as other revenue and energy efficiency program expenses in 2013.
Oregon Regulatory Matters
Oregon Base Rate Changes: On February 23, 2012, the OPUC issued an order approving a settlement stipulation that 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. Subsequently, 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, for inclusion of the Langley Gulch power plant in Idaho Power's Oregon rate base.
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 OATT, which allows
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.12
transmission rates to be updated annually based primarily on financial and operational data Idaho Power files with the FERC. Idaho
Power's OATT rates submitted to the FERC in Idaho Power's three most recent annual OATT Final Informational Filings were as
follows:
Applicable Period
OATT Rate
(per kW-year)
October 1, 2014 to September 30, 2015 $ 22.71
October 1, 2013 to September 30, 2014 $ 22.80
October 1, 2012 to September 30, 2013 $21.32
Idaho Power's current OATT rate is based on a net annual transmission revenue requirement of $120.8 million, which represents the
OATT formulaic determination of Idaho Power's net cost of providing OATT-based transmission service.
4. LONG-TERM DEBT
The following table summarizes Idaho Power's long-term debt at December 31 (in thousands of dollars):
2014 2013
First mortgage bonds:
6.025% Series due 2018 $ 120,000 $ 120,000
6.15% Series due 2019 100,000 100,000
4.50% Series due 2020 130,000 130,000
3.40% Series due 2020 100,000 100,000
2.95% Series due 2022 75,000 75,000
2.50% Series due 2023 75,000 75,000
6% Series due 2032 100,000 100,000
5.50% Series due 2033 70,000 70,000
5.50% Series due 2034 50,000 50,000
5.875% Series due 2034 55,000 55,000
5.30% Series due 2035 60,000 60,000
6.30% Series due 2037 140,000 140,000
6.25% Series due 2037 100,000 100,000
4.85% Series due 2040 100,000 100,000
4.30% Series due 2042 75,000 75,000
4.00% Series due 2043 75,000 75,000
Total first mortgage bonds 1,425,000 1,425,000
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 3,191 4,255
Unamortized premium/discount - net (3,034) (3,278)
Total Idaho Power outstanding debt(2) 1,615,502 1,616,322
Current maturities of long-term debt (1,064) (1,064)
Total long-term debt $ 1,614,438 $ 1,615,258
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.13
(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, 2014 to $1.591 billion.
(2) At December 31, 2014 and 2013, the overall effective cost of Idaho Power's outstanding debt was 5.19 percent.
At December 31, 2014, the maturities for the aggregate amount of Idaho Power long-term debt outstanding were as follows (in
thousands of dollars):
2015 2016 2017 2018 2019 Thereafter
$1,064 $1,064 $1,064 $120,000 $100,000 $1,395,344
Long-Term Debt Issuances, Maturities, and Availability
On April 8, 2013, Idaho Power issued $75 million in principal amount of 2.50% first mortgage bonds, Series I, maturing on April 1,
2023, and $75 million in principal amount of 4.00% first mortgage bonds, Series I, maturing on April 1, 2043. On October 1, 2013,
Idaho Power used a portion of the net proceeds of the April 2013 sale of first mortgage bonds to satisfy its obligations upon maturity
of $70 million in principal amount of 4.25% first mortgage bonds.
In February 2013, Idaho Power filed applications with the IPUC, OPUC, and Wyoming Public Service Commission (WPSC) seeking
authorization to issue and sell from time to time up to $500 million in aggregate principal amount of debt securities and first mortgage
bonds. In April 2013, Idaho Power received orders from the IPUC, OPUC, and WPSC authorizing such issuance and sales, subject to
conditions specified in the orders. The order from the IPUC approved the issuance of the securities through April 9, 2015, subject to
extension upon request to the IPUC. The OPUC’s and WPSC’s orders do not impose a time limitation for issuances, but the OPUC
order does impose a number of other conditions, including a maximum interest rate limit of 7 percent.
In anticipation of the expiration of the prior registration statement, on May 22, 2013, IDACORP and Idaho Power filed a joint shelf
registration statement with the SEC, which became effective upon filing, for the offer and sale of, in the case of Idaho Power, an
unspecified principal amount of its first mortgage bonds and debt securities. On July 12, 2013, Idaho Power entered into a Selling
Agency Agreement with eight 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, secured medium term notes, Series J (Series J Notes), under
Idaho Power’s Indenture of Mortgage and Deed of Trust, dated as of October 1, 1937, as amended and supplemented (Indenture).
Also on July 12, 2013, Idaho Power entered into the Forty-seventh Supplemental Indenture, dated as of July 1, 2013, to the Indenture.
The Forty-seventh Supplemental Indenture provides for, among other items, the issuance of up to $500 million in aggregate principal
amount of Series J Notes pursuant to the Indenture. As of December 31, 2014, Idaho Power had not sold any first mortgage bonds,
including Series J Notes, or debt securities under the Selling Agency Agreement.
Mortgage: As of December 31, 2014, Idaho Power could issue under its Indenture approximately $1.6 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 Indenture.
The mortgage of the Indenture 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 of the Indenture. The lien 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
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.14
common to properties. The mortgage of the Indenture 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 of the Indenture 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 Indenture 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
Indenture 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 Indenture and supplemental
indentures to the Indenture. Idaho Power may amend the Indenture and increase this amount without consent of the holders of the
first mortgage bonds. The Indenture 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 in place a credit facility that 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, in each case, an applicable margin.
The margin is based on Idaho Power's senior unsecured long-term indebtedness credit rating by Moody's Investors Service, Inc.,
Standard and Poor's Ratings Services, and Fitch Rating Services, Inc., as set forth on a schedule to the credit agreements. Under the
credit facility, the company pays a facility fee on the commitment based on the company's credit rating for senior unsecured long-term
debt securities. While the credit facility provided for an original termination date of October 26, 2016, the credit agreement granted
Idaho Power the right to request up to two one-year extensions, in each case subject to certain conditions. In October 2012 and
October 2013, Idaho Power executed agreements with the lenders, extending the maturity date under the credit agreement to October
26, 2018. No other terms of the credit facility, including the amount of permitted borrowings, were affected by the extensions.
At December 31, 2014, no loans were outstanding under Idaho Power's facility. At December 31, 2014, Idaho Power had regulatory
authority to incur up to $450 million in 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, 2014 and
December 31, 2013:
2014 2013
Commercial paper balances:
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.15
At the end of year $ — $ —
Average during the year $ — $ 2,209
Weighted-average interest rate
At the end of the year —%—%
6. COMMON STOCK
Idaho Power Common Stock
No contributions were made to Idaho Power in 2014 or 2013, and no additional shares of Idaho Power common stock were issued.
Restrictions on Dividends
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. 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. At December 31, 2014, the leverage ratio for Idaho Power was
47 percent. Based on these restrictions, Idaho Power’s dividends were limited to $944 million at December 31, 2014. There are
additional facility covenants, subject to exceptions, that prohibit or restrict the sale or disposition of property without consent and any
agreements restricting dividend payments to the company from any material subsidiary. At December 31, 2014, Idaho Power was in
compliance with those covenants.
Idaho Power’s Revised Policy and Code of Conduct relating to transactions between and among Idaho Power, IDACORP, and other
affiliates, which was approved by the IPUC in April 2008, provides 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, 2014, Idaho Power's common equity capital was 53 percent of its total adjusted capital. Further, Idaho Power must
obtain approval from the OPUC before it can directly or indirectly loan funds or issue notes or give credit on its books to IDACORP.
Idaho Power’s articles of incorporation contain restrictions on the payment of dividends on its common stock if preferred stock
dividends are in arrears. As of the date of this report, Idaho Power has no preferred stock outstanding.
In addition to contractual restrictions on the amount and payment of dividends, the Federal Power Act prohibits the payment of
dividends from "capital accounts." The term "capital account" is undefined in the Federal Power Act or its regulations, but Idaho
Power does not believe the restriction would limit Idaho Power's ability to pay dividends out of current year earnings or retained
earnings.
In accordance with Section 10(d) of the Federal Power Act, Idaho Power has $13.3 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.
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.16
The LTICP (for officers, key employees, and directors) permits the grant of stock options, restricted stock, performance shares, and
several other types of stock-based awards. The RSP (for officers and key employees) permits only the grant of restricted stock or
performance-based restricted stock. At December 31, 2014, the maximum number of shares available under the LTICP and RSP were
1,166,210 and 15,796, respectively, excluding (i) issued but unvested performance-based restricted shares and (ii) issued but unvested
time-based restricted shares.
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. The performance conditions are two equally-weighted metrics, cumulative earnings per
share (CEPS) and total shareholder return (TSR) relative to a peer group. Depending 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 grant-date 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 this portion of the awards is charged to compensation
expense over the requisite service period, based on the number of shares expected to vest. The grant-date 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 this portion of the 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. Share amounts represent the shares of IDACORP
common stock:
Number of
Shares
Weighted-Average
Grant Date
Fair Value
Nonvested shares at January 1, 2014 305,984 $ 36.85
Shares granted 105,367 48.74
Shares forfeited (35,298) 46.34
Shares vested (125,657) 30.09
Nonvested shares at December 31, 2014 250,396 $ 43.91
The total fair value of shares vested during the years ended December 31, 2014 and 2013 was $6.6 million and $5.0 million,
respectively. At December 31, 2014, Idaho Power had $4.6 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
1.69 years. IDACORP uses original issue and/or treasury shares for these awards.
In 2014, a total of 14,599 of IDACORP common stock shares were awarded to directors of IDACORP and Idaho Power at a grant
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.17
date fair value of $56.05 per share. Directors elected to defer receipt of 8,004 of these shares, which are being held as deferred stock
units with dividend equivalents reinvested in additional stock units.
Stock Options: IDACORP has not granted any stock option awards since 2006 and has no plans to do so in the future. At December
31, 2014, there were no outstanding options.
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):
2014 2013
Compensation cost $ 5,458 $ 4,783
Income tax benefit 2,134 1,870
No equity compensation costs have been capitalized.
8. COMMITMENTS
Purchase Obligations
At December 31, 2014, Idaho Power had the following long-term commitments relating to purchases of energy, capacity, transmission
rights, and fuel (in thousands of dollars):
2015 2016 2017 2018 2019 Thereafter
Cogeneration and power production $ 181,468 $ 189,493 $ 229,255 $ 240,280 $ 238,501 $ 4,064,213
Power and transmission rights 6,370 5,416 3,337 1,199 1,105 4,487
Fuel 64,415 42,124 41,744 9,352 9,169 68,359
As of December 31, 2014, Idaho Power had 781 MW nameplate capacity of PURPA-related projects on-line, with an additional 521
MW nameplate capacity of projects projected to be on-line by June 1, 2017. The power purchase contracts for these projects have
original contract terms ranging from one to 35 years. Idaho Power's expenses associated with PURPA-related projects were
approximately $145 million in 2014 and $131 million in 2013.
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):
2015 2016 2017 2018 2019 Thereafter
Operating leases $ 162 $ 1,039 $ 1,065 $ 1,088 $ 1,167 $ 14,136
Equipment, maintenance, and service agreements 61,492 19,610 8,279 7,794 7,978 31,489
FERC and other industry-related fees 12,954 6,813 6,813 6,813 6,813 34,063
Idaho Power’s expense for operating leases was approximately $5.8 million in 2014 and $5.2 million in 2013.
Guarantees
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.18
Through a self-bonding mechanism, Idaho Power guarantees its portion of reclamation activities and obligations at BCC, of which
IERCo owns a one-third interest. This guarantee, which is renewed annually with the Wyoming Department of Environmental
Quality, was $70 million at December 31, 2014, representing IERCo's one-third share of BCC's total reclamation obligation. BCC
has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs. At December 31, 2014, the value
of the reclamation trust fund was $67 million. During 2014 the reclamation trust fund distributed approximately $13 million for
reclamation activity costs associated with the BCC surface mine. BCC periodically assesses the adequacy of the reclamation trust
fund and its estimate of future reclamation costs. To ensure that the reclamation trust fund maintains adequate reserves, BCC has the
ability to add a per-ton surcharge to coal sales, 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
fund and the ability to apply a per-ton surcharge, the estimated fair value of this guarantee is minimal.
Idaho Power enters into financial agreements and power purchase and sale agreements that include indemnification provisions
relating to various forms of claims or liabilities that may arise from the transactions contemplated by these agreements. Generally, a
maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the
obligation under such indemnification provisions cannot be reasonably estimated. Idaho Power periodically evaluates the likelihood
of incurring costs under such indemnities based on historical experience and the evaluation of the specific indemnities. As of
December 31, 2014, 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 within 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, and adjust the amount as
appropriate. If the loss contingency at issue is not both probable and reasonably estimable Idaho Power does not establish an accrual
and the matter will continue to be monitored for any developments that would make the loss contingency both probable and
reasonably estimable. As of the date of this report, Idaho Power's accruals for loss contingencies are 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. 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.
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
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.19
States Court of Appeals for the Ninth Circuit. Idaho Power and IESCo (as successor to IDACORP Energy L.P.) believe that
settlement releases they have obtained will restrict potential claims that might result from the disposition of pending proceedings 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 in the Pacific Northwest markets 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 has characterized these ripple
claims as "speculative." However, the FERC has refused to dismiss Idaho Power and IESCo from the proceedings in the Pacific
Northwest and refused to approve portions of two settlements that provided for waivers of claims in those proceedings, despite only
limited objections from two market participants to one of the two settlements and no objections to the other settlement. Idaho Power
and IESCo have petitions for review of the FERC's decisions refusing to approve the waiver provision of the settlements, on the basis
that the FERC failed to apply its established precedents and rules. The petitions for review are pending in the Ninth Circuit Court of
Appeals.
Based on its evaluation of the merits of ripple claims and the inability to estimate the potential exposure should the claims ultimately
have any merit, particularly in light of Idaho Power and IESCo being both purchasers and sellers in the energy market during the
relevant period, Idaho Power and IESCo have no amount accrued relating to the 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.
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 the company 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 pending environmental
regulations, including the EPA's proposed rule under Section 111(d) of the Clean Air Act, 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 estimate 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. Idaho Power
also sponsors a defined contribution 401(k) employee savings plan and provides certain post-employment benefits.
Pension Plans
Idaho Power has two pension plans – a noncontributory defined benefit pension plan (pension plan) and a nonqualified defined
benefit pension plan for certain senior management employees called the Security Plan for Senior Management Employees (SMSP).
Idaho Power also has a nonqualified defined benefit pension plan for directors that was frozen in 2002. Remaining vested benefits
from that plan are included with the SMSP in the disclosures below. The benefits under these plans are based on years of service and
the employee's final average earnings.
Idaho Power’s funding policy for the 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 2014 and
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.20
2013 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.
The following table summarizes the changes in benefit obligations and plan assets of these plans (in thousands of dollars):
Pension Plan Pension Plan SMSP SMSP
2014 2013 2014 2013
Change in benefit obligation:
Benefit obligation at January 1 $ 695,093 $ 767,692 $ 77,773 $ 80,515
Service cost 25,292 31,357 1,645 2,178
Interest cost 35,415 31,830 3,856 3,258
Actuarial loss (gain) 114,496 (112,215) 15,324 (4,663)
Benefits paid (25,484) (23,571) (4,188) (3,515)
Projected benefit obligation at December 31 844,812 695,093 94,410 77,773
Change in plan assets:
Fair value at January 1 545,092 460,862 — —
Actual return on plan assets 10,111 77,801 — —
Employer contributions 30,000 30,000 — —
Benefits paid (25,484) (23,571) — —
Fair value at December 31 559,719 545,092 — —
Funded status at end of year $ (285,093) $ (150,001) $ (94,410) $ (77,773)
Amounts recognized in the statement of financial
position consist of:
Other current liabilities $ — $ — $ (4,193) $ (3,905)
Noncurrent liabilities (285,093) (150,001) (90,217) (73,868)
Net amount recognized $ (285,093) $ (150,001) $ (94,410) $ (77,773)
Amounts recognized in accumulated other
comprehensive income consist of:
Net loss $ 263,350 $ 120,587 $ 38,808 $ 26,102
Prior service cost 295 642 857 1,077
Subtotal 263,645 121,229 39,665 27,179
Less amount recorded as regulatory asset (263,645) (121,229) — —
Net amount recognized in accumulated other
comprehensive income $ — $ — $ 39,665 $ 27,179
Accumulated benefit obligation $ 719,617 $ 591,649 $ 84,684 $ 70,530
The actuarial loss affecting the change in projected benefit obligations from December 31, 2013 to December 31, 2014 is due to the
reduction in the discount rates, as identified in the plan assumptions table included later in this footnote.
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. The fair value of
these investments was approximately $65.0 million and $59.2 million at December 31, 2014 and 2013, respectively, and is reflected
in Investments and in Company-owned life insurance on the consolidated balance sheets.
The following table 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 Pension Plan SMSP SMSP
2014 2013 2014 2013
Service cost $ 25,292 $ 31,357 $ 1,645 $ 2,178
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.21
Interest cost 35,415 31,830 3,856 3,258
Expected return on plan assets (42,289) (35,755) — —
Amortization of net loss 3,911 17,118 2,618 2,840
Amortization of prior service cost 347 347 220 212
Net periodic pension cost 22,676 44,897 8,339 8,488
Adjustments due to the effects of regulation(1) 12,124 (9,013) — —
Net periodic benefit cost recognized for financial reporting $ 34,800 $ 35,884 $ 8,339 $ 8,488
(1) 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.
The following table shows the components of other comprehensive income for the plans (in thousands of dollars):

Pension
Plan
Pension
Plan SMSP SMSP
2014 2013 2014 2013
Actuarial (loss) gain during the year
$ (146,674) $ 154,261

$ (15,324) $ 4,664

Reclassification adjustments for:
Amortization of net loss 3,911 17,118 2,618 2,840
Amortization of prior service cost 347 347 220 212
Adjustment for deferred tax effects 55,678 (67,136) 4,881 (3,017)
Adjustment due to the effects of regulation 86,738 (104,590) — —
Other comprehensive income recognized related to pension
benefit plans
$ — $ — $ (7,605) $ 4,699

In 2015, Idaho Power expects to recognize as components of net periodic benefit cost $18.8 million from amortizing amounts
recorded in accumulated other comprehensive income (or as a regulatory asset for the pension plan) as of December 31, 2014, relating
to the pension plan and SMSP. This amount consists of $14.2 million of amortization of net loss and $0.2 million of amortization of
prior service cost for the pension plan, and $4.2 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):
2015 2016 2017 2018 2019 2020-2024
Pension Plan $ 27,634 $ 29,938 $ 32,428 $ 35,036 $ 37,644 $ 226,411
SMSP 4,274 4,198 4,262 4,134 4,291 23,868
As of December 31, 2014, Idaho Power's minimum required contribution to the pension plan is estimated to be zero in 2015, though
Idaho Power plans to contribute at least $20 million to the pension plan during 2015.
Postretirement Benefits
Idaho Power maintains a defined benefit postretirement benefit plan (consisting of health care and death benefits) that covers all
employees who were enrolled in the active-employee 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
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.22
of Idaho Power’s future obligations under this plan.
The following table summarizes the changes in benefit obligation and plan assets (in thousands of dollars):
2014 2013
Change in accumulated benefit obligation:
Benefit obligation at January 1 $ 57,341 $ 72,547
Service cost 1,011 1,315
Interest cost 2,841 2,633
Actuarial loss (gain) 7,026 (16,788)
Benefits paid(1) (2,220) (2,366)
Benefit obligation at December 31 65,999 57,341
Change in plan assets:
Fair value of plan assets at January 1 37,111 33,387
Actual return on plan assets 3,888 6,212
Employer contributions(1) (404) (122)
Benefits paid(1) (2,220) (2,366)
Fair value of plan assets at December 31 38,375 37,111
Funded status at end of year (included in noncurrent liabilities) $ (27,624) $ (20,230)
(1) Contributions and benefits paid are each net of $3,379 thousand and $3,272 thousand of plan participant contributions, and $344 thousand and $372 thousand of
Medicare Part D subsidy receipts for 2014 and 2013, respectively.
Amounts recognized in accumulated other comprehensive income consist of the following (in thousands of dollars):
2014 2013
Net loss $ 759 $ (4,974)
Prior service cost 145 328
Subtotal 904 (4,646)
Less amount recognized in regulatory assets (904) 4,646
Net amount recognized in accumulated other comprehensive income $ — $ —
The net periodic postretirement benefit cost was as follows (in thousands of dollars):
2014 2013
Service cost $ 1,011 $ 1,315
Interest cost 2,841 2,633
Expected return on plan assets (2,595) (2,328)
Amortization of net loss — 98
Amortization of prior service cost 183 (229)
Amortization of unrecognzied transition obligation — —
Net periodic postretirement benefit cost $ 1,440 $ 1,489
The following table shows the components of other comprehensive income for the plan (in thousands of dollars):
2014 2013
Actuarial (loss) gain during the year $ (5,733) $ 20,673
Reclassification adjustments for:
Amortization of net loss — 98
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.23
Amortization of prior service cost 183 (229)
Adjustment for deferred tax effects 2,170 (8,031)
Adjustment due to the effects of regulation 3,380 (12,511)
Other comprehensive income related to postretirement benefit plans $ — $ —
In 2015, Idaho Power expects to recognize as a component of net periodic benefit cost $15 thousand from amortizing amounts
recorded in accumulated other comprehensive income as of December 31, 2014, relating to the postretirement benefit plan. The entire
amount represents $15 thousand 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):
2015 2016 2017 2018 2019 2020-2024
Expected benefit payments $ 3,970 $ 4,040 $ 4,090 $ 4,160 $ 4,210 $ 21,310
Expected Medicare Part D subsidy receipts 390 430 470 520 560 3,560
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:
Pension Plan Pension Plan SMSP SMSP
Postretirement
Benefits
Postretirement
Benefits
2014 2013 2014 2013 2014 2013
Discount rate 4.25 % 5.20 % 4.20 % 5.10 % 4.20 % 5.15 %
Rate of compensation
increase(1)4.30 % 4.38 % 4.50 % 4.50 % — —
Medical trend rate — — — — 6.4 % 6.8 %
Dental trend rate — — — — 5.0 % 5.0 %
Measurement date 12/31/2014 12/31/2013 12/31/2014 12/31/2013 12/31/2014 12/31/2013
(1) The 2014 rate of compensation increase assumption for the pension plan includes an inflation component of 2.75% plus a 1.55% 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.
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:

Pension
Plan
Pension
Plan SMSP SMSP
Postretiremen
t Benefits
Postretiremen
t Benefits
2014 2013 2014 2013 2014 2013
Discount rate 5.20 % 4.20 % 5.10 % 4.15 % 5.15 % 4.20 %
Expected long-term rate of return
on assets 7.75 % 7.75 % — — 7.25 % 7.25 %
Rate of compensation increase 4.30 % 4.38 % 4.50 % 4.50 % — —
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.24
Medical trend rate — — — — 6.4 % 6.8 %
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
6.4 percent in 2014 and is assumed to decrease gradually to 5.1 percent by 2093. The assumed dental cost trend rate used to measure
the expected cost of dental benefits covered by the plan was 5.0 percent for all years. A one percentage point change in the assumed
health care cost trend rate would have the following effects at December 31, 2014 (in thousands of dollars):

One-Percentage-Point
Increase
One-Percentage-Point
Decrease
Effect on total of cost components $ 325 $ (241)
Effect on accumulated postretirement benefit obligation 3,426 (2,657)
Plan Assets
Pension Asset Allocation Policy: The target allocation and actual allocations at December 31, 2014 for the pension asset portfolio by
asset class is set forth below:
Asset Class Target
Allocation
Actual
Allocation
December 31,
2014
Debt securities 24 % 24 %
Equity securities 54 % 55 %
Real estate 6 % 6 %
Other plan assets 16 % 15 %
Total 100 %100 %
Assets are rebalanced as necessary to keep the portfolio close to target allocations.
The plan’s principal investment objective is to maximize total return (defined as the sum of realized interest and dividend income and
realized and unrealized gain or loss in market price) consistent with prudent parameters of risk and the liability profile of the
portfolio. Emphasis is placed on preservation and growth of capital along with adequacy of cash flow sufficient to fund current and
future payments to pensioners.
The three major goals in Idaho Power’s asset allocation process are to:
•determine if the investments have the potential to earn the rate of return assumed in the actuarial liability calculations;
•match the cash flow needs of the plan. Idaho Power sets bond allocations sufficient to cover at least five years of benefit
payments and cash allocations sufficient to cover the current year benefit payments. Idaho Power then utilizes growth
instruments (equities, real estate, venture capital) to fund the longer-term liabilities of the plan; and
•maintain a prudent risk profile consistent with ERISA fiduciary standards.
Allowable plan investments include stocks and stock funds, investment-grade bonds and bond funds, core real estate funds, private
equity funds, and cash and cash equivalents. With the exception of real estate holdings and private equity, investments must be
readily marketable so that an entire holding can be disposed of quickly with only a minor effect upon market price.
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.25
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 yield on the Moody's AA Corporate Bond Index. This historical
risk premium is then added to the current yield on the Moody's AA Corporate Bond Index. 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, 2014
Pension plan assets:
Cash and cash equivalents $ 19,190 $ — $ — $ 19,190
Short-term bonds — 10,991 — 10,991
Intermediate bonds — 101,867 — 101,867
Long-term bonds — 21,615 — 21,615
Equity Securities: Large-Cap 66,151 — — 66,151
Equity Securities: Mid-Cap 68,974 — — 68,974
Equity Securities: Small-Cap 50,972 — — 50,972
Equity Securities: Micro-Cap 22,962 — — 22,962
Equity Securities: International 6,555 57,705 — 64,260
Equity Securities: Emerging
Markets 8,629 22,915 — 31,544
Real estate — — 33,996 33,996
Private market investments — — 37,118 37,118
Commodities funds — 30,079 — 30,079
Total pension assets $ 243,433 $ 245,172 $ 71,114 $ 559,719
Postretirement plan assets(1) $ 11 $ 38,364 $ — $ 38,375
Assets at December 31, 2013
Pension plan assets:
Cash and cash equivalents $ 33,030 $ — $ — $ 33,030
Short-term bonds — 11,068 — 11,068
Intermediate bonds — 76,312 — 76,312
Long-term bonds — 19,024 — 19,024
Equity Securities: Large-Cap 71,042 — — 71,042
Equity Securities: Mid-Cap 23,346 23,112 — 46,458
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.26
Equity Securities: Small-Cap 48,998 — — 48,998
Equity Securities: Micro-Cap 24,687 — — 24,687
Equity Securities: International 19,128 74,908 — 94,036
Equity Securities: Emerging
Markets 3,523 22,107 — 25,630
Equity Securities: Market Neutral 3,870 — — 3,870
Real estate — — 28,019 28,019
Private market investments — — 33,709 33,709
Commodities funds — 29,209 — 29,209
Total pension assets $ 227,624 $ 255,740 $ 61,728 $ 545,092
Postretirement plan assets(1) $ 75 $ 37,036 $ — $ 37,111
(1) The postretirement benefits assets are primarily life insurance contracts.
For the year ended December 31, 2014, the only significant transfer in and out of Levels 1, 2, or 3 was $23.1 million of mid-cap
equity security investments that were transferred from Level 2 to Level 1. For the year ended December 31, 2013, there were no
significant transfers into or out of Levels 1, 2, or 3.
The following table presents a reconciliation of the beginning and ending balances of the fair value measurements using significant
unobservable inputs (Level 3) (in thousands of dollars):

Private
Equity
Real
Estate Total
Beginning balance - January 1, 2013 $ 30,507 $ 27,874 $ 58,381
Realized gains — 739 739
Unrealized gains 2,941 1,579 4,520
Purchases 89 4,726 4,815
Sales — (6,899) (6,899)
Settlements 172 — 172
Ending balance - December 31, 2013 33,709 28,019 61,728
Realized gains 1,430 866 2,296
Unrealized (losses) gains (545) 1,305 760
Purchases 2,434 3,806 6,240
Settlements 90 — 90
Ending balance - December 31, 2014 $ 37,118 $ 33,996 $ 71,114
Fair Value Measurement of Level 2 and Level 3 Plan Asset Inputs:
Level 2 Bonds, Equity Securities, and Level 2 Commodities: These investments represent U.S. government and agency bonds,
corporate bonds, and commingled funds consisting of publicly traded equity securities or exchange-traded commodity contracts and
other contractual claims to commodity holdings. The U.S. government and agency bonds, as well as the corporate bonds, are not
traded on an exchange and are valued utilizing quoted prices for similar assets or liabilities in active markets. The commingled funds
themselves are not publicly traded, and therefore no publicly quoted market price is readily available. The value of these investments
is calculated by the custodian for the fund company on a monthly basis, and is based on market prices of the assets held by the
commingled fund divided by the number of fund shares outstanding.
Level 2 Postretirement Assets: These assets represent an investment in a life insurance contract and are recorded at fair value, which
is the cash surrender value, less any unpaid expenses. The cash surrender value of this insurance contract is contractually equal to the
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.27
insurance contract's proportionate share of the market value of an associated investment account held by the insurer. The investments
held by the insurer's investment account are all instruments traded on exchanges with readily determinable market prices.
Level 3 Real Estate: Real estate holdings represent investments in open-ended commingled real estate funds. As the property
interests held in these real estate funds are not frequently traded, establishing the market value of the property interests held by the
fund, and the resulting unit value of fund shareholders, is based on unobservable inputs including property appraisals by the fund
company, property appraisals by independent appraisal firms, analysis of the replacement cost of the property, discounted cash flows
generated by property rents and changes in property values, and comparisons with sale prices of similar properties in similar markets.
These open-ended real estate funds also furnish annual audited financial statements that are also used to further validate the
information provided.
Level 3 Private Market Investments: Private market investments represent two categories: fund of hedge funds and venture capital
funds. These funds are valued by the fund company based on the estimated fair value of the underlying fund holdings divided by the
fund shares outstanding. Some hedge fund strategies utilize securities with readily available market prices, while others utilize less
liquid investment vehicles that are valued based on unobservable inputs including cost, operating results, recent funding activity, or
comparisons with similar investment vehicles. Venture capital fund investments are valued by the fund company based on estimated
fair value of the underlying fund holdings divided by the fund shares outstanding. Some venture capital investments have progressed
to the point that they have readily available exchange-based market valuations. Early stage venture investments are valued based on
unobservable inputs including cost, operating results, discounted cash flows, the price of recent funding events, or pending offers
from other viable entities. These private market investments furnish annual audited financial statements that are also used to further
validate the information provided.
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.
Employee Savings Plan
Idaho Power has a defined contribution plan designed to comply with Section 401(k) of the Internal Revenue Code and that covers
substantially all employees. Idaho Power matches specified percentages of employee contributions to the plan. Matching annual
contributions were approximately $7 million each year for 2013 and 2014.
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,
2014 and 2013 is $2.0 million and $1.9 million, respectively.
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.28
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 2014 and 2013 (in thousands of
dollars):
2014 2014 2013 2013
Balance Avg Rate Balance Avg Rate
Production $ 2,316,941 2.48 % $ 2,272,381 2.47 %
Transmission 1,016,207 2.03 % 974,697 2.01 %
Distribution 1,516,933 2.72 % 1,459,666 2.72 %
General and Other 398,131 5.49 % 373,658 5.91 %
Total in service 5,248,212 2.68 % 5,080,402 2.69 %
Accumulated provision for depreciation (2,021,074) (1,940,654)
In service - net $ 3,227,138 $ 3,139,748
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 for each facility is included in the Consolidated Statements of Income.
These jointly-owned facilities, including balance sheet amounts and the extent of Idaho Power’s participation, were as follows at
December 31, 2014 (in thousands of dollars):
Name of Plant Location
Utility
Plant in
Service
Construction
Work in
Progress
Accumulated
Provision for
Depreciation Ownership %MW(1)
Jim Bridger Units 1-4 Rock Springs, WY $ 569,220 $ 59,394 $ 293,432 33 771
Boardman Boardman, OR 80,951 125 60,031 10 64
Valmy Units 1 and 2 Winnemucca, NV 372,791 19,023 193,756 50 284
(1) Idaho Power’s share of nameplate capacity.
IERCo, Idaho Power’s wholly-owned subsidiary, is a joint venture in BCC. Idaho Power’s coal purchases from the joint venture
were $79 million in 2014 and 2013.
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 each year for 2013 and 2014.
12. ASSET RETIREMENT OBLIGATIONS (ARO)
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.29
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 estimated settlement 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 biphenyl-contaminated equipment at its distribution facilities
and the reclamation and removal costs at its jointly-owned coal-fired generation facilities. In 2014, changes in estimates at its
distribution facilities and at the coal-fired generation facilities resulted in a net decrease of $4.1 million in the recorded AROs. The
decrease in the AROs in 2014 is primarily due to decreases in estimated future costs related to evaporation ponds at the Valmy
generating facility.
Idaho Power also has additional AROs associated with its transmission system, hydroelectric facilities, natural gas-fired generation
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 following table presents the changes in the carrying amount of AROs (in thousands of dollars):
2014 2013
Balance at beginning of year $ 25,765 $ 22,982
Accretion expense 1,061 1,041
Revisions in estimated cash flows (4,140) 2,722
Liability settled (756) (980)
Balance at end of year $21,930 $25,765
13. INVESTMENTS
The table below summarizes Idaho Power’s investments as of December 31 (in thousands of dollars):
2014 2013
Idaho Power investments:
IERCo $ 83,477 $ 91,385
Available-for-sale equity securities 44,942 41,119
Executive deferred compensation plan investments 141 1,153
Other investments 1 1
Total Idaho Power investments 128,561 133,658
Investments in Equity Securities
Investments in securities classified as available-for-sale securities are reported at fair value. Any unrealized gains or losses on
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.30
available-for-sale securities are included in income, as the fair value option has been elected for these instruments. Unrealized gains
and losses on available-for-sale securities were immaterial at December 31, 2014 and December 31, 2013.
The following table summarizes sales of available-for-sale securities (in thousands of dollars):
2014 2013
Proceeds from sales $ — $ 25,661
Gross realized gains from sales — 11,637
Gross realized losses from sales — —
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, 2014 and December 31, 2013, there were no
indicators of other-than-temporary impairment related to Idaho Power's investments.
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 be influenced by market participants’ nonperformance of their contractual
obligations and commitments, which affects the supply of or demand for the commodity. Idaho Power uses derivative instruments,
such as physical and financial forward contracts, for both electricity and fuel to manage the risks relating to these commodity price
exposures. The primary objectives of Idaho Power’s energy purchase and sale activity are to meet the demand of retail electric
customers, maintain appropriate physical reserves to ensure reliability, and make economic use of temporary surpluses that may
develop.
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. Idaho Power offsets fair value amounts
recognized on its balance sheet and applies collateral related to derivative instruments executed with the same counterparty under the
same master netting agreement. Idaho Power does not offset a counterparty's current derivative contracts with the counterparty's
long-term derivative contracts, although Idaho Power's master netting arrangements would allow current and long-term positions to be
offset in the event of default. Also, in the event of default, Idaho Power's master netting arrangements would allow for the offsetting
of all transactions executed under the master netting arrangement. These types of transactions may include non-derivative
instruments, derivatives qualifying for scope exceptions, receivables and payables arising from settled positions, and other forms of
non-cash collateral (such as letters of credit). These types of transactions are excluded from the offsetting presented in the derivative
fair value and offsetting table below.
The table below presents the gains and losses on derivatives not designated as hedging instruments for the years ended December 31,
2014 and 2013 (in thousands of dollars):
Location of Realized Gain/(Loss) on
Derivatives Recognized in Income
Gain/(Loss on
Derivatives Recognized
in Income(1)
2014
Gain/(Loss on
Derivatives Recognized
in Income(1)
2013
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.31
Financial swaps Off-system sales $ (4,119) $ (2,637)
Financial swaps Purchased power (1,416) 947
Financial swaps Fuel expense 3,862 731
Financial swaps Other operations and maintenance (158) 35
Forward contracts Off-system sales 277 185
Forward contracts Purchased power (279) (196)
Forward contracts Fuel expense 94 217
(1) Excludes unrealized gains or losses on 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 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.
Derivative Instrument Summary
The table below presents the fair values and locations of derivative instruments not designated as hedging instruments recorded on the
balance sheets and reconciles the gross amounts of derivatives recognized as assets and as liabilities to the net amounts presented in
the balance sheets at December 31, 2014 and 2013 (in thousands of dollars):
Asset
Derivatives
Asset
Derivatives
Asset
Derivatives
Balance Sheet Location Gross Fair
Value
Amounts
Offset
Net Assets
December 31, 2014
Current:
Financial swaps Other current assets $ 2,509 $ (2,002)(1) $ 507
Financial swaps Other current liabilities 379 (379) —
Forward contracts Other current assets 64 — 64
Forward contracts Other current liabilities — — —
Long-term:
Forward contracts Other assets 63 — 63
Total $ 3,015 $ (2,381) $ 634
December 31, 2013
Current:
Financial swaps Other current assets $ 1,451 $ (175) $ 1,276
Financial swaps Other current liabilities 373 (373) 0
Forward contracts Other current assets 109 — 109
Forward contracts Other current liabilities — — 0
Long-term:
Financial swaps Other assets 189 (28) 161
Forward contracts Other assets 126 — 126
Total $ 2,248 $ (576) $ 1,672
Liability
Derivatives
Liability
Derivatives
Liability
Derivatives
Balance Sheet Location Gross Fair
Value
Amounts
Offset
Net Assets
December 31, 2014
Current:
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.32
Financial swaps Other current assets $ 756 $ (756) $ —
Financial swaps Other current liabilities 4,335 (379) 3,956
Forward contracts Other current assets — — —
Forward contracts Other current liabilities 5 — 5
Long-term:
Forward contracts Other assets — — —
Total $ 5,096 $ (1,135) $ 3,961
December 31, 2013
Current:
Financial swaps Other current assets $ 175 $ (175) $ —
Financial swaps Other current liabilities 1,975 (1,429)(1) 546
Forward contracts Other current assets — — —
Forward contracts Other current liabilities 26 — 26
Long-term:
Financial swaps Other assets 28 (28) —
Forward contracts Other assets — — —
Total $ 2,204 $ (1,632) $ 572
(1) Current asset and current liability derivative amounts offset include $1.2 million and $1.1 million of collateral payable and receivable for the periods ending
December 31, 2014 and 2013, respectively.
The table below presents the volumes of derivative commodity forward contracts and swaps outstanding at December 31, 2014 and
2013 (in thousands of units):
Commodity Units December 31, 2014 December 31, 2013
Electricity purchases MWh 115 89
Electricity sales MWh 238 603
Natural gas purchases MMBtu 6,913 10,804
Natural gas sales MMBtu 409 555
Diesel purchases Gallons 243 906
Credit Risk
At December 31, 2014, Idaho Power did not have material credit risk 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 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 commonly under Western Systems
Power Pool agreements, physical gas contracts are usually under North American Energy Standards Board contracts, and financial
transactions are usually under International Swaps and Derivatives Association, Inc. contracts. These contracts 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
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.33
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, 2014, was $5.1 million. Idaho Power posted no cash collateral related to this
amount. If the credit-risk-related contingent features underlying these agreements were triggered on December 31, 2014, Idaho
Power would have been required to post an additional $5.9 million of cash collateral to its counterparties.
15. FAIR VALUE MEASUREMENTS
Idaho Power has categorized its 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 the following:
a) quoted prices for similar assets or liabilities in active markets;
b) quoted prices for identical or similar assets or liabilities in non-active markets;
c) pricing models whose inputs are observable for substantially the full term of the asset or liability; and
d) pricing models whose inputs are derived principally from or corroborated by observable market data through
correlation or other means for substantially the full term of the asset or liability.
Idaho Power Level 2 inputs are based on quoted market prices adjusted for location using corroborated, observable market
data.
• Level 3: Financial assets and liabilities whose values are based on prices or valuation techniques that require inputs that are
both unobservable and significant to the overall fair value measurement. These inputs reflect management’s own
assumptions about the assumptions a market participant would use in pricing the asset or liability.
Idaho Power’s assessment of a particular input's significance 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. An item recorded at fair value is
reclassified among levels when changes in the nature of valuation inputs cause the item to no longer meet the criteria for the level in
which it was previously categorized. There were no transfers between levels or material changes in valuation techniques or inputs
during the years ended December 31, 2014 and 2013.
The following table presents information about Idaho Power’s assets and liabilities measured at fair value on a recurring basis as of
December 31, 2014 and 2013 (in thousands of dollars):
December 31, 2014 December 31, 2013
Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets:
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.34
Derivatives $506 $ 128 $ —$ 634 $ 1,437 $ 235 $ —$ 1,672
Money market funds 100 — —100 100 — —100
Trading securities: Equity securities 141 — —141 1,153 — —1,153
Available-for-sale securities: Equity
securities 44,942 — —44,942 41,119 — —41,119
Liabilities:
Derivatives $17 $3,944 $—$3,961 $546 $26 $—$572
Idaho Power’s derivatives are contracts entered into as part of its management of loads and resources. Electricity derivatives are
valued on the Intercontinental Exchange (ICE) with quoted prices in an active market. Natural gas and diesel derivative valuations
are performed using New York Mercantile Exchange (NYMEX) and ICE pricing, adjusted for location basis, which are also quoted
under NYMEX and ICE pricing. 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 the carrying value and estimated fair value of financial instruments that are not reported at fair value, as of
December 31, 2014 and 2013, using available market information and appropriate valuation methodologies (in thousands of dollars):
December 31, 2014 December 31, 2013
Carrying
Amount
Estimated Fair
Value
Carrying
Amount
Estimated Fair
Value
Liabilities:
Long-term debt(1)$1,615,502 $1,788,197 $1,616,322 $1,600,248
(1) Long-term debt is categorized as Level 2 within the fair value hierarchy, as defined earlier in this Note 15.
Long-term debt is not traded on an exchange and is valued using quoted rates for similar debt in active markets. Carrying values for
cash and cash equivalents, deposits, customer and other receivables, notes payable, accounts payable, interest accrued, and taxes
accrued approximate fair value.
16. CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME
Comprehensive income includes net income, unrealized holding gains and losses on available-for-sale marketable securities, and
amounts related to the SMSP. The table below presents changes in components of accumulated other comprehensive income (AOCI),
net of tax, during the years ended December 31, 2014 and 2013 (in thousands of dollars). Items in parentheses indicate reductions to
AOCI.
Unrealized Gains and
Losses on
Available-for-Sale
Securities
Defined Benefit
Pension Items
Total
December 31, 2014
Balance at beginning of period $ — $ (16,553) $ (16,553)
Other comprehensive income before reclassifications — (9,333) (9,333)
Amounts reclassified from AOCI — 1,728 1,728
Net current-period other comprehensive income — (7,605) (7,605)
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.35
Balance at end of period $ — $ (24,158) $ (24,158)
December 31, 2013
Balance at beginning of period $ 4,136 $ (21,252) $ (17,116)
Other comprehensive income before reclassifications 2,951 2,840 5,791
Amounts reclassified from AOCI (7,087) 1,859 (5,228)
Net current-period other comprehensive income (4,136) 4,699 563
Balance at end of period $ — $ (16,553) $ (16,553)
The table below presents amounts reclassified out of components of AOCI and the income statement location of those amounts
reclassified during the years ended December 31, 2014 and 2013 (in thousands of dollars). Items in parentheses indicate increases to
net income.

Amount Reclassified from AOCI
2014
Amount Reclassified from AOCI
2013
Unrealized gains on available-for-sale securities
Realized gain on sale of securities, before tax(1) $ — $ (11,637)
Tax benefit(2) — 4,550
Net of tax — (7,087)
Amortization of defined benefit pension items(3)
Prior service cost 220 212
Net loss 2,618 2,839
Total before tax 2,838 3,051
Tax benefit(2) (1,110) (1,192)
Net of tax 1,728 1,859
Total reclassification for the period $ 1,728 $ (5,228)
(1) The realized gain is included in Idaho Power's consolidated income statement in other income (expense), net.
(2) The tax benefit is included in income tax expense (benefit) in the consolidated income statement of Idaho Power.
(3) Amortization of these items is included in Idaho Power's consolidated income statement in other expense, net.
17. 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 $1.4 million in 2014 and $1.0 million in 2013.
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.36
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 each year for 2013 and 2014.
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.37
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
1. Report in columns (b),(c),(d) and (e) the amounts of accumulated other comprehensive income items, on a net-of-tax basis, where appropriate.
2. Report in columns (f) and (g) the amounts of other categories of other cash flow hedges.
3. For each category of hedges that have been accounted for as "fair value hedges", report the accounts affected and the related amounts in a footnote.
4. Report data on a year-to-date basis.
Other
Adjustments
(e)
Foreign Currency
Hedges
(d)
Minimum Pension
Liability adjustment
(net amount)
(c)
Unrealized Gains and
Losses on Available-
for-Sale Securities
(b)
Item
(a)
4,136,553 ( 21,252,222)
Balance of Account 219 at Beginning of
Preceding Year
1
( 7,087,026) 1,858,601
Preceding Qtr/Yr to Date Reclassifications
from Acct 219 to Net Income
2
2,950,473 2,840,246
Preceding Quarter/Year to Date Changes in
Fair Value
3
( 4,136,553) 4,698,847Total (lines 2 and 3) 4
( 16,553,375)
Balance of Account 219 at End of Preceding
Quarter/Year
5
( 16,553,375)
Balance of Account 219 at Beginning of
Current Year
6
1,728,379
Current Qtr/Yr to Date Reclassifications
from Acct 219 to Net Income
7
( 9,333,003)
Current Quarter/Year to Date Changes in
Fair Value
8
( 7,604,624)Total (lines 7 and 8) 9
( 24,157,999)
Balance of Account 219 at End of Current
Quarter/Year
10
FERC FORM NO. 1 (NEW 06-02)Page 122a
Other Cash Flow
Hedges
[Specify]
(g)
Other Cash Flow
Hedges
Interest Rate Swaps
(f)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
Total
Comprehensive
Income
(j)
Net Income (Carried
Forward from
Page 117, Line 78)
(i)
Totals for each
category of items
recorded in
Account 219
(h)
( 17,115,669) 1
( 5,228,425) 2
5,790,719 3
176,741,143 177,303,437 562,294 4
( 16,553,375) 5
( 16,553,375) 6
1,728,379 7
( 9,333,003) 8
189,386,993 181,782,369( 7,604,624) 9
( 24,157,999) 10
FERC FORM NO. 1 (NEW 06-02)Page 122b
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.(b)(a)
Classification Electric
(c)
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Total Company for the
Current Year/Quarter Ended
Report in Column (c) the amount for electric function, in column (d) the amount for gas function, in column (e), (f), and (g) report other (specify) and in
column (h) common function.
Utility Plant 1
In Service 2
5,248,212,331 5,248,212,331Plant in Service (Classified) 3
Property Under Capital Leases 4
Plant Purchased or Sold 5
Completed Construction not Classified 6
Experimental Plant Unclassified 7
5,248,212,331 5,248,212,331Total (3 thru 7) 8
Leased to Others 9
7,090,431 7,090,431Held for Future Use 10
401,929,509 401,929,509Construction Work in Progress 11
Acquisition Adjustments 12
5,657,232,271 5,657,232,271Total Utility Plant (8 thru 12) 13
2,021,073,827 2,021,073,827Accum Prov for Depr, Amort, & Depl 14
3,636,158,444 3,636,158,444Net Utility Plant (13 less 14) 15
Detail of Accum Prov for Depr, Amort & Depl 16
In Service: 17
1,997,908,418 1,997,908,418Depreciation 18
Amort & Depl of Producing Nat Gas Land/Land Right 19
Amort of Underground Storage Land/Land Rights 20
23,165,409 23,165,409Amort of Other Utility Plant 21
2,021,073,827 2,021,073,827Total In Service (18 thru 21) 22
Leased to Others 23
Depreciation 24
Amortization and Depletion 25
Total Leased to Others (24 & 25) 26
Held for Future Use 27
Depreciation 28
Amortization 29
Total Held for Future Use (28 & 29) 30
Abandonment of Leases (Natural Gas) 31
Amort of Plant Acquisition Adj 32
2,021,073,827 2,021,073,827Total Accum Prov (equals 14) (22,26,30,31,32) 33
FERC FORM NO. 1 (ED. 12-89) Page 200
(g)
Common
(h)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Gas Other (Specify)
(d) (e) (f)
Other (Specify)Other (Specify)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
FERC FORM NO. 1 (ED. 12-89) Page 201
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
NUCLEAR FUEL MATERIALS (Account 120.1 through 120.6 and 157)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
Description of item Balance
(c)(b)(a)
Changes during YearBeginning of Year Additions
1. Report below the costs incurred for nuclear fuel materials in process of fabrication, on hand, in reactor, and in cooling; owned by the
respondent.
2. If the nuclear fuel stock is obtained under leasing arrangements, attach a statement showing the amount of nuclear fuel leased, the
quantity used and quantity on hand, and the costs incurred under such leasing arrangements.
Nuclear Fuel in process of Refinement, Conv, Enrichment & Fab (120.1) 1
Fabrication 2
Nuclear Materials 3
Allowance for Funds Used during Construction 4
(Other Overhead Construction Costs, provide details in footnote) 5
SUBTOTAL (Total 2 thru 5) 6
Nuclear Fuel Materials and Assemblies 7
In Stock (120.2) 8
In Reactor (120.3) 9
SUBTOTAL (Total 8 & 9) 10
Spent Nuclear Fuel (120.4) 11
Nuclear Fuel Under Capital Leases (120.6) 12
(Less) Accum Prov for Amortization of Nuclear Fuel Assem (120.5) 13
TOTAL Nuclear Fuel Stock (Total 6, 10, 11, 12, less 13) 14
Estimated net Salvage Value of Nuclear Materials in line 9 15
Estimated net Salvage Value of Nuclear Materials in line 11 16
Est Net Salvage Value of Nuclear Materials in Chemical Processing 17
Nuclear Materials held for Sale (157) 18
Uranium 19
Plutonium 20
Other (provide details in footnote): 21
TOTAL Nuclear Materials held for Sale (Total 19, 20, and 21) 22
FERC FORM NO. 1 (ED. 12-89)Page 202
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
NUCLEAR FUEL MATERIALS (Account 120.1 through 120.6 and 157)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
Balance
(f)(e)(d)
Changes during Year
End of YearAmortization Other Reductions (Explain in a footnote)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
FERC FORM NO. 1 (ED. 12-89) Page 203
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
Account Balance Additions
(c)(b)(a)
Beginning of Year
1. Report below the original cost of electric plant in service according to the prescribed accounts.
2. In addition to Account 101, Electric Plant in Service (Classified), this page and the next include Account 102, Electric Plant Purchased or Sold; 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)
1. INTANGIBLE PLANT 1
(301) Organization 5,703 2
(302) Franchises and Consents 29,492,883 -196,102 3
(303) Miscellaneous Intangible Plant 32,001,618 2,704,134 4
TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4) 61,500,204 2,508,032 5
2. PRODUCTION PLANT 6
A. Steam Production Plant 7
(310) Land and Land Rights 1,707,109 5,099 8
(311) Structures and Improvements 147,607,746 5,720,605 9
(312) Boiler Plant Equipment 574,685,386 30,968,367 10
(313) Engines and Engine-Driven Generators 11
(314) Turbogenerator Units 157,130,004 2,456,602 12
(315) Accessory Electric Equipment 69,526,524 625,133 13
(316) Misc. Power Plant Equipment 16,424,380 535,355 14
(317) Asset Retirement Costs for Steam Production 10,045,806 15
TOTAL Steam Production Plant (Enter Total of lines 8 thru 15) 977,126,955 40,311,161 16
B. Nuclear Production Plant 17
(320) Land and Land Rights 18
(321) Structures and Improvements 19
(322) Reactor Plant Equipment 20
(323) Turbogenerator Units 21
(324) Accessory Electric Equipment 22
(325) Misc. Power Plant Equipment 23
(326) Asset Retirement Costs for Nuclear Production 24
TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24) 25
C. Hydraulic Production Plant 26
(330) Land and Land Rights 30,921,432 267,825 27
(331) Structures and Improvements 172,021,110 3,009,623 28
(332) Reservoirs, Dams, and Waterways 253,221,758 9,357,143 29
(333) Water Wheels, Turbines, and Generators 201,680,871 5,615,318 30
(334) Accessory Electric Equipment 52,291,611 4,995,191 31
(335) Misc. Power PLant Equipment 21,004,289 812,228 32
(336) Roads, Railroads, and Bridges 8,183,435 1,401,205 33
(337) Asset Retirement Costs for Hydraulic Production 34
TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34) 739,324,506 25,458,533 35
D. Other Production Plant 36
(340) Land and Land Rights 2,690,006 37
(341) Structures and Improvements 133,753,938 7,148,416 38
(342) Fuel Holders, Products, and Accessories 7,982,028 2,470,519 39
(343) Prime Movers 236,639,588 4,939,595 40
(344) Generators 73,353,524 -6,998,268 41
(345) Accessory Electric Equipment 95,671,190 -7,063,625 42
(346) Misc. Power Plant Equipment 5,839,469 407,924 43
(347) Asset Retirement Costs for Other Production 44
TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44) 555,929,743 904,561 45
TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45) 2,272,381,204 66,674,255 46
Page 204FERC FORM NO. 1 (REV. 12-05)
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofIdaho Power Company X
04/15/2015 2014/Q4
Line
No.
Account Balance Additions
(c)(b)(a)
Beginning of Year
3. TRANSMISSION PLANT 47
(350) Land and Land Rights 36,087,730 102,069 48
(352) Structures and Improvements 70,075,081 2,716,121 49
(353) Station Equipment 388,935,103 13,971,575 50
(354) Towers and Fixtures 162,004,612 6,341,023 51
(355) Poles and Fixtures 129,115,202 14,311,741 52
(356) Overhead Conductors and Devices 188,088,876 9,279,054 53
(357) Underground Conduit 54
(358) Underground Conductors and Devices 55
(359) Roads and Trails 390,266 56
(359.1) Asset Retirement Costs for Transmission Plant 57
TOTAL Transmission Plant (Enter Total of lines 48 thru 57) 974,696,870 46,721,583 58
4. DISTRIBUTION PLANT 59
(360) Land and Land Rights 4,859,147 316,069 60
(361) Structures and Improvements 32,820,611 913,719 61
(362) Station Equipment 196,765,816 5,794,037 62
(363) Storage Battery Equipment 63
(364) Poles, Towers, and Fixtures 235,549,416 7,425,968 64
(365) Overhead Conductors and Devices 126,034,768 3,619,432 65
(366) Underground Conduit 46,289,611 1,157,996 66
(367) Underground Conductors and Devices 207,476,280 12,302,488 67
(368) Line Transformers 471,882,211 28,734,467 68
(369) Services 56,858,427 1,369,592 69
(370) Meters 73,143,443 7,766,427 70
(371) Installations on Customer Premises 2,901,563 94,180 71
(372) Leased Property on Customer Premises -38,361 2,302 72
(373) Street Lighting and Signal Systems 4,588,849 73
(374) Asset Retirement Costs for Distribution Plant 533,712 74
TOTAL Distribution Plant (Enter Total of lines 60 thru 74) 1,459,665,493 69,496,677 75
5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT 76
(380) Land and Land Rights 77
(381) Structures and Improvements 78
(382) Computer Hardware 79
(383) Computer Software 80
(384) Communication Equipment 81
(385) Miscellaneous Regional Transmission and Market Operation Plant 82
(386) Asset Retirement Costs for Regional Transmission and Market Oper 83
TOTAL Transmission and Market Operation Plant (Total lines 77 thru 83) 84
6. GENERAL PLANT 85
(389) Land and Land Rights 16,579,675 -4,824 86
(390) Structures and Improvements 102,938,584 4,701,008 87
(391) Office Furniture and Equipment 40,898,058 7,308,118 88
(392) Transportation Equipment 67,727,230 6,807,324 89
(393) Stores Equipment 1,908,757 45,847 90
(394) Tools, Shop and Garage Equipment 7,196,937 616,301 91
(395) Laboratory Equipment 12,444,681 806,460 92
(396) Power Operated Equipment 12,801,276 1,136,844 93
(397) Communication Equipment 43,926,012 12,801,448 94
(398) Miscellaneous Equipment 5,736,818 265,832 95
SUBTOTAL (Enter Total of lines 86 thru 95) 312,158,028 34,484,358 96
(399) Other Tangible Property 97
(399.1) Asset Retirement Costs for General Plant 98
TOTAL General Plant (Enter Total of lines 96, 97 and 98) 312,158,028 34,484,358 99
TOTAL (Accounts 101 and 106) 5,080,401,799 219,884,905 100
(102) Electric Plant Purchased (See Instr. 8) 101
(Less) (102) Electric Plant Sold (See Instr. 8) 102
(103) Experimental Plant Unclassified 103
TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103) 5,080,401,799 219,884,905 104
Page 206FERC FORM NO. 1 (REV. 12-05)
(f)
Transfers Balance atEnd of Year
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofIdaho Power Company X
04/15/2015 2014/Q4
Line
No.(g)
Adjustments
(e)
Retirements
(d)
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued)
distributions of these tentative classifications in columns (c) and (d), including the reversals of the prior years tentative account distributions of 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
1
5,703 2
29,296,781 3
29,627,507 5,078,245 4
58,929,991 5,078,245 5
6
7
1,712,208 8
150,084,364 3,243,987 9
595,163,147 10,490,606 10
11
159,336,727 249,879 12
70,043,047 108,610 13
15,934,815 1,024,920 14
6,372,118 -3,673,688 15
998,646,426 -3,673,688 15,118,002 16
17
18
19
20
21
22
23
24
25
26
31,188,341 -916 27
175,002,423 28,310 28
262,578,901 29
207,190,561 105,628 30
56,827,891 458,911 31
21,769,922 46,595 32
9,584,640 33
34
764,142,679 -916 639,444 35
36
2,690,006 37
140,902,354 38
10,452,547 39
238,896,447 2,682,736 40
66,355,256 41
88,607,565 42
6,247,393 43
44
554,151,568 2,682,736 45
2,316,940,673 -916 -3,673,688 18,440,182 46
Page 205FERC FORM NO. 1 (REV. 12-05)
(f)
Transfers Balance atEnd of Year
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofIdaho Power Company X
04/15/2015 2014/Q4
Line
No.(g)
Adjustments
(e)
Retirements
(d)
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued)
47
36,146,124 -2,730 40,945 48
72,737,991 15,382 68,593 49
399,787,968 -15,001 3,103,709 50
168,186,852 158,783 51
142,597,655 829,288 52
196,360,600 1,007,330 53
54
55
390,266 56
57
1,016,207,456 -2,349 5,208,648 58
59
5,175,131 -85 60
33,716,699 16,845 34,476 61
202,030,200 -32,341 497,312 62
63
241,088,379 1,887,005 64
128,008,024 1,646,176 65
47,294,326 153,281 66
218,656,607 1,122,161 67
494,614,876 6,001,802 68
57,867,385 360,634 69
80,528,574 381,296 70
2,914,525 -16,845 64,373 71
-84,348 48,289 72
4,588,849 73
533,712 74
1,516,932,939 -32,426 12,196,805 75
76
77
78
79
80
81
82
83
84
85
16,578,582 3,731 86
107,038,338 -15,382 585,872 87
45,902,762 2,303,414 88
74,214,375 320,179 89
1,936,397 18,207 90
7,574,780 238,458 91
12,652,489 14,262 612,914 92
13,938,120 93
53,788,304 33,080 2,972,236 94
5,577,125 425,525 95
339,201,272 35,691 7,476,805 96
97
98
339,201,272 35,691 7,476,805 99
5,248,212,331 -3,673,688 48,400,685 100
101
102
103
5,248,212,331 -3,673,688 48,400,685 104
Page 207FERC FORM NO. 1 (REV. 12-05)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ELECTRIC PLANT LEASED TO OTHERS (Account 104)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
Name of Lessee Description of
(b)(a)
(Designate associated companieswith a double asterisk) Property Leased CommissionAuthorization(c)
ExpirationDate ofLease(d)
Balance atEnd of Year(e)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO. 1 (ED. 12-95) Page 213
47 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ELECTRIC PLANT HELD FOR FUTURE USE (Account 105)
Idaho Power Company X
04/15/2015 2014/Q4
Line Description and Location Date Originally Included Balance atEnd of Year(c)(b)(a)Of Property in This Account Date Expected to be usedin Utility Service (d)No.
1. Report separately each property held for future use at end of the year having an original cost of $250,000 or more. Group other items of property 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.
Land and Rights: 1
12/31/82Boise Operations Center 655,550 2
Production 109,961 3
Transmission Stations 423,089 4
Transmission Lines 195,489 5
Distribution Stations 1,077,217 6
12/30/02Beacon Light Substation 465,662 7
2/29/08Homedale Substation 109,453 8
1/31/08North River Operations Center 2,630,412 9
3/31/09Line #854 500 Kv 308,066 10
11
12
13
Column B if no date listed it is various 14
15
16
17
18
19
20
Other Property: 21
12/31/82Boise Operations Center 72,785 22
Transmission Stations 199,069 23
Distribution Stations 69,941 24
2/29/08Homedale Substation 217,797 25
12/30/02Beacon Light Substation 555,940 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 (ED. 12-96) Page 214
47 Total 7,090,431
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
Description of Project Construction work in progress -
(b)(a)Electric (Account 107)
1. Report below descriptions and balances at end of year of projects in process of construction (107)
2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (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.
79,830,017ROLLUP RELIC COST BROWNLEE 1
54,409,576ROLLUP RELIC COST HELLS CANYON 2
26,705,505GATEWAY WEST 500KV LINE 3
26,503,011BRIDGER 2011C038 JB3 SCR SYS D 4
25,260,594ROLLUP RELIC COST OXBOW 5
21,460,986BOARDMAN - HEMINGWAY 500 KV LI 6
20,296,218HELLS CANYON RELICENSING OUTSI 7
17,320,740BRIDGER 2011C039 JB4 SCR SYS D 8
10,570,351CIAC LIABILITY RECLASS 9
8,913,910BROWNLEE TURBINE REFURBISHMENT 10
7,534,197B2H PERMITTING 11/1/2011 & FOR 11
5,358,000BRIDGER UNDISTRIBUTED WORK ORD 12
4,984,852VALMY 98281993 V2 COOLING TOWE 13
3,964,000VALMY UNDISTRIBUTED WORK ORDER 14
3,489,100VALMY 98306281V2 SCRUBBER INLE 15
2,798,630MPSN REPLACE C232&C233 SERIES 16
2,777,076VALMY 98306280 V2 SCRUBBER SPR 17
2,711,029LEGAL DEPT. LABOR FOR RELICENS 18
2,369,744LOWER SALMON RUNNER REPLACEMEN 19
2,327,924REL-HCC OREGON REAUTHORIZATION 20
2,286,270B2H TLINE CONSTRUCTION COSTS 21
2,213,993HCC WATERSHED ENHANCEMENT PROG 22
2,102,511CORPORATE AIRPLANE ENGINE REPL 23
1,963,324CHQB100177 - SPARE XFRMR LANGL 24
1,821,189BRIDGER 2012C075 U1 MERCURY CO 25
1,813,914BRIDGER 2012C076 U2 MERCURY CO 26
1,805,544BRIDGER 2012C078 U4 MERCURY CO 27
1,800,943BRIDGER 2012C077 U3 MERCURY CO 28
1,624,495HCPR110116 REPL T233 GSU 29
1,545,259PAYROLL & IBNR ACCRUAL 30
1,476,314BRIDGER 2014C037 U3 REPLACE FI 31
1,316,817HBND-041:ALT LINE ROUTE TO GAR 32
1,279,798WQ HCC401 APPLICATION, REVISIO 33
1,273,198WDRI-KCHM NEW 138KV 34
1,213,293TNDY ADD 69 KV BREAKERS EXPAND 35
1,200,163RELICENSING: BAKER COUNTY SETT 36
1,120,300REC - BAKER COUNTY SETTLEMENT 37
1,083,319WQ HCC401 CERTIFICATION OPS AN 38
1,068,315314 DESIGN TEAMS - CAPITAL - C 39
1,067,075FALL CHINOOK PROGRAM - REDD SU 40
41,268,015OTHER MINOR PROJECTS UNDER $1,000,000 41
42
FERC FORM NO. 1 (ED. 12-87) Page 216
43 TOTAL 401,929,509
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT (Account 108)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
Item Total
(c)(b)(a)(d)
Section A. Balances and Changes During Year
(c+d+e)Electric Plant inService Electric Plant Held for Future Use Electric PlantLeased to Others(e)
1. Explain in a footnote any important adjustments during year.
2. Explain in a footnote any difference between the amount for book cost of plant retired, Line 11, column (c), and that reported 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.
Balance Beginning of Year 1 1,919,582,910 1,919,582,910
Depreciation Provisions for Year, Charged to 2
(403) Depreciation Expense 3 125,245,540 125,245,540
(403.1) Depreciation Expense for Asset
Retirement Costs
4 495,029 495,029
(413) Exp. of Elec. Plt. Leas. to Others 5
Transportation Expenses-Clearing 6 3,723,850 3,723,850
Other Clearing Accounts 7
Other Accounts (Specify, details in footnote): 8
Fuel Stock 9 102,213 102,213
TOTAL Deprec. Prov for Year (Enter Total of
lines 3 thru 9)
10 129,566,632 129,566,632
Net Charges for Plant Retired: 11
Book Cost of Plant Retired 12 43,281,494 43,281,494
Cost of Removal 13 10,451,825 10,451,825
Salvage (Credit) 14 1,921,106 1,921,106
TOTAL Net Chrgs. for Plant Ret. (Enter Total
of lines 12 thru 14)
15 51,812,213 51,812,213
Other Debit or Cr. Items (Describe, details in
footnote):
16
CIAC, Reserve Adj and ARO activity. 17 571,089 571,089
Book Cost or Asset Retirement Costs Retired 18
Balance End of Year (Enter Totals of lines 1,
10, 15, 16, and 18)
19 1,997,908,418 1,997,908,418
Steam Production 20
Section B. Balances at End of Year According to Functional Classification
541,682,229 541,682,229
Nuclear Production 21
Hydraulic Production-Conventional 22 390,670,339 390,670,339
Hydraulic Production-Pumped Storage 23
Other Production 24 72,501,209 72,501,209
Transmission 25 312,623,040 312,623,040
Distribution 26 567,894,311 567,894,311
Regional Transmission and Market Operation 27
General 28 112,537,290 112,537,290
TOTAL (Enter Total of lines 20 thru 28) 29 1,997,908,418 1,997,908,418
Page 219FERC FORM NO. 1 (REV. 12-05)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
Description of Investment Date Acquired
(c)(b)(a)
Amount of Investment atBeginning of YearDate Of Maturity (d)
1. Report below investments in Accounts 123.1, investments in Subsidiary Companies.
2. Provide a subheading for each company and List there under the information called for below. Sub - TOTAL by company and give a TOTAL 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.
Idaho Energy Resources Company 1
50002/01/74Common Stock 2
2,462,594Capital contributions 3
88,921,479Equity in earnings 4
5
91,384,573Subtotal Idaho Energy Resources Company 6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
FERC FORM NO. 1 (ED. 12-89) Page 224
42 Total Cost of Account 123.1 $TOTAL 91,384,573 2,463,094
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1) (Continued)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
Equity in Subsidiary Earnings of Year Revenues for Year Amount of Investment atEnd of Year Gain or Loss from InvestmentDisposed of(e) (f) (g) (h)
4. For any securities, notes, or accounts that were pledged designate such securities, notes, or accounts in a footnote, and state the name of 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
1
500 2
2,462,594 3
81,014,366 15,000,000 7,092,887 4
5
83,477,460 15,000,000 7,092,887 6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
FERC FORM NO. 1 (ED. 12-89) Page 225
42 7,092,887 15,000,000 83,477,460
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
MATERIALS AND SUPPLIES
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
Account Balance Balance
(c)(b)(a)
Department orDepartments which
(d)
Beginning of Year End of Year Use Material
1. For Account 154, report the amount of plant materials and operating supplies under the primary functional classifications as indicated in column (a);
estimates of amounts by function are acceptable. In column (d), designate the department or departments which use the class of material.
2. Give an explanation of important inventory adjustments during the year (in a footnote) showing general classes of material and supplies and the
various accounts (operating expenses, clearing accounts, plant, etc.) affected debited or credited. Show separately debit or credits to stores expense
clearing, if applicable.
41,546,323 Electric 55,170,482 1 Fuel Stock (Account 151)
Electric 599 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
16,506,169 17,010,420 7 Production Plant (Estimated)
10,947,716 11,212,105 8 Transmission Plant (Estimated)
20,538,847 20,564,459 9 Distribution Plant (Estimated)
10 Regional Transmission and Market Operation Plant
(Estimated)
1,274,973 1,518,495 11 Assigned to - Other (provide details in footnote)
49,267,705 Electric 50,305,479 12 TOTAL Account 154 (Enter Total of lines 5 thru 11)
13 Merchandise (Account 155)
14 Other Materials and Supplies (Account 156)
15 Nuclear Materials Held for Sale (Account 157) (Not
applic to Gas Util)
4,375,589 Electric 5,098,760 16 Stores Expense Undistributed (Account 163)
17
18
19
95,189,617 110,575,320 20 TOTAL Materials and Supplies (Per Balance Sheet)
Page 227FERC FORM NO. 1 (REV. 12-05)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
Allowances (Accounts 158.1 and 158.2)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
SO2 Allowances Inventory Current Year
(b)(a)(Account 158.1)No. Amt.(c)No.(d)Amt.(e)
1. Report below the particulars (details) called for concerning allowances.
2. Report all acquisitions of allowances at cost.
3. Report allowances in accordance with a weighted average cost allocation method and other accounting as prescribed by General
Instruction No. 21 in the Uniform System of Accounts.
4. Report the allowances transactions by the period they are first eligible for use: the current year’s allowances in columns (b)-(c),
allowances for the three succeeding years in columns (d)-(i), starting with the following year, and allowances for the remaining
succeeding years in columns (j)-(k).
5. Report on line 4 the Environmental Protection Agency (EPA) issued allowances. Report withheld portions Lines 36-40.
2015
Balance-Beginning of Year 1
2
Acquired During Year: 3
Issued (Less Withheld Allow) 4
Returned by EPA 5
6
7
Purchases/Transfers: 8
9
10
11
12
13
14
Total 15
16
Relinquished During Year: 17
Charges to Account 509 18
Other: 19
20
Cost of Sales/Transfers: 21
22
23
24
25
26
27
Total 28
Balance-End of Year 29
30
Sales: 31
Net Sales Proceeds(Assoc. Co.) 32
Net Sales Proceeds (Other) 33
Gains 34
Losses 35
Allowances Withheld (Acct 158.2)
Balance-Beginning of Year 36
Add: Withheld by EPA 37
Deduct: Returned by EPA 38
Cost of Sales 39
Balance-End of Year 40
41
Sales: 42
Net Sales Proceeds (Assoc. Co.) 43
Net Sales Proceeds (Other) 44
Gains 45
Losses 46
FERC FORM NO. 1 (ED. 12-95) Page 228a
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
Allowances (Accounts 158.1 and 158.2)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.(f) (j)No. Amt.(g)No.(h)Amt.(i)No. Amt. No. Amt.(k) (l) (m)
Future Years Totals
(Continued)
6. Report on Lines 5 allowances returned by the EPA. Report on Line 39 the EPA’s sales of the withheld allowances. Report on Lines
43-46 the net sales proceeds and gains/losses resulting from the EPA’s sale or auction of the withheld allowances.
7. Report on Lines 8-14 the names of vendors/transferors of allowances acquire and identify associated companies (See "associated
company" under "Definitions" in the Uniform System of Accounts).
8. Report on Lines 22 - 27 the name of purchasers/ transferees of allowances disposed of an identify associated companies.
9. Report the net costs and benefits of hedging transactions on a separate line under purchases/transfers and sales/transfers.
10. Report on Lines 32-35 and 43-46 the net sales proceeds and gains or losses from allowance sales.
2016 2017
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO. 1 (ED. 12-95) Page 229a
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
Allowances (Accounts 158.1 and 158.2)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
NOx Allowances Inventory Current Year
(b)(a)(Account 158.1)No. Amt.(c)No.(d)Amt.(e)
1. Report below the particulars (details) called for concerning allowances.
2. Report all acquisitions of allowances at cost.
3. Report allowances in accordance with a weighted average cost allocation method and other accounting as prescribed by General
Instruction No. 21 in the Uniform System of Accounts.
4. Report the allowances transactions by the period they are first eligible for use: the current year’s allowances in columns (b)-(c),
allowances for the three succeeding years in columns (d)-(i), starting with the following year, and allowances for the remaining
succeeding years in columns (j)-(k).
5. Report on line 4 the Environmental Protection Agency (EPA) issued allowances. Report withheld portions Lines 36-40.
2015
Balance-Beginning of Year 1
2
Acquired During Year: 3
Issued (Less Withheld Allow) 4
Returned by EPA 5
6
7
Purchases/Transfers: 8
9
10
11
12
13
14
Total 15
16
Relinquished During Year: 17
Charges to Account 509 18
Other: 19
20
Cost of Sales/Transfers: 21
22
23
24
25
26
27
Total 28
Balance-End of Year 29
30
Sales: 31
Net Sales Proceeds(Assoc. Co.) 32
Net Sales Proceeds (Other) 33
Gains 34
Losses 35
Allowances Withheld (Acct 158.2)
Balance-Beginning of Year 36
Add: Withheld by EPA 37
Deduct: Returned by EPA 38
Cost of Sales 39
Balance-End of Year 40
41
Sales: 42
Net Sales Proceeds (Assoc. Co.) 43
Net Sales Proceeds (Other) 44
Gains 45
Losses 46
FERC FORM NO. 1 (ED. 12-95) Page 228b
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
Allowances (Accounts 158.1 and 158.2)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.(f) (j)No. Amt.(g)No.(h)Amt.(i)No. Amt. No. Amt.(k) (l) (m)
Future Years Totals
(Continued)
6. Report on Lines 5 allowances returned by the EPA. Report on Line 39 the EPA’s sales of the withheld allowances. Report on Lines
43-46 the net sales proceeds and gains/losses resulting from the EPA’s sale or auction of the withheld allowances.
7. Report on Lines 8-14 the names of vendors/transferors of allowances acquire and identify associated companies (See "associated
company" under "Definitions" in the Uniform System of Accounts).
8. Report on Lines 22 - 27 the name of purchasers/ transferees of allowances disposed of an identify associated companies.
9. Report the net costs and benefits of hedging transactions on a separate line under purchases/transfers and sales/transfers.
10. Report on Lines 32-35 and 43-46 the net sales proceeds and gains or losses from allowance sales.
2016 2017
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO. 1 (ED. 12-95) Page 229b
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
EXTRAORDINARY PROPERTY LOSSES (Account 182.1)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
(c)(b)(a)(d)
Description of Extraordinary Loss[Include in the description the date ofCommission Authorization to use Acc 182.1and period of amortization (mo, yr to mo, yr).]
Total Amount of Loss
LossesRecognisedDuring Year
WRITTEN OFF DURING YEAR
AccountCharged Amount
Balance at
End of Year
(f)(e)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
FERC FORM NO. 1 (ED. 12-88)Page 230a
20 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
UNRECOVERED PLANT AND REGULATORY STUDY COSTS (182.2)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
(c)(b)(a)(d)
Description of Unrecovered Plant Total Amount of Charges
CostsRecognisedDuring Year
WRITTEN OFF DURING YEAR
AccountCharged Amount
Balance at
End of Year
(f)(e)
and Regulatory Study Costs [Includein the description of costs, the date ofCommission Authorization to use Acc 182.2and period of amortization (mo, yr to mo, yr)]
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
FERC FORM NO. 1 (ED. 12-88)Page 230b
49 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
Transmission Service and Generation Interconnection Study Costs
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.Description Costs Incurred During
(b)(a)
Period Account Charged
(c)
ReimbursementsReceived During
(d)
Account CreditedWith Reimbursement
(e)
1. Report the particulars (details) called for concerning the costs incurred and the reimbursements received for performing transmission service 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.
the Period
Transmission Studies 1
4,210BLACK CANYON SISR 186623 ( 5,370) 186623 2
2,776BPAP NETWORK SIS 78318516 186623 186623 3
3,627BPAP NETWORK SIS 78862937 186623 3,447 186623 4
1,831BPAP TRANS SIS 80289606 186623 ( 10,000) 186623 5
PAC PTP SIS 80381517 186623 ( 10,000) 186623 6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Generation Studies 21
ALAMEDA SOLAR CENTER - GI 416 186623 ( 738) 186623 22
10,601AMERICAN FALLS SOLAR # 431 186623 ( 20,127) 186623 23
6,725AMERICAN FALLS SOLAR II # 433 186623 ( 13,508) 186623 24
3,781BENSON CREEK WINDFARM GI 401 186623 186623 25
4,915BLACK CREEK SOLAR #434 186623 ( 4,914) 186623 26
13,775BOISE CITY SOLAR #432 186623 ( 50,000) 186623 27
BURNT RIVER #2 PROJECT 251 186623 96,144 186623 28
BURNT RIVER PROJECT 209 186623 91,424 186623 29
85CLARK 2 SOLAR-20MW #438 186623 ( 1,000) 186623 30
85CLARK 4 SOLAR-20MW #440 186623 ( 1,000) 186623 31
857CLARK SOLAR 1 #437 7MW 186623 ( 10,000) 186623 32
170CLARK SOLAR 3 #439 30MW 186623 ( 10,000) 186623 33
( 159)EIGHTMILE HYDRO GI 406 186623 186623 34
17,838GRANDVIEW PV SOLAR FIVE GI 411 186623 ( 27,479) 186623 35
GRANDVIEW PV SOLAR FIVEA GI 418 186623 ( 1,300) 186623 36
5,981GROVE SOLAR CENTER - GI 414 186623 ( 31,187) 186623 37
1,605HEAD OF THE U HYDRO GI 409 186623 12,502 186623 38
HORSE CREEK SOLAR CENTER - GI 417 186623 ( 1,171) 186623 39
25,129HYLINE SOLAR CENTER - GI 419 186623 ( 39,247) 186623 40
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
Transmission Service and Generation Interconnection Study Costs
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.Description Costs Incurred During
(b)(a)
Period Account Charged
(c)
ReimbursementsReceived During
(d)
Account CreditedWith Reimbursement
(e)
the Period
(continued)
Transmission Studies 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Generation Studies 21
1,741LITTLE WOOD RIVER RANCH II GI 410 186623 ( 5,136) 186623 22
MAGPIE WIND PROJECT 235 186623 104,869 186623 23
MOUTAIN HOME SOLAR-20MW #435 186623 ( 1,000) 186623 24
MT. HOME SOLAR #444 186623 ( 1,000) 186623 25
8,486MURPHY FLAT POWER NORTH #426 186623 ( 13,423) 186623 26
3,540MURPHY FLAT POWER SOUTH #427 186623 ( 1,000) 186623 27
244MURPHY FLAT WIND FARM 186623 35,176 186623 28
21,796OPEN RANGE SOLAR CENTER - GI 413 186623 ( 31,965) 186623 29
ORCHARD RANCH SOLAR-20MW #441 186623 ( 1,000) 186623 30
POCATELLO SOLAR-20MW #436 186623 ( 1,000) 186623 31
12,652RAILROAD SOLAR CENTER - GI 423 186623 ( 37,842) 186623 32
16,818RAILROAD SOLAR CENTER - GI 424 186623 ( 35,858) 186623 33
SAGEBRUSH SOLAR CENTER - GI 415 186623 153 186623 34
1,534SALMON RIVER CANAL 550KW 186623 ( 1,000) 186623 35
SIMCO SOLAR #442 186623 ( 1,000) 186623 36
5,489SIMCOE SOLAR CENTER #428 186623 ( 13,426) 186623 37
TILLI SOLAR #443 186623 ( 1,000) 186623 38
2,707TURNER SOLAR CENTER - GI 420 186623 ( 1,707) 186623 39
20,012VALE AIR SOLAR CENTER - GI 412 186623 ( 39,111) 186623 40
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
Transmission Service and Generation Interconnection Study Costs
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.Description Costs Incurred During
(b)(a)
Period Account Charged
(c)
ReimbursementsReceived During
(d)
Account CreditedWith Reimbursement
(e)
the Period
(continued)
Transmission Studies 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Generation Studies 21
WRIGHT PLACE SOLAR #445 186623 ( 1,000) 186623 22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.2
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
OTHER REGULATORY ASSETS (Account 182.3)
Idaho Power Company X
04/15/2015
2014/Q4
Line
No.
Description and Purpose of Debits CREDITS
Written off During the
Quarter /Year Account
Charged (d)(c)(a)
Balance at end of
Current Quarter/Year
(e)
Other Regulatory Assets Written off During
the Period Amount
(f)
1. Report below the particulars (details) called for concerning other regulatory assets, including rate order docket number, if applicable.
2. Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $100,000 which ever is less), may be grouped
by classes.
3. For Regulatory Assets being amortized, show period of amortization.
Balance at Beginning
of Current
Quarter/Year
(b)
16,765,815 17,033,635 148,979230 416,799Asset Retirement Obligations (182341) 1
IPUC Order# 29414-OPUC Order# 04-585 2
3
1,628,450 3,960,704 6,866,388244 9,198,642ASC 815 Mark to Market - ST (182330) 4
5
710,482,403 802,188,345282 91,705,942FAS 109 Unfunded (182322) 6
Accum Deferred Income Noncurrent 7
8
63,093,814 45,412,570 73,675,167Various 55,993,923PCA Deferral Idaho - IPUC Order #33049 9
(Amort period 06/15 thru 05/16) (182323) 10
11
30,418,393 12,535,848 76,309,131various 58,426,586PCA Prior Year Deferral Idaho - IPUC Order #33049 12
(Amort period 06/14 thru 05/15) (182324) 13
14
15,431,297 16,811,911 16,063,980440/421 17,444,594Fixed Cost Adjuustment (FCA) (182302) 15
IPUC Order #33047 (Amort period 06/15 thru 05/1 16
17
4,094,478 6,925,678 12,081,243440/442 14,912,443Prior Year FCA IPUC Order #33047 (182309) 18
(Amort period 6/14 thru 5/15) 19
20
( 4,646,030) 903,788 182,989228 5,732,807AOCI Impact of Unfunded Post Retirement Liability 21
IPUC Order #30256 (182306) 22
23
2,524,479 2,750,366 116,997401/4073 342,884Oregon Pension Expense Capitalized (182339) 24
OPUC Order #10-064 (Amort period thru 2052) 25
26
27,062,657 20,077,507 29,598,897421/228 22,613,747Deferred Pension Expense Net of Contributions 27
IPUC Order #30333 (182321) 28
29
121,228,583 263,644,763 4,309,107228 146,725,287AOCI Impact of Unfunded Pension Liability 30
IPUC Order #30256 (182320) 31
32
( 6,092,288) -1,055,813 33,316,131401 38,352,606PCA Unbilled Forecast IPUC Order #53049 (182325) 33
34
7,538,300 5,534,507 2,184,844557/421 181,051PCAM Oregon 2008 (182346) 35
OPUC Order #08-238 & UE277 ( Amort 1/14 - 7/17) 36
37
( 793,327) -568,429421 224,898PCAM Interest Reserve 2008 (182329) 38
OPUC Order #08-238 & UE 277 (Amort 1/14 - 7/17) 39
40
26,915 26,984401/421 69Excess Power Cost Deferral 2007 (182358) 41
IPUC Order #09-189 (amort period 1/11 - 1/14) 42
43
FERC FORM NO. 1/3-Q (REV. 02-04)Page 232
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
OTHER REGULATORY ASSETS (Account 182.3)
Idaho Power Company X
04/15/2015
2014/Q4
Line
No.
Description and Purpose of Debits CREDITS
Written off During the
Quarter /Year Account
Charged (d)(c)(a)
Balance at end of
Current Quarter/Year
(e)
Other Regulatory Assets Written off During
the Period Amount
(f)
1. Report below the particulars (details) called for concerning other regulatory assets, including rate order docket number, if applicable.
2. Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $100,000 which ever is less), may be grouped
by classes.
3. For Regulatory Assets being amortized, show period of amortization.
Balance at Beginning
of Current
Quarter/Year
(b)
749,740 1,217,507 5,912,680various 6,380,447Idaho Boardman Decomissioning #32549 (182493) 1
2
3
230,655 230,6554012009 Reorg IPUC Order #30914 (182318) 4
(Amort period 01/10 thru 12/14) 5
6
974,888 286,732 688,156400OATT Revenue Deferred Reserve (182336) 7
IPUC Order #30940 (amort period 06/12 thru 5/15) 8
9
45,520,420 40,816,708 33,846,846401/421 29,143,134Idaho Pension Cash (182327) 10
IPUC Order #32248 11
(Amort period beginning 06/11 thru unknown) 12
13
( 136,099) -158,302 1,815,670557/421 1,793,4672008 PCAM Unbilled Amort (182356) 14
(Amort period 1/14 thru 7/17) 15
16
348,837 305,233 43,604402Lidar Surveys IPUC Order #32426 (182361) 17
(Amort period 01/12 thru 12/21) 18
19
149,773 74,887 74,886402Bennett Mtn Maintenance IPUC Order #32426 20
(Amort period 01/12 thru 12/15) (182379) 21
22
( 2,576,701) -2,380,650 48,212,040400/401 48,408,091PCA Unbilled Amortization (182316) 23
(Amort period 06/14 thru 05/15) 24
25
1,204,047 261,340 942,707403/411Idaho Boardman ARO Order #32549 (182393) 26
(Amort period thru 2020) 27
28
872,084 941,957 69,873Langley Revenue Accrual Order #12-226 (182398) 29
30
273,536 302,932 363,845various 393,241Minor items (32) 31
32
33
34
35
36
37
38
39
40
41
42
43
1,036,375,119TOTAL :44 1,237,823,724 347,011,926 548,460,531
FERC FORM NO. 1/3-Q (REV. 02-04)Page 232.1
Schedule Page: 232 Line No.: 9 Column: d
Contra accounts include 557, 421, 254, 440.
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
MISCELLANEOUS DEFFERED DEBITS (Account 186)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
Description of Miscellaneous Debits CREDITS
Account
(c)(b)(a)
Balance at
End of Year
(d)
Deferred Debits Amount
(e)
Balance at
Beginning of Year
(f)Charged
1. Report below the particulars (details) called for concerning miscellaneous deferred debits.
2. For any deferred debit being amortized, show period of amortization in column (a)
3. Minor item (1% of the Balance at End of Year for Account 186 or amounts less than $100,000, whichever is less) may be grouped by
classes.
659,834 425,944 246,788 12,898 401Prepaid ROW (186160) 1
Rents/Easements Long Term 2
3
54,483 1,791,148 3,313,563 5,050,228 165Long-Term Portfolio (186255) 4
5
1,306,535 1,241,610 64,925151Advance Prepaid (186709) 6
Coal Royalties 7
8
18,115,431 20,059,079 6,216,769 8,160,417 426Security plan (186720) 9
Net Insurance Asset 10
11
162,500 147,948 14,552401American Falls Bond Ref(186722) 12
(Amort 04/00 - 02/25) 13
14
907,071 669,396 237,675431Prepaid Credit Facility(186025) 15
(amort period 10/12 thru 10/17) 16
17
3,921,641 3,834,224 1,150,865 1,063,448 426Company Owned (186726) 18
Life Insurance 19
20
11,548,930 10,506,921 1,042,009401American Falls Water Rights 21
(amort 01/06 - 02/25) (186727) 22
23
4,254,545 3,190,909 1,063,636253Milner Bond Guarantee (186734) 24
(Amort 02/07 - 2/17) 25
26
535,991 487,991 48,000401American Falls - Bond refinance 27
(Amort through 02/25)(186770) 28
29
160,469 160,469 22 22 186Shelf Registration (186732) 30
31
837,710 1,659,405 981,269 1,802,964 variousPrepaid Exp (186052) 32
Contract I.T. Long Term 33
34
1,186,330 1,130,749 62,220 6,639 228/401Long Term (186121) 35
Workers Compensation 36
37
254,793 425,610 680,403 401Power Plant- Bridger (186780) 38
39
79,544 3,442,421 3,362,877 variousTransmission & Generation 40
Studies (186623) 41
42
1,458,328 1,458,328151/401Prepaid Coal LT (186797) 43
44
19,424 4,127 64,274 48,977 VariousMinor Items (2) 45
46
FERC FORM NO. 1 (ED. 12-94) Page 233
49 TOTAL
47 Misc. Work in Progress
48 Deferred Regulatory Comm.
Expenses (See pages 350 - 351)
45,208,766 45,564,713
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ACCUMULATED DEFERRED INCOME TAXES (Account 190)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
Description and Location Balance of Begining
(c)(b)(a)
Balance at Endof Year of Year
1. Report the information called for below concerning the respondent’s accounting for deferred income taxes.
2. At Other (Specify), include deferrals relating to other income and deductions.
Electric 1
2
3
4
97,597,101 118,958,964Other Electric (See footnote) 5
6
169,747,033 106,991,643Other (See footnote) 7
267,344,134 225,950,607TOTAL Electric (Enter Total of lines 2 thru 7) 8
Gas 9
10
11
12
13
14
Other 15
TOTAL Gas (Enter Total of lines 10 thru 15 16
21,759,450 20,824,214Other Non Electric See footnote 17
289,103,584 246,774,821TOTAL (Acct 190) (Total of lines 8, 16 and 17) 18
Notes
FERC FORM NO. 1 (ED. 12-88) Page 234
Schedule Page: 234 Line No.: 5 Column: b
Beginning Balance Ending Balance
Federal NOL-Operating 28,544,014 0
Prov for Rate Refund-HC Relicensing (AFUDC) 23,062,458 28,529,481
Regulatory Asset-Non Current 23,538,502 18,067,486
Deferred Idaho ITC 15,346,759 17,378,549
VEBA-Post Retirement Benefits 9,962,466 10,617,384
Incentive Deferral-Profit Sharing-Not in Rates 0 5,085,262
Stock Based Compensation-FAS123R 3,532,282 3,782,196
Revenue Sharing 2,972,019 3,127,266
Pension Expense-Oregon 2,204,483 2,488,771
Rate Case Disallowance 2,389,579 2,273,741
Regulatory Liability-Current 1,826,860 1,918,442
Construction Advances 2,059,244 1,016,324
Valmy Union Pacific Contract 1,083,462 919,072
Asset Retirement Obligation (ARO) 425,053 865,690
M & E Reserve 0 592,049
Postretirement Benefits-SFAS112 579,781 568,869
Bridger Revenue Deferral 191,185 316,603
Executive Deferred Compensation 450,715 54,988
Deferred GBC Federal 31,500 31,500
CSPP Co-Generator Overpayment 470,282 0
Oregon NOL-Operating 247,299 0
Provision for Rate Refunds 155,600 0
Montana NOL-Operating 101,480 0
Boardman Decommission (298,653) 0
Non-VEBA Pension and Benefits 82,596 (36,572)
Total Other Electric 118,958,964 97,597,101
Schedule Page: 234 Line No.: 7 Column: b

Pension-FAS 158 47,394,315 103,071,920
Regulatory Asset-FASB 109 50,788,061 50,814,726
Minimum Pension Liability 10,625,633 15,507,051
Postretirement Plan-FAS 158 (1,816,365) 353,336
Total Other 106,991,643 169,747,033
Schedule Page: 234 Line No.: 17 Column: b

Senior Management Security Plan 19,664,453 21,402,608
Micron CIAC-Depr Timing Diff 574,719 336,836
Federal NOL-Non Operating 534,662 0
Meridian Gold CIAC-Depr Timing Diff 42,118 20,006
Oregon NOL-Non Operating 6,409 0
Montana NOL-Non Operating 1,854 0
Total Non Electric 20,824,214 21,759,450
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
CAPITAL STOCKS (Account 201 and 204)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
Class and Series of Stock and Number of shares
(c)(b)(a)
Call Price at
End of Year
Par or Stated
Value per share
(d)
Name of Stock Series Authorized by Charter
1. Report below the particulars (details) called for concerning common and preferred stock at end of year, distinguishing separate 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.
Account 201 1
2.50 50,000,000 Common Stock all of which is held by 2
IdaCorp, Inc. and not traded 3
2.50 50,000,000Total Common Stock 4
5
Account 204 - None 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. 12-91) Page 250
AS REACQUIRED STOCK (Account 217)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
CAPITAL STOCKS (Account 201 and 204) (Continued)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
OUTSTANDING PER BALANCE SHEET HELD BY RESPONDENT
IN SINKING AND OTHER FUNDS
Shares(g)Cost(h)Shares SharesAmount
(Total amount outstanding without reductionfor amounts held by respondent)
Amount(e) (f)(i) (j)
3. Give particulars (details) concerning shares of any class and series of stock authorized to be issued by a regulatory 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.
1
97,877,030 39,150,812 2
3
97,877,030 39,150,812 4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
FERC FORM NO. 1 (ED. 12-88) Page 251
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofIdaho Power Company X
04/15/2015 2014/Q4
Line Item Amount(b)(a)
OTHER PAID-IN CAPITAL (Accounts 208-211, inc.)
No.
Report below the balance at the end of the year and the information specified below for the respective other paid-in capital accounts. Provide 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.
Account 208 - Donations received from stockholders - None 1
2
Account 209 - Reduction in par or stated value of Capital Stock - None 3
4
Account 210 - Gain on reacquired Capital Stock - None 5
6
7
Account 211 - Miscellaneous paid-in Capital - None 8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
FERC FORM NO. 1 (ED. 12-87) Page 253
40 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
CAPITAL STOCK EXPENSE (Account 214)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
Class and Series of Stock Balance at End of Year(b)(a)
1. Report the balance at end of the year of discount on capital stock for each class and series of capital stock.
2. If any change occurred during the year in the balance in respect to any class or series of stock, attach a statement giving particulars
(details) of the change. State the reason for any charge-off of capital stock expense and specify the account charged.
2,096,925Common Stock 1
2
3
4
5
6
7
8
9
Explanation of Changes during the year: 10
11
12
13
14
15
16
17
18
19
20
21
FERC FORM NO. 1 (ED. 12-87) Page 254b
22 TOTAL 2,096,925
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
LONG-TERM DEBT (Account 221, 222, 223 and 224)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
Class and Series of Obligation, Coupon Rate
(c)(b)(a)
Total expense,
Premium or Discount
Principal Amount
Of Debt issued(For new issue, give commission Authorization numbers and dates)
1. Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221, Bonds, 222,
Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt.
2. In column (a), for new issues, give Commission authorization numbers and dates.
3. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds.
4. For advances from Associated Companies, report separately advances on notes and advances on open accounts. 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.
Account 221: 1
First Mortgage Bonds: 2
1,190,698 130,000,0004.50% Series due 2020 3
234,601 4 D
5
728,701 70,000,0005.50% Series due 2033 6
36,400 7 D
8
1,034,909 100,000,0006.15% Series Due 2019 9
184,949 10 D
11
1,159,871 100,000,0003.40% Series due 2020 12
498,864 13 D
14
408,411 60,000,0005.30% Series Due 2035 15 D
3,802,019 16
17
742,017 75,000,0004.00% Series due 2043 18
193,836 19 D
20
1,191,216 100,000,0006.00% Series due 2032 21
543,244 22 D
23
-585,759 55,000,0005.875% Series due 2034 24
746,961 25 D
26
524,419 50,000,0005.50% Series due 2034 27
383,322 28 D
29
1,284,871 100,000,0004.85% Series Due 2040 30
169,984 31 D
32
FERC FORM NO. 1 (ED. 12-96)Page 256
33 TOTAL 1,627,045,000 26,907,384
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
LONG-TERM DEBT (Account 221, 222, 223 and 224)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
Class and Series of Obligation, Coupon Rate
(c)(b)(a)
Total expense,
Premium or Discount
Principal Amount
Of Debt issued(For new issue, give commission Authorization numbers and dates)
1. Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221, Bonds, 222,
Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt.
2. In column (a), for new issues, give Commission authorization numbers and dates.
3. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds.
4. For advances from Associated Companies, report separately advances on notes and advances on open accounts. 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.
1,495,799 140,000,0006.30% Series due 2037 1
278,367 2 D
3
1,141,489 100,000,0006.25% Series due 2037 4
267,677 5 D
6
188,545 4,360,000Port of Morrow Variable due 2027 7
1,697,856 49,800,000Humboldt Variable due 2024 8
3,026,122 116,300,000Sweetwater Variable due 2026 9
10
648,267 75,000,0002.50% Series due 2023 11
371,854 12 D
13
1,630,120 120,000,0006.025 % Series Due 2018 14
15
802,240 75,000,0004.30% Series Due 2042 16
49,417 17 D
708,490 75,000,0002.95% Series Due 2022 18
127,607 19 D
26,907,384 1,595,460,000Subtotal Account 221 20
21
Account 222 - Reaquired Bonds 22
23
Account 223: Advances for Associated Companies 24
25
Account 224: 26
19,885,000Bond Guarantee - American Falls 27
11,700,000Note Guarantee - Milner Dam 28
31,585,000Subtotal Account 224 29
30
31
32
FERC FORM NO. 1 (ED. 12-96)Page 256.1
33 TOTAL 1,627,045,000 26,907,384
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
LONG-TERM DEBT (Account 221, 222, 223 and 224) (Continued)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.Nominal Dateof Issue Date ofMaturity
AMORTIZATION PERIOD
Date From Date To
Outstanding(Total amount outstanding withoutreduction for amounts held byrespondent)
Interest for YearAmount(d) (e) (f) (g) (h) (i)
10. Identify separate undisposed amounts applicable to issues which were redeemed in prior years.
11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, 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.
1
2
130,000,000 5,850,0003/1/2011/20/093/1/2011/20/09 3
4
5
70,000,000 3,850,00003/31/3305/01/0304/01/3305/01/03 6
7
8
100,000,000 6,150,0004/1/194/1/094/1/194/1/09 9
10
11
100,000,000 3,400,0005/1/2011/1/105/1/202011/1/10 12
13
14
60,000,000 3,180,00008/26/3508/26/0508/26/3508/26/05 15
16
17
75,000,000 3,000,0004/1/20434/8/20134/1/20434/8/2013 18
19
20
100,000,000 6,000,00011/15/3211/15/0211/15/3211/15/02 21
22
23
55,000,000 3,231,25008/16/3408/16/0408/16/3408/16/04 24
25
26
50,000,000 2,750,00003/15/3403/26/0403/15/3403/26/04 27
28
29
100,000,000 4,850,0008/15/402/15/108/15/402/15/10 30
31
32
FERC FORM NO. 1 (ED. 12-96)Page 257
33 1,618,535,909 80,561,920
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
LONG-TERM DEBT (Account 221, 222, 223 and 224) (Continued)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.Nominal Dateof Issue Date ofMaturity
AMORTIZATION PERIOD
Date From Date To
Outstanding(Total amount outstanding withoutreduction for amounts held byrespondent)
Interest for YearAmount(d) (e) (f) (g) (h) (i)
10. Identify separate undisposed amounts applicable to issues which were redeemed in prior years.
11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, 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.
140,000,000 8,820,0006/15/376/22/076/15/20376/22/07 1
2
3
100,000,000 6,250,00010/15/3710/18/0710/15/203710/18/07 4
5
6
4,360,000 17,72002/01/2705/17/0002/01/2705/17/00 7
49,800,000 2,564,70012/01/2411/01/0312/01/2410/22/03 8
116,300,000 6,105,7507/15/2610/3/067/15/2610/3/06 9
10
75,000,000 1,875,0004/1/20234/8/20134/1/20234/8/2013 11
12
13
120,000,000 7,230,0007/15/087/10/087/15/187/10/08 14
15
75,000,000 3,225,0004/1/424/13/124/1/424/13/12 16
17
75,000,000 2,212,5004/1/224/13/124/1/224/13/12 18
19
1,595,460,000 80,561,920 20
21
22
23
24
25
26
19,885,0002/1/2504/26/00 27
3,190,90902/10/92 28
23,075,909 29
30
31
32
FERC FORM NO. 1 (ED. 12-96)Page 257.1
33 1,618,535,909 80,561,920
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
RECONCILIATION OF REPORTED NET INCOME WITH TAXABLE INCOME FOR FEDERAL INCOME TAXES
Idaho Power Company X
04/15/2015 2014/Q4
Particulars (Details)(b)(a)Amount LineNo.
1. Report the reconciliation of reported net income for the year with taxable income used in computing Federal income tax accruals and show
computation of such tax accruals. Include in the reconciliation, as far as practicable, the same detail as furnished on Schedule M-1 of the tax return for
the year. Submit a reconciliation even though there is no taxable income for the year. Indicate clearly the nature of each reconciling amount.
2. If the utility is a member of a group which files a consolidated Federal tax return, reconcile reported net income with taxable net income as if a separate
return were to be field, indicating, however, intercompany amounts to be eliminated in such a consolidated return. State names of group member, tax
assigned to each group member, and basis of allocation, assignment, or sharing of the consolidated tax among the group members.
3. A substitute page, designed to meet a particular need of a company, may be used as Long as the data is consistent and meets the requirements of the
above instructions. For electronic reporting purposes complete Line 27 and provide the substitute Page in the context of a footnote.
189,386,993Net Income for the Year (Page 117) 1
2
3
Taxable Income Not Reported on Books 4
-98,931,827 5
6
7
8
Deductions Recorded on Books Not Deducted for Return 9
50,782,788 10
11
12
13
Income Recorded on Books Not Included in Return 14
19,918,608 15
16
17
18
Deductions on Return Not Charged Against Book Income 19
114,202,966 20
21
22
23
24
25
26
7,116,380Federal Tax Net Income 27
Show Computation of Tax: 28
2,490,733Tenative Federal Tax @ 35% 29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
FERC FORM NO. 1 (ED. 12-96)Page 261
Schedule Page: 261 Line No.: 5 Column: b

4000-FEDERAL NOL $ (113,211,345)
4003-CONSTRUCTION ADVANCES (2,979,771)
4005-AVOIDED COST 6,508,216
4010-EMISSION ALLOWANCES (ACCT 283) 13,495
4013-CIAC - TAXABLE - ACCT 107 8,850,300
4021-ENGINEERING FEES - TAXABLE - ACCT 107 528,786
4024-RENEWABLE ENERGY CERTIFICATES (REC) SALES 2,023,523
4506-MERIDIAN GOLD CIAC - DEPR TIMING DIFF - NON-OP (56,560)
4507-MICRON CIAC - DEPR TIMING DIFF - NON-OP (608,471)
Total $ (98,931,827)
Schedule Page: 261 Line No.: 10 Column: b

Total Federal and State taxes deducted on books $ 15,784,451
5001-BAD DEBT EXPENSE (398,034)
5010-POSTEMPLOYMENT BENEFITS-SFAS112 (27,913)
5014-VACATION ACCRUAL TAX ADJ - ACCT 242 586,964
5017-INJURIES & DAMAGES 379,858
5019-DEFERRED DIRECTORS FEES (343,330)
5022-263A CAPITALIZED OVERHEADS (25,000,000)
5023-PENSION EXPENSE (ACCT 283) 3,846,847
5024-NON-DEDUCTIBLE MEALS 500,000
5025-MILNER FALLING WATER (48,550)
5028-OREGON OPERATING PROPERTY TAX ADJ (9,810)
5033-NON-VEBA PENSION & BENEFITS (304,817)
5035-PCA EXPENSE DEFERRAL 30,331,264
5043-AMERICAN FALLS - FALLING WATER CONTRACT 219,181
5046-EXECUTIVE DEFERRED COMP - ST (984,570)
5047-EXECUTIVE DEFERRED COMP - LT (27,649)
5048-BONUS DEFERRAL-OPERATING (DT 283) (Old Event) (13,834)
5070-INCENTIVE DEFERRAL-CRI & RELIABILITY-INCLUDED IN RATES 8,189,137
5071-INCENTIVE DEFERRAL-PROFIT SHARING-NOT IN RATES (DT 190) 13,007,448
5052-AMORTIZATION OF ACCOUNT 181 272,059
5053-STOCK BASED COMPENSATION - FAS 123R 659,039
5055-OPUC GRID WEST LOANS 14,191
5057-INTERVENER FUNDING ORDERS (98,495)
5058-FIXED COST ADJUSTMENT (4,211,813)
5060-OREGON - PCAM 1,776,896
5061-PENSION EXPENSE - OREGON 727,172
5062-2011 LIDAR SURVEYS DEFERRAL 43,605
5063-BENNETT MTN MAINT DEFERRAL 74,886
5064-BRIDGER REVENUE DEFERRAL 320,803
5065-VALMY UNION PACIFIC CONTRACT (420,488)
5066-BOARDMAN DECOMMISSION (DT 190) 763,915
5066-BOARDMAN DECOMMISSION (DT 283) (1,238,525)
5067-ASSET RETIREMENT OBLIGATION (ARO) 804,745
5068-CSPP CO-GENERATOR OVERPAYMENT (1,202,920)
5069-M & E RESERVE 1,514,386
5501-SMSP - INSURANCE COSTS (177,316)
5503-EDC - UNREALIZED GAIN/LOSS FROM RABBI TRUST (19,873)
5504-NON-DEDUCTIBLE POLITICAL EXPENSES 1,171,441
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
5505-SMSP - NET 4,445,979
5510-FINES & PENALTIES - OPERATING. 36,000
5516-NON-DEDUCTIBLE POLITICAL EXP - O&M ACCTS 100,000
5517-SMSP - UNREALIZED GAIN/LOSS FOR TAX 49,886
5531-RATE CASE DISALLOWANCES (296,299)
5532-DELIVERY ACCRUALS (13,129)
Total $ 50,782,788
Schedule Page: 261 Line No.: 15 Column: b

7009-PROVISION FOR RATE REFUNDS $ 398,006
7010-PROV FOR RATE REFUND - HC RELICENSING (AFUDC) (13,983,946)
7011-OATT REVENUE DEFICIENCY (688,156)
7012-REVENUE SHARING (397,102)
7013-LANGLEY REVENUE ACCRUAL 48,838
7501-REVERSE EQUITY EARNINGS OF SUBSIDIARIES 7,092,887
7502-ALLOWANCE FOR OFUDC 17,930,898
7503-ALLOWANCE FOR BFUDC 8,464,109
7509-SMSP - INSURANCE PROCEEDS 1,053,074
Total $ 19,918,608
Schedule Page: 261 Line No.: 20 Column: b

8001-VEBA - POST RETIREMENT BENEFITS $ (1,731,048)
8009-DEPR TIMING DIFF - OPERATING - FEDERAL 12,993,378
8020-CONSERVATION EXPENSES 973,123
8025-MANUFACTURING DEDUCTION 5,296,634
8027-NEVADA OPERATING PROPERTY TAX ADJ 142,023
8034-REMOVAL COSTS 10,445,838
8038-OREGON EXCESS POWER COSTS (47,212)
8041-AMERICAN FALLS REFINANCE - OLD COSTS (47,999)
8042-GAIN/LOSS ON REACQUIRED DEBT (1,060,585)
8057-REORGANIZATION COSTS (230,656)
8059-SOFTWARE - LABOR COSTS DEDUCTED - ACCT 107 500,000
8072-RELICENSING - LABOR COSTS DEDUCTED - ACCT 107 2,800,000
8073-REPAIRS DEDUCTION 75,000,000
8077-PREPAID INSURANCE & OTHER EXPENSES (605,997)
8501-COLI - INSURANCE COSTS 112,012
8504-OREGON NON-OP PROPERTY TAX ADJUSTMENT 55
8703-IPCO - 162 (M) $1m THRESHOLD (207,282)
8901-REGULATORY ASSET - CURRENT (13,994,159)
8901-REGULATORY ASSET - NON CURRENT 13,994,159
8902-REGULATORY LIABILITY - CURRENT (234,256)
8902-REGULATORY LIABILITY - NON CURRENT 234,256
STATE INCOME TAX DEDUCTED ON FEDERAL RETURN 9,870,682
Total $ 114,202,966
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
Kind of Tax
(See instruction 5)
BALANCE AT BEGINNING OF YEAR
Taxes Accrued(Account 236)Prepaid Taxes(Include in Account 165)
TaxesChargedDuringYear
TaxesPaid During
Adjust-
mentsYear(a) (b) (c) (d) (e) (f)
1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts 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.
Federal: 1
12,446,979 -10,331,231 4,917,038Income 2
14,044,743 14,043,578 -13Social Security - (FOAB) 3
91,850 91,850Unemployment 4
26,583,572 3,804,197 4,917,025 Subtotal Federal 5
6
State of Idaho: 7
20,753,612 20,820,653 8,961,328Property 8
22,146 23,015 10,639Non-Operating 9
9,695,941 6,921,987 -139,933Income 10
1,416,517 1,404,355 98,314KWH 11
651,894 651,894Unemployment 12
2,688,423 2,688,423Regulatory Commission 13
150 150Business License - Sho Ban 14
35,228,683 32,510,477 8,930,348 Subtotal Idaho 15
16
State of Oregon 17
2,872,585 2,862,775 1,425,833Property 18
1,837 1,782 863Non-Operating Property 19
54,224 -110,880 -6,462Income 20
186,899 186,899Regulatory Commission 21
51,486 51,486Unemployment 22
807,855 800,080 213,724Franchise 23
3,974,886 3,792,142 1,426,696 207,262 Subtotal Oregon 24
25
State of Montana: 26
305,096 321,531 144,976Property 27
305,096 321,531 144,976 Subtotal Montana 28
29
State of Nevada: 30
1,315,753 1,173,729 360,323Property 31
1,315,753 1,173,729 360,323 Subtotal Nevada 32
33
State of Wyoming 34
4,744 4,744Corporate License 35
1,577,652 1,604,927 775,189Property 36
1,582,396 1,609,671 775,189 Subtotal Wyoming 37
5,336 -140,147 128,086Other States Income 38
-14,838,808Payroll Tax Credit 39
5,060 -37,631 1,524Canada GST tax 40
1,787,019
FERC FORM NO. 1 (ED. 12-96)Page 262
TOTAL41 28,232,792 69,000,782 -37,631 15,104,410
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.(Taxes accrued
BALANCE AT END OF YEARPrepaid Taxes Electric(Account 408.1, 409.1)Extraordinary Items(Account 409.3)
Adjustments to Ret.OtherEarnings (Account 439)(g) (h) (i) (j) (k) (l)Account 236)(Incl. in Account 165)
DISTRIBUTION OF TAXES CHARGED
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 (l) 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 (l) 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 (l) the taxes charged to utility plant or other balance sheet accounts.
9. For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax.
1
-2,917,498 -7,413,733 -17,861,172 2
14,043,578 -1,179 3
91,850 4
-2,917,498 6,721,695 -17,862,351 5
6
7
797 20,819,856 9,028,370 8
23,015 11,508 9
-207,384 7,129,371 -2,913,887 10
1,404,355 86,152 11
651,894 12
2,688,423 13
150 14
-183,572 32,694,049 6,212,143 15
16
17
119,240 2,743,535 1,435,643 18
1,782 918 19
-23,430 -87,450 -171,566 20
186,899 21
51,486 22
800,080 205,949 23
97,592 3,694,550 1,436,561 34,383 24
25
26
321,531 161,411 27
321,531 161,411 28
29
30
1,173,729 502,346 31
1,173,729 502,346 32
33
34
4,744 35
1,604,927 802,464 36
1,609,671 802,464 37
-6,810 -133,337 -17,398 38
-14,838,808 39
34,095 40
FERC FORM NO. 1 (ED. 12-96)Page 263
41 1,938,907 31,243,080 -3,010,288 -10,635,253
Schedule Page: 262 Line No.: 2 Column: l
Account 409.2 $ (914,126)
Account 234.020 (2,003,372)
------------
Total $(2,917,498)
============
Schedule Page: 262 Line No.: 8 Column: l
Account 107 $ 797
Schedule Page: 262 Line No.: 9 Column: l
Account 408.2 $ 23,015

Schedule Page: 262 Line No.: 10 Column: l
Account 409.2 $ (23,447)
Account 234.020 (183,937)
-----------
Total $ (207,384)
===========

Schedule Page: 262 Line No.: 18 Column: l
Account 107 $ 119,240
Schedule Page: 262 Line No.: 19 Column: l
Account 408.2 $ 1,782
Schedule Page: 262 Line No.: 20 Column: l
Account 409.2 $ (14,076)
Account 234.020 (9,353)
----------
Total $ (23,430)
==========
Schedule Page: 262 Line No.: 38 Column: l
Account 409.2 $ (3,692)
Account 234.020 (3,118)
---------
Total $ (6,810)
=========
Schedule Page: 262 Line No.: 39 Column: i
This amount is an offset to lines 3, 4, 11 & 22. Each month employer paid taxes flow into
various 408.1 accounts. In that same month these amounts are offset with a different 408.1
account. These payroll taxes are then allocated back to the balance sheet and O & M
accounts based on current month labor charges.
Schedule Page: 262 Line No.: 40 Column: f
Canada GST accrual is an adjustment because the offset account is not a 600 expense
account.
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
Account Balance at Beginning
(c)(b)(a)
of YearSubdivisions AdjustmentsDeferred for Year Allocations toCurrent Year's IncomeAccount No. Amount Account No. Amount(d) (e) (f)(g)
Report below information applicable to Account 255. Where appropriate, segregate the balances and transactions by utility and 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.
Electric Utility 1
3% 2
4% -54,475 541,998 53,324 3
7% 4
10% 54,475 21,047,565 1,402,464 5
1,187,853 26,029 6
411.4 56,343,874 3,044,087 411.4 1,520,729 7
TOTAL 79,121,290 3,044,087 3,002,546 8
Other (List separately
and show 3%, 4%, 7%,
10% and TOTAL)
9
Line 6 Col A 11% 10
11
State of Idaho 411.4 56,343,874 3,044,087 411.4 1,520,729 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 266
Balance at End
(i)(h)
of Year
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255) (continued)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.ADJUSTMENT EXPLANATIONAverage Periodof Allocationto Income
1
2
434,199 10.16 3
4
19,699,576 15.01 5
1,161,824 45.64 6
57,867,232 37.05 7
79,162,831 8
9
10
11
57,867,232 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
Schedule Page: 266 Line No.: 3 Column: g
The adjusting entry is to tie the ending balance to the record detail and work papers.
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
OTHER DEFFERED CREDITS (Account 253)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
Description and Other DEBITS
Credits
Account(c)(b)(a)
Balance at
End of Year
(d)
Deferred Credits Amount
(e)
Balance at
Beginning of Year Contra
(f)
1. Report below the particulars (details) called for concerning other deferred credits.
2. For any deferred credit being amortized, show the period of amortization.
3. Minor items (5% of the Balance End of Year for Account 253 or amounts less than $100,000, whichever is greater) may be grouped by classes.
900,249Smart Grid (253200) 210,872 1,111,121107/401 1
2
899,702Point to Point Trans Study(253201) 1,287,950 474,248 86,0002472 3
4
3,266,666FTV (253202) 2,866,666 400,000400 5
(Amort Period Mar 1998-Feb 2023) 6
7
217,500Sho Ban Trans ROW (253480) 202,500 15,000107 8
(Amort Period Jan 2005-Dec 2027) 9
10
715,735Milner Falling Water (253953) 667,185 1,117,149 1,165,699186/401 11
Amort Period (Feb 1992 - Feb 2017) 12
13
1,483,006Postretirement Benefits (253960) 1,455,093 27,913401 14
15
4,226,431Directors Deferred Compensation 3,883,100 589,636 932,967131 16
(253980-253999) 17
18
676,000Operations Accrual (253550) 1,271,388 669,823 74,435232/401 19
(amort period 1 year for dues) 20
21
1,432Minor Items (1) 253042 1,760 44,806 44,478various 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 (ED. 12-94) Page 269
47 TOTAL 3,106,534 3,857,613 11,635,642 12,386,721
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ACCUMULATED DEFERRED INCOME TAXES - ACCELERATED AMORTIZATION PROPERTY (Account 281)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.Account
(a) (b) (c) (d)
Balance atBeginning of Year
CHANGES DURING YEAR
Amounts Debited Amounts Credited
to Account 410.1 to Account 411.1
1. Report the information called for below concerning the respondent’s accounting for deferred income taxes rating to amortizable
property.
2. For other (Specify),include deferrals relating to other income and deductions.
1 Accelerated Amortization (Account 281)
2 Electric
3 Defense Facilities
4 Pollution Control Facilities
5 Other (provide details in footnote):
6
7
8 TOTAL Electric (Enter Total of lines 3 thru 7)
9 Gas
10 Defense Facilities
11 Pollution Control Facilities
12 Other (provide details in footnote):
13
14
15 TOTAL Gas (Enter Total of lines 10 thru 14)
16
17 TOTAL (Acct 281) (Total of 8, 15 and 16)
18 Classification of TOTAL
19 Federal Income Tax
20 State Income Tax
21 Local Income Tax
FERC FORM NO. 1 (ED. 12-96)Page 272
NOTES
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ACCUMULATED DEFERRED INCOME TAXES _ ACCELERATED AMORTIZATION PROPERTY (Account 281) (Continued)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
CHANGES DURING YEAR ADJUSTMENTS
Balance at
End of YearDebitsCreditsAmounts Debited
to Account 410.2
Amounts Credited
to Account 411.2 AccountCredited Amount DebitedAccount Amount
(e)(f)(h)(j)(k)(g)(i)
3. Use footnotes as required.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
FERC FORM NO. 1 (ED. 12-96)Page 273
NOTES (Continued)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ACCUMULATED DEFFERED INCOME TAXES - OTHER PROPERTY (Account 282)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.Account
(a) (b) (c) (d)
Balance atBeginning of Year
CHANGES DURING YEAR
Amounts Debited Amounts Credited
to Account 410.1 to Account 411.1
1. Report the information called for below concerning the respondent’s accounting for deferred income taxes rating to property not
subject to accelerated amortization
2. For other (Specify),include deferrals relating to other income and deductions.
Account 282 1
Electric 436,837,016 30,575,458 16,294,782 2
Gas 3
Other 4
TOTAL (Enter Total of lines 2 thru 4) 436,837,016 30,575,458 16,294,782 5
Non-Operating Property 6
Other - Regulatory Asset 706,253,450 7
8
TOTAL Account 282 (Enter Total of lines 5 thru 8) 1,143,090,466 30,575,458 16,294,782 9
Classification of TOTAL 10
Federal Income Tax 980,163,502 30,306,822 16,294,782 11
State Income Tax 162,926,964 268,636 12
Local Income Tax 13
FERC FORM NO. 1 (ED. 12-96)Page 274
NOTES
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ACCUMULATED DEFERRED INCOME TAXES - OTHER PROPERTY (Account 282) (Continued)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
CHANGES DURING YEAR ADJUSTMENTS
Balance at
End of YearDebitsCreditsAmounts Debited
to Account 410.2
Amounts Credited
to Account 411.2 AccountCredited Amount DebitedAccount Amount
(e)(f)(h)(j)(k)(g)(i)
3. Use footnotes as required.
1
451,117,692 2
3
4
451,117,692 5
6
182 797,512,669 446,723182 91,705,942 7
8
1,248,630,361 446,723 91,705,942 9
10
1,071,548,840 374,733 77,748,031 11
177,081,521 71,990 13,957,911 12
13
FERC FORM NO. 1 (ED. 12-96)Page 275
NOTES (Continued)
Schedule Page: 274 Line No.: 5 Column: b

2014 Changes during Year Adj Dr Adj Cr 2014
Beginning DR to CR to DR to CR to Acct. Acct. End
Account Balance 410.1 411.1 410.2 411.2 Cr Amt Dr.Amt Bal
(a)b c d e f g h i j k
Depr Timing Diff-Oper 424,062,833 28,367,950 12,652,571 439,778,212
Intang-labor costs- Acct
107
14,385,202 2,997,709 17,382,911
CIAC-Taxable-Acct 107 (3,060,909)430,646 3,380,470 (6,010,733)
Valmy Capitalized Items 198,266 76,500 121,766
Software - labor costs 1,567,943 (1,220,847)347,096
Eng Fees in Acct 107 (316,318)185,241 (501,560)
TOTAL 436,837,016 30,575,458 16,294,782 0 0 0 0 451,117,692
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ACCUMULATED DEFFERED INCOME TAXES - OTHER (Account 283)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.Account
(a) (b) (c) (d)
Balance atBeginning of Year
CHANGES DURING YEAR
Amounts Debited Amounts Credited to Account 410.1 to Account 411.1
1. Report the information called for below concerning the respondent’s accounting for deferred income taxes relating to amounts
recorded in Account 283.
2. For other (Specify),include deferrals relating to other income and deductions.
Account 283 1
Electric 2
69,353,539 51,837,119 91,672,316Other Electric -- See Note 3
4
5
6
7
45,577,950 Other -- See Note 8
69,353,539 51,837,119 137,250,266TOTAL Electric (Total of lines 3 thru 8) 9
Gas 10
11
12
13
14
15
16
TOTAL Gas (Total of lines 11 thru 16) 17
838,607 Other -- See Note 18
69,353,539 51,837,119 138,088,873TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18) 19
Classification of TOTAL 20
58,177,498 43,483,779 115,836,413Federal Income Tax 21
11,176,041 8,353,340 22,252,460State Income Tax 22
Local Income Tax 23
FERC FORM NO. 1 (ED. 12-96)Page 276
NOTES
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ACCUMULATED DEFERRED INCOME TAXES - OTHER (Account 283) (Continued)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
CHANGES DURING YEAR ADJUSTMENTS
Balance at
End of Year
Debits CreditsAmounts Debited
to Account 410.2
Amounts Credited
to Account 411.2 AccountCredited Amount DebitedAccount Amount
(e) (f) (h) (j) (k)(g) (i)
3. Provide in the space below explanations for Page 276 and 277. Include amounts relating to insignificant items listed under Other.
4. Use footnotes as required.
1
2
74,155,896 3
4
5
6
7
103,425,257 57,847,307 8
177,581,153 57,847,307 9
10
11
12
13
14
15
16
17
851,124 68,392 80,909 18
178,432,277 57,847,307 68,392 80,909 19
20
149,678,643 48,525,449 57,371 67,871 21
28,753,634 9,321,858 11,021 13,038 22
23
FERC FORM NO. 1 (ED. 12-96)Page 277
NOTES (Continued)
Schedule Page: 276 Line No.: 3 Column: b

2014 Changes during Year Adj Dr Adj Cr 2014
Beginning DR to CR to DR to CR to Acct.Acct. End
Account Balance 410.1 411.1 410.2 411.2 Cr Amt Dr Amt Bal
(a)b c d e f g h i j k
Pension Expense 20,232,517 20,309,544 21,607,803 18,934,259
PCA Expense 33,169,456 6,656,883 18,514,891 21,311,448
Conservation Exp 1,409,026 3,426,730 3,046,288 1,789,468
Fixed Cost Adj 7,633,602 2,203,129 556,520 9,280,211
Reg Asset-Current 23,538,502 15,615,540 21,086,556 18,067,486
Oregon PCAM 2,636,947 0 694,677 1,942,270
Reg Liab-Non Current 1,826,860 2,647,701 2,556,119 1,918,442
Boardman Decommission 0 537,210 53,009 484,201
Oregon Excess Power Costs (43,430)6,432 24,889 (61,888)
OATT Revenue Deficiency 381,132 269,035 112,098
Renewable Energy Cert-sales 217,848 345,165 791,096 (228,084)
Langley Revenue Accr 331,688 19,093 350,781
Reorganization Costs 90,175 0 90,175 (0)
2011 LIDAR Surveys Def 136,378 0 17,047 119,331
Bennett Mtn Maint Def 58,554 29,277 29,277
Intervenor Funding Orders 82,837 38,507 121,344
OPUC Grid West Loans 6,472 0 5,548 925
Emission Allowances (751)9,749 5,276 3,722
Bonus Deferral (10,970)10,970 0
Delivery Accruals (24,528)10,465 5,332 (19,395)
TOTAL 91,672,316 51,837,119 69,353,539 0 0 0 0 74,155,896
Schedule Page: 276 Line No.: 8 Column: b

2014 Changes during Year Adj Dr Adj Cr 2014
Beginning DR to CR to DR to CR to Acct
.
Acct. End
Account Balance 410.1 411.1 410.2 411.2 Cr Amt Dr Amt Bal
(a)b c d e f g h i j k
Pension-FAS 158 47,394,315 190 55,677,606 103,071,921
Postretirement Plan-FAS
158
(1,816,365) 190 2,169,701 353,336
TOTAL 45,577,950 0 0 0 0 57,847307 103,425,257
Schedule Page: 276 Line No.: 18 Column: b

2014 Changes during Year Adj Dr Adj Cr 2014
Beginning DR to CR to DR to CR to Acct
.
Acct.End
Account Balance 410.1 411.1 410.2 411.2 Cr Amt Dr Amt Bal
(a)b c d e f g h i j k
EDC-Unrealized G/L from
Rabbi Trust
535,261 15,954 8,185 543,030
SMSP-Unrealized G/L
from Rabbi Trust
(22,448)40,704 60,207 (41,951)
Royalty Income 325,457 24,230 349,687
Oregon Non-Op Prop Tax
Adj
337 21 0 358
TOTAL 838,607 0 0 80,909 68,392 0 0 851,124
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
OTHER REGULATORY LIABILITIES (Account 254)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
Description and Purpose of DEBITS
CreditsAccount
(d)(c)(a)
Balance at End
of Current
Quarter/Year
(e)
Other Regulatory Liabilities Amount
(f)
Credited
1. Report below the particulars (details) called for concerning other regulatory liabilities, including rate order docket number, if applicable.
2. Minor items (5% of the Balance in Account 254 at end of period, or amounts less than $100,000 which ever is less), may be grouped
by classes.
3. For Regulatory Liabilities being amortized, show period of amortization.
Balance at Begining
of Current
Quarter/Year
(b)
1,384,229 7,425,080 1,817,027 7,857,878Market to Market Short Term - (254001) 175 1
IPUC Order #28661 2
3
288,132 977,925 63,322 753,115FAS 133 - Market to Market - (254203) 175 4
IPUC Order # 28661 5
6
50,788,060 825,696 50,814,726 852,362Unfunded Accum Def Income Tax (254966) various 7
8
6,685,745 51,643,514 -782,231 44,175,538Idaho DSM Rider (254201) various 9
Order #29026 10
11
( 3,694,183) 1,925,980 -3,907,536 1,712,627Oregon DSM Rider - (254202) various 12
Advise #05-03 13
14
1,787,012 66,751 2,400,864 680,603Oregon Solar Pilot - (254005) various 15
Order #10-198 16
17
22,807 23,584 132,831 133,608Green Tags Oregon (254415) 1823 18
Order #11-086 19
20
4,228,953 4,675,677 446,724Regulatory Unfunded Accum Def Income Tax (254419) 21
22
7,602,043 7,624,233 7,999,145 8,021,335Revenue Sharing (254101) 182 23
IPUC Order #32558 24
25
624,555 2,457,934 643,903 2,477,282BPA Credit Residential Idaho (254401) 131/400 26
Advice # 11-03 (ID) #11-15 (OR) 27
28
90,075 90,075 112,536 112,536WAQC Carryover (254901) various 29
IPUC Order #29505 30
31
489,027 809,830 320,803Bridger Depreciation #12-296 -(254800) various 32
33
80,545 575,835 63,175 558,465Minor Items (7) various 34
35
36
37
38
39
40
FERC FORM NO. 1/3-Q (REV 02-04) Page 278
41 TOTAL 68,102,876 73,636,607 64,843,269 70,377,000
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ELECTRIC OPERATING REVENUES (Account 400)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.Title of Account
(c)(b)(a)
Operating Revenues Year
to Date Quarterly/Annual
1. The following instructions generally apply to the annual version of these pages. Do not report quarterly data in columns (c), (e), (f), and (g). Unbilled revenues and 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.
Operating Revenues
Previous year (no Quarterly)
Sales of Electricity 1
513,914,273(440) Residential Sales 500,194,726 2
(442) Commercial and Industrial Sales 3
436,445,539Small (or Comm.) (See Instr. 4) 453,982,593 4
165,918,266Large (or Ind.) (See Instr. 4) 182,675,224 5
3,828,398(444) Public Street and Highway Lighting 4,133,623 6
(445) Other Sales to Public Authorities 7
(446) Sales to Railroads and Railways 8
(448) Interdepartmental Sales 9
1,120,106,476TOTAL Sales to Ultimate Consumers 1,140,986,166 10
54,472,513(447) Sales for Resale 77,164,887 11
1,174,578,989TOTAL Sales of Electricity 1,218,151,053 12
18,735,088(Less) (449.1) Provision for Rate Refunds 18,348,408 13
1,155,843,901TOTAL Revenues Net of Prov. for Refunds 1,199,802,645 14
Other Operating Revenues 15
(450) Forfeited Discounts 16
3,565,357(451) Miscellaneous Service Revenues 3,780,239 17
(453) Sales of Water and Water Power 18
24,427,455(454) Rent from Electric Property 23,695,291 19
(455) Interdepartmental Rents 20
36,377,773(456) Other Electric Revenues 27,734,886 21
21,936,382(456.1) Revenues from Transmission of Electricity of Others 22,627,916 22
(457.1) Regional Control Service Revenues 23
(457.2) Miscellaneous Revenues 24
25
86,306,967TOTAL Other Operating Revenues 77,838,332 26
1,242,150,868TOTAL Electric Operating Revenues 1,277,640,977 27
Page 300FERC FORM NO. 1/3-Q (REV. 12-05)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ELECTRIC OPERATING REVENUES (Account 400)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
MEGAWATT HOURS SOLD
Previous Year (no Quarterly)Current Year (no Quarterly)
AVG.NO. CUSTOMERS PER MONTH
Year to Date Quarterly/Annual Amount Previous year (no Quarterly)
(d) (e) (f) (g)
6. Commercial and industrial Sales, Account 442, may be classified according to the basis of classification (Small or Commercial, and Large or Industrial) regularly used 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.
1
5,365,313 418,892 425,036 4,965,076 2
3
6,040,697 83,439 84,425 5,877,580 4
3,181,866 117 116 3,217,070 5
31,478 2,205 2,380 32,641 6
7
8
9
14,619,354 504,653 511,957 14,092,367 10
1,683,327 2,220,419 11
16,302,681 504,653 511,957 16,312,786 12
13
16,302,681 504,653 511,957 16,312,786 14
Page 301
Line 12, column (b) includes $ of unbilled revenues.
Line 12, column (d) includes MWH relating to unbilled revenues
-6,191,476
-75,221
FERC FORM NO. 1/3-Q (REV. 12-05)
Schedule Page: 300 Line No.: 17 Column: b
This amount consists of:
Service Establishment/Connection Charges $2,953,981
(Includes late and after hour charges)
Misc. Under $250,000 826,258
3,780,239
Schedule Page: 300 Line No.: 21 Column: b
This amount consists of:
DSM Activity $27,153,830
Stand-by-Service 321,995
Misc. Under $250,000 259,061
27,734,886
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofIdaho Power Company X
04/15/2015 2014/Q4
Line
No.Description of Service
(a)
REGIONAL TRANSMISSION SERVICE REVENUES (Account 457.1)
1. The respondent shall report below the revenue collected for each service (i.e., control area administration, market administration, etc.)
performed pursuant to a Commission approved tariff. All amounts separately billed must be detailed below.
Balance at End of
(c)(b)
Balance at End of
Quarter 1 Quarter 2
Balance at End of
Quarter 3
(d) (e)
Balance at End of
Year
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
FERC FORM NO. 1/3-Q (NEW. 12-05) Page 302
46 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh 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.
1 440 - Residential Sales:
5,002,678 423,570 11,811 0.0981 490,769,694 2 01 - Residential
4,234 22 192,455 0.0936 396,120 3 03 - Residential Master Meter
24,949 1,444 17,278 0.0944 2,355,949 4 05 - Residential - TOD
2,670 0.2440 651,491 5 15 - Dusk to dawn lighting
-69,455 0.0859 -5,963,733 6 Unbilled Revenues
11,985,205 7 Other Revenues
4,965,076 425,036 11,682 0.1007 500,194,726 8 Total 440
9
10 442-Commercial & Industrial Sales
151,333 30,433 4,973 0.1203 18,212,254 11 07 - General service
475,373 208 2,285,447 0.0644 30,601,202 12 09P - General service
3,282,762 33,227 98,798 0.0732 240,216,057 13 09S - General service
6,268 4 1,567,000 0.0718 449,941 14 09T - General service
4,144 0.1793 742,891 15 15 - Dusk to Dawn Light
2,236,085 109 20,514,541 0.0577 129,042,450 16 19P - Uniform rate contracts
6,279 1 6,279,000 0.0642 403,268 17 19S - Uniform rate contracts
120,445 3 40,148,333 0.0589 7,091,329 18 19T - Uniform rate contracts
1,966,297 19,692 99,853 0.0791 155,477,335 19 24S - Irrigation Pumping
10,526 861 12,225 0.0862 907,059 20 40 - General service
841,166 3 280,388,667 0.0503 42,295,181 21 Special Contracts
-6,028 0.0434 -261,363 22 Commercial & Industrial Unbill
11,480,213 23 Other Revenues
9,094,650 84,541 107,577 0.0700 636,657,817 24 Total 442
25
26 444 - Public Street Lighting:
1,120 450 2,489 0.0864 96,802 27 40 - General service
28,403 1,450 19,588 0.1322 3,753,574 28 41 - Street lighting
2,856 480 5,950 0.0630 179,973 29 42 - Traffic control lighting
262 0.1283 33,620 30 Unbilled
69,654 31 Other Revenues
32,641 2,380 13,715 0.1266 4,133,623 32 Total 444
33
34
35
36
37
38
39
40
14,092,367 1,140,986,166 511,957 27,526 0.0810
-75,221 -6,191,476 0 0 0.0823
14,167,588 1,147,177,642 511,957 27,673 0.0810
FERC FORM NO. 1 (ED. 12-95) Page 304
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average AverageMonthly NCP Demand Monthly CP Demand
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than 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.
Arizona Public Service Co.n/an/an/aWSPPSF 1
Avista Corp.n/an/an/aWSPPSF 2
Avista Corp.n/an/an/aWSPPOS 3
Black Hills Power Inc.n/an/an/aWSPPSF 4
Black Hills Power Inc.n/an/an/aWSPPOS 5
Bonneville Power Administration n/an/an/aWSPPSF 6
BP Energy Company n/an/an/aWSPPSF 7
Cargill Power Markets LLC n/an/an/aWSPPOS 8
Cargill Power Markets LLC n/an/an/aWSPPOS 9
Cargill Power Markets LLC n/an/an/a-OS 10
Cargill Power Markets LLC n/an/an/aWSPPSF 11
Chelan County PUD n/an/an/aWSPPSF 12
Citigroup Energy Inc.n/an/an/aWSPPSF 13
Citigroup Energy Inc.n/an/an/a-OS 14
FERC FORM NO. 1 (ED. 12-90) Page 310
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average AverageMonthly NCP Demand Monthly CP Demand
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than 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.
City of Glendale n/an/an/aWSPPSF 1
Clatskanie PUD n/an/an/aWSPPSF 2
EDF Trading North America, LLC n/an/an/aWSPPSF 3
EDF Trading North America, LLC n/an/an/aWSPPOS 4
Eugene Electric Board n/an/an/aWSPPSF 5
Exelon Generation Company. LLC n/an/an/aWSPPSF 6
Grant County Public Utility District #2 n/an/an/aWSPPSF 7
IBERDROLA RENEWABLES, Inc.n/an/an/aWSPPOS 8
IBERDROLA RENEWABLES, Inc.n/an/an/aWSPPSF 9
IBERDROLA RENEWABLES, Inc.n/an/an/aWSPPOS 10
J. Aron & Company n/an/an/aWSPPSF 11
Jeffries Bache n/an/an/a-OS 12
Los Angeles Department of Water & Power n/an/an/aWSPPSF 13
Macquarie Energy LLC n/an/an/aWSPPOS 14
FERC FORM NO. 1 (ED. 12-90) Page 310.1
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average AverageMonthly NCP Demand Monthly CP Demand
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than 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.
Morgan Stanley Capital Group Inc.n/an/an/aWSPPSF 1
Morgan Stanley Capital Group Inc.n/an/an/aWSPPOS 2
Morgan Stanley Capital Group Inc.n/an/an/aWSPPOS 3
Nevada Power Company, dba NVEnergy n/an/an/aWSPPOS 4
Nevada Power Company, dba NVEnergy n/an/an/aWSPPSF 5
Nevada Power Company, dba NVEnergy n/an/an/aWSPPOS 6
NorthWestern Energy n/an/an/aWSPPSF 7
PacifiCorp Inc.n/an/an/aWSPPSF 8
PacifiCorp Inc.n/an/an/aT-7OS 9
Portland General Electric Company n/an/an/aWSPPOS 10
Platte River Power Authority n/an/an/aWSPPSF 11
Portland General Electric Company n/an/an/aWSPPSF 12
Powerex Corp.n/an/an/aWSPPOS 13
Powerex Corp.n/an/an/aWSPPSF 14
FERC FORM NO. 1 (ED. 12-90) Page 310.2
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average AverageMonthly NCP Demand Monthly CP Demand
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than 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.
PPL EnergyPlus, LLC n/an/an/aWSPPOS 1
PPL EnergyPlus, LLC n/an/an/aWSPPSF 2
Public Service Company of New Mexico n/an/an/aWSPPSF 3
Puget Sound Energy, Inc.n/an/an/aWSPPSF 4
Rainbow Energy Marketing Corporation n/an/an/aWSPPOS 5
Rainbow Energy Marketing Corporation n/an/an/aWSPPSF 6
Seattle City Light n/an/an/aWSPPOS 7
Seattle City Light n/an/an/aWSPPSF 8
Shell Energy North America (US), L.P.n/an/an/aWSPPOS 9
Shell Energy North America (US), L.P.n/an/an/aWSPPSF 10
Sierra Pacific Power Co., dba NV Energy n/an/an/aT-7OS 11
Sierra Pacific Power Co., dba NV Energy n/an/an/aWSPPOS 12
Sierra Pacific Power Co., dba NV Energy n/an/an/aWSPPSF 13
Snohomish County PUD n/an/an/aWSPPSF 14
FERC FORM NO. 1 (ED. 12-90) Page 310.3
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average AverageMonthly NCP Demand Monthly CP Demand
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than 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.
Southern Cal Edison n/an/an/aWSPPOS 1
Tenaska Power Services Co.n/an/an/aWSPPOS 2
Tenaska Power Services Co.n/an/an/aWSPPSF 3
The Energy Authority, Inc.n/an/an/aWSPPOS 4
The Energy Authority, Inc.n/an/an/aWSPPSF 5
TransAlta Energy Marketing (U.S.) Inc.n/an/an/aWSPPOS 6
TransAlta Energy Marketing (U.S.) Inc.n/an/an/aWSPPSF 7
Tucson Electric Power Company n/an/an/aWSPPSF 8
Prior Year Adjustments n/an/an/a-AD 9
Prior Year Write Off Recovered n/an/an/a-AD 10
Oatt Rate Refund n/an/an/a-AD 11
Transmission Penalty Distribution n/an/an/a-AD 12
13
14
FERC FORM NO. 1 (ED. 12-90) Page 310.4
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447) (Continued)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)Total ($)REVENUE
($)($)($)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as 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.
152,680 152,680 6,120 1
13,140,061 13,140,061 335,232 2
2,175 2,175 87 3
37,486 37,486 840 4
19 19 5
5,521,287 5,521,287 164,019 6
72,661 72,661 2,800 7
110,968 110,968 8
624 624 24 9
-139,784 -139,784 10
371,629 371,629 14,283 11
245 12
2,450 2,450 56 13
-204,360 -204,360 14
FERC FORM NO. 1 (ED. 12-90) Page 311
0
75,567,752
75,567,752
0
2,220,419
2,220,419
0 0
1,597,135
1,597,135
77,164,887
77,164,887
0
0
0
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447) (Continued)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)Total ($)REVENUE
($)($)($)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as 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.
4,136,386 4,136,386 90,000 1
5,780 5,780 171 2
618,450 618,450 14,214 3
310,492 310,492 4
178,749 178,749 4,968 5
4,554,931 4,554,931 136,951 6
774,364 774,364 24,237 7
52,800 52,800 8
291,316 291,316 8,682 9
10
1,772 1,772 38 11
-2,792,018 -2,792,018 12
7,874,193 7,874,193 199,100 13
-1,266,434 -1,266,434 14
FERC FORM NO. 1 (ED. 12-90) Page 311.1
0
75,567,752
75,567,752
0
2,220,419
2,220,419
0 0
1,597,135
1,597,135
77,164,887
77,164,887
0
0
0
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447) (Continued)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)Total ($)REVENUE
($)($)($)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as 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.
2,537,545 2,537,545 80,777 1
480 480 20 2
448,193 448,193 3
32,446 32,446 4
3,587,355 3,587,355 133,404 5
16,320 16,320 480 6
1,733,573 1,733,573 34,795 7
866,793 866,793 23,423 8
2,217 2,217 69 9
38,873 38,873 10
935 935 17 11
2,494,290 2,494,290 67,585 12
17,831 17,831 785 13
1,369,537 1,369,537 48,415 14
FERC FORM NO. 1 (ED. 12-90) Page 311.2
0
75,567,752
75,567,752
0
2,220,419
2,220,419
0 0
1,597,135
1,597,135
77,164,887
77,164,887
0
0
0
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447) (Continued)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)Total ($)REVENUE
($)($)($)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as 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.
40,180 40,180 1
336,618 336,618 9,363 2
3,200 3,200 100 3
519,293 519,293 12,478 4
15,593 15,593 5
1,452,174 1,452,174 49,536 6
6,450 6,450 215 7
622,449 622,449 17,638 8
754,958 754,958 9
9,244,324 9,244,324 265,522 10
1,819 1,819 49 11
3,715 3,715 12
24,550 24,550 800 13
13,280 13,280 430 14
FERC FORM NO. 1 (ED. 12-90) Page 311.3
0
75,567,752
75,567,752
0
2,220,419
2,220,419
0 0
1,597,135
1,597,135
77,164,887
77,164,887
0
0
0
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447) (Continued)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)Total ($)REVENUE
($)($)($)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as 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.
735 735 1
10,950 10,950 2
514,208 514,208 20,513 3
3,373 3,373 4
15,851,245 15,851,245 427,455 5
72,656 72,656 6
680,341 680,341 23,727 7
26,035 26,035 754 8
2 9
10,822 10,822 10
-2,523 -2,523 11
3,377 3,377 12
13
14
FERC FORM NO. 1 (ED. 12-90) Page 311.4
0
75,567,752
75,567,752
0
2,220,419
2,220,419
0 0
1,597,135
1,597,135
77,164,887
77,164,887
0
0
0
Schedule Page: 310 Line No.: 3 Column: b
Non-firm Sales
Schedule Page: 310 Line No.: 5 Column: b
Financial Transmission Losses
Schedule Page: 310 Line No.: 8 Column: b
Financial Transmission Losses
Schedule Page: 310 Line No.: 9 Column: b
Non-firm Sales
Schedule Page: 310 Line No.: 10 Column: b
ISDA Master Agreement with Cargill Power Markets LLC, dated June 13, 2011
Schedule Page: 310 Line No.: 14 Column: b
ISDA Master Agreement with Citigroup Energy, Inc., dated March 7, 2011
Schedule Page: 310.1 Line No.: 4 Column: b
ISDA Master Agreement with EDF Trading North America, LLC, dated October 25, 2012.
Schedule Page: 310.1 Line No.: 8 Column: b
Financial Transmission Losses
Schedule Page: 310.1 Line No.: 10 Column: b
Non-firm Sales
Schedule Page: 310.1 Line No.: 12 Column: b
Prudential Bache Commodities (Jeffries Bache), LLC Futures Account Document, dated September 4, 2008
Schedule Page: 310.1 Line No.: 14 Column: b
ISDA Master Agreement with Macquarie Energy, LLC dated April 12, 2011
Schedule Page: 310.2 Line No.: 2 Column: b
Non-firm Sales
Schedule Page: 310.2 Line No.: 3 Column: b
Financial Transmission Losses
Schedule Page: 310.2 Line No.: 4 Column: b
Financial Transmission Losses
Schedule Page: 310.2 Line No.: 6 Column: b
Unit Contingent Sales
Schedule Page: 310.2 Line No.: 9 Column: b
Spinning or Operating Reserves
Schedule Page: 310.2 Line No.: 10 Column: b
Financial Transmission Losses
Schedule Page: 310.2 Line No.: 13 Column: b
Non-firm Sales
Schedule Page: 310.3 Line No.: 1 Column: b
Financial Transmission Losses
Schedule Page: 310.3 Line No.: 5 Column: b
Financial Transmission Losses
Schedule Page: 310.3 Line No.: 7 Column: b
Non-firm Sales
Schedule Page: 310.3 Line No.: 9 Column: b
Financial Transmission Losses
Schedule Page: 310.3 Line No.: 11 Column: b
Spinning or Operating Reserves
Schedule Page: 310.3 Line No.: 12 Column: b
Financial Transmission Losses
Schedule Page: 310.4 Line No.: 1 Column: b
Financial Transmission Losses
Schedule Page: 310.4 Line No.: 2 Column: b
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Financial Transmission Losses
Schedule Page: 310.4 Line No.: 4 Column: b
Financial Transmission Losses
Schedule Page: 310.4 Line No.: 6 Column: b
Financial Transmission Losses
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofIdaho Power Company X
04/15/2015 2014/Q4
Line
No.
Account Amount for
(c)(b)(a)Current Year Previous YearAmount for
If the amount for previous year is not derived from previously reported figures, explain in footnote.
1. POWER PRODUCTION EXPENSES 1
A. Steam Power Generation 2
Operation 3
(500) Operation Supervision and Engineering 4 1,524,957 1,376,709
(501) Fuel 5 160,276,741 156,172,175
(502) Steam Expenses 6 8,840,885 8,741,266
(503) Steam from Other Sources 7
(Less) (504) Steam Transferred-Cr. 8
(505) Electric Expenses 9 1,741,112 1,599,507
(506) Miscellaneous Steam Power Expenses 10 9,473,766 9,598,723
(507) Rents 11 348,322 530,520
(509) Allowances 12
TOTAL Operation (Enter Total of Lines 4 thru 12) 13 182,205,783 178,018,900
Maintenance 14
(510) Maintenance Supervision and Engineering 15 101,619 277,886
(511) Maintenance of Structures 16 637,844 708,308
(512) Maintenance of Boiler Plant 17 12,461,886 10,923,064
(513) Maintenance of Electric Plant 18 5,398,984 6,044,954
(514) Maintenance of Miscellaneous Steam Plant 19 4,541,443 5,806,415
TOTAL Maintenance (Enter Total of Lines 15 thru 19) 20 23,141,776 23,760,627
TOTAL Power Production Expenses-Steam Power (Entr Tot lines 13 & 20) 21 205,347,559 201,779,527
B. Nuclear Power Generation 22
Operation 23
(517) Operation Supervision and Engineering 24
(518) Fuel 25
(519) Coolants and Water 26
(520) Steam Expenses 27
(521) Steam from Other Sources 28
(Less) (522) Steam Transferred-Cr. 29
(523) Electric Expenses 30
(524) Miscellaneous Nuclear Power Expenses 31
(525) Rents 32
TOTAL Operation (Enter Total of lines 24 thru 32) 33
Maintenance 34
(528) Maintenance Supervision and Engineering 35
(529) Maintenance of Structures 36
(530) Maintenance of Reactor Plant Equipment 37
(531) Maintenance of Electric Plant 38
(532) Maintenance of Miscellaneous Nuclear Plant 39
TOTAL Maintenance (Enter Total of lines 35 thru 39) 40
TOTAL Power Production Expenses-Nuc. Power (Entr tot lines 33 & 40) 41
C. Hydraulic Power Generation 42
Operation 43
(535) Operation Supervision and Engineering 44 6,034,727 5,700,460
(536) Water for Power 45 5,679,423 7,316,134
(537) Hydraulic Expenses 46 13,572,536 14,097,825
(538) Electric Expenses 47 1,432,669 1,530,453
(539) Miscellaneous Hydraulic Power Generation Expenses 48 4,855,798 5,732,591
(540) Rents 49 141,597 259,705
TOTAL Operation (Enter Total of Lines 44 thru 49) 50 31,716,750 34,637,168
C. Hydraulic Power Generation (Continued) 51
Maintenance 52
(541) Mainentance Supervision and Engineering 53 83,805 122,182
(542) Maintenance of Structures 54 1,427,309 1,387,369
(543) Maintenance of Reservoirs, Dams, and Waterways 55 1,148,299 366,307
(544) Maintenance of Electric Plant 56 2,617,210 2,279,584
(545) Maintenance of Miscellaneous Hydraulic Plant 57 3,005,680 2,554,638
TOTAL Maintenance (Enter Total of lines 53 thru 57) 58 8,282,303 6,710,080
TOTAL Power Production Expenses-Hydraulic Power (tot of lines 50 & 58) 59 39,999,053 41,347,248
FERC FORM NO. 1 (ED. 12-93) Page 320
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofIdaho Power Company X
04/15/2015 2014/Q4
Line
No.
Account Amount for
(c)(b)(a)Current Year Previous YearAmount for
If the amount for previous year is not derived from previously reported figures, explain in footnote.
D. Other Power Generation 60
Operation 61
(546) Operation Supervision and Engineering 62 1,360,914 813,875
(547) Fuel 63 54,204,949 45,068,831
(548) Generation Expenses 64 3,427,130 3,596,219
(549) Miscellaneous Other Power Generation Expenses 65 585,699 905,574
(550) Rents 66
TOTAL Operation (Enter Total of lines 62 thru 66) 67 59,578,692 50,384,499
Maintenance 68
(551) Maintenance Supervision and Engineering 69 99
(552) Maintenance of Structures 70 301,287 378,067
(553) Maintenance of Generating and Electric Plant 71 131,162 86,516
(554) Maintenance of Miscellaneous Other Power Generation Plant 72 1,233,983 1,391,428
TOTAL Maintenance (Enter Total of lines 69 thru 72) 73 1,666,531 1,856,011
TOTAL Power Production Expenses-Other Power (Enter Tot of 67 & 73) 74 61,245,223 52,240,510
E. Other Power Supply Expenses 75
(555) Purchased Power 76 214,941,823 237,121,899
(556) System Control and Load Dispatching 77 1,403,451 -1,242
(557) Other Expenses 78 -34,629,989 25,139,587
TOTAL Other Power Supply Exp (Enter Total of lines 76 thru 78) 79 181,715,285 262,260,244
TOTAL Power Production Expenses (Total of lines 21, 41, 59, 74 & 79) 80 488,307,120 557,627,529
2. TRANSMISSION EXPENSES 81
Operation 82
(560) Operation Supervision and Engineering 83 3,560,221 4,019,284
84
(561.1) Load Dispatch-Reliability 85 39,635 55,425
(561.2) Load Dispatch-Monitor and Operate Transmission System 86 1,702,334 1,673,701
(561.3) Load Dispatch-Transmission Service and Scheduling 87 1,036,729 926,555
(561.4) Scheduling, System Control and Dispatch Services 88
(561.5) Reliability, Planning and Standards Development 89
(561.6) Transmission Service Studies 90
(561.7) Generation Interconnection Studies 91 94,561 38,422
(561.8) Reliability, Planning and Standards Development Services 92
(562) Station Expenses 93 2,403,457 2,458,270
(563) Overhead Lines Expenses 94 732,402 669,240
(564) Underground Lines Expenses 95
(565) Transmission of Electricity by Others 96 5,637,278 6,081,299
(566) Miscellaneous Transmission Expenses 97 49,579 18,274
(567) Rents 98 2,917,528 3,284,850
TOTAL Operation (Enter Total of lines 83 thru 98) 99 18,173,724 19,225,320
Maintenance 100
(568) Maintenance Supervision and Engineering 101 323,417 169,505
(569) Maintenance of Structures 102 7,617 26,645
(569.1) Maintenance of Computer Hardware 103 7,491 9,454
(569.2) Maintenance of Computer Software 104 734,188 960,142
(569.3) Maintenance of Communication Equipment 105 4,564 42,031
(569.4) Maintenance of Miscellaneous Regional Transmission Plant 106
(570) Maintenance of Station Equipment 107 3,610,183 3,702,550
(571) Maintenance of Overhead Lines 108 3,588,427 3,198,420
(572) Maintenance of Underground Lines 109
(573) Maintenance of Miscellaneous Transmission Plant 110 607 1,593
TOTAL Maintenance (Total of lines 101 thru 110) 111 8,276,494 8,110,340
TOTAL Transmission Expenses (Total of lines 99 and 111) 112 26,450,218 27,335,660
FERC FORM NO. 1 (ED. 12-93) Page 321
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofIdaho Power Company X
04/15/2015 2014/Q4
Line
No.
Account Amount for
(c)(b)(a)Current Year Previous YearAmount for
If the amount for previous year is not derived from previously reported figures, explain in footnote.
3. REGIONAL MARKET EXPENSES 113
Operation 114
(575.1) Operation Supervision 115
(575.2) Day-Ahead and Real-Time Market Facilitation 116
(575.3) Transmission Rights Market Facilitation 117
(575.4) Capacity Market Facilitation 118
(575.5) Ancillary Services Market Facilitation 119
(575.6) Market Monitoring and Compliance 120
(575.7) Market Facilitation, Monitoring and Compliance Services 121
(575.8) Rents 122
Total Operation (Lines 115 thru 122) 123
Maintenance 124
(576.1) Maintenance of Structures and Improvements 125
(576.2) Maintenance of Computer Hardware 126
(576.3) Maintenance of Computer Software 127
(576.4) Maintenance of Communication Equipment 128
(576.5) Maintenance of Miscellaneous Market Operation Plant 129
Total Maintenance (Lines 125 thru 129) 130
TOTAL Regional Transmission and Market Op Expns (Total 123 and 130) 131
4. DISTRIBUTION EXPENSES 132
Operation 133
(580) Operation Supervision and Engineering 134 4,160,840 4,028,859
(581) Load Dispatching 135 3,529,347 3,643,133
(582) Station Expenses 136 1,375,049 1,180,321
(583) Overhead Line Expenses 137 3,111,427 3,138,798
(584) Underground Line Expenses 138 2,402,213 2,525,008
(585) Street Lighting and Signal System Expenses 139 74,337 76,902
(586) Meter Expenses 140 4,421,678 4,424,696
(587) Customer Installations Expenses 141 673,959 694,859
(588) Miscellaneous Expenses 142 5,754,224 5,788,865
(589) Rents 143 366,175 466,127
TOTAL Operation (Enter Total of lines 134 thru 143) 144 25,869,249 25,967,568
Maintenance 145
(590) Maintenance Supervision and Engineering 146 168,884 16,451
(591) Maintenance of Structures 147
(592) Maintenance of Station Equipment 148 3,816,291 3,950,824
(593) Maintenance of Overhead Lines 149 14,492,291 13,906,165
(594) Maintenance of Underground Lines 150 645,600 630,375
(595) Maintenance of Line Transformers 151 286,874 148,125
(596) Maintenance of Street Lighting and Signal Systems 152 536,040 531,740
(597) Maintenance of Meters 153 750,543 735,448
(598) Maintenance of Miscellaneous Distribution Plant 154 412,978 418,635
TOTAL Maintenance (Total of lines 146 thru 154) 155 21,109,501 20,337,763
TOTAL Distribution Expenses (Total of lines 144 and 155) 156 46,978,750 46,305,331
5. CUSTOMER ACCOUNTS EXPENSES 157
Operation 158
(901) Supervision 159 491,363 503,846
(902) Meter Reading Expenses 160 1,484,232 1,698,642
(903) Customer Records and Collection Expenses 161 14,060,136 16,630,398
(904) Uncollectible Accounts 162 5,805,414 6,715,796
(905) Miscellaneous Customer Accounts Expenses 163 271 95
TOTAL Customer Accounts Expenses (Total of lines 159 thru 163) 164 21,841,416 25,548,777
FERC FORM NO. 1 (ED. 12-93) Page 322
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofIdaho Power Company X
04/15/2015 2014/Q4
Line
No.
Account Amount for
(c)(b)(a)Current Year Previous YearAmount for
If the amount for previous year is not derived from previously reported figures, explain in footnote.
6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES 165
Operation 166
(907) Supervision 167 531,496 593,673
(908) Customer Assistance Expenses 168 42,690,734 34,149,782
(909) Informational and Instructional Expenses 169 264,701 374,524
(910) Miscellaneous Customer Service and Informational Expenses 170 574,875 696,365
TOTAL Customer Service and Information Expenses (Total 167 thru 170) 171 44,061,806 35,814,344
7. SALES EXPENSES 172
Operation 173
(911) Supervision 174
(912) Demonstrating and Selling Expenses 175
(913) Advertising Expenses 176
(916) Miscellaneous Sales Expenses 177
TOTAL Sales Expenses (Enter Total of lines 174 thru 177) 178
8. ADMINISTRATIVE AND GENERAL EXPENSES 179
Operation 180
(920) Administrative and General Salaries 181 69,143,869 73,163,837
(921) Office Supplies and Expenses 182 17,610,990 17,437,094
(Less) (922) Administrative Expenses Transferred-Credit 183 26,882,864 27,257,584
(923) Outside Services Employed 184 5,271,865 4,705,146
(924) Property Insurance 185 3,673,489 3,461,411
(925) Injuries and Damages 186 5,694,399 6,125,055
(926) Employee Pensions and Benefits 187 62,531,128 61,971,169
(927) Franchise Requirements 188
(928) Regulatory Commission Expenses 189 3,975,664 3,457,838
(929) (Less) Duplicate Charges-Cr. 190
(930.1) General Advertising Expenses 191 496,936 453,160
(930.2) Miscellaneous General Expenses 192 4,246,371 4,907,415
(931) Rents 193 6,536 176
TOTAL Operation (Enter Total of lines 181 thru 193) 194 145,768,383 148,424,717
Maintenance 195
(935) Maintenance of General Plant 196 5,252,115 7,508,482
TOTAL Administrative & General Expenses (Total of lines 194 and 196) 197 151,020,498 155,933,199
TOTAL Elec Op and Maint Expns (Total 80,112,131,156,164,171,178,197) 198 778,659,808 848,564,840
FERC FORM NO. 1 (ED. 12-93) Page 323
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing 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.
N/AN/AN/AAgPower Jerome / Double A Digester -LU 1
.488MwAllan Ravenscroft/Malad River -LU 2
N/AN/AN/ABannock County, Idaho -LU 3
N/AN/AN/ABennett Creek Wind Farm -LU 4
N/AN/AN/ABettencourt DryCreek Biofactory -LU 5
N/AN/AN/ABig Sky West Dairy Digester -LU 6
Big Wood Canal Company - 7
N/AN/AN/A Black Canyon #3 -LU 8
N/AN/AN/A Jim Knight -LU 9
N/AN/AN/A Sagebrush -LU 10
N/AN/AN/ABlind Canyon Hydro -LU 11
N/AN/AN/ABranchflower/Trout Company -LU 12
N/AN/AN/ABurley Butte Wind Park -LU 13
N/AN/AN/ABypass Limited -LU 14
FERC FORM NO. 1 (ED. 12-90) Page 326
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing 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.
N/AN/AN/ACamp Reed Wind Park -LU 1
N/AN/AN/ACargill Inc./B6 Anaerobic Digester -LU 2
N/AN/AN/ACassia Wind Farm -LU 3
N/AN/AN/ACity of Cove, Oregon / Mill Creek -LU 4
N/AN/AN/ACity of Hailey -LU 5
N/AN/AN/ACity of Pocatello -LU 6
N/AN/AN/AClear Springs Food Inc. -LU 7
.05MwClifton E. Jenson/Birch Creek -LU 8
N/AN/AN/ACold Springs Windfarm, LLC -LU 9
Consolidated Hydro Inc. / Enel - 10
N/AN/AN/A Barber Dam -LU 11
N/AN/AN/A Dietrich Drop -LU 12
N/AN/AN/A GeoBon #2 -LU 13
N/AN/AN/A Lowline #2 -LU 14
FERC FORM NO. 1 (ED. 12-90) Page 326.1
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing 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.
N/AN/AN/A Rock Creek #2 -LU 1
N/AN/AN/AContractors Power Group Inc./Mile 28 -LU 2
N/AN/AN/ACrystal Springs Hydro -LU 3
.084MwCurry Cattle Company -LU 4
N/AN/AN/ADavid McCollum/Canyon Springs -LU 5
N/AN/AN/ADavid R Snedigar -LU 6
N/AN/AN/ADesert Meadow Wind Farm -LU 7
N/AN/AN/AEightmile Hydro Corp -LU 8
N/AN/AN/AFaulkner Brothers Hydro Inc. -LU 9
N/AN/AN/AFisheries Development -OS 10
N/AN/AN/AFossil Gulch Wind -LU 11
N/AN/AN/AG2 Energy Hidden Hollow -LU 12
N/AN/AN/AGolden Valley Wind Park -LU 13
N/AN/AN/AHammett Hill Windfarm, LLC -LU 14
FERC FORM NO. 1 (ED. 12-90) Page 326.2
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing 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.
N/AN/AN/AHazelton B Power Company -LU 1
N/AN/AN/AHigh Mesa Energy -LU 2
N/AN/AN/AH.K. Hydro Mud Creek S & S -LU 3
N/AN/AN/AHorseshoe Bend Hydro -LU 4
N/AN/AN/AHorseshoe Bend Wind/United Materials -LU 5
N/AN/AN/AHot Springs Wind Farm --LU 6
N/AN/AN/AIdaho Winds / Sawtooth Wind Project -LU 7
N/AN/AN/AJ R Simplot Co. -LU 8
N/AN/AN/AJ.M. Miller/Sahko Hydro -LU 9
N/AN/AN/AJames B. Howell / CHI Elk Creek -LU 10
N/AN/AN/AJohn R LeMoyne --LU 11
N/AN/AN/AKasel & Witherspoon -LU 12
N/AN/AN/AKootenai Electric Cooperative / Fighti -LU 13
N/AN/AN/AKoyle Hydro Inc. -LU 14
FERC FORM NO. 1 (ED. 12-90) Page 326.3
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing 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.
N/AN/AN/ALateral 10 Ventures -LU 1
N/AN/AN/ALemhi Hydro Power Co./Schaffner -LU 2
N/AN/AN/ALime Wind -LU 3
N/AN/AN/ALittle Mac Power Co./Cedar Draw -LU 4
N/AN/AN/ALittle Wood River Irrigation District -LU 5
N/AN/AN/AMagic Reservoir Hydro -LU 6
N/AN/AN/AMainline Windfarm -LU 7
N/AN/AN/AMarco Rancher's Irrigation Inc. -LU 8
N/AN/AN/AMarysville Hydro Partners/Falls River -LU 9
N/AN/AN/AMilner Dam Wind Park -LU 10
N/AN/AN/AMud Creek White Hydro, Inc -LU 11
N/AN/AN/ANew Energy One / Rock Creek Dairy -LU 12
N/AN/AN/AOregon Trail Wind Park -LU 13
Owyhee Irrigation District 14
FERC FORM NO. 1 (ED. 12-90) Page 326.4
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing 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.
N/AN/AN/A Mitchell Butte -LU 1
N/AN/AN/A Owyhee Dam -LU 2
N/AN/AN/APaynes Ferry Wind Park -LU 3
1.389Pigeon Cove Power -LU 4
N/AN/AN/APilgrim Stage Station Wind Park -LU 5
N/AN/AN/APristine Springs Inc #1 -LU 6
N/AN/AN/APristine Springs Inc. #3 -LU 7
N/AN/AN/AReynolds Irrigation District -LU 8
Richard Kaster 9
N/AN/AN/A Box Canyon -LU 10
N/AN/AN/A Briggs Creek -LU 11
N/AN/AN/ARiverside Hydro/Mora Drop -LU 12
Riverside Investments 13
N/AN/AN/A Arena Drop -LU 14
FERC FORM NO. 1 (ED. 12-90) Page 326.5
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing 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.
N/AN/AN/A Fargo Drop -LU 1
1.732MwRock Creek #1 Joint Venture -LU 2
N/AN/AN/ARockland Wind Project -LU 3
N/AN/AN/ARupert Cogeneration Partners/Magic Val -LU 4
N/AN/AN/ARyegrass Windfarm -LU 5
N/AN/AN/ASalmon Falls Wind Park -LU 6
N/AN/AN/ASE Hazelton A LP -LU 7
Shorock Hydro Inc. 8
N/AN/AN/A Shoshone CSPP -LU 9
N/AN/AN/A Shoshone #2 -LU 10
N/AN/AN/ASnake River Pottery -LU 11
N/AN/AN/ASouth Forks Joint Venture/Lowline Cana -LU 12
4.942MwTamarack Energy Partnership -LU 13
N/AN/AN/ATasco - Nampa -OS 14
FERC FORM NO. 1 (ED. 12-90) Page 326.6
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing 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.
N/AN/AN/ATasco - Twin Falls -OS 1
N/AN/AN/ATed S. Sorenson/Tiber Dam -LU 2
N/AN/AN/AThousand Springs Wind Park -LU 3
N/AN/AN/ATuana Gulch Wind Park -LU 4
N/AN/AN/ATuana Springs Expansion -LU 5
N/AN/AN/ATwin Falls Energy/Lowline Midway Hydro -LU 6
N/AN/AN/ATwo Ponds Windfarm -LU 7
N/AN/AN/AWhite Water Ranch -LU 8
N/AN/AN/AWilliam Arkoosh/Littlewood -LU 9
N/AN/AN/AWillis and Betty Deveny/Shingle Creek -LF 10
N/AN/AN/AWilson Power Company -LU 11
N/AN/AN/AYahoo Creek Wind Park -LU 12
N/AN/AN/APrior Period Overpayment Recovery -OS 13
Scheduling Deviation -OS 14
FERC FORM NO. 1 (ED. 12-90) Page 326.7
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing 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.
Other Purchased Power 1
N/AN/AN/AArizona Public Service Co. WSPPSF 2
N/AN/AN/AAvista Corp. T-12OS 3
N/AN/AN/AAvista Corp. WSPPSF 4
N/AN/AN/AAvista Corp. WSPPOS 5
N/AN/AN/ABlack Hills Power Inc. WSPPSF 6
N/AN/AN/ABonneville Power Administration WSPPOS 7
N/AN/AN/ABonneville Power Administration WSPPOS 8
N/AN/AN/ABonneville Power Administration WSPPSF 9
N/AN/AN/ABP Energy Company WSPPSF 10
N/AN/AN/ACalpine Energy Services, L.P. WSPPSF 11
N/AN/AN/ACargill Power Markets LLC WSPPSF 12
N/AN/AN/AChelan Co PUD WSPPOS 13
N/AN/AN/ACitigroup Energy Inc. WSPPSF 14
FERC FORM NO. 1 (ED. 12-90) Page 326.8
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing 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.
N/AN/AN/ACitigroup Energy Inc. -OS 1
N/AN/AN/ACity of Glendale WSPPSF 2
N/AN/AN/AClatskanie PUD WSPPSF 3
N/AN/AN/AConstellation Energy Control and Dispa WSPPOS 4
N/AN/AN/AEDF Trading North America, LLC WSPPSF 5
N/AN/AN/AEugene Water & Electric Board WSPPSF 6
N/AN/AN/AExelon Generation Company, LLC WSPPSF 7
N/AN/AN/AGrant CO Public Utility District #2 -- WSPPOS 8
N/AN/AN/AGrant CO Public Utility District #2 -- WSPPSF 9
N/AN/AN/AIBERDROLA RENEWABLES, Inc. WSPPSF 10
N/AN/AN/AJ. Aron & Company WSPPSF 11
N/AN/AN/AJ.P. Morgan Ventures Energy Corporatio WSPPSF 12
N/AN/AN/AJefferies Bache -OS 13
N/AN/AN/ALos Angeles Dept of Water & Power - En WSPPSF 14
FERC FORM NO. 1 (ED. 12-90) Page 326.9
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing 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.
N/AN/AN/AMunicipal Energy Agency of Nebraska WSPPSF 1
N/AN/AN/AMorgan Stanley Capital Group Inc. ISDASF 2
N/AN/AN/ANevada Power Company, DBA NV Energy WSPPSF 3
N/AN/AN/ANorthWestern Energy T-7OS 4
N/AN/AN/ANorthWestern Energy WSPPSF 5
N/AN/AN/APacifiCorp Inc. T-13OS 6
N/AN/AN/APacifiCorp Inc. WSPPSF 7
N/AN/AN/APacifiCorp Inc. WSPPOS 8
N/AN/AN/APortland General Electric Company T-14OS 9
N/AN/AN/APortland General Electric Company WSPPSF 10
N/AN/AN/APowerex Corp. WSPPSF 11
N/AN/AN/APPL EnergyPlus, LLC WSPPSF 12
N/AN/AN/APPL EnergyPlus, LLC WSPPOS 13
N/AN/AN/APublic Service Company of New Mexico WSPPSF 14
FERC FORM NO. 1 (ED. 12-90) Page 326.10
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing 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.
N/AN/AN/APuget Sound Energy, Inc. T-9OS 1
N/AN/AN/APuget Sound Energy, Inc. WSPPSF 2
N/AN/AN/ARainbow Energy Marketing Corporation WSPPSF 3
N/AN/AN/ASalt River Project WSPPSF 4
N/AN/AN/ASeattle City Light WSPPOS 5
N/AN/AN/ASeattle City Light WSPPOS 6
N/AN/AN/ASeattle City Light WSPPSF 7
N/AN/AN/AShell Energy North America (US), L.P. WSPPSF 8
N/AN/AN/ASierra Pacific Power Co., dba NV Energ T-55OS 9
N/AN/AN/ASnohomish County PUD WSPPSF 10
N/AN/AN/ATacoma Power WSPPOS 11
N/AN/AN/ATacoma Power WSPPSF 12
N/AN/AN/ATenaska Power Services Co. WSPPSF 13
N/AN/AN/AThe Energy Authority, Inc. WSPPSF 14
FERC FORM NO. 1 (ED. 12-90) Page 326.11
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing 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.
N/AN/AN/ATransAlta Energy Marketing (U.S.) Inc. WSPPSF 1
N/AN/AN/ATurlock Irrigation District WSPPSF 2
N/AN/AN/ARaft River Energy I LLC -LU 3
N/AN/AN/ATelocaset Wind Power Partners LLC APP-ALU 4
N/AN/AN/ANeal Hot Springs Unit #1 -LU 5
N/AN/AN/ANet Metering Customers -OS 6
N/AN/AN/AOregon Solar Customers -OS 7
N/AN/AN/APrior Year Adjustments -AD 8
N/AN/AN/APrior Year Adjustments -OS 9
Power Exchanges - 10
Bonneville Power Administration -EX 11
NorthWestern Energy -EX 12
PacifiCorp Inc. -EX 13
Powerex Corp. -EX 14
FERC FORM NO. 1 (ED. 12-90) Page 326.12
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing 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.
Sierra Pacific Power Co., dba NV Energ -EX 1
Clatskanie PUD 153EX 2
Other Transactions 3
Acctg Valuation of Clatskanie PUD 4
N/AN/AN/ADemand Response Avoided Energy -OS 5
N/AN/AN/AClark Canyon Damages -OS 6
N/AN/AN/APacifiCorp Loss Repayment -OS 7
8
9
10
11
12
13
14
FERC FORM NO. 1 (ED. 12-90) Page 326.13
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior 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 (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by 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.
2,267,324 2,267,324 1 27,305
155,672 62,590 218,262 2 1,604
208,408 208,408 3 4,816
2,688,291 2,688,291 4 44,719
1,094,933 1,094,933 5 13,455
517,645 517,645 6 8,762
7
23,357 23,357 8 333
68,977 68,977 9 953
69,618 69,618 10 964
347,470 347,470 11 3,366
48,651 48,651 12 693
3,334,374 3,334,374 13 61,275
1,464,756 1,464,756 14 27,052
FERC FORM NO. 1 (ED. 12-90) Page 327
4,148,611 324,803 211,221 2,815,124 232,321,276 1,985,499 237,121,899
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior 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 (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by 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.
5,615,388 5,615,388 1 66,813
702,326 702,326 2 8,468
1,525,090 1,525,090 3 26,647
270,590 270,590 4 3,702
3,580 3,580 5 50
104,145 104,145 6 1,407
333,945 333,945 7 3,532
17,500 12,434 29,934 8 321
3,502,993 3,502,993 9 53,793
10
538,180 538,180 11 10,349
839,625 839,625 12 15,142
234,774 234,774 13 3,064
419,399 419,399 14 7,654
FERC FORM NO. 1 (ED. 12-90) Page 327.1
4,148,611 324,803 211,221 2,815,124 232,321,276 1,985,499 237,121,899
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior 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 (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by 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.
358,045 358,045 1 6,828
334,097 334,097 2 4,755
704,700 704,700 3 10,437
26,796 25,316 52,112 4 638
15,563 15,563 5 521
93,905 93,905 6 1,346
4,069,461 4,069,461 7 62,680
7,438 7,438 8 139
253,809 253,809 9 3,265
35,623 35,623 10 1,152
1,389,340 1,389,340 11 24,775
1,123,012 1,123,012 12 18,259
1,843,655 1,843,655 13 34,007
3,942,261 3,942,261 14 60,610
FERC FORM NO. 1 (ED. 12-90) Page 327.2
4,148,611 324,803 211,221 2,815,124 232,321,276 1,985,499 237,121,899
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior 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 (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by 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.
1,613,586 1,613,586 1 22,826
4,616,740 4,616,740 2 97,693
135,121 135,121 3 1,615
3,107,261 3,107,261 4 44,794
1,071,969 1,071,969 5 19,321
2,475,077 2,475,077 6 41,453
4,617,988 4,617,988 7 59,691
3,744,319 3,744,319 8 74,878
80,206 80,206 9 1,130
296,037 296,037 10 4,192
35,417 35,417 11 626
306,397 306,397 12 3,494
482,669 482,669 13 5,900
269,371 269,371 14 2,906
FERC FORM NO. 1 (ED. 12-90) Page 327.3
4,148,611 324,803 211,221 2,815,124 232,321,276 1,985,499 237,121,899
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior 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 (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by 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.
487,034 487,034 1 7,567
98,057 98,057 2 1,273
426,161 426,161 3 5,817
391,208 391,208 4 6,002
143,368 143,368 5 2,071
278,193 278,193 6 5,806
3,844,357 3,844,357 7 59,185
149,801 149,801 8 2,196
3,646,985 3,646,985 9 54,155
3,202,889 3,202,889 10 59,061
30,610 30,610 11 460
1,020,631 1,020,631 12 13,390
2,096,620 2,096,620 13 38,403
14
FERC FORM NO. 1 (ED. 12-90) Page 327.4
4,148,611 324,803 211,221 2,815,124 232,321,276 1,985,499 237,121,899
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior 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 (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by 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.
2,903 2,903 1 96
260,408 260,408 2 10,655
5,374,826 5,374,826 3 63,921
486,150 290,674 776,824 4 8,482
1,809,265 1,809,265 5 33,185
49,850 49,850 6 808
65,916 65,916 7 1,231
94,590 94,590 8 1,259
9
136,478 136,478 10 2,049
251,069 251,069 11 3,668
285,491 285,491 12 4,916
13
126,368 126,368 14 1,578
FERC FORM NO. 1 (ED. 12-90) Page 327.5
4,148,611 324,803 211,221 2,815,124 232,321,276 1,985,499 237,121,899
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior 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 (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by 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.
162,914 162,914 1 3,487
552,508 361,700 914,208 2 9,163
16,003,917 16,003,917 3 263,174
5,076,275 5,076,275 4 76,713
3,660,876 3,660,876 5 56,392
3,534,112 3,534,112 6 65,142
1,652,669 1,652,669 7 23,682
8
128,652 128,652 9 1,427
151,502 151,502 10 2,113
22,835 22,835 11 334
2,108,441 2,108,441 12 29,140
1,576,498 1,309,257 2,885,755 13 28,870
2,162 2,162 14 84
FERC FORM NO. 1 (ED. 12-90) Page 327.6
4,148,611 324,803 211,221 2,815,124 232,321,276 1,985,499 237,121,899
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior 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 (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by 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.
33 33 1 1
1,564,466 1,564,466 2 28,813
1,799,288 1,799,288 3 32,787
1,642,697 1,642,697 4 30,056
4,351,059 4,351,059 5 79,036
541,845 541,845 6 8,810
4,024,407 4,024,407 7 62,355
44,886 44,886 8 654
241,027 241,027 9 3,157
70,342 70,342 10 928
1,878,057 1,878,057 11 26,527
5,441,691 5,441,691 12 65,032
-1,884,407 -1,884,407 13
14 -4,830
FERC FORM NO. 1 (ED. 12-90) Page 327.7
4,148,611 324,803 211,221 2,815,124 232,321,276 1,985,499 237,121,899
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior 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 (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by 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.
1
7,963 7,963 2 393
258 258 3 11
3,779,679 3,779,679 4 135,562
249,576 249,576 5
3,225 3,225 6 75
678,417 678,417 7
2,534 2,534 8 111
2,551,020 2,551,020 9 78,087
102,000 102,000 10 8,000
-595 -595 11 219
293,515 293,515 12 8,437
108 108 13 4
6,818,064 6,818,064 14 151,200
FERC FORM NO. 1 (ED. 12-90) Page 327.8
4,148,611 324,803 211,221 2,815,124 232,321,276 1,985,499 237,121,899
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior 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 (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by 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.
-104,044 -104,044 1
1,772 1,772 2 38
3,592 3,592 3 325
79 79 4 2
4,322,798 4,322,798 5 115,825
76,859 76,859 6 2,842
77,358 77,358 7 8,817
148 148 8 5
8,225 8,225 9 175
2,951,306 2,951,306 10 92,730
2,691,169 2,691,169 11 62,400
1,076,400 1,076,400 12 20,800
1,520,390 1,520,390 13
8,403 8,403 14 252
FERC FORM NO. 1 (ED. 12-90) Page 327.9
4,148,611 324,803 211,221 2,815,124 232,321,276 1,985,499 237,121,899
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior 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 (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by 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.
1,260 1,260 1 30
3,519,175 3,519,175 2 88,123
285,274 285,274 3 6,319
258 258 4 9
165,077 165,077 5 5,545
1,744 1,744 6 73
175,683 175,683 7 5,593
180,673 180,673 8
354 354 9 10
366,566 366,566 10 10,507
4,137,949 4,137,949 11 125,810
6,532,457 6,532,457 12 206,278
3,375 3,375 13 75
135,335 135,335 14 2,875
FERC FORM NO. 1 (ED. 12-90) Page 327.10
4,148,611 324,803 211,221 2,815,124 232,321,276 1,985,499 237,121,899
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior 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 (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by 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.
446 446 1 15
419,651 419,651 2 15,227
220,226 220,226 3 6,497
5,250 5,250 4 110
150 150 5 6
12,396 12,396 6 400
416,270 416,270 7 12,977
216,694 216,694 8 7,243
952 952 9 41
16,955 16,955 10 1,397
69 69 11 2
18,025 18,025 12 400
20,704 20,704 13 547
470,756 470,756 14 25,626
FERC FORM NO. 1 (ED. 12-90) Page 327.11
4,148,611 324,803 211,221 2,815,124 232,321,276 1,985,499 237,121,899
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior 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 (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by 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.
397,120 397,120 1 11,907
52,933 52,933 2 4,108
4,987,942 4,987,942 3 78,916
16,446,275 16,446,275 4 292,788
18,747,659 18,747,659 5 183,529
214 214 6 544
27,804 27,804 7 696
8 2
-2,453 -2,453 9
10
69,122 11
977 19,041 12
137,305 163,705 13
277 14
FERC FORM NO. 1 (ED. 12-90) Page 327.12
4,148,611 324,803 211,221 2,815,124 232,321,276 1,985,499 237,121,899
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior 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 (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by 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.
4,764 1
68,175 72,658 2
3
-163,570 -163,570 4
7,940,697 7,940,697 5
-373,490 -373,490 6
7 81,625
8
9
10
11
12
13
14
FERC FORM NO. 1 (ED. 12-90) Page 327.13
4,148,611 324,803 211,221 2,815,124 232,321,276 1,985,499 237,121,899
Schedule Page: 326 Line No.: 2 Column: e
Unavailable
Schedule Page: 326 Line No.: 2 Column: f
Unavailable
Schedule Page: 326.1 Line No.: 8 Column: e
Unavailable
Schedule Page: 326.1 Line No.: 8 Column: f
Unavailable
Schedule Page: 326.2 Line No.: 4 Column: e
Unavailable
Schedule Page: 326.2 Line No.: 4 Column: f
Unavailable
Schedule Page: 326.2 Line No.: 10 Column: b
Non Firm Purchases
Schedule Page: 326.3 Line No.: 1 Column: a
Ida West, a subsidiary of Idaho Power Company, has partial ownership of these projects.
Schedule Page: 326.5 Line No.: 4 Column: e
Unavailable
Schedule Page: 326.5 Line No.: 4 Column: f
Unavailable
Schedule Page: 326.6 Line No.: 2 Column: e
Unavailable
Schedule Page: 326.6 Line No.: 2 Column: f
Unavailable
Schedule Page: 326.6 Line No.: 12 Column: a
Ida West, a subsidiary of Idaho Power Company, has partial ownership of these projects.
Schedule Page: 326.6 Line No.: 13 Column: a
The Tamarack Energy Partnership demand readings are taken from an electronic demand
recorder provided by Idaho Power Co. The actual demand is not used in determining the cost
of energy.
Schedule Page: 326.6 Line No.: 13 Column: e
Unavailable
Schedule Page: 326.6 Line No.: 13 Column: f
Unavailable
Schedule Page: 326.6 Line No.: 14 Column: b
Non Firm Purchases
Schedule Page: 326.7 Line No.: 1 Column: b
Non Firm Purchases
Schedule Page: 326.7 Line No.: 11 Column: a
Ida West, a subsidiary of Idaho Power Company, has partial ownership of these projects.
Schedule Page: 326.7 Line No.: 13 Column: a
Prior Period Overpayment Recovery (JR Simplot)
Schedule Page: 326.7 Line No.: 14 Column: a
Difference between booked and scheduled energy
Schedule Page: 326.8 Line No.: 3 Column: b
Non Firm Purchases
Schedule Page: 326.8 Line No.: 5 Column: b
Financial Transmission Losses
Schedule Page: 326.8 Line No.: 7 Column: b
Financial Transmission losses
Schedule Page: 326.8 Line No.: 8 Column: b
Non Firm Purchases
Schedule Page: 326.8 Line No.: 13 Column: b
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Non Firm Purchases
Schedule Page: 326.9 Line No.: 1 Column: b
ISDA Naster Agreement with Citigroup Energy PLC dated March 7, 2011.
Schedule Page: 326.9 Line No.: 4 Column: b
Non Firm Purchases
Schedule Page: 326.9 Line No.: 8 Column: b
Non Firm Purchases
Schedule Page: 326.9 Line No.: 13 Column: b
Prudential Bache Commodities LLC (Jeffries Bache) Futures Account Document, dated
September 4, 2008.
Schedule Page: 326.10 Line No.: 4 Column: b
Non Firm Purchases
Schedule Page: 326.10 Line No.: 6 Column: b
Non Firm Purchases
Schedule Page: 326.10 Line No.: 8 Column: b
Financial Transmission Losses
Schedule Page: 326.10 Line No.: 9 Column: b
Non Firm Purchases
Schedule Page: 326.10 Line No.: 13 Column: b
Non Firm Purchases
Schedule Page: 326.11 Line No.: 1 Column: b
Non Firm Purchases
Schedule Page: 326.11 Line No.: 5 Column: b
Non Firm Purchases
Schedule Page: 326.11 Line No.: 6 Column: b
Non Firm Purchases
Schedule Page: 326.11 Line No.: 9 Column: b
Non Firm Purchases
Schedule Page: 326.11 Line No.: 11 Column: b
Non Firm Purchases
Schedule Page: 326.12 Line No.: 3 Column: b
Unavailable
Schedule Page: 326.12 Line No.: 6 Column: b
Schedule 84 Net Metering
Schedule Page: 326.12 Line No.: 7 Column: b
Schedule 88 Oregon Solar
Schedule Page: 326.12 Line No.: 9 Column: b
Financial Transmission Losses
Schedule Page: 326.12 Line No.: 11 Column: b
Financial Transmission losses
Schedule Page: 326.12 Line No.: 12 Column: b
Financial Transmission Losses
Schedule Page: 326.12 Line No.: 13 Column: b
Financial Transmission losses
Schedule Page: 326.12 Line No.: 14 Column: b
Financial Transmission Losses
Schedule Page: 326.13 Line No.: 1 Column: b
Financial Transmission Losses
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofIdaho Power Company X 04/15/2015 2014/Q4
Line
No.
Payment By
(c)(b)(a)(d)
Statistical
cation
Classifi-
(Footnote Affiliation)
(Including transactions referred to as 'wheeling')
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)Energy Received From Energy Delivered To
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities, 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.
Bonneville Power Administration - OTEC Bonneville Power Administration Oregon Trails Electric Co-op FNO 1
Bonneville Power Administration - OTEC Bonneville Power Administration Oregon Trails Electric Co-op AD 2
Bonneville Power Administration - USBR Bonneville Power Administration United States Bureau of Reclamati FNO 3
Bonneville Power Administration - USBR Bonneville Power Administration United States Bureau of Reclamati AD 4
Bonneville Power Administration - PF Bonneville Power Administration Priority Firm Customers FNO 5
Bonneville Power Administration - PF Bonneville Power Administration Priority Firm Customers AD 6
Bonneville Power Administration - Raft Bonneville Power Administration Raft River Idaho Customers AD 7
Milner Irrigation District United States Bureau of Reclamati Milner Irrigation District OLF 8
Shell Energy North America (US), L.P. Seattle City Light Bonneville Power Administration OS 9
PacifiCorp PacifiCorp West PacifiCorp West FNO 10
PacifiCorp PacifiCorp West PacifiCorp West AD 11
United States Bureau of Indian Affairs Bonneville Power Administration United States Bureau of Indian Af OS 12
United Materials of Great Falls NorthWestern/PacifiCorp East Idaho Power Company OS 13
United Materials of Great Falls PacifiCorp East Idaho Power Company OS 14
Avista Corporation NorthWestern/PacifiCorp East Avista NF 15
Avista Corporation AD 16
Black Hills Power Inc. NorthWestern/PacifiCorp East PacifiCorp East NF 17
Black Hills Power Inc.AD 18
Bonneville Power Administration NorthWestern/PacifiCorp East Sierra Pacific Power NF 19
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration NF 20
Bonneville Power Administration Bonneville Power Administration Sierra Pacific Power NF 21
Bonneville Power Administration Avista Bonneville Power Administration NF 22
Bonneville Power Administration Avista Sierra Pacific Power NF 23
Bonneville Power Administration AD 24
Cargill Power Markets LLC NorthWestern/PacifiCorp East Sierra Pacific Power NF 25
Cargill Power Markets LLC PacifiCorp East NorthWestern/PacifiCorp East NF 26
Cargill Power Markets LLC PacifiCorp East Bonneville Power Administration NF 27
Cargill Power Markets LLC NorthWestern/PacifiCorp East Bonneville Power Administration NF 28
Cargill Power Markets LLC NorthWestern/PacifiCorp East Sierra Pacific Power NF 29
Cargill Power Markets LLC PacifiCorp East Sierra Pacific Power NF 30
Cargill Power Markets LLC PacifiCorp West PacifiCorp East NF 31
Cargill Power Markets LLC PacifiCorp West PacifiCorp East SFP 32
Cargill Power Markets LLC PacifiCorp West Sierra Pacific Power NF 33
34
FERC FORM NO. 1 (ED. 12-90) Page 328
TOTAL
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofIdaho Power Company X 04/15/2015 2014/Q4
Line
No.
Payment By
(c)(b)(a)(d)
Statistical
cation
Classifi-
(Footnote Affiliation)
(Including transactions referred to as 'wheeling')
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)Energy Received From Energy Delivered To
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities, 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.
Cargill Power Markets LLC PacifiCorp West Sierra Pacific Power SFP 1
Cargill Power Markets LLC PacifiCorp West PacifiCorp East NF 2
Cargill Power Markets LLC PacifiCorp West NorthWestern/PacifiCorp East NF 3
Cargill Power Markets LLC PacifiCorp West Bonneville Power Administration NF 4
Cargill Power Markets LLC PacifiCorp West Sierra Pacific Power NF 5
Cargill Power Markets LLC NorthWestern/PacifiCorp East Sierra Pacific Power NF 6
Cargill Power Markets LLC Bonneville Power Administration PacifiCorp East NF 7
Cargill Power Markets LLC Bonneville Power Administration Sierra Pacific Power NF 8
Cargill Power Markets LLC Avista PacifiCorp East NF 9
Cargill Power Markets LLC Avista PacifiCorp East SFP 10
Cargill Power Markets LLC Avista Bonneville Power Administration NF 11
Cargill Power Markets LLC Avista Sierra Pacific Power NF 12
Cargill Power Markets LLC Avista Sierra Pacific Power SFP 13
Cargill Power Markets LLC Sierra Pacific Power Bonneville Power Administration NF 14
Cargill Power Markets LLC AD 15
Constellation Energy AD 16
Endure Energy AD 17
Iberdrola Renewables LLC PacifiCorp East Sierra Pacific Power NF 18
Iberdrola Renewables LLC NorthWestern/PacifiCorp East PacifiCorp East NF 19
Iberdrola Renewables LLC NorthWestern/PacifiCorp East PacifiCorp East NF 20
Iberdrola Renewables LLC NorthWestern/PacifiCorp East Sierra Pacific Power NF 21
Iberdrola Renewables LLC Idaho Power Company PacifiCorp East NF 22
Iberdrola Renewables LLC Idaho Power Company Sierra Pacific Power NF 23
Iberdrola Renewables LLC NorthWestern/PacifiCorp East Sierra Pacific Power NF 24
Iberdrola Renewables LLC Bonneville Power Administration PacifiCorp East NF 25
Iberdrola Renewables LLC Bonneville Power Administration Sierra Pacific Power NF 26
Iberdrola Renewables LLC Avista PacifiCorp East NF 27
Iberdrola Renewables LLC Avista Sierra Pacific Power NF 28
Iberdrola Renewables LLC Sierra Pacific Power Bonneville Power Administration NF 29
Iberdrola Renewables LLC Idaho Power Company Bonneville Power Administration NF 30
Iberdrola Renewables LLC AD 31
MacQuarie Cook AD 32
Morgan Stanley Capital Group Inc. NorthWestern/PacifiCorp East PacifiCorp East NF 33
34
FERC FORM NO. 1 (ED. 12-90) Page 328.1
TOTAL
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofIdaho Power Company X 04/15/2015 2014/Q4
Line
No.
Payment By
(c)(b)(a)(d)
Statistical
cation
Classifi-
(Footnote Affiliation)
(Including transactions referred to as 'wheeling')
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)Energy Received From Energy Delivered To
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities, 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.
Morgan Stanley Capital Group Inc. NorthWestern/PacifiCorp East Idaho Power Company NF 1
Morgan Stanley Capital Group Inc. NorthWestern/PacifiCorp East Bonneville Power Administration NF 2
Morgan Stanley Capital Group Inc. NorthWestern/PacifiCorp East Sierra Pacific Power NF 3
Morgan Stanley Capital Group Inc. NorthWestern/PacifiCorp East Sierra Pacific Power SFP 4
Morgan Stanley Capital Group Inc. PacifiCorp East NorthWestern/PacifiCorp East NF 5
Morgan Stanley Capital Group Inc. PacifiCorp East Idaho Power Company NF 6
Morgan Stanley Capital Group Inc. PacifiCorp East NorthWestern/PacifiCorp East NF 7
Morgan Stanley Capital Group Inc. PacifiCorp East Bonneville Power Administration NF 8
Morgan Stanley Capital Group Inc. PacifiCorp East Sierra Pacific Power NF 9
Morgan Stanley Capital Group Inc. NorthWestern/PacifiCorp East PacifiCorp East NF 10
Morgan Stanley Capital Group Inc. NorthWestern/PacifiCorp East PacifiCorp East NF 11
Morgan Stanley Capital Group Inc. NorthWestern/PacifiCorp East PacifiCorp West NF 12
Morgan Stanley Capital Group Inc. NorthWestern/PacifiCorp East Idaho Power Company NF 13
Morgan Stanley Capital Group Inc. NorthWestern/PacifiCorp East Bonneville Power Administration NF 14
Morgan Stanley Capital Group Inc. NorthWestern/PacifiCorp East Sierra Pacific Power NF 15
Morgan Stanley Capital Group Inc. NorthWestern/PacifiCorp East Sierra Pacific Power SFP 16
Morgan Stanley Capital Group Inc. PacifiCorp East NorthWestern/PacifiCorp East NF 17
Morgan Stanley Capital Group Inc. PacifiCorp East PacifiCorp East NF 18
Morgan Stanley Capital Group Inc. PacifiCorp East NorthWestern/PacifiCorp East NF 19
Morgan Stanley Capital Group Inc. PacifiCorp East Idaho Power Company NF 20
Morgan Stanley Capital Group Inc. PacifiCorp East Bonneville Power Administration NF 21
Morgan Stanley Capital Group Inc. PacifiCorp East Sierra Pacific Power NF 22
Morgan Stanley Capital Group Inc. PacifiCorp East Sierra Pacific Power SFP 23
Morgan Stanley Capital Group Inc. PacifiCorp West PacifiCorp East NF 24
Morgan Stanley Capital Group Inc. NorthWestern/PacifiCorp East Idaho Power Company NF 25
Morgan Stanley Capital Group Inc. Idaho Power Company PacifiCorp East NF 26
Morgan Stanley Capital Group Inc. Idaho Power Company PacifiCorp East NF 27
Morgan Stanley Capital Group Inc. Idaho Power Company PacifiCorp West NF 28
Morgan Stanley Capital Group Inc. Idaho Power Company Sierra Pacific Power NF 29
Morgan Stanley Capital Group Inc. PacifiCorp West PacifiCorp East NF 30
Morgan Stanley Capital Group Inc. PacifiCorp West Idaho Power Company NF 31
Morgan Stanley Capital Group Inc. PacifiCorp West Bonneville Power Administration NF 32
Morgan Stanley Capital Group Inc. PacifiCorp West Sierra Pacific Power NF 33
34
FERC FORM NO. 1 (ED. 12-90) Page 328.2
TOTAL
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofIdaho Power Company X 04/15/2015 2014/Q4
Line
No.
Payment By
(c)(b)(a)(d)
Statistical
cation
Classifi-
(Footnote Affiliation)
(Including transactions referred to as 'wheeling')
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)Energy Received From Energy Delivered To
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities, 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.
Morgan Stanley Capital Group Inc. Idaho Power Company PacifiCorp East NF 1
Morgan Stanley Capital Group Inc. Idaho Power Company Bonneville Power Administration NF 2
Morgan Stanley Capital Group Inc. Idaho Power Company Sierra Pacific Power NF 3
Morgan Stanley Capital Group Inc. NorthWestern/PacifiCorp East PacifiCorp East NF 4
Morgan Stanley Capital Group Inc. NorthWestern/PacifiCorp East PacifiCorp East NF 5
Morgan Stanley Capital Group Inc. NorthWestern/PacifiCorp East PacifiCorp West NF 6
Morgan Stanley Capital Group Inc. NorthWestern/PacifiCorp East Idaho Power Company NF 7
Morgan Stanley Capital Group Inc. NorthWestern/PacifiCorp East Bonneville Power Administration NF 8
Morgan Stanley Capital Group Inc. NorthWestern/PacifiCorp East Sierra Pacific Power NF 9
Morgan Stanley Capital Group Inc. Bonneville Power Administration PacifiCorp East NF 10
Morgan Stanley Capital Group Inc. Bonneville Power Administration PacifiCorp East NF 11
Morgan Stanley Capital Group Inc. Bonneville Power Administration NorthWestern/PacifiCorp East NF 12
Morgan Stanley Capital Group Inc. Bonneville Power Administration Sierra Pacific Power NF 13
Morgan Stanley Capital Group Inc. Avista PacifiCorp East NF 14
Morgan Stanley Capital Group Inc. Avista PacifiCorp East NF 15
Morgan Stanley Capital Group Inc. Avista NorthWestern/PacifiCorp East NF 16
Morgan Stanley Capital Group Inc. Avista Bonneville Power Administration NF 17
Morgan Stanley Capital Group Inc. Avista Sierra Pacific Power NF 18
Morgan Stanley Capital Group Inc. Avista Sierra Pacific Power SFP 19
Morgan Stanley Capital Group Inc. Sierra Pacific Power PacifiCorp East NF 20
Morgan Stanley Capital Group Inc. Sierra Pacific Power NorthWestern/PacifiCorp East NF 21
Morgan Stanley Capital Group Inc. Sierra Pacific Power PacifiCorp East NF 22
Morgan Stanley Capital Group Inc. Sierra Pacific Power NorthWestern/PacifiCorp East NF 23
Morgan Stanley Capital Group Inc. Sierra Pacific Power Bonneville Power Administration NF 24
Morgan Stanley Capital Group Inc.AD 25
Nevada Power Company PacifiCorp East Sierra Pacific Power NF 26
Nevada Power Company PacifiCorp East Sierra Pacific Power NF 27
Nevada Power Company PacifiCorp East Sierra Pacific Power SFP 28
Nevada Power Company NorthWestern/PacifiCorp East Sierra Pacific Power NF 29
Nevada Power Company Bonneville Power Administration Sierra Pacific Power NF 30
Nevada Power Company Avista Sierra Pacific Power NF 31
Nevada Power Company Avista Sierra Pacific Power SFP 32
Nevada Power Company Sierra Pacific Power PacifiCorp East NF 33
34
FERC FORM NO. 1 (ED. 12-90) Page 328.3
TOTAL
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofIdaho Power Company X 04/15/2015 2014/Q4
Line
No.
Payment By
(c)(b)(a)(d)
Statistical
cation
Classifi-
(Footnote Affiliation)
(Including transactions referred to as 'wheeling')
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)Energy Received From Energy Delivered To
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities, 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.
Nevada Power Company Sierra Pacific Power Idaho Power Company NF 1
Nevada Power Company Sierra Pacific Power Bonneville Power Administration NF 2
Northwestern Energy AD 3
PacifiCorp Inc. PacifiCorp East PacifiCorp West NF 4
PacifiCorp Inc. PacifiCorp East Idaho Power Company NF 5
PacifiCorp Inc. PacifiCorp East Idaho Power Company LFP 6
PacifiCorp Inc. PacifiCorp East Bonneville Power Administration NF 7
PacifiCorp Inc. PacifiCorp East PacifiCorp East NF 8
PacifiCorp Inc. PacifiCorp East PacifiCorp East SFP 9
PacifiCorp Inc. PacifiCorp East PacifiCorp West NF 10
PacifiCorp Inc. PacifiCorp East Idaho Power Company NF 11
PacifiCorp Inc. PacifiCorp East Bonneville Power Administration NF 12
PacifiCorp Inc. PacifiCorp West PacifiCorp East NF 13
PacifiCorp Inc. PacifiCorp West PacifiCorp East SFP 14
PacifiCorp Inc. PacifiCorp West Bonneville Power Administration NF 15
PacifiCorp Inc. Idaho Power Company Sierra Pacific Power SFP 16
PacifiCorp Inc. Idaho Power Company PacifiCorp East NF 17
PacifiCorp Inc. Idaho Power Company PacifiCorp East NF 18
PacifiCorp Inc. Idaho Power Company PacifiCorp East NF 19
PacifiCorp Inc. Idaho Power Company PacifiCorp East LFP 20
PacifiCorp Inc. Idaho Power Company NorthWestern/PacifiCorp East NF 21
PacifiCorp Inc. Idaho Power Company Idaho Power Company LFP 22
PacifiCorp Inc. Idaho Power Company Idaho Power Company NF 23
PacifiCorp Inc. Idaho Power Company Bonneville Power Administration NF 24
PacifiCorp Inc. Idaho Power Company Avista NF 25
PacifiCorp Inc. Bonneville Power Administration PacifiCorp East NF 26
PacifiCorp Inc. Avista PacifiCorp East NF 27
PacifiCorp Inc. Avista PacifiCorp West NF 28
PacifiCorp Inc. Avista Bonneville Power Administration NF 29
PacifiCorp Inc.AD 30
Portland General Electric Company PacifiCorp East NorthWestern/PacifiCorp East NF 31
Portland General Electric Company PacifiCorp East Bonneville Power Administration NF 32
Portland General Electric Company NorthWestern/PacifiCorp East Bonneville Power Administration NF 33
34
FERC FORM NO. 1 (ED. 12-90) Page 328.4
TOTAL
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofIdaho Power Company X 04/15/2015 2014/Q4
Line
No.
Payment By
(c)(b)(a)(d)
Statistical
cation
Classifi-
(Footnote Affiliation)
(Including transactions referred to as 'wheeling')
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)Energy Received From Energy Delivered To
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities, 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.
Portland General Electric Company NorthWestern/PacifiCorp East Sierra Pacific Power NF 1
Portland General Electric Company PacifiCorp East Bonneville Power Administration NF 2
Portland General Electric Company Idaho Power Company PacifiCorp East NF 3
Portland General Electric Company Idaho Power Company Sierra Pacific Power NF 4
Portland General Electric Company NorthWestern/PacifiCorp East Bonneville Power Administration NF 5
Portland General Electric Company Bonneville Power Administration Sierra Pacific Power NF 6
Portland General Electric Company Sierra Pacific Power Bonneville Power Administration NF 7
Portland General Electric Company AD 8
Powerex Corporation PacifiCorp East NorthWestern/PacifiCorp East NF 9
Powerex Corporation PacifiCorp East PacifiCorp East NF 10
Powerex Corporation PacifiCorp East PacifiCorp West NF 11
Powerex Corporation PacifiCorp East Idaho Power Company NF 12
Powerex Corporation PacifiCorp East NorthWestern/PacifiCorp East NF 13
Powerex Corporation PacifiCorp East Bonneville Power Administration NF 14
Powerex Corporation PacifiCorp East Sierra Pacific Power NF 15
Powerex Corporation NorthWestern/PacifiCorp East PacifiCorp East NF 16
Powerex Corporation NorthWestern/PacifiCorp East PacifiCorp East SFP 17
Powerex Corporation NorthWestern/PacifiCorp East PacifiCorp East NF 18
Powerex Corporation NorthWestern/PacifiCorp East Idaho Power Company NF 19
Powerex Corporation NorthWestern/PacifiCorp East Bonneville Power Administration NF 20
Powerex Corporation NorthWestern/PacifiCorp East Sierra Pacific Power NF 21
Powerex Corporation PacifiCorp East NorthWestern/PacifiCorp East NF 22
Powerex Corporation PacifiCorp East PacifiCorp West NF 23
Powerex Corporation PacifiCorp East Idaho Power Company NF 24
Powerex Corporation PacifiCorp East Bonneville Power Administration NF 25
Powerex Corporation PacifiCorp East Sierra Pacific Power NF 26
Powerex Corporation PacifiCorp West PacifiCorp East NF 27
Powerex Corporation PacifiCorp West PacifiCorp East SFP 28
Powerex Corporation PacifiCorp West PacifiCorp East NF 29
Powerex Corporation PacifiCorp West Sierra Pacific Power NF 30
Powerex Corporation NorthWestern/PacifiCorp East NorthWestern/PacifiCorp East NF 31
Powerex Corporation NorthWestern/PacifiCorp East PacifiCorp East NF 32
Powerex Corporation NorthWestern/PacifiCorp East Idaho Power Company NF 33
34
FERC FORM NO. 1 (ED. 12-90) Page 328.5
TOTAL
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofIdaho Power Company X 04/15/2015 2014/Q4
Line
No.
Payment By
(c)(b)(a)(d)
Statistical
cation
Classifi-
(Footnote Affiliation)
(Including transactions referred to as 'wheeling')
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)Energy Received From Energy Delivered To
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities, 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.
Powerex Corporation NorthWestern/PacifiCorp East NorthWestern/PacifiCorp East NF 1
Powerex Corporation NorthWestern/PacifiCorp East Bonneville Power Administration NF 2
Powerex Corporation NorthWestern/PacifiCorp East Sierra Pacific Power NF 3
Powerex Corporation Idaho Power Company PacifiCorp East NF 4
Powerex Corporation Idaho Power Company PacifiCorp East SFP 5
Powerex Corporation Idaho Power Company PacifiCorp East NF 6
Powerex Corporation Idaho Power Company PacifiCorp West NF 7
Powerex Corporation Idaho Power Company Sierra Pacific Power NF 8
Powerex Corporation Idaho Power Company Sierra Pacific Power SFP 9
Powerex Corporation PacifiCorp West NorthWestern/PacifiCorp East NF 10
Powerex Corporation PacifiCorp West NorthWestern/PacifiCorp East NF 11
Powerex Corporation PacifiCorp West Bonneville Power Administration NF 12
Powerex Corporation PacifiCorp West Sierra Pacific Power NF 13
Powerex Corporation Idaho Power Company PacifiCorp West NF 14
Powerex Corporation Idaho Power Company Idaho Power Company NF 15
Powerex Corporation Idaho Power Company Bonneville Power Administration NF 16
Powerex Corporation NorthWestern/PacifiCorp East PacifiCorp East SFP 17
Powerex Corporation NorthWestern/PacifiCorp East PacifiCorp East NF 18
Powerex Corporation NorthWestern/PacifiCorp East Idaho Power Company NF 19
Powerex Corporation NorthWestern/PacifiCorp East Bonneville Power Administration NF 20
Powerex Corporation NorthWestern/PacifiCorp East Sierra Pacific Power NF 21
Powerex Corporation Bonneville Power Administration PacifiCorp East NF 22
Powerex Corporation Bonneville Power Administration PacifiCorp East SFP 23
Powerex Corporation Bonneville Power Administration PacifiCorp East NF 24
Powerex Corporation Bonneville Power Administration PacifiCorp West NF 25
Powerex Corporation Bonneville Power Administration Sierra Pacific Power NF 26
Powerex Corporation Bonneville Power Administration Sierra Pacific Power SFP 27
Powerex Corporation Avista PacifiCorp East NF 28
Powerex Corporation Avista Sierra Pacific Power NF 29
Powerex Corporation Sierra Pacific Power NorthWestern/PacifiCorp East NF 30
Powerex Corporation Sierra Pacific Power Idaho Power Company NF 31
Powerex Corporation Sierra Pacific Power NorthWestern/PacifiCorp East NF 32
Powerex Corporation Sierra Pacific Power Bonneville Power Administration NF 33
34
FERC FORM NO. 1 (ED. 12-90) Page 328.6
TOTAL
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofIdaho Power Company X 04/15/2015 2014/Q4
Line
No.
Payment By
(c)(b)(a)(d)
Statistical
cation
Classifi-
(Footnote Affiliation)
(Including transactions referred to as 'wheeling')
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)Energy Received From Energy Delivered To
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities, 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.
Powerex Corporation AD 1
PPL EnergyPlus, LLC NorthWestern/PacifiCorp East Bonneville Power Administration NF 2
PPL EnergyPlus, LLC PacifiCorp East Bonneville Power Administration NF 3
PPL EnergyPlus, LLC PacifiCorp East Sierra Pacific Power NF 4
PPL EnergyPlus, LLC NorthWestern/PacifiCorp East PacifiCorp East NF 5
PPL EnergyPlus, LLC NorthWestern/PacifiCorp East Bonneville Power Administration NF 6
PPL EnergyPlus, LLC NorthWestern/PacifiCorp East Sierra Pacific Power NF 7
PPL EnergyPlus, LLC AD 8
Puget Sound Energy, Inc. Idaho Power Company NorthWestern/PacifiCorp East NF 9
Puget Sound Energy, Inc. PacifiCorp West Bonneville Power Administration NF 10
Puget Sound Energy, Inc. PacifiCorp West Avista NF 11
Puget Sound Energy, Inc. Avista Bonneville Power Administration NF 12
Puget Sound Energy, Inc.AD 13
Rainbow Energy Marketing Corporation PacifiCorp East NorthWestern/PacifiCorp East NF 14
Rainbow Energy Marketing Corporation PacifiCorp East NorthWestern/PacifiCorp East NF 15
Rainbow Energy Marketing Corporation PacifiCorp East NorthWestern/PacifiCorp East SFP 16
Rainbow Energy Marketing Corporation PacifiCorp East NorthWestern/PacifiCorp East NF 17
Rainbow Energy Marketing Corporation PacifiCorp East NorthWestern/PacifiCorp East NF 18
Rainbow Energy Marketing Corporation PacifiCorp East NorthWestern/PacifiCorp East SFP 19
Rainbow Energy Marketing Corporation PacifiCorp West PacifiCorp East NF 20
Rainbow Energy Marketing Corporation Avista PacifiCorp East NF 21
Rainbow Energy Marketing Corporation Avista PacifiCorp East SFP 22
Rainbow Energy Marketing Corporation AD 23
Seattle City Light AD 24
Sempra Energy AD 25
Shell Energy North America (US), L.P. PacifiCorp East Bonneville Power Administration NF 26
Shell Energy North America (US), L.P. PacifiCorp East Sierra Pacific Power NF 27
Shell Energy North America (US), L.P. PacifiCorp East Sierra Pacific Power SFP 28
Shell Energy North America (US), L.P. PacifiCorp East Bonneville Power Administration NF 29
Shell Energy North America (US), L.P. PacifiCorp East Sierra Pacific Power NF 30
Shell Energy North America (US), L.P. PacifiCorp East Sierra Pacific Power SFP 31
Shell Energy North America (US), L.P. Idaho Power Company PacifiCorp East NF 32
Shell Energy North America (US), L.P. Idaho Power Company PacifiCorp East NF 33
34
FERC FORM NO. 1 (ED. 12-90) Page 328.7
TOTAL
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofIdaho Power Company X 04/15/2015 2014/Q4
Line
No.
Payment By
(c)(b)(a)(d)
Statistical
cation
Classifi-
(Footnote Affiliation)
(Including transactions referred to as 'wheeling')
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)Energy Received From Energy Delivered To
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities, 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.
Shell Energy North America (US), L.P. Idaho Power Company Sierra Pacific Power NF 1
Shell Energy North America (US), L.P. Idaho Power Company Sierra Pacific Power SFP 2
Shell Energy North America (US), L.P. Idaho Power Company Bonneville Power Administration NF 3
Shell Energy North America (US), L.P. Idaho Power Company Sierra Pacific Power SFP 4
Shell Energy North America (US), L.P. PacifiCorp West Bonneville Power Administration NF 5
Shell Energy North America (US), L.P. PacifiCorp West Sierra Pacific Power SFP 6
Shell Energy North America (US), L.P. NorthWestern/PacifiCorp East Bonneville Power Administration NF 7
Shell Energy North America (US), L.P. NorthWestern/PacifiCorp East Sierra Pacific Power NF 8
Shell Energy North America (US), L.P. Bonneville Power Administration PacifiCorp East NF 9
Shell Energy North America (US), L.P. Bonneville Power Administration Sierra Pacific Power NF 10
Shell Energy North America (US), L.P. Avista PacifiCorp East NF 11
Shell Energy North America (US), L.P. Avista Sierra Pacific Power NF 12
Shell Energy North America (US), L.P. Avista Sierra Pacific Power SFP 13
Shell Energy North America (US), L.P. Sierra Pacific Power PacifiCorp East NF 14
Shell Energy North America (US), L.P. Sierra Pacific Power PacifiCorp East SFP 15
Shell Energy North America (US), L.P. Sierra Pacific Power PacifiCorp East NF 16
Shell Energy North America (US), L.P. Sierra Pacific Power Bonneville Power Administration NF 17
Shell Energy North America (US), L.P. Sierra Pacific Power Bonneville Power Administration SFP 18
Shell Energy North America (US), L.P. Sierra Pacific Power Bonneville Power Administration LFP 19
Shell Energy North America (US), L.P. Sierra Pacific Power Avista NF 20
Shell Energy North America (US), L.P. Sierra Pacific Power Sierra Pacific Power NF 21
Shell Energy North America (US), L.P. Sierra Pacific Power Sierra Pacific Power SFP 22
Shell Energy North America (US), L.P. Sierra Pacific Power PacifiCorp East NF 23
Shell Energy North America (US), L.P. Sierra Pacific Power NorthWestern/PacifiCorp East NF 24
Shell Energy North America (US), L.P. Sierra Pacific Power Bonneville Power Administration NF 25
Shell Energy North America (US), L.P. Idaho Power Company PacifiCorp East NF 26
Shell Energy North America (US), L.P. Idaho Power Company PacifiCorp East SFP 27
Shell Energy North America (US), L.P. Idaho Power Company Bonneville Power Administration NF 28
Shell Energy North America (US), L.P. Idaho Power Company Bonneville Power Administration SFP 29
Shell Energy North America (US), L.P.AD 30
Sierra Pacific Power Co. PacifiCorp East Sierra Pacific Power NF 31
Sierra Pacific Power Co. NorthWestern/PacifiCorp East Sierra Pacific Power NF 32
Sierra Pacific Power Co. PacifiCorp East Sierra Pacific Power NF 33
34
FERC FORM NO. 1 (ED. 12-90) Page 328.8
TOTAL
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofIdaho Power Company X 04/15/2015 2014/Q4
Line
No.
Payment By
(c)(b)(a)(d)
Statistical
cation
Classifi-
(Footnote Affiliation)
(Including transactions referred to as 'wheeling')
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)Energy Received From Energy Delivered To
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities, 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.
Sierra Pacific Power Co. Idaho Power Company Sierra Pacific Power NF 1
Sierra Pacific Power Co. Avista Sierra Pacific Power NF 2
Sierra Pacific Power Co. Sierra Pacific Power PacifiCorp East NF 3
Sierra Pacific Power Co. Sierra Pacific Power Bonneville Power Administration NF 4
Sierra Pacific Power Co.AD 5
Southern California Edison PacifiCorp East Sierra Pacific Power NF 6
Southern California Edison Bonneville Power Administration PacifiCorp East NF 7
Southern California Edison AD 8
Tenaska Power Services Co. NorthWestern/PacifiCorp East PacifiCorp East NF 9
Tenaska Power Services Co. NorthWestern/PacifiCorp East PacifiCorp East NF 10
Tenaska Power Services Co. NorthWestern/PacifiCorp East Sierra Pacific Power NF 11
Tenaska Power Services Co. PacifiCorp East Bonneville Power Administration NF 12
Tenaska Power Services Co. PacifiCorp West PacifiCorp East NF 13
Tenaska Power Services Co. PacifiCorp West PacifiCorp East SFP 14
Tenaska Power Services Co. Bonneville Power Administration PacifiCorp East NF 15
Tenaska Power Services Co. Bonneville Power Administration PacifiCorp East NF 16
Tenaska Power Services Co. Bonneville Power Administration Sierra Pacific Power NF 17
Tenaska Power Services Co. Avista PacifiCorp East NF 18
Tenaska Power Services Co. Avista Sierra Pacific Power NF 19
Tenaska Power Services Co.AD 20
The Energy Authority, Inc. PacifiCorp East Bonneville Power Administration NF 21
The Energy Authority, Inc. Bonneville Power Administration PacifiCorp East NF 22
The Energy Authority, Inc. Bonneville Power Administration PacifiCorp East NF 23
Transalta Energy Marketing (U.S.) Inc. PacifiCorp East NorthWestern/PacifiCorp East NF 24
Transalta Energy Marketing (U.S.) Inc. PacifiCorp East Idaho Power Company NF 25
Transalta Energy Marketing (U.S.) Inc. PacifiCorp East Bonneville Power Administration NF 26
Transalta Energy Marketing (U.S.) Inc. PacifiCorp East Sierra Pacific Power NF 27
Transalta Energy Marketing (U.S.) Inc. NorthWestern/PacifiCorp East PacifiCorp East NF 28
Transalta Energy Marketing (U.S.) Inc. NorthWestern/PacifiCorp East Sierra Pacific Power NF 29
Transalta Energy Marketing (U.S.) Inc. PacifiCorp East NorthWestern/PacifiCorp East NF 30
Transalta Energy Marketing (U.S.) Inc. PacifiCorp East Bonneville Power Administration NF 31
Transalta Energy Marketing (U.S.) Inc. PacifiCorp East Sierra Pacific Power NF 32
Transalta Energy Marketing (U.S.) Inc. Idaho Power Company PacifiCorp East NF 33
34
FERC FORM NO. 1 (ED. 12-90) Page 328.9
TOTAL
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofIdaho Power Company X 04/15/2015 2014/Q4
Line
No.
Payment By
(c)(b)(a)(d)
Statistical
cation
Classifi-
(Footnote Affiliation)
(Including transactions referred to as 'wheeling')
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)Energy Received From Energy Delivered To
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities, 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.
Transalta Energy Marketing (U.S.) Inc. Idaho Power Company Sierra Pacific Power NF 1
Transalta Energy Marketing (U.S.) Inc. Bonneville Power Administration PacifiCorp East NF 2
Transalta Energy Marketing (U.S.) Inc. Bonneville Power Administration Sierra Pacific Power NF 3
Transalta Energy Marketing (U.S.) Inc. Sierra Pacific Power Idaho Power Company NF 4
Transalta Energy Marketing (U.S.) Inc. Sierra Pacific Power Bonneville Power Administration NF 5
Transalta Energy Marketing (U.S.) Inc.AD 6
United Materials of Great Falls NorthWestern/PacifiCorp East Idaho Power Company NF 7
Utah Associated Municipal Power PacifiCorp East Sierra Pacific Power NF 8
Utah Associated Municipal Power Sierra Pacific Power PacifiCorp East NF 9
Utah Associated Municipal Power AD 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
FERC FORM NO. 1 (ED. 12-90) Page 328.10
TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
(Including transactions reffered to as 'wheeling')
FERC RateSchedule of
Tariff Number
(e)
Point of Receipt(Subsatation or Other
Designation)
(f)
Point of Delivery(Substation or Other
(g)
BillingDemand
(MW)
(h)
TRANSFER OF ENERGY
MegaWatt HoursReceived(i)Delivered(j)
MegaWatt HoursDesignation)
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or 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.
9 333,238 333,238 1
9 2
9 267,961 267,961 3
9 4
9 1,236,894 1,236,894 5
9 6
9 7
Minidoka, IdahoLegacy Various in Idaho 8,846 8,846 8
4 308,061 308,061 9
9 2,049 2,049 10
9 11
LaGrande, OregonLegacy Various in Idaho 16,782 16,782 12
JEFF5/6 IPCO 15,555 15,555 13
BRDY5/6 IPCO 3,764 3,764 14
JEFF8 LOLO 798 798 15
8 16
BPAT.NWMT8 BRDY 25 25 17
8 18
BPAT.NWMT8 M345 1,719 1,719 19
LAGRANDE8 LAGRANDE 1,079 1,079 20
LAGRANDE8 M345 34,394 34,394 21
LOLO8 LAGRANDE 322 322 22
LOLO8 M345 5,429 5,429 23
8 24
AVAT.NWMT8 M345 46 46 25
BORA8 BPAT.NWMT 818 818 26
BORA8 LAGRANDE 4,923 4,923 27
BPAT.NWMT8 LAGRANDE 775 775 28
BPAT.NWMT8 M345 944 944 29
BRDY8 M345 396 396 30
ENPR8 BORA 740 740 31
ENPR7 BORA 1,269 1,269 32
ENPR8 M345 916 916 33
34
FERC FORM NO. 1 (ED. 12-90) Page 329
0 6,721,533 6,721,533
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
(Including transactions reffered to as 'wheeling')
FERC RateSchedule of
Tariff Number
(e)
Point of Receipt(Subsatation or Other
Designation)
(f)
Point of Delivery(Substation or Other
(g)
BillingDemand
(MW)
(h)
TRANSFER OF ENERGY
MegaWatt HoursReceived(i)Delivered(j)
MegaWatt HoursDesignation)
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or 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.
ENPR7 M345 320 320 1
JBSN8 BORA 467 467 2
JBSN8 BPAT.NWMT 20 20 3
JBSN8 LAGRANDE 735 735 4
JBSN8 M345 160 160 5
JEFF8 M345 254 254 6
LAGRANDE8 BORA 468 468 7
LAGRANDE8 M345 667 667 8
LOLO8 BORA 984 984 9
LOLO7 BORA 1,318 1,318 10
LOLO8 LAGRANDE 25 25 11
LOLO8 M345 66,652 66,652 12
LOLO7 M345 5,416 5,416 13
M3458 LAGRANDE 1,400 1,400 14
8 15
8 16
8 17
BORA8 M345 62 62 18
BPAT.NWMT8 BORA 120 120 19
BPAT.NWMT8 BRDY 49 49 20
BPAT.NWMT8 M345 1,969 1,969 21
HMWY8 BORA 3,541 3,541 22
HMWY8 M345 2,714 2,714 23
JEFF8 M345 100 100 24
LAGRANDE8 BORA 4,321 4,321 25
LAGRANDE8 M345 25,422 25,422 26
LOLO8 BORA 412 412 27
LOLO8 M345 263 263 28
M3458 LAGRANDE 1,834 1,834 29
OBBLPR8 LAGRANDE 20 20 30
8 31
8 32
AVAT.NWMT8 BRDY 417 417 33
34
FERC FORM NO. 1 (ED. 12-90) Page 329.1
0 6,721,533 6,721,533
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
(Including transactions reffered to as 'wheeling')
FERC RateSchedule of
Tariff Number
(e)
Point of Receipt(Subsatation or Other
Designation)
(f)
Point of Delivery(Substation or Other
(g)
BillingDemand
(MW)
(h)
TRANSFER OF ENERGY
MegaWatt HoursReceived(i)Delivered(j)
MegaWatt HoursDesignation)
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or 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.
AVAT.NWMT8 HMWY 87 87 1
AVAT.NWMT8 LAGRANDE 51 51 2
AVAT.NWMT8 M345 22,002 22,002 3
AVAT.NWMT7 M345 47,695 47,695 4
BORA8 BPAT.NWMT 281 281 5
BORA8 HMWY 45 45 6
BORA8 JEFF 25 25 7
BORA8 LAGRANDE 426 426 8
BORA8 M345 7,224 7,224 9
BPAT.NWMT8 BORA 638 638 10
BPAT.NWMT8 BRDY 96 96 11
BPAT.NWMT8 ENPR 360 360 12
BPAT.NWMT8 HMWY 75 75 13
BPAT.NWMT8 LAGRANDE 18,742 18,742 14
BPAT.NWMT8 M345 11,972 11,972 15
BPAT.NWMT7 M345 3,262 3,262 16
BRDY8 AVAT.NWMT 82 82 17
BRDY8 BORA 2 2 18
BRDY8 BPAT.NWMT 118 118 19
BRDY8 HMWY 392 392 20
BRDY8 LAGRANDE 12,636 12,636 21
BRDY8 M345 35,780 35,780 22
BRDY7 M345 510 510 23
ENPR8 BRDY 30 30 24
GSHN8 HMWY 96 96 25
HMWY8 BORA 12,608 12,608 26
HMWY8 BRDY 1,638 1,638 27
HMWY8 JBSN 942 942 28
HMWY8 M345 3,679 3,679 29
JBSN8 BORA 1,975 1,975 30
JBSN8 HMWY 25 25 31
JBSN8 LAGRANDE 250 250 32
JBSN8 M345 298 298 33
34
FERC FORM NO. 1 (ED. 12-90) Page 329.2
0 6,721,533 6,721,533
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
(Including transactions reffered to as 'wheeling')
FERC RateSchedule of
Tariff Number
(e)
Point of Receipt(Subsatation or Other
Designation)
(f)
Point of Delivery(Substation or Other
(g)
BillingDemand
(MW)
(h)
TRANSFER OF ENERGY
MegaWatt HoursReceived(i)Delivered(j)
MegaWatt HoursDesignation)
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or 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.
JBWT8 BORA 14 14 1
JBWT8 LAGRANDE 1,930 1,930 2
JBWT8 M345 1,530 1,530 3
JEFF8 BORA 2,581 2,581 4
JEFF8 BRDY 128 128 5
JEFF8 ENPR 258 258 6
JEFF8 HMWY 13 13 7
JEFF8 LAGRANDE 10,801 10,801 8
JEFF8 M345 139,494 139,494 9
LAGRANDE8 BORA 6,060 6,060 10
LAGRANDE8 BRDY 2,870 2,870 11
LAGRANDE8 JEFF 35 35 12
LAGRANDE8 M345 22,679 22,679 13
LOLO8 BORA 4,118 4,118 14
LOLO8 BRDY 14 14 15
LOLO8 JEFF 80 80 16
LOLO8 LAGRANDE 25 25 17
LOLO8 M345 10,415 10,415 18
LOLO7 M345 3,572 3,572 19
M3458 BORA 2,078 2,078 20
M3458 BPAT.NWMT 759 759 21
M3458 BRDY 313 313 22
M3458 JEFF 135 135 23
M3458 LAGRANDE 1,198 1,198 24
8 25
BORA8 M345 594 594 26
BRDY8 M345 7,371 7,371 27
BRDY7 M345 4,984 4,984 28
JEFF8 M345 4,471 4,471 29
LAGRANDE8 M345 2,531 2,531 30
LOLO8 M345 673 673 31
LOLO7 M345 800 800 32
M3458 BRDY 260 260 33
34
FERC FORM NO. 1 (ED. 12-90) Page 329.3
0 6,721,533 6,721,533
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
(Including transactions reffered to as 'wheeling')
FERC RateSchedule of
Tariff Number
(e)
Point of Receipt(Subsatation or Other
Designation)
(f)
Point of Delivery(Substation or Other
(g)
BillingDemand
(MW)
(h)
TRANSFER OF ENERGY
MegaWatt HoursReceived(i)Delivered(j)
MegaWatt HoursDesignation)
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or 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.
M3458 HMWY 790 790 1
M3458 LAGRANDE 1,360 1,360 2
8 3
BORA8 ENPR 1,684 1,684 4
BORA8 HMWY 444 444 5
BORA7 KPRT 1,340,222 1,340,222 6
BORA8 LAGRANDE 2,195 2,195 7
BRDY8 BRDY 1,096 1,096 8
BRDY7 BRDY 76 76 9
BRDY8 ENPR 300 300 10
BRDY8 KPRT 5,243 5,243 11
BRDY8 LAGRANDE 500 500 12
ENPR8 BORA 211,505 211,505 13
ENPR7 BORA 117,399 117,399 14
ENPR8 LAGRANDE 264 264 15
HMWY7 M345 3,676 3,676 16
IPCOGEN8 BORA 50 50 17
JBWT8 BORA 1,614 1,614 18
JBWT8 BRDY 19 19 19
JBWT7 BRDY 162,792 162,792 20
JBWT8 GSHN 36,135 36,135 21
JBWT7 HMWY 644,162 644,162 22
JBWT8 KPRT 3,673 3,673 23
JBWT8 LAGRANDE 31,250 31,250 24
JBWT8 LOLO 123 123 25
LAGRANDE8 BORA 292 292 26
LOLO8 BORA 1,098 1,098 27
LOLO8 ENPR 3,896 3,896 28
LOLO8 LAGRANDE 3 3 29
8 30
BORA8 BPAT.NWMT 681 681 31
BORA8 LAGRANDE 75 75 32
BPAT.NWMT8 LAGRANDE 15 15 33
34
FERC FORM NO. 1 (ED. 12-90) Page 329.4
0 6,721,533 6,721,533
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
(Including transactions reffered to as 'wheeling')
FERC RateSchedule of
Tariff Number
(e)
Point of Receipt(Subsatation or Other
Designation)
(f)
Point of Delivery(Substation or Other
(g)
BillingDemand
(MW)
(h)
TRANSFER OF ENERGY
MegaWatt HoursReceived(i)Delivered(j)
MegaWatt HoursDesignation)
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or 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.
BPAT.NWMT8 M345 501 501 1
BRDY8 LAGRANDE 13,476 13,476 2
HMWY8 BORA 3,837 3,837 3
HMWY8 M345 1,092 1,092 4
JEFF8 LAGRANDE 5,919 5,919 5
LAGRANDE8 M345 6,238 6,238 6
M3458 LAGRANDE 719 719 7
8 8
BORA8 BPAT.NWMT 476 476 9
BORA8 BRDY 4 4 10
BORA8 ENPR 32 32 11
BORA8 HMWY 1,853 1,853 12
BORA8 JEFF 14 14 13
BORA8 LAGRANDE 11,765 11,765 14
BORA8 M345 121 121 15
BPAT.NWMT8 BORA 633 633 16
BPAT.NWMT7 BORA 66,625 66,625 17
BPAT.NWMT8 BRDY 157 157 18
BPAT.NWMT8 HMWY 5 5 19
BPAT.NWMT8 LAGRANDE 397 397 20
BPAT.NWMT8 M345 3,564 3,564 21
BRDY8 BPAT.NWMT 520 520 22
BRDY8 ENPR 95 95 23
BRDY8 HMWY 1,148 1,148 24
BRDY8 LAGRANDE 7,809 7,809 25
BRDY8 M345 3,974 3,974 26
ENPR8 BORA 108,510 108,510 27
ENPR7 BORA 87,870 87,870 28
ENPR8 BRDY 868 868 29
ENPR8 M345 2,887 2,887 30
GSHN8 BPAT.NWMT 210 210 31
GSHN8 BRDY 2 2 32
GSHN8 HMWY 560 560 33
34
FERC FORM NO. 1 (ED. 12-90) Page 329.5
0 6,721,533 6,721,533
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
(Including transactions reffered to as 'wheeling')
FERC RateSchedule of
Tariff Number
(e)
Point of Receipt(Subsatation or Other
Designation)
(f)
Point of Delivery(Substation or Other
(g)
BillingDemand
(MW)
(h)
TRANSFER OF ENERGY
MegaWatt HoursReceived(i)Delivered(j)
MegaWatt HoursDesignation)
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or 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.
GSHN8 JEFF 45 45 1
GSHN8 LAGRANDE 2,927 2,927 2
GSHN8 M345 9 9 3
HMWY8 BORA 81,942 81,942 4
HMWY7 BORA 22,273 22,273 5
HMWY8 BRDY 5,275 5,275 6
HMWY8 JBSN 50 50 7
HMWY8 M345 35,568 35,568 8
HMWY7 M345 4,810 4,810 9
JBSN8 BPAT.NWMT 27 27 10
JBSN8 JEFF 40 40 11
JBSN8 LAGRANDE 925 925 12
JBSN8 M345 47 47 13
JBWT8 ENPR 40 40 14
JBWT8 HMWY 330 330 15
JBWT8 LAGRANDE 2,388 2,388 16
JEFF7 BORA 624 624 17
JEFF8 BRDY 46 46 18
JEFF8 HMWY 445 445 19
JEFF8 LAGRANDE 905 905 20
JEFF8 M345 15 15 21
LAGRANDE8 BORA 11,348 11,348 22
LAGRANDE7 BORA 2,347 2,347 23
LAGRANDE8 BRDY 6,767 6,767 24
LAGRANDE8 JBSN 355 355 25
LAGRANDE8 M345 77,404 77,404 26
LAGRANDE7 M345 7,666 7,666 27
LOLO8 BORA 170 170 28
LOLO8 M345 528 528 29
M3458 BPAT.NWMT 8 8 30
M3458 HMWY 193 193 31
M3458 JEFF 3 3 32
M3458 LAGRANDE 542 542 33
34
FERC FORM NO. 1 (ED. 12-90) Page 329.6
0 6,721,533 6,721,533
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
(Including transactions reffered to as 'wheeling')
FERC RateSchedule of
Tariff Number
(e)
Point of Receipt(Subsatation or Other
Designation)
(f)
Point of Delivery(Substation or Other
(g)
BillingDemand
(MW)
(h)
TRANSFER OF ENERGY
MegaWatt HoursReceived(i)Delivered(j)
MegaWatt HoursDesignation)
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or 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.
8 1
BPAT.NWMT8 LAGRANDE 8,009 8,009 2
BRDY8 LAGRANDE 12,328 12,328 3
BRDY8 M345 263 263 4
JEFF8 BORA 987 987 5
JEFF8 LAGRANDE 10,932 10,932 6
JEFF8 M345 175 175 7
8 8
HMWY8 AVAT.NWMT 8 8 9
JBSN8 LAGRANDE 1,296 1,296 10
JBSN8 LOLO 672 672 11
LOLO8 LAGRANDE 1,358 1,358 12
8 13
BORA8 BPAT.NWMT 432 432 14
BORA8 JEFF 200 200 15
BORA7 JEFF 1,968 1,968 16
BRDY8 AVAT.NWMT 72 72 17
BRDY8 JEFF 150 150 18
BRDY7 JEFF 727 727 19
JBSN8 BRDY 200 200 20
LOLO8 BORA 2,063 2,063 21
LOLO7 BORA 1,380 1,380 22
8 23
8 24
8 25
BORA8 LAGRANDE 1,065 1,065 26
BORA8 M345 336 336 27
BORA7 M345 756 756 28
BRDY8 LAGRANDE 22,052 22,052 29
BRDY8 M345 26,201 26,201 30
BRDY7 M345 23,580 23,580 31
HMWY8 BORA 407 407 32
HMWY8 BRDY 1,790 1,790 33
34
FERC FORM NO. 1 (ED. 12-90) Page 329.7
0 6,721,533 6,721,533
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
(Including transactions reffered to as 'wheeling')
FERC RateSchedule of
Tariff Number
(e)
Point of Receipt(Subsatation or Other
Designation)
(f)
Point of Delivery(Substation or Other
(g)
BillingDemand
(MW)
(h)
TRANSFER OF ENERGY
MegaWatt HoursReceived(i)Delivered(j)
MegaWatt HoursDesignation)
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or 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.
HMWY8 M345 45,891 45,891 1
HMWY7 M345 6,787 6,787 2
IPCOGEN8 LAGRANDE 845 845 3
IPCOGEN7 LAGRANDE 80 80 4
JBSN8 LAGRANDE 8 8 5
JBSN7 M345 2,200 2,200 6
JEFF8 LAGRANDE 2,019 2,019 7
JEFF8 M345 1,154 1,154 8
LAGRANDE8 BRDY 7,743 7,743 9
LAGRANDE8 M345 87,127 87,127 10
LOLO8 BORA 23 23 11
LOLO8 M345 68,925 68,925 12
LOLO7 M345 25,524 25,524 13
LYPK8 BORA 8,486 8,486 14
LYPK7 BORA 2,469 2,469 15
LYPK8 BRDY 1,339 1,339 16
LYPK8 LAGRANDE 16,513 16,513 17
LYPK7 LAGRANDE 96 96 18
LYPK7 LAGRANDE 36,582 36,582 19
LYPK8 LOLO 18 18 20
LYPK8 M345 43,517 43,517 21
LYPK7 M345 198,617 198,617 22
M3458 BRDY 150 150 23
M3458 JEFF 8 8 24
M3458 LAGRANDE 1,655 1,655 25
MDSK8 BORA 256 256 26
MDSK7 BORA 3,672 3,672 27
MDSK8 LAGRANDE 1,485 1,485 28
OBBLPR7 LAGRANDE 400 400 29
8 30
BORA8 M345 130 130 31
BPAT.NWMT8 M345 556 556 32
BRDY8 M345 50 50 33
34
FERC FORM NO. 1 (ED. 12-90) Page 329.8
0 6,721,533 6,721,533
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
(Including transactions reffered to as 'wheeling')
FERC RateSchedule of
Tariff Number
(e)
Point of Receipt(Subsatation or Other
Designation)
(f)
Point of Delivery(Substation or Other
(g)
BillingDemand
(MW)
(h)
TRANSFER OF ENERGY
MegaWatt HoursReceived(i)Delivered(j)
MegaWatt HoursDesignation)
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or 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.
HMWY8 M345 280 280 1
LOLO8 M345 200 200 2
M3458 BORA 1,311 1,311 3
M3458 LAGRANDE 361 361 4
8 5
BORA8 M345 227 227 6
LAGRANDE8 BORA 605 605 7
8 8
BPAT.NWMT8 BORA 308 308 9
BPAT.NWMT8 BRDY 846 846 10
BPAT.NWMT8 M345 128 128 11
BRDY8 LAGRANDE 941 941 12
JBSN8 BRDY 342 342 13
JBSN7 BRDY 4,736 4,736 14
LAGRANDE8 BORA 600 600 15
LAGRANDE8 BRDY 5 5 16
LAGRANDE8 M345 22 22 17
LOLO8 BORA 342 342 18
LOLO8 M345 600 600 19
8 20
BRDY8 LAGRANDE 90 90 21
LAGRANDE8 BORA 563 563 22
LAGRANDE8 BRDY 2,793 2,793 23
BORA8 BPAT.NWMT 11 11 24
BORA8 HMWY 429 429 25
BORA8 LAGRANDE 3,504 3,504 26
BORA8 M345 80 80 27
BPAT.NWMT8 BORA 66 66 28
BPAT.NWMT8 M345 29 29 29
BRDY8 BPAT.NWMT 160 160 30
BRDY8 LAGRANDE 300 300 31
BRDY8 M345 20 20 32
HMWY8 BORA 39,138 39,138 33
34
FERC FORM NO. 1 (ED. 12-90) Page 329.9
0 6,721,533 6,721,533
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
(Including transactions reffered to as 'wheeling')
FERC RateSchedule of
Tariff Number
(e)
Point of Receipt(Subsatation or Other
Designation)
(f)
Point of Delivery(Substation or Other
(g)
BillingDemand
(MW)
(h)
TRANSFER OF ENERGY
MegaWatt HoursReceived(i)Delivered(j)
MegaWatt HoursDesignation)
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or 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.
HMWY8 M345 1,802 1,802 1
LAGRANDE8 BORA 6,049 6,049 2
LAGRANDE8 M345 4,592 4,592 3
M3458 HMWY 50 50 4
M3458 LAGRANDE 121 121 5
8 6
AVAT.NWMT8 IPCO 1 1 7
BORA8 M345 10,848 10,848 8
M3458 BORA 27 27 9
8 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
FERC FORM NO. 1 (ED. 12-90) Page 329.10
0 6,721,533 6,721,533
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
(m)(l)(k)(n)
(k+l+m)
Total Revenues ($)
(Including transactions reffered to as 'wheeling')
($)
Energy Charges
($)
(Other Charges)Demand Charges
($)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from 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.
1,270,731 1,297,718 26,987 1
-20,161 -20,161 2
1,309,561 1,166,427 -143,134 3
-9,420 -9,420 4
4,630,939 4,687,109 56,170 5
-45,830 -45,830 6
-8,758 -8,758 7
14,330 14,330 8
184,783 184,783 9
8,018 9,325 1,307 10
-114 -114 11
54,702 54,702 12
18,455 18,455 13
4,466 4,466 14
2,080 2,080 15
-69 -69 16
117 117 17
-51 -51 18
6,616 6,616 19
4,153 4,153 20
132,383 132,383 21
1,239 1,239 22
20,896 20,896 23
-989 -989 24
143 143 25
2,537 2,537 26
15,268 15,268 27
2,404 2,404 28
2,928 2,928 29
1,228 1,228 30
2,295 2,295 31
3,936 3,936 32
2,841 2,841 33
34
FERC FORM NO. 1 (ED. 12-90) Page 330
7,189,668 22,627,916 0 15,438,248
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
(m)(l)(k)(n)
(k+l+m)
Total Revenues ($)
(Including transactions reffered to as 'wheeling')
($)
Energy Charges
($)
(Other Charges)Demand Charges
($)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the amount
of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including out of
period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge
shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column (n).
Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
992 992 1
1,448 1,448 2
62 62 3
2,280 2,280 4
496 496 5
788 788 6
1,451 1,451 7
2,069 2,069 8
3,052 3,052 9
4,088 4,088 10
78 78 11
206,715 206,715 12
16,797 16,797 13
4,342 4,342 14
-18,793 -18,793 15
-349 -349 16
-20 -20 17
259 259 18
502 502 19
205 205 20
8,237 8,237 21
14,813 14,813 22
11,353 11,353 23
418 418 24
18,076 18,076 25
106,346 106,346 26
1,724 1,724 27
1,100 1,100 28
7,672 7,672 29
84 84 30
-395 -395 31
-10 -10 32
1,617 1,617 33
34
FERC FORM NO. 1 (ED. 12-90) Page 330.1
7,189,668 22,627,916 0 15,438,248
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
(m)(l)(k)(n)
(k+l+m)
Total Revenues ($)
(Including transactions reffered to as 'wheeling')
($)
Energy Charges
($)
(Other Charges)Demand Charges
($)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the amount
of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including out of
period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge
shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column (n).
Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
337 337 1
198 198 2
85,333 85,333 3
184,982 184,982 4
1,090 1,090 5
175 175 6
97 97 7
1,652 1,652 8
28,018 28,018 9
2,474 2,474 10
372 372 11
1,396 1,396 12
291 291 13
72,690 72,690 14
46,433 46,433 15
12,651 12,651 16
318 318 17
8 8 18
458 458 19
1,520 1,520 20
49,008 49,008 21
138,770 138,770 22
1,978 1,978 23
116 116 24
372 372 25
48,899 48,899 26
6,353 6,353 27
3,653 3,653 28
14,269 14,269 29
7,660 7,660 30
97 97 31
970 970 32
1,156 1,156 33
34
FERC FORM NO. 1 (ED. 12-90) Page 330.2
7,189,668 22,627,916 0 15,438,248
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
(m)(l)(k)(n)
(k+l+m)
Total Revenues ($)
(Including transactions reffered to as 'wheeling')
($)
Energy Charges
($)
(Other Charges)Demand Charges
($)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the amount
of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including out of
period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge
shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column (n).
Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
54 54 1
7,485 7,485 2
5,934 5,934 3
10,010 10,010 4
496 496 5
1,001 1,001 6
50 50 7
41,891 41,891 8
541,018 541,018 9
23,503 23,503 10
11,131 11,131 11
136 136 12
87,959 87,959 13
15,971 15,971 14
54 54 15
310 310 16
97 97 17
40,394 40,394 18
13,854 13,854 19
8,059 8,059 20
2,944 2,944 21
1,214 1,214 22
524 524 23
4,646 4,646 24
-5,250 -5,250 25
2,419 2,419 26
30,019 30,019 27
20,298 20,298 28
18,208 18,208 29
10,308 10,308 30
2,741 2,741 31
3,258 3,258 32
1,059 1,059 33
34
FERC FORM NO. 1 (ED. 12-90) Page 330.3
7,189,668 22,627,916 0 15,438,248
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
(m)(l)(k)(n)
(k+l+m)
Total Revenues ($)
(Including transactions reffered to as 'wheeling')
($)
Energy Charges
($)
(Other Charges)Demand Charges
($)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the amount
of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including out of
period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge
shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column (n).
Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
3,217 3,217 1
5,539 5,539 2
-28 -28 3
10,055 10,055 4
2,651 2,651 5
6
13,106 13,106 7
6,544 6,544 8
454 454 9
1,791 1,791 10
31,305 31,305 11
2,985 2,985 12
1,262,864 1,262,864 13
700,972 700,972 14
1,576 1,576 15
21,949 21,949 16
299 299 17
9,637 9,637 18
113 113 19
972,006 972,006 20
215,757 215,757 21
3,846,194 3,846,194 22
21,931 21,931 23
186,589 186,589 24
734 734 25
1,744 1,744 26
6,556 6,556 27
23,262 23,262 28
18 18 29
-106,595 -106,595 30
3,035 3,035 31
334 334 32
67 67 33
34
FERC FORM NO. 1 (ED. 12-90) Page 330.4
7,189,668 22,627,916 0 15,438,248
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
(m)(l)(k)(n)
(k+l+m)
Total Revenues ($)
(Including transactions reffered to as 'wheeling')
($)
Energy Charges
($)
(Other Charges)Demand Charges
($)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the amount
of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including out of
period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge
shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column (n).
Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
2,232 2,232 1
60,049 60,049 2
17,098 17,098 3
4,866 4,866 4
26,375 26,375 5
27,797 27,797 6
3,204 3,204 7
-145 -145 8
2,036 2,036 9
17 17 10
137 137 11
7,926 7,926 12
60 60 13
50,321 50,321 14
518 518 15
2,707 2,707 16
284,966 284,966 17
672 672 18
21 21 19
1,698 1,698 20
15,244 15,244 21
2,224 2,224 22
406 406 23
4,910 4,910 24
33,400 33,400 25
16,997 16,997 26
464,115 464,115 27
375,835 375,835 28
3,713 3,713 29
12,348 12,348 30
898 898 31
9 9 32
2,395 2,395 33
34
FERC FORM NO. 1 (ED. 12-90) Page 330.5
7,189,668 22,627,916 0 15,438,248
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
(m)(l)(k)(n)
(k+l+m)
Total Revenues ($)
(Including transactions reffered to as 'wheeling')
($)
Energy Charges
($)
(Other Charges)Demand Charges
($)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the amount
of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including out of
period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge
shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column (n).
Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
192 192 1
12,519 12,519 2
38 38 3
350,480 350,480 4
95,265 95,265 5
22,562 22,562 6
214 214 7
152,130 152,130 8
20,573 20,573 9
115 115 10
171 171 11
3,956 3,956 12
201 201 13
171 171 14
1,411 1,411 15
10,214 10,214 16
2,669 2,669 17
197 197 18
1,903 1,903 19
3,871 3,871 20
64 64 21
48,537 48,537 22
10,039 10,039 23
28,944 28,944 24
1,518 1,518 25
331,070 331,070 26
32,789 32,789 27
727 727 28
2,258 2,258 29
34 34 30
825 825 31
13 13 32
2,318 2,318 33
34
FERC FORM NO. 1 (ED. 12-90) Page 330.6
7,189,668 22,627,916 0 15,438,248
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
(m)(l)(k)(n)
(k+l+m)
Total Revenues ($)
(Including transactions reffered to as 'wheeling')
($)
Energy Charges
($)
(Other Charges)Demand Charges
($)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the amount
of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including out of
period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge
shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column (n).
Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
-34,259 -34,259 1
34,098 34,098 2
52,486 52,486 3
1,120 1,120 4
4,202 4,202 5
46,542 46,542 6
745 745 7
-1,188 -1,188 8
25 25 9
4,055 4,055 10
2,103 2,103 11
4,249 4,249 12
-720 -720 13
1,522 1,522 14
705 705 15
6,934 6,934 16
254 254 17
528 528 18
2,561 2,561 19
705 705 20
7,268 7,268 21
4,862 4,862 22
-2,844 -2,844 23
-23,282 -23,282 24
-1,145 -1,145 25
4,717 4,717 26
1,488 1,488 27
3,349 3,349 28
97,680 97,680 29
116,058 116,058 30
104,448 104,448 31
1,803 1,803 32
7,929 7,929 33
34
FERC FORM NO. 1 (ED. 12-90) Page 330.7
7,189,668 22,627,916 0 15,438,248
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
(m)(l)(k)(n)
(k+l+m)
Total Revenues ($)
(Including transactions reffered to as 'wheeling')
($)
Energy Charges
($)
(Other Charges)Demand Charges
($)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the amount
of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including out of
period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge
shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column (n).
Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
203,275 203,275 1
30,063 30,063 2
3,743 3,743 3
354 354 4
35 35 5
9,745 9,745 6
8,943 8,943 7
5,112 5,112 8
34,298 34,298 9
385,931 385,931 10
102 102 11
305,305 305,305 12
113,059 113,059 13
37,589 37,589 14
10,936 10,936 15
5,931 5,931 16
73,145 73,145 17
425 425 18
162,041 162,041 19
80 80 20
192,760 192,760 21
879,779 879,779 22
664 664 23
35 35 24
7,331 7,331 25
1,134 1,134 26
16,265 16,265 27
6,578 6,578 28
1,772 1,772 29
-1,783 -1,783 30
557 557 31
2,381 2,381 32
214 214 33
34
FERC FORM NO. 1 (ED. 12-90) Page 330.8
7,189,668 22,627,916 0 15,438,248
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
(m)(l)(k)(n)
(k+l+m)
Total Revenues ($)
(Including transactions reffered to as 'wheeling')
($)
Energy Charges
($)
(Other Charges)Demand Charges
($)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the amount
of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including out of
period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge
shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column (n).
Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
1,199 1,199 1
856 856 2
5,613 5,613 3
1,546 1,546 4
-14,169 -14,169 5
1,125 1,125 6
2,999 2,999 7
-4 -4 8
1,000 1,000 9
2,747 2,747 10
416 416 11
3,056 3,056 12
1,111 1,111 13
15,380 15,380 14
1,948 1,948 15
16 16 16
71 71 17
1,111 1,111 18
1,948 1,948 19
-96 -96 20
381 381 21
2,382 2,382 22
11,818 11,818 23
43 43 24
1,696 1,696 25
13,854 13,854 26
316 316 27
261 261 28
115 115 29
633 633 30
1,186 1,186 31
79 79 32
154,739 154,739 33
34
FERC FORM NO. 1 (ED. 12-90) Page 330.9
7,189,668 22,627,916 0 15,438,248
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
(m)(l)(k)(n)
(k+l+m)
Total Revenues ($)
(Including transactions reffered to as 'wheeling')
($)
Energy Charges
($)
(Other Charges)Demand Charges
($)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from 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.
7,125 7,125 1
23,916 23,916 2
18,155 18,155 3
198 198 4
478 478 5
-419 -419 6
5 5 7
40,577 40,577 8
101 101 9
-164 -164 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
FERC FORM NO. 1 (ED. 12-90) Page 330.10
7,189,668 22,627,916 0 15,438,248
Schedule Page: 328 Line No.: 1 Column: h
The network service agreement between Idaho Power and the Bonneville Power Administration
for the Oregon Trail Electric Cooperative expires September 30,2028. The billing demand
for network servics is the customers demand at the time of Idaho Power Company
transmission system peak and varies by month.
Schedule Page: 328 Line No.: 2 Column: h
Rate refund for June 2006 thru April 2014, pursuant to Formula Rate Audit.
Schedule Page: 328 Line No.: 3 Column: h
The network service agreement between Idaho Power and the Bonneville Power Administration
for the USBR expired December 31,2014 and was subsequently renewed, with a new expiration
date of 12/31/23. The billing demand for network service is the customers demand at the
time of Idaho Power Company transmission system peak and varies by month.
Schedule Page: 328 Line No.: 4 Column: e
Open Access Transmission tariff, Schedule 9 Network Integration Transmission Service.
Schedule Page: 328 Line No.: 4 Column: h
Rate refund for June 2006 thru April 2014, pursuant to Formula Rate Audit.
Schedule Page: 328 Line No.: 5 Column: h
The network service agreement between Idaho Power and the Bonneville Power Administration
for the Priority Firm Customers expires September 30,2028. The billing demand for network
service is the customer's demand at the time of Idaho power Company transmission system
peak and varies by month.
Schedule Page: 328 Line No.: 6 Column: h
Rate refund for June 2006 thru April 2014, pursuant to Formula Rate Audit.
Schedule Page: 328 Line No.: 7 Column: h
Rate refund for June 2006 thru April 2014, pursuant to Formula Rate Audit.
Schedule Page: 328 Line No.: 8 Column: e
Legacy, contract prior to the Open Access Transmission Tariff.
Schedule Page: 328 Line No.: 8 Column: h
The contract between Idaho Power and the Milner Irrigation District expires December 31,
2017.
Schedule Page: 328 Line No.: 9 Column: e
4, Open Access Transmission Tariff, Schedule 4 Energy Imbalance Service.
Schedule Page: 328 Line No.: 9 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 Shell and Shell is now
responsible for payment.
Schedule Page: 328 Line No.: 10 Column: h
The contract between Idaho Power and PacifiCorp - Imnaha expires on March 31,2016.
Schedule Page: 328 Line No.: 11 Column: h
Rate refund for June 2006 thru April 2014, pursuant to Formula Rate Audit.
Schedule Page: 328 Line No.: 12 Column: h
The agreement between Idaho Power and the United States Department of the Interior, Bureau
of Indian Affairs is subject to termination upon 90 days written notice by the Bureau.
Schedule Page: 328 Line No.: 13 Column: e
5/6, Open Access Transmission Tariff,Schedule 5/6 Operating Reserves.
Schedule Page: 328 Line No.: 13 Column: h
The agreement between Idaho Power and United Materials of Great Falls, Inc. has no
expiration date and can be terminated by either party at any time.
Schedule Page: 328 Line No.: 14 Column: h
The agreement between Idaho Power and United Materials of Great Falls, Inc. has no
expiration date and can be terminated by either party at any time.

Schedule Page: 328 Line No.: 15 Column: e
7/8, Open Access Transmission Tariff, Schedule 7/8 Point-to-Point Transmission Service.
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Schedule Page: 328 Line No.: 16 Column: h
Rate refund for June 2006 thru April 2014, pursuant to Formula Rate Audit.
Schedule Page: 328 Line No.: 18 Column: h
Rate refund for June 2006 thru April 2014, pursuant to Formula Rate Audit.
Schedule Page: 328 Line No.: 24 Column: h
Rate refund for June 2006 thru April 2014, pursuant to Formula Rate Audit.
Schedule Page: 328.1 Line No.: 10 Column: e
7/8, Open Access Transmission tariff, Schedule 7/8 Point-to-Point Transmission Service.
Schedule Page: 328.1 Line No.: 15 Column: h
Rate refund for June 2006 thru April 2014, pursuant to Formula Rate Audit.
Schedule Page: 328.1 Line No.: 16 Column: h
Rate refund for June 2006 thru April 2014, pursuant to Formula Rate Audit.
Schedule Page: 328.1 Line No.: 17 Column: h
Rate refund for June 2006 thru April 2014, pursuant to Formula Rate Audit.
Schedule Page: 328.1 Line No.: 31 Column: h
Rate refund for June 2006 thru April 2014, pursuant to Formula Rate Audit.
Schedule Page: 328.1 Line No.: 32 Column: h
Rate refund for June 2006 thru April 2014, pursuant to Formula Rate Audit.
Schedule Page: 328.3 Line No.: 25 Column: h
Rate Refund for June 2006 thru April 2014, pursuant to Formula Rate Audit.
Schedule Page: 328.4 Line No.: 3 Column: h
Rate refund for June 2006 thru April 2014, pursuant to Formula Rate Audit.
Schedule Page: 328.4 Line No.: 6 Column: h
Legacy agrement providing OATT-like service, but billed under 454 facilities revenue.
Schedule Page: 328.4 Line No.: 30 Column: h
Rate refund for June 2006 thru April 2014, pursuant to Formula Rate Audit.
Schedule Page: 328.5 Line No.: 8 Column: h
Rate refund for June 2006 thru April 2014, pursuant to Formula Rate Audit.
Schedule Page: 328.7 Line No.: 1 Column: h
Rate refund for June 2006 thru April 2014, pursuant to Formula Rate Audit.
Schedule Page: 328.7 Line No.: 8 Column: h
Rate refund for June 2006 thru April 2014, pursuant to Formula Rate Audit.
Schedule Page: 328.7 Line No.: 12 Column: h
Rate fefund for June 2006 thru April 2014, pursuant to Formula Rate Audit.
Schedule Page: 328.7 Line No.: 23 Column: h
Rate refund for June 2006, thru April 2014, pursuant to Formula Rate Audit.
Schedule Page: 328.7 Line No.: 24 Column: h
Rate refund for June 2006 Thru April 2014, pursuant to Formula Rate Audit.
Schedule Page: 328.7 Line No.: 25 Column: h
Rate refund for June 2006 thru April 2014, pursuant to Formula Rate Audit.
Schedule Page: 328.8 Line No.: 30 Column: h
Rate refund for June 2006 thru April 2014, pursuant to Formula Rate Audit.
Schedule Page: 328.9 Line No.: 5 Column: h
Rate refund for June 2006 thru April 2014, pursuant to Formula Rate Audit.
Schedule Page: 328.9 Line No.: 8 Column: h
Rate refund for June 2006 thru April 2014, pursuant to Formula Rate Audit.
Schedule Page: 328.9 Line No.: 20 Column: h
Rate refund for June 2006 thru April 2014, pursuant to Formula Rat Audit.
Schedule Page: 328.10 Line No.: 6 Column: h
Rate refund for June 2006 thru April 2014, pursuant to Formula Rate Audit.
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY BY ISO/RTOs
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
Payment Received by Statistical
(b)(a)
(Transmission Owner Name) Classification
FERC Rate Schedule
or Tariff Number
(c)
Total Revenue by Rate
Schedule or Tarirff
(d)
Total Revenue
(e)
1. Report in Column (a) the Transmission Owner receiving revenue for the transmission of electricity by the ISO/RTO.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in Column (a).
3. In Column (b) 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.
4. In column (c) 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 (b) was provided.
5. In column (d) report the revenue amounts as shown on bills or vouchers.
6. Report in column (e) the total revenues distributed to the entity listed in column (a).
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
Page 331
40 TOTAL
FERC FORM NO. 1/3-Q (REV 03-07)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.Name of Company or Public
(d)(c)(a)Authority (Footnote Affiliations)
TRANSFER OF ENERGY
Magawatt-hoursReceived
Magawatt-
Deliveredhours
EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
DemandCharges($)(e)
EnergyCharges
(f)($)
OtherCharges($)
(g)($)
Total Cost ofTransmission
(h)
(Including transactions referred to as "wheeling")
1. Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other 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.
Statistical
Classification(b)
NF 193,324 193,324 30,392 30,392Avista Corp-WWP Div 1
SFP 941,879 941,879 217,709 217,709Avista Corp-WWP Div 2
AD -124 -124Avista Corp-WWP Div 3
LFP 3,701,617 3,701,617 1,036,928 1,036,928Bonneville Power Admin 4
SFP 9,200 9,200 1,840 1,840Bonneville Power Admin 5
NF 1,820 1,820 364 364Bonneville Power Admin 6
OS 21,804 21,804 4,220 4,220Bonneville Power Admin 7
OS 3,743 3,743Bonneville Power Admin 8
OS -420 -420Cargill Power Markets 9
OS -70,383 -70,383Exelon Generation Co 10
OS -870 -870lerdrola Renewables 11
OS -16,664 -16,664Morgan Stanley Capital 12
OS -6,796 -6,796NextEra Energy 13
LFP 49,900 49,900 4,808 4,808Northwestern Energy 14
NF 5,938 5,938 1,716 1,716NorthWesern Energy 15
SFP 130,363 130,363 14,027 14,027NorthWestern Energy 16
FERC FORM NO. 1/3-Q (REV. 02-04) Page 332
1,493,306 1,493,306 6,340,973 -259,674 6,081,299TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.Name of Company or Public
(d)(c)(a)Authority (Footnote Affiliations)
TRANSFER OF ENERGY
Magawatt-hoursReceived
Magawatt-
Deliveredhours
EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
DemandCharges($)(e)
EnergyCharges
(f)($)
OtherCharges($)
(g)($)
Total Cost ofTransmission
(h)
(Including transactions referred to as "wheeling")
1. Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other 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.
Statistical
Classification(b)
LFP 779,022 779,022 79,660 79,660PacifiCorp Inc. 1
NF 291,828 291,828 53,945 53,945PacifiCorp Inc. 2
SFP 37,134 37,134 5,880 5,880PacifiCorp Inc. 3
OS 151,304 151,304PaifiCorp Inc. 4
OS -41,600 -41,600PacifiCorp Inc 5
OS -136,828 -136,828Powerex Corp. 6
SFP 65,040 65,040 40,217 40,217Puget Sound Energy, Inc 7
NF -336 -336Sierra Pacific Power Co 8
SFP 1,800 1,800 1,200 1,200Snohomish County PUD 9
SFP 600 600 400 400TransAlta Energy U.S. 10
OS -30,996 -30,996TransAlta Eenrgy U.S. 11
12
13
14
15
16
FERC FORM NO. 1/3-Q (REV. 02-04) Page 332.1
1,493,306 1,493,306 6,340,973 -259,674 6,081,299TOTAL
Schedule Page: 332 Line No.: 3 Column: a
Unreserved Use Refund
Schedule Page: 332 Line No.: 4 Column: b
Contract Expiration Date 09/30/2016
Schedule Page: 332 Line No.: 8 Column: a
Reserves Provided.
Schedule Page: 332 Line No.: 9 Column: a
Resale Transmission
Schedule Page: 332 Line No.: 10 Column: a
Resale Transmission.
Schedule Page: 332 Line No.: 11 Column: a
Resale Transmission
Schedule Page: 332 Line No.: 12 Column: a
Resale Transmission
Schedule Page: 332 Line No.: 13 Column: a
Resale Transmission
Schedule Page: 332 Line No.: 14 Column: b
Contract can be terminated at anytime, with 30 days prior notice.
Schedule Page: 332.1 Line No.: 1 Column: b
Contract Expiration Date 05/31/2019
Schedule Page: 332.1 Line No.: 5 Column: a
2012/2013 PTP True Up - PacifiCorp
Schedule Page: 332.1 Line No.: 6 Column: a
Resale Transmission
Schedule Page: 332.1 Line No.: 8 Column: a
Resale Transmission
Schedule Page: 332.1 Line No.: 11 Column: a
Resale Transmission
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Idaho Power Company X 04/15/2015 2014/Q4
Line Description Amount
(b)(a)No.
453,508Industry Association Dues 1
Nuclear Power Research Expenses 2
Other Experimental and General Research Expenses 3
1,682,703Pub & Dist Info to Stkhldrs...expn servicing outstanding Securities 4
67,304Oth Expn >=5,000 show purpose, recipient, amount. Group if < $5,000 5
32,475Stephen Allred 6
54,585Thomas Carlile 7
87,057Richard Dahl 8
69,622Ronald Jibson 9
74,317Judith Johnson 10
69,518Dennis Johnson 11
38,577J Lamont Keen 12
87,459Christine King 13
59,865Jan Packwood 14
81,611Joan Smith 15
156,865Robert Tinstman 16
70,729Thomas Willford 17
18
23,000Accociated Taxpayers of Idaho 19
5,000Boston College for Corporations 20
5,000Business Plus 21
13,050Ceati International 22
86,120Corporate Executive Board 23
14,000Idaho Association of Commerce & industry 24
12,750Idaho Technology Council 25
7,125National Association of Directors 26
33,482National Hydropower Assoc 27
7,000North American Energy Standard 28
279,952Northwest Power pool 29
38,869Pacific NW Utilities 30
5,000Utility Variable Generation industry 31
1,163,224Western Energy Coordinating Council 32
30,568Western Energy Institute 33
5,915Misc Memberships under $2,000 (7) 34
35
91,165Chambers of Commerce & Other Civic Organizations 36
37
38
39
40
41
42
43
44
45
4,907,415
FERC FORM NO. 1 (ED. 12-94) Page 335
46 TOTAL
Schedule Page: 335 Line No.: 4 Column: b
Recipient Purpose Amount
American Stock Transfer & Trust Mgmt Services $ 75,181
Broadridge Financial Solutions Proxy & Bulletin 49,240
Deutsche Bank Broker Fees 43,482
E Source Mgmt Services 35,756
Moody's Analytics Mgmt Services 32,729
NASDAQ Corp Solutions Mgmt Services 70,138
New York Stock Exchange Listing Services 46,628
Rate Related Amortization Misc Expense 230,655
Stock Based Compensation Misc Expense 752,952
Wells Fargo Shareowner Service Mgmt Services 115,889
Payroll Related Expenses Misc Expense 167,051
Miscellaneous 63,002
----------
Total $1,682,703
==========

Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Account 403, 404, 405)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.Functional Classification Depreciation
(d)(b)(a)
Amortization of
Total
(Except amortization of aquisition adjustments)
A. Summary of Depreciation and Amortization Charges
Expense(Account 403)
Limited TermElectric Plant Amortization ofOther ElectricPlant (Acc 405)(e) (f)
1. Report in section A for the year the amounts for : (b) Depreciation Expense (Account 403; (c) Depreciation Expense for Asset
Retirement Costs (Account 403.1; (d) Amortization of Limited-Term Electric Plant (Account 404); and (e) Amortization of Other Electric
Plant (Account 405).
2. Report in Section 8 the rates used to compute amortization charges for electric plant (Accounts 404 and 405). State the basis used to
compute charges and whether any changes have been made in the basis or rates used from the preceding report year.
3. Report all available information called for in Section C every fifth year beginning with report year 1971, reporting annually only changes
to columns (c) through (g) from the complete report of the preceding year.
Unless composite depreciation accounting for total depreciable plant is followed, list numerically in column (a) each plant subaccount,
account or functional classification, as appropriate, to which a rate is applied. Identify at the bottom of Section C the type of plant included
in any sub-account used.
In column (b) report all depreciable plant balances to which rates are applied showing subtotals by functional Classifications and showing
composite total. Indicate at the bottom of section C the manner in which column balances are obtained. If average balances, state the
method of averaging used.
For columns (c), (d), and (e) report available information for each plant subaccount, account or functional classification Listed in column
(a). If plant mortality studies are prepared to assist in estimating average service Lives, show in column (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.
(Account 404)(c)
DepreciationExpense for AssetRetirement Costs(Account 403.1)
7,172,382 7,172,382 1 Intangible Plant
25,014,381 24,519,352 2 Steam Production Plant 495,029
3 Nuclear Production Plant
14,054,949 14,054,949 4 Hydraulic Production Plant-Conventional
5 Hydraulic Production Plant-Pumped Storage
17,190,565 17,190,565 6 Other Production Plant
20,082,639 20,082,639 7 Transmission Plant
40,300,184 40,300,184 8 Distribution Plant
9 Regional Transmission and Market Operation
9,097,851 9,097,851 10 General Plant
11 Common Plant-Electric
132,912,951 125,245,540 7,172,382 12 TOTAL 495,029
Acct 404 Balance 1/1/14 2014 Amortization Balance 12/31/14 Remaining months
(1) 48,000 12,000 36,000 36
(2) 11,885,442 545,446 10,339,996 -
(3) 5,468,500 189,366 5,251,629 333
(4) 19,158,412 6,115,880 15,747,708 -
(5) 4,035,897 287,899 3,747,997 168
(6) 209,847 8,026 201,821 -
(7) 618,074 13,765 604,625 -
------------------ ------------- --------------
Total 40,424,173 7,611,634 35,929,777
(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 Relicensing (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).
(7) FERC License Complianc Costs (Termination date will be expirtion date of the FERC Licenses).
FERC FORM NO. 1 (REV. 12-03) Page 336
B. Basis for Amortization Charges
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.Account No.
(c)(b)(a)(d) (e)
C. Factors Used in Estimating Depreciation Charges
Depreciable
Plant Base(In Thousands)
Estimated
Avg. ServiceLife
Net
Salvage(Percent)
Applied
Depr. rates
Mortality
CurveType
Average
RemainingLife(f) (g)(Percent)
75.00 3.64 20.20R4.0310.20 638 12
100.00 -10.00 1.89 21.30S1.0311.00 150,084 13
60.00 -5.00 1.43 21.80R3.0312.10 81,618 14
60.00 -5.00 2.70 20.90R1.5312.20 509,205 15
25.00 20.00 2.35 7.90R3.0312.30 4,341 16
45.00 -5.00 3.24 19.40S1.0314.00 159,337 17
60.00 1.45 19.80S1.5315.00 70,043 18
45.00 -5.00 3.68 19.00R0.5316.00 11,737 19
12.00 15.00 8.72 6.30L2.0316.10 84 20
12.00 15.00 0.82 7.90L2.0316.40 247 21
12.00 15.00 3.19 5.10L2.0316.50 83 22
20.00 15.00 4.76 18.00L2.0316.60 106 23
20.00 15.00 2.87 14.40L2.0316.70 80 24
20.00 30.00 3.53 16.60O1.0316.80 3,583 25
35.00 15.00 2.45 34.70S1.0316.90 14 26
317.00 6,372 27
Subtotal Steam 997,572 28
100.00 -25.00 2.38 33.00R2.5331.00 175,002 29
95.00 -20.00 1.31 39.80S4.0332.10 19,461 30
95.00 -20.00 1.65 35.60S4.0332.20 237,646 31
1.44 49.10SQUARE332.30 5,472 32
80.00 -5.00 1.72 32.60R3.0333.00 207,191 33
50.00 -5.00 2.71 26.10R1.5334.00 56,828 34
95.00 2.25 28.10R2.0335.00 21,069 35
15.00 6.86 6.50SQUARE335.10 93 36
20.00 5.76 5.30SQUARE335.20 366 37
5.00 12.16 3.30SQUARE335.30 242 38
75.00 2.33 21.40R3.0336.00 9,585 39
Subtotal Hydro 732,955 40
2.83 27.20SQUARE341.00 140,902 41
50.00 2.57 28.50S2.5342.00 10,453 42
40.00 3.33 25.90S1.5343.00 238,896 43
45.00 2.64 26.80S2.0344.00 66,355 44
50.00 3.39 22.60S1.5345.00 88,608 45
35.00 3.28 24.50S2.5346.00 6,247 46
Subtotal Other 551,461 47
70.00 1.39 58.80R3.0350.20 31,604 48
30.00 3.33350.22 115 49
65.00 -35.00 1.84 53.70R3.0352.00 72,738 50
FERC FORM NO. 1 (REV. 12-03) Page 337
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.Account No.
(c)(b)(a)(d) (e)
C. Factors Used in Estimating Depreciation Charges
Depreciable
Plant Base(In Thousands)
Estimated
Avg. ServiceLife
Net
Salvage(Percent)
Applied
Depr. rates
Mortality
CurveType
Average
RemainingLife(f) (g)(Percent)
50.00 -5.00 1.90 40.70R1.5353.00 399,788 12
65.00 -15.00 1.70 50.80S3.0354.00 168,187 13
60.00 -70.00 2.77 43.60R2.0355.00 142,598 14
65.00 -40.00 2.25 48.50R2.0356.00 196,361 15
65.00 0.79 24.00R2.5359.00 390 16
Subtotal Transmission 1,011,781 17
30.00 3.33 30.00360.22 348 18
65.00 -40.00 2.14 53.30R2.5361.00 33,717 19
50.00 -5.00 2.00 40.20R1.0362.00 202,030 20
44.00 -45.00 3.08 31.30R1.5364.00 241,031 21
12.00 8.34364.10 58 22
45.00 -35.00 2.98 33.60R0.5365.00 128,008 23
60.00 -20.00 1.95 48.40R2.0366.00 47,294 24
46.00 -15.00 2.26 35.30R2.0367.00 218,657 25
35.00 -3.00 2.58 27.00R1.0368.00 494,615 26
40.00 -40.00 2.55 29.50R2.0369.00 57,867 27
22.00 1.00 3.46 17.50O1.0370.00 16,483 28
15.00 6.96 13.10S2.5370.10 64,046 29
12.00 -2.00 9.00S4.0371.10 30
17.00 -2.00 1.51 14.70R1.5371.20 2,915 31
30.00 -25.00 2.41 20.60R1.0373.20 4,505 32
374.00 534 33
Subtotal Distribution 1,512,108 34
100.00 -5.00 2.58 28.80S0.5390.11 28,255 35
55.00 -5.00 1.90 44.30S0.5390.12 78,578 36
35.00 2.15 25.70S3.0390.20 205 37
20.00 2.88 12.90SQUARE391.11 14,135 38
5.00 11.12 3.20SQUARE391.20 24,364 39
8.00 11.22 5.70L2.0391.21 7,404 40
12.00 15.00 7.50 8.90L2.0392.10 841 41
10.00 50.00 1.73 3.40S2.5392.30 2,920 42
12.00 15.00 7.36 6.80L2.0392.40 23,547 43
12.00 15.00 3.53 9.00L2.0392.50 1,123 44
20.00 15.00 4.14 13.40L2.0392.60 34,652 45
20.00 15.00 3.21 12.50L2.0392.70 6,304 46
35.00 15.00 2.10 24.30S1.0392.90 4,826 47
25.00 3.30 19.40SQUARE393.00 1,936 48
20.00 4.13 13.30SQUARE394.00 7,575 49
20.00 4.29 12.10SQUARE395.00 12,652 50
FERC FORM NO. 1 (REV. 12-03) Page 337.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.Account No.
(c)(b)(a)(d) (e)
C. Factors Used in Estimating Depreciation Charges
Depreciable
Plant Base(In Thousands)
Estimated
Avg. ServiceLife
Net
Salvage(Percent)
Applied
Depr. rates
Mortality
CurveType
Average
RemainingLife(f) (g)(Percent)
20.00 30.00 1.66 17.60O1.0396.00 13,938 12
15.00 4.25 8.30SQUARE397.10 4,913 13
15.00 5.38 9.80SQUARE397.20 32,820 14
15.00 5.31 8.00SQUARE397.30 4,330 15
10.00 7.90 6.50SQUARE397.40 11,725 16
15.00 5.20 10.60SQUARE398.00 5,577 17
Subtotal General 322,620 18
Total Plant 5,128,497 19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
FERC FORM NO. 1 (REV. 12-03) Page 337.2
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
REGULATORY COMMISSION EXPENSES
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
Description Assessed by
(c)(b)(a)
Total Expense forExpenses
of
(d)
(Furnish name of regulatory commission or body the Regulatory
docket or case number and a description of the case)Commission Utility Current Year(b) + (c)
Deferredin Account182.3 at Beginning of Year(e)
1. Report particulars (details) of regulatory commission expenses incurred during the current year (or incurred in previous years, if 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.
Federal Energy Regulatory Commission: 1
Annual admin charges assessed by FERC 2,598,261 2,598,261 2
3
Regulatory FERC fees Tru-up -89,330 -89,330 4
5
General Regulatory Expenses and 6
Various other Dockets 743,604 743,604 7
8
Oregon Hydro - Fees Amortization 158,501 158,501 9
10
Regulatory Commission Expenses - Idaho 11
Rate Case - Misc expenses -21,427 -21,427 12
13
Regulatory Commission Expenses - Oregon 14
Rate Case - Misc expenses 843 843 15
General Regulatory 58,643 58,643 16
Other OPUC expenses 8,743 8,743 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
FERC FORM NO. 1 (ED. 12-96) Page 350
46 TOTAL 2,756,762 701,076 3,457,838
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
REGULATORY COMMISSION EXPENSES (Continued)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
(j)(i)(f)(k) (l)
EXPENSES INCURRED DURING YEAR AMORTIZED DURING YEAR
CURRENTLY CHARGED TO
Department AccountNo.(g)
Amount
(h)
Deferred to
Account 182.3
Contra
Account Amount Deferred in Account 182.3End of Year
3. Show in column (k) any expenses incurred in prior years which are being amortized. List in column (a) the period of amortization.
4. List in column (f), (g), and (h) expenses incurred during year which were charged currently to income, plant, or other accounts.
5. Minor items (less than $25,000) may be grouped.
1
Electric 2 2,598,261928
3
Electric 4 -89,330928
5
6
Electric 7 743,604928
8
Electric 9 158,501928
10
11
Electric 12 -21,427928
13
14
Electric 15 843928
Electric 16 58,643928
Electric 17 8,743928
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
FERC FORM NO. 1 (ED. 12-96) Page 351
46 3,457,838
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
Description
(b)(a)
Classification
1. Describe and show below costs incurred and accounts charged during the year for technological research, development, and demonstration (R, D & D)
project initiated, continued or concluded during the year. Report also support given to others during the year for jointly-sponsored projects.(Identify
recipient regardless of affiliation.) For any R, D & D work carried with others, show separately the respondent's cost for the year and cost chargeable to
others (See definition of research, development, and demonstration in Uniform System of Accounts).
2. Indicate in column (a) the applicable classification, as shown below:
Classifications:
A. Electric R, D & D Performed Internally: a. Overhead
(1) Generation b. Underground
a. hydroelectric (3) Distribution
i. Recreation fish and wildlife (4) Regional Transmission and Market Operation
ii Other hydroelectric (5) Environment (other than equipment)
b. Fossil-fuel steam (6) Other (Classify and include items in excess of $50,000.)
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
Idaho Power did not incur any Research and 1
Development expenditures in 2014. 2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
FERC FORM NO. 1 (ED. 12-87) Page 352
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES (Continued)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
AMOUNTS CHARGED IN CURRENT YEAR
(e)(c)
Costs Incurred Internally
Current Year Costs Incurred Externally
Current Year
(d)Account Amount(f)
Unamortized
Accumulation
(g)
(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 & D (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 (g) 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.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
FERC FORM NO. 1 (ED. 12-87) Page 353
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DISTRIBUTION OF SALARIES AND WAGES
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
Classification
(c)(b)(a)
Direct Payroll Allocation of Total
(d)
Distribution Payroll charged forClearing Accounts
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.
Electric 1
Operation 2
22,607,567Production 3
6,826,884Transmission 4
Regional Market 5
17,605,437Distribution 6
11,413,469Customer Accounts 7
4,849,214Customer Service and Informational 8
Sales 9
43,649,783Administrative and General 10
106,952,354TOTAL Operation (Enter Total of lines 3 thru 10) 11
Maintenance 12
4,940,951Production 13
3,388,364Transmission 14
Regional Market 15
8,231,515Distribution 16
1,000,896Administrative and General 17
17,561,726TOTAL Maintenance (Total of lines 13 thru 17) 18
Total Operation and Maintenance 19
27,548,518Production (Enter Total of lines 3 and 13) 20
10,215,248Transmission (Enter Total of lines 4 and 14) 21
Regional Market (Enter Total of Lines 5 and 15) 22
25,836,952Distribution (Enter Total of lines 6 and 16) 23
11,413,469Customer Accounts (Transcribe from line 7) 24
4,849,214Customer Service and Informational (Transcribe from line 8) 25
Sales (Transcribe from line 9) 26
44,650,679Administrative and General (Enter Total of lines 10 and 17) 27
124,514,080 124,514,080TOTAL Oper. and Maint. (Total of lines 20 thru 27) 28
Gas 29
Operation 30
Production-Manufactured Gas 31
Production-Nat. Gas (Including Expl. and Dev.) 32
Other Gas Supply 33
Storage, LNG Terminaling and Processing 34
Transmission 35
Distribution 36
Customer Accounts 37
Customer Service and Informational 38
Sales 39
Administrative and General 40
TOTAL Operation (Enter Total of lines 31 thru 40) 41
Maintenance 42
Production-Manufactured Gas 43
Production-Natural Gas (Including Exploration and Development) 44
Other Gas Supply 45
Storage, LNG Terminaling and Processing 46
Transmission 47
FERC FORM NO. 1 (ED. 12-88) Page 354
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofIdaho Power Company X
04/15/2015 2014/Q4
Line
No.
Classification
(c)(b)(a)
Direct Payroll Allocation of Total
(d)
Distribution Payroll charged forClearing Accounts
DISTRIBUTION OF SALARIES AND WAGES (Continued)
Distribution 48
Administrative and General 49
TOTAL Maint. (Enter Total of lines 43 thru 49) 50
Total Operation and Maintenance 51
Production-Manufactured Gas (Enter Total of lines 31 and 43) 52
Production-Natural Gas (Including Expl. and Dev.) (Total lines 32, 53
Other Gas Supply (Enter Total of lines 33 and 45) 54
Storage, LNG Terminaling and Processing (Total of lines 31 thru 47) 55
Transmission (Lines 35 and 47) 56
Distribution (Lines 36 and 48) 57
Customer Accounts (Line 37) 58
Customer Service and Informational (Line 38) 59
Sales (Line 39) 60
Administrative and General (Lines 40 and 49) 61
TOTAL Operation and Maint. (Total of lines 52 thru 61) 62
Other Utility Departments 63
Operation and Maintenance 64
124,514,080 124,514,080TOTAL All Utility Dept. (Total of lines 28, 62, and 64) 65
Utility Plant 66
Construction (By Utility Departments) 67
Electric Plant 68
Gas Plant 69
Other (provide details in footnote): 70
TOTAL Construction (Total of lines 68 thru 70) 71
Plant Removal (By Utility Departments) 72
Electric Plant 73
Gas Plant 74
Other (provide details in footnote): 75
TOTAL Plant Removal (Total of lines 73 thru 75) 76
Other Accounts (Specify, provide details in footnote): 77
5,014,170 5,014,170Stores Expense 78
3,055,719 3,055,719Other clearing accounts 79
53,485,019 53,485,019Construction Work in Progress 80
2,847,464 2,847,464Other Work in Progress 81
22,802,332 22,802,332Paid Absences 82
760 760Preliminary Survey and Investigation 83
5,388,094 5,388,094Other Accounts 84
85
86
87
88
89
90
91
92
93
94
92,593,558 92,593,558TOTAL Other Accounts 95
217,107,638 217,107,638TOTAL SALARIES AND WAGES 96
FERC FORM NO. 1 (ED. 12-88) Page 355
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
COMMON UTILITY PLANT AND EXPENSES
Idaho Power Company X
04/15/2015 2014/Q4
1. Describe the property carried in the utility's accounts as common utility plant and show the book cost of such plant at end of year classified by accounts
as provided by Plant Instruction 13, Common Utility Plant, of the Uniform System of Accounts. Also show the allocation of such plant costs to the
respective departments using the common utility plant and explain the basis of allocation used, giving the allocation factors.
2. Furnish the accumulated provisions for depreciation and amortization at end of year, showing the amounts and classifications of such accumulated
provisions, and amounts allocated to utility departments using the Common utility plant to which such accumulated provisions relate, including explanation
of basis of allocation and factors used.
3. Give for the year the expenses of operation, maintenance, rents, depreciation, and amortization for common utility plant classified by accounts as
provided by the Uniform System of Accounts. Show the allocation of such expenses to the departments using the common utility plant to which such
expenses are related. Explain the basis of allocation used and give the factors of allocation.
4. Give date of approval by the Commission for use of the common utility plant classification and reference to order of the Commission or other
authorization.
FERC FORM NO. 1 (ED. 12-87) Page 356
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofIdaho Power Company X
04/15/2015 2014/Q4
Line
No.
Description of Item(s) Balance at End of
(c)(b)(a)
Balance at End of
AMOUNTS INCLUDED IN ISO/RTO SETTLEMENT STATEMENTS
Quarter 1 Quarter 2
Balance at End of
Quarter 3
(d) (e)
1. The respondent shall report below the details called for concerning amounts it recorded in Account 555, Purchase Power, and Account 447, Sales for
Resale, for items shown on ISO/RTO Settlement Statements. Transactions should be separately netted for each ISO/RTO administered energy market for
purposes of determining whether an entity is a net seller or purchaser in a given hour. Net megawatt hours are to be used as the basis for determining
whether a net purchase or sale has occurred. In each monthly reporting period, the hourly sale and purchase net amounts are to be aggregated and
separately reported in Account 447, Sales for Resale, or Account 555, Purchased Power, respectively.
Balance at End of
Year
Energy 1
Net Purchases (Account 555) 2
Net Sales (Account 447) 3
Transmission Rights 4
Ancillary Services 5
Other Items (list separately) 6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
FERC FORM NO. 1/3-Q (NEW. 12-05) Page 397
46 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASES AND SALES OF ANCILLARY SERVICES
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
Type of Ancillary Service
(a)
Report the amounts for each type of ancillary service shown in column (a) for the year as specified in Order No. 888 and defined in the
respondents Open Access Transmission Tariff.
In columns for usage, report usage-related billing determinant and the unit of measure.
(1) On line 1 columns (b), (c), (d), (e), (f) and (g) report the amount of ancillary services purchased and sold during the year.
(2) On line 2 columns (b) (c), (d), (e), (f), and (g) report the amount of reactive supply and voltage control services purchased and sold
during the year.
(3) On line 3 columns (b) (c), (d), (e), (f), and (g) report the amount of regulation and frequency response services purchased and sold
during the year.
(4) On line 4 columns (b), (c), (d), (e), (f), and (g) report the amount of energy imbalance services purchased and sold during the year.
(5) On lines 5 and 6, columns (b), (c), (d), (e), (f), and (g) report the amount of operating reserve spinning and supplement services
purchased and sold during the period.
(6) On line 7 columns (b), (c), (d), (e), (f), and (g) report the total amount of all other types ancillary services purchased or sold during the
year. Include in a footnote and specify the amount for each type of other ancillary service provided.
Number of Units
Unit of
Measure Dollars
(b) (c) (d)
Number of Units
Unit of
Measure Dollars
(e) (f) (g)
Usage - Related Billing Determinant Usage - Related Billing Determinant
Amount Purchased for the Year Amount Sold for the Year
Scheduling, System Control and Dispatch 1
Reactive Supply and Voltage 2
Regulation and Frequency Response 3
Energy Imbalance 4
Operating Reserve - Spinning 5
Operating Reserve - Supplement 6
Other 7
Total (Lines 1 thru 7) 8
FERC FORM NO. 1 (New 2-04) Page 398
Idaho Power Company
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
MONTHLY TRANSMISSION SYSTEM PEAK LOAD
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
Monthly Peak
MW - Total
(c)(b)(a)
Month
NAME OF SYSTEM:
Day of
Monthly
Peak
(1) Report the monthly peak load on the respondent's transmission system. If the respondent has two or more power systems which are not 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 (j) by month the system' monthly maximum megawatt load by statistical classifications. See General Instruction for the
definition of each statistical classification.
(d)
Hour of
Monthly
Peak
(e)
Firm Network
Service for Self
(f)
Firm Network
Service for
Others
(g)
Long-Term Firm
Point-to-point
Reservations
(h)
Other Long-
Term Firm
Service
(i)
Short-Term Firm
Point-to-point
Reservation
(j)
Other
Service
320 567 217 3,687 800 6 4,791January 1
325 567 220 3,597 800 4 4,709February 2
523 567 190 3,097 90019 4,377March 3
1,168 1,701 627 10,381 13,877Total for Quarter 1 4
628 567 159 2,827 800 7 4,181April 5
479 567 284 3,488210026 4,818May 6
223 567 342 4,364170024 5,496June 7
1,330 1,701 785 10,679 14,495Total for Quarter 2 8
227 463 357 4,769140014 5,816July 9
179 463 274 4,413160011 5,329August 10
176 463 248 4,092170016 4,979September 11
582 1,389 879 13,274 16,124Total for Quarter 3 12
205 463 162 3,3451800 8 4,175October 13
73 463 244 4,012 80018 4,792November 14
109 463 234 3,896190030 4,702December 15
387 1,389 640 11,253 13,669Total for Quarter 4 16
3,467 6,180 2,931 45,587 58,165
Total Year to
Date/Year
17
FERC FORM NO. 1/3-Q (NEW. 07-04) Page 400
Schedule Page: 400 Line No.: 17 Column: e
Includes 1836 MW associated with pre‐Order No. 888 transmission agreements between PacifiCorp and Idaho Power.   
The contract demand associated with the pre‐Order No. 888 transmission agreements is part of Idaho Power’s total firm
load and is included in the load denominator in the computation of, and accordance with, Idaho Power’s Open Access
Transmission Tariff (“OATT”) rate.  On October 24, 2014, the Parties entered into a Joint Purchase and Sale Agreement
and a Termination Agreement that will, if closing occurs, result in the elimination of 1836 MW of contract demand that is
associated with the pre‐Order No. 888 transmission agreements that terminate as part of the transaction.  In addition,
310 MW of Firm Point‐To‐Point Transmission Service Agreements   will become effective if closing occurs. The Parties
anticipate all required regulatory approvals will be received and the transaction will close no later than September, 2015.
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
MONTHLY ISO/RTO TRANSMISSION SYSTEM PEAK LOAD
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.
Monthly Peak
MW - Total
(c)(b)(a)
Month
NAME OF SYSTEM:
Day of
Monthly
Peak
(1) Report the monthly peak load on the respondent's transmission system. If the Respondent has two or more power systems which are not 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 Column (c) and (d) the specified information for each monthly transmission - system peak load reported on Column (b).
(4) Report on Columns (e) through (i) by month the system’s transmission usage by classification. Amounts reported as Through and Out Service in
Column (g) are to be excluded from those amounts reported in Columns (e) and (f).
(5) Amounts reported in Column (j) for Total Usage is the sum of Columns (h) and (i).
(d)
Hour of
Monthly
Peak
(e)
Imports into
ISO/RTO
(f)
Exports from
ISO/RTO
(g)
Through and
Out Service
(h)
Network
Service Usage
(i)
Point-to-Point
Service Usage
(j)
Total Usage
January 1
February 2
March 3
Total for Quarter 1 4
April 5
May 6
June 7
Total for Quarter 2 8
July 9
August 10
September 11
Total for Quarter 3 12
October 13
November 14
December 15
Total for Quarter 4 16
Total Year to
Date/Year
17
FERC FORM NO. 1/3-Q (NEW. 07-04) Page 400a
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ELECTRIC ENERGY ACCOUNT
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
Item
(a)(b)(a)(b)
Line
No.MegaWatt Hours Item MegaWatt Hours
Report below the information called for concerning the disposition of electric energy generated, purchased, exchanged and wheeled during the year.
SOURCES OF ENERGY1
Generation (Excluding Station Use):2
5,850,665Steam3
Nuclear4
6,169,847Hydro-Conventional5
Hydro-Pumped Storage6
1,174,857Other7
Less Energy for Pumping8
13,195,369Net Generation (Enter Total of lines 3
through 8)
9
4,148,611Purchases10
Power Exchanges:11
324,803Received12
211,221Delivered13
113,582Net Exchanges (Line 12 minus line 13)14
Transmission For Other (Wheeling)15
6,721,533Received16
6,721,324Delivered17
209Net Transmission for Other (Line 16 minus
line 17)
18
Transmission By Others Losses19
17,457,771TOTAL (Enter Total of lines 9, 10, 14, 18
and 19)
20
DISPOSITION OF ENERGY21
14,092,367Sales to Ultimate Consumers (Including
Interdepartmental Sales)
22
Requirements Sales for Resale (See
instruction 4, page 311.)
23
2,220,419Non-Requirements Sales for Resale (See
instruction 4, page 311.)
24
Energy Furnished Without Charge25
Energy Used by the Company (Electric
Dept Only, Excluding Station Use)
26
1,144,985Total Energy Losses27
17,457,771TOTAL (Enter Total of Lines 22 Through
27) (MUST EQUAL LINE 20)
28
FERC FORM NO. 1 (ED. 12-90)Page 401a
(d)
Day of Month
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
MONTHLY PEAKS AND OUTPUT
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.Total Monthly Energy Megawatts
(c)(b)(a)
Hour
(e)
MONTHLY PEAK
Month
NAME OF SYSTEM:Idaho Power Company
Monthly Non-RequirmentsSales for Resale &Associated Losses (See Instr. 4)
1. Report the monthly peak load and energy output. If the respondent has two or more power which are not physically integrated, furnish the 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).
(f)
January 29 6 2,175 240,689 9 AM 1,523,503
February 30 6 2,204 314,599 8 AM 1,399,729
March 31 12 1,843 260,659 8 AM 1,328,178
April 32 24 1,816 164,970 10 AM 1,231,532
May 33 27 2,436 82,077 7 PM 1,412,244
June 34 23 2,781 114,271 7 PM 1,636,434
July 35 8 3,184 47,418 6 PM 1,875,812
August 36 1 2,949 199,356 5 PM 1,635,278
September 37 16 2,434 186,995 6 PM 1,398,021
October 38 7 1,735 195,349 6 PM 1,236,921
November 39 18 2,253 207,977 8 AM 1,352,620
December 40 31 2,205 206,059 10 AM 1,423,437
FERC FORM NO. 1 (ED. 12-90) Page 401b
41 TOTAL 17,453,709 2,220,419
Schedule Page: 401 Line No.: 5 Column: b
The sum of line 12 on pages 406 thru 407 is different than the total on page 401 by
72,413 Mw. The 72,413 Mw is made up of Clear Lakes Power Plant 16,963 Mw and Thousand
Springs Power Plant 55,450 Mw. Thousand Springs and Clear lakes is included in the total
on page 401 line 5 but they are not included on pages 406-407. They are not included on
page 406-407 because plants generating less than 10 Mw are excluded, per instruction 1 on
page 406.
Schedule Page: 401 Line No.: 17 Column: b
Page 329 Column I differs from Page 401 by 209 MWH, reported for Lucky Peak variation and
BPA Energy imbalalnce 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.
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
BoardmanJim Bridger
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofIdaho Power Company X
04/15/2015 2014/Q4
Line
No.
Item
(b)(a)(c)
Plant
Name:
Plant
Name:
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.
SteamSteam 1 Kind of Plant (Internal Comb, Gas Turb, Nuclear
ConventionalSemi-Outdoor Boiler 2 Type of Constr (Conventional, Outdoor, Boiler, etc)
19801974 3 Year Originally Constructed
19801979 4 Year Last Unit was Installed
64.20770.50 5 Total Installed Cap (Max Gen Name Plate Ratings-MW)
62734 6 Net Peak Demand on Plant - MW (60 minutes)
65858760 7 Plant Hours Connected to Load
00 8 Net Continuous Plant Capability (Megawatts)
00 9 When Not Limited by Condenser Water
00 10 When Limited by Condenser Water
00 11 Average Number of Employees
2693350004651499000 12 Net Generation, Exclusive of Plant Use - KWh
106610499457 13 Cost of Plant: Land and Land Rights
1240808468495219 14 Structures and Improvements
63479074480941021 15 Equipment Costs
43482222640264 16 Asset Retirement Costs
80341990552575961 17 Total Cost
1251.4329717.1654 18 Cost per KW of Installed Capacity (line 17/5) Including
537592265285 19 Production Expenses: Oper, Supv, & Engr
6671067118487670 20 Fuel
00 21 Coolants and Water (Nuclear Plants Only)
7772785361847 22 Steam Expenses
00 23 Steam From Other Sources
00 24 Steam Transferred (Cr)
00 25 Electric Expenses
10204706727902 26 Misc Steam (or Nuclear) Power Expenses
0529967 27 Rents
00 28 Allowances
19835577787 29 Maintenance Supervision and Engineering
659280 30 Maintenance of Structures
2620787416751 31 Maintenance of Boiler (or reactor) Plant
21231563164373 32 Maintenance of Electric Plant
242925669116 33 Maintenance of Misc Steam (or Nuclear) Plant
11680216147700698 34 Total Production Expenses
0.04340.0318 35 Expenses per Net KWh
Coal Oil Coal Oil 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)
Tons Barrels Tons Barrels 37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)
2587129 4065 0 161681 1761 0 38 Quantity (Units) of Fuel Burned
9174 140000 0 8459 138800 0 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
43.327 158.528 0.000 41.067 122.529 0.000 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year
45.490 118.042 0.000 39.740 126.340 0.000 41 Average Cost of Fuel per Unit Burned
2.464 20.075 0.000 2.399 21.673 0.000 42 Average Cost of Fuel Burned per Million BTU
0.025 0.000 0.000 0.025 0.000 0.000 43 Average Cost of Fuel Burned per KWh Net Gen
10274.000 0.000 0.000 9983.000 0.000 0.000 44 Average BTU per KWh Net Generation
FERC FORM NO. 1 (REV. 12-03) Page 402
Langley Gulch
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofIdaho Power Company X
04/15/2015 2014/Q4
Line
No.
Item
(b)(a)(c)
Plant
Name:
Plant
Name:
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.
Gas Turbine 1 Kind of Plant (Internal Comb, Gas Turb, Nuclear
Conventional 2 Type of Constr (Conventional, Outdoor, Boiler, etc)
2012 3 Year Originally Constructed
2012 4 Year Last Unit was Installed
0.00318.45 5 Total Installed Cap (Max Gen Name Plate Ratings-MW)
0305 6 Net Peak Demand on Plant - MW (60 minutes)
04027 7 Plant Hours Connected to Load
0300 8 Net Continuous Plant Capability (Megawatts)
00 9 When Not Limited by Condenser Water
00 10 When Limited by Condenser Water
021 11 Average Number of Employees
01049182000 12 Net Generation, Exclusive of Plant Use - KWh
02287261 13 Cost of Plant: Land and Land Rights
0133486018 14 Structures and Improvements
0241890950 15 Equipment Costs
00 16 Asset Retirement Costs
0377664229 17 Total Cost
01185.9451 18 Cost per KW of Installed Capacity (line 17/5) Including
0505916 19 Production Expenses: Oper, Supv, & Engr
036289736 20 Fuel
00 21 Coolants and Water (Nuclear Plants Only)
00 22 Steam Expenses
00 23 Steam From Other Sources
00 24 Steam Transferred (Cr)
02851598 25 Electric Expenses
0301718 26 Misc Steam (or Nuclear) Power Expenses
00 27 Rents
00 28 Allowances
00 29 Maintenance Supervision and Engineering
095463 30 Maintenance of Structures
039718 31 Maintenance of Boiler (or reactor) Plant
0825878 32 Maintenance of Electric Plant
00 33 Maintenance of Misc Steam (or Nuclear) Plant
040910027 34 Total Production Expenses
0.00000.0390 35 Expenses per Net KWh
Gas 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)
MCF 37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)
7121881 0 0 0 0 0 38 Quantity (Units) of Fuel Burned
1027 0 0 0 0 0 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
5.096 0.000 0.000 0.000 0.000 0.000 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year
5.096 0.000 0.000 0.000 0.000 0.000 41 Average Cost of Fuel per Unit Burned
5.370 0.000 0.000 0.000 0.000 0.000 42 Average Cost of Fuel Burned per Million BTU
0.035 0.000 0.000 0.000 0.000 0.000 43 Average Cost of Fuel Burned per KWh Net Gen
6971.000 0.000 0.000 0.000 0.000 0.000 44 Average BTU per KWh Net Generation
FERC FORM NO. 1 (REV. 12-03) Page 402.1
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.
Bennett MountainDanskinValmy
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
(e) (f)
Plant
Name:
Plant
Name:
(d)
Plant
Name:
(Continued)
Gas TurbineSteam Gas Turbine 1
ConventionalOutdoor Conventional 2
20051981 2001 3
20051985 2008 4
172.80283.50 270.90 5
191260 244 6
5336359 414 7
1640 261 8
00 0 9
00 0 10
50 8 11
70483000929831000 55192000 12
16884421106140 402745 13
6088380769181061 5715935 14
0296057640 106887152 15
0-616367 0 16
62572249365728474 113005832 17
362.10791290.0475 417.1496 18
10536573832 168641 19
488120831013438 3883525 20
00 0 21
02602142 0 22
00 0 23
00 0 24
3490891599507 388047 25
1588301850352 314876 26
0554 0 27
00 0 28
01744 0 29
125325642380 157279 30
57333244236 155 31
317289757425 248261 32
0113006 0 33
584801042398616 5160784 34
0.08300.0456 0.0935 35
Coal Oil GasGas 36
Tons Barrels MCFMCF 37
494841 12308 0 730067 0 0576521 0 0 38
9407 138778 0 1027 0 01027 0 0 39
37.821 136.187 0.000 6.686 0.000 0.0006.736 0.000 0.000 40
59.159 138.253 0.000 6.686 0.000 0.0006.736 0.000 0.000 41
3.144 23.719 0.000 6.940 0.000 0.0006.630 0.000 0.000 42
0.033 0.000 0.000 0.069 0.000 0.0000.070 0.000 0.000 43
10089.000 0.000 0.000 10638.000 0.000 0.00010728.000 0.000 0.000 44
FERC FORM NO. 1 (REV. 12-03) Page 403
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.
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
(e) (f)
Plant
Name:
Plant
Name:
(d)
Plant
Name:
(Continued)
1
2
3
4
0.000.00 0.00 5
00 0 6
00 0 7
00 0 8
00 0 9
00 0 10
00 0 11
00 0 12
00 0 13
00 0 14
00 0 15
00 0 16
00 0 17
00 0 18
00 0 19
00 0 20
00 0 21
00 0 22
00 0 23
00 0 24
00 0 25
00 0 26
00 0 27
00 0 28
00 0 29
00 0 30
00 0 31
00 0 32
00 0 33
00 0 34
0.00000.0000 0.0000 35
36
37
0 0 0 0 0 00 0 0 38
0 0 0 0 0 00 0 0 39
0.000 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 40
0.000 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 41
0.000 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 42
0.000 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 43
0.000 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 44
FERC FORM NO. 1 (REV. 12-03) Page 403.1
Schedule Page: 402 Line No.: 3 Column: b
This footnote applies to lines 3 and 4. The Jim Bridger Power
Plant consists of four equal units constructed jointly by Idaho
Power Company and Pacific Power and Light Company, with Idaho
owning 1/3 and PacifiCorp owning 2/3. Unit #1 was placed in
commercial operation November 30, 1974, Unit #2 December 1, 1975,
Unit #3 September 1, 1976, and Unit #4 November 29, 1979.
Schedule Page: 402 Line No.: 3 Column: c
This footnote applies to lines 3 and 4. The Boardman plant
consists of one unit constructed jointly by Portland General
Electric Company, Idaho Power Company, and Pacific Northwest
Generating Company, with Idaho Power Company owning 10%. The
unit was placed in commercial operation August 3, 1980.
Schedule Page: 403 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.
Schedule Page: 402 Line No.: 5 Column: b
This footnote applies to line 5 and lines 12 through 43.
Information reflects Idaho Power Company's share as explained
in 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: 403 Line No.: 5 Column: d
This footnote applies to line 5 and lines 12 through 43.
Information reflects Idaho Power Company's share as explained
in note for line 3 page 403 column D.
Schedule Page: 402 Line No.: 9 Column: b
This footnote applies to lines 9, 10, and 11. PacifiCorp
as operator of the plant will report this
information.
Schedule Page: 402 Line No.: 9 Column: c
This footnote applies to lines 9, 10, and 11. Portland General
Electric Company, as operator will report this information.
Schedule Page: 403 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.
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
1975
Bliss
2736
American Falls
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
Item FERC Licensed Project No.
(b)(a)(c)
Plant Name:
FERC Licensed Project No.
Plant Name:
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.
Kind of Plant (Run-of-River or Storage) 1 Run-of-River Run-of-River
Plant Construction type (Conventional or Outdoor) 2 Outdoor Outdoor
Year Originally Constructed 3 1978 1949
Year Last Unit was Installed 4 1978 1950
Total installed cap (Gen name plate Rating in MW) 5 92.30 75.00
Net Peak Demand on Plant-Megawatts (60 minutes) 6 99 52
Plant Hours Connect to Load 7 4,997 8,760
Net Plant Capability (in megawatts) 8
(a) Under Most Favorable Oper Conditions 9 110 76
(b) Under the Most Adverse Oper Conditions 10 0 1
Average Number of Employees 11 4 4
Net Generation, Exclusive of Plant Use - Kwh 12 264,207,000 301,557,000
Cost of Plant 13
Land and Land Rights 14 875,318 768,366
Structures and Improvements 15 11,935,359 1,094,991
Reservoirs, Dams, and Waterways 16 4,293,075 8,670,708
Equipment Costs 17 32,743,435 9,409,661
Roads, Railroads, and Bridges 18 839,276 486,477
Asset Retirement Costs 19 0 0
TOTAL cost (Total of 14 thru 19) 20 50,686,463 20,430,203
Cost per KW of Installed Capacity (line 20 / 5) 21 549.1491 272.4027
Production Expenses 22
Operation Supervision and Engineering 23 205,189 822,283
Water for Power 24 1,397,935 666,110
Hydraulic Expenses 25 119,243 648,634
Electric Expenses 26 96,270 41,218
Misc Hydraulic Power Generation Expenses 27 298,420 404,270
Rents 28 143 11,636
Maintenance Supervision and Engineering 29 9,955 7,264
Maintenance of Structures 30 136,098 54,320
Maintenance of Reservoirs, Dams, and Waterways 31 64,125 11,304
Maintenance of Electric Plant 32 271,688 189,883
Maintenance of Misc Hydraulic Plant 33 87,987 153,050
Total Production Expenses (total 23 thru 33) 34 2,687,053 3,009,972
Expenses per net KWh 35 0.0102 0.0100
FERC FORM NO. 1 (REV. 12-03) Page 406
2726
Malad
1971
Hells Canyon
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
Item FERC Licensed Project No.
(b)(a)(c)
Plant Name:
FERC Licensed Project No.
Plant Name:
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.
Kind of Plant (Run-of-River or Storage) 1 Storage Run-of-River
Plant Construction type (Conventional or Outdoor) 2 Outdoor Outdoor
Year Originally Constructed 3 1967 1948
Year Last Unit was Installed 4 1967 1948
Total installed cap (Gen name plate Rating in MW) 5 391.50 21.77
Net Peak Demand on Plant-Megawatts (60 minutes) 6 439 23
Plant Hours Connect to Load 7 8,760 8,756
Net Plant Capability (in megawatts) 8
(a) Under Most Favorable Oper Conditions 9 445 25
(b) Under the Most Adverse Oper Conditions 10 137 21
Average Number of Employees 11 5 1
Net Generation, Exclusive of Plant Use - Kwh 12 1,623,091,000 95,302,000
Cost of Plant 13
Land and Land Rights 14 1,880,381 205,375
Structures and Improvements 15 2,888,412 2,827,184
Reservoirs, Dams, and Waterways 16 52,966,090 6,262,987
Equipment Costs 17 19,847,008 10,262,830
Roads, Railroads, and Bridges 18 922,781 309,505
Asset Retirement Costs 19 0 0
TOTAL cost (Total of 14 thru 19) 20 78,504,672 19,867,881
Cost per KW of Installed Capacity (line 20 / 5) 21 200.5228 912.6266
Production Expenses 22
Operation Supervision and Engineering 23 391,480 100,191
Water for Power 24 252,820 720,714
Hydraulic Expenses 25 706,805 79,575
Electric Expenses 26 241,292 37,156
Misc Hydraulic Power Generation Expenses 27 509,470 112,164
Rents 28 31,631 0
Maintenance Supervision and Engineering 29 19,394 2,766
Maintenance of Structures 30 55,592 38,357
Maintenance of Reservoirs, Dams, and Waterways 31 108,326 16,773
Maintenance of Electric Plant 32 333,032 44,893
Maintenance of Misc Hydraulic Plant 33 427,046 55,550
Total Production Expenses (total 23 thru 33) 34 3,076,888 1,208,139
Expenses per net KWh 35 0.0019 0.0127
FERC FORM NO. 1 (REV. 12-03) Page 406.1
2778
Shoshone Falls
2777
Upper Salmon
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
Item FERC Licensed Project No.
(b)(a)(c)
Plant Name:
FERC Licensed Project No.
Plant Name:
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.
Kind of Plant (Run-of-River or Storage) 1 Run-of-River Run-of-River
Plant Construction type (Conventional or Outdoor) 2 Outdoor Conventional
Year Originally Constructed 3 1937 1907
Year Last Unit was Installed 4 1947 1921
Total installed cap (Gen name plate Rating in MW) 5 34.50 12.50
Net Peak Demand on Plant-Megawatts (60 minutes) 6 34 13
Plant Hours Connect to Load 7 8,760 4,693
Net Plant Capability (in megawatts) 8
(a) Under Most Favorable Oper Conditions 9 39 14
(b) Under the Most Adverse Oper Conditions 10 32 11
Average Number of Employees 11 4 2
Net Generation, Exclusive of Plant Use - Kwh 12 191,224,000 42,929,000
Cost of Plant 13
Land and Land Rights 14 202,398 313,328
Structures and Improvements 15 2,069,321 1,231,506
Reservoirs, Dams, and Waterways 16 6,009,169 4,863,517
Equipment Costs 17 8,908,550 4,703,941
Roads, Railroads, and Bridges 18 29,359 51,383
Asset Retirement Costs 19 0 0
TOTAL cost (Total of 14 thru 19) 20 17,218,797 11,163,675
Cost per KW of Installed Capacity (line 20 / 5) 21 499.0956 893.0940
Production Expenses 22
Operation Supervision and Engineering 23 318,486 183,649
Water for Power 24 241,379 142,205
Hydraulic Expenses 25 368,449 119,810
Electric Expenses 26 92,996 48,168
Misc Hydraulic Power Generation Expenses 27 285,631 233,300
Rents 28 0 28
Maintenance Supervision and Engineering 29 6,650 3,996
Maintenance of Structures 30 85,360 22,470
Maintenance of Reservoirs, Dams, and Waterways 31 25,036 875
Maintenance of Electric Plant 32 85,328 81,483
Maintenance of Misc Hydraulic Plant 33 178,270 119,901
Total Production Expenses (total 23 thru 33) 34 1,687,585 955,885
Expenses per net KWh 35 0.0088 0.0223
FERC FORM NO. 1 (REV. 12-03) Page 406.2
1971
Brownlee Oxbow
1971
Cascade
2848
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
Idaho Power Company X
04/15/2015 2014/Q4
FERC Licensed Project No.
(e)(d)(f)
Plant Name:
FERC Licensed Project No.
Plant Name:
FERC Licensed Project No.
Plant Name:
Line
No.
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.
Run-of-River StorageStorage 1
Outdoor OutdoorOutdoor 2
1983 19611958 3
1984 19611980 4
12.42 190.00585.40 5
14 209615 6
8,750 8,7608,760 7
8
15 221747 9
1 202220 10
2 77 11
43,078,000 831,631,0001,916,947,000 12
13
82,142 1,212,76718,232,716 14
7,364,154 10,709,43432,155,940 15
3,145,630 30,435,63067,180,945 16
13,311,381 18,754,55258,941,432 17
122,668 565,842518,444 18
0 00 19
24,025,975 61,678,225177,029,477 20
1,934.4585 324.6222302.4077 21
22
242,699 419,169761,964 23
171,003 245,333465,585 24
440,368 687,2081,264,604 25
120,353 212,093253,884 26
331,652 511,9621,074,106 27
108 19,016115,980 28
3,668 15,08923,312 29
9,618 351,403103,542 30
-8 243-12,186 31
86,668 157,025437,940 32
78,483 233,555581,357 33
1,484,612 2,852,0965,070,088 34
0.0345 0.00340.0026 35
FERC FORM NO. 1 (REV. 12-03) Page 407
2055
C J Strike Twin Falls
18
Swan Falls
503
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
Idaho Power Company X
04/15/2015 2014/Q4
FERC Licensed Project No.
(e)(d)(f)
Plant Name:
FERC Licensed Project No.
Plant Name:
FERC Licensed Project No.
Plant Name:
Line
No.
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.
Run-of-River Run-of-RiverRun-of-River 1
Conventional ConventionalOutdoor 2
1910 19351952 3
1994 19951952 4
25.00 52.7482.80 5
18 4460 6
8,751 5,9408,760 7
8
24 5391 9
14 5084 10
4 35 11
110,848,000 59,763,000366,278,000 12
13
229,890 255,4995,476,746 14
27,237,723 10,980,0599,681,585 15
15,906,987 7,975,47310,806,251 16
30,609,794 21,200,82113,419,581 17
835,946 1,917,6031,602,868 18
0 00 19
74,820,340 42,329,45540,987,031 20
2,992.8136 802.6063495.0125 21
22
747,525 177,450812,529 23
568,175 133,137641,914 24
1,005,213 137,8811,127,584 25
33,633 65,02446,580 26
566,126 166,856598,565 27
10,179 3,37061,259 28
6,935 4,0529,179 29
70,868 31,573167,971 30
32,468 9,18279,491 31
153,011 101,736158,655 32
133,731 85,426110,131 33
3,327,864 915,6873,813,858 34
0.0300 0.01530.0104 35
FERC FORM NO. 1 (REV. 12-03) Page 407.1
1971
Common Facilities Milner
2899
Lower Salmon
2061
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
Idaho Power Company X
04/15/2015 2014/Q4
FERC Licensed Project No.
(e)(d)(f)
Plant Name:
FERC Licensed Project No.
Plant Name:
FERC Licensed Project No.
Plant Name:
Line
No.
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.
Run-of-River Run-of-River 1
Outdoor Conventional 2
1949 1992 3
1949 1992 4
60.00 59.450.00 5
36 440 6
8,757 3,8680 7
8
64 610 9
60 10 10
5 20 11
197,065,000 53,514,0000 12
13
424,428 138,100114,367 14
2,869,695 10,447,13640,956,158 15
6,920,148 17,188,30713,556,785 16
8,149,447 28,835,7332,096,941 17
88,693 501,87799,051 18
0 00 19
18,452,411 57,111,15356,823,302 20
307.5402 960.65860.0000 21
22
278,036 167,2300 23
213,833 1,407,5130 24
271,860 116,6586,911,220 25
103,894 34,8980 26
309,322 256,0680 27
2,869 3,4310 28
5,001 2,8060 29
92,696 36,2410 30
3,267 14,9050 31
105,375 44,8820 32
79,956 61,778121,392 33
1,466,109 2,146,4107,032,612 34
0.0074 0.04010.0000 35
FERC FORM NO. 1 (REV. 12-03) Page 407.2
Schedule Page: 406 Line No.: 1 Column: b
American Falls generating capacity is dependent upon water releases controlled by the
USBR.
Schedule Page: 406 Line No.: 1 Column: e
Cascade generating capacity is dependent upon water releases controlled by the USBR.
Schedule Page: 406 Line No.: 1 Column: f
Upstream storage in Brownlee Reservoir
Schedule Page: 406.1 Line No.: 1 Column: b
Upstream storage in Brownlee Reservoir
Schedule Page: 406.1 Line No.: 1 Column: c
Lower Malad maximum demand 15,000 Kw, Upper Malad maximum demand 9,000 Kw non-coincident.
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
FERC Licensed Project No.
Plant Name:
(b)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PUMPED STORAGE GENERATING PLANT STATISTICS (Large Plants)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
Item
(a)
1. Large plants and pumped storage plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. If any plant is leased, operating under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in a
footnote. Give project number.
3. If net peak demand for 60 minutes is not available, give the which is available, specifying period.
4. If a group of employees attends more than one generating plant, report on line 8 the approximate average number of employees assignable to each
plant.
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."
1 Type of Plant Construction (Conventional or Outdoor)
2 Year Originally Constructed
3 Year Last Unit was Installed
4 Total installed cap (Gen name plate Rating in MW)
5 Net Peak Demaind on Plant-Megawatts (60 minutes)
6 Plant Hours Connect to Load While Generating
7 Net Plant Capability (in megawatts)
8 Average Number of Employees
9 Generation, Exclusive of Plant Use - Kwh
10 Energy Used for Pumping
11 Net Output for Load (line 9 - line 10) - Kwh
12 Cost of Plant
13 Land and Land Rights
14 Structures and Improvements
15 Reservoirs, Dams, and Waterways
16 Water Wheels, Turbines, and Generators
17 Accessory Electric Equipment
18 Miscellaneous Powerplant Equipment
19 Roads, Railroads, and Bridges
20 Asset Retirement Costs
21 Total cost (total 13 thru 20)
22 Cost per KW of installed cap (line 21 / 4)
23 Production Expenses
24 Operation Supervision and Engineering
25 Water for Power
26 Pumped Storage Expenses
27 Electric Expenses
28 Misc Pumped Storage Power generation Expenses
29 Rents
30 Maintenance Supervision and Engineering
31 Maintenance of Structures
32 Maintenance of Reservoirs, Dams, and Waterways
33 Maintenance of Electric Plant
34 Maintenance of Misc Pumped Storage Plant
35 Production Exp Before Pumping Exp (24 thru 34)
36 Pumping Expenses
37 Total Production Exp (total 35 and 36)
38 Expenses per KWh (line 37 / 9)
FERC FORM NO. 1 (REV. 12-03) Page 408
FERC Licensed Project No.
Plant Name:
FERC Licensed Project No.
Plant Name:
(d)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PUMPED STORAGE GENERATING PLANT STATISTICS (Large Plants) (Continued)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
FERC Licensed Project No.
Plant Name:
(e)(c)
6. Pumping energy (Line 10) is that energy measured as input to the plant for pumping purposes.
7. Include on Line 36 the cost of energy used in pumping into the storage reservoir. When this item cannot be accurately computed leave Lines 36, 37
and 38 blank and describe at the bottom of the schedule the company's principal sources of pumping power, the estimated amounts of energy from each
station or other source that individually provides more than 10 percent of the total energy used for pumping, and production expenses per net MWH as
reported herein for each source described. Group together stations and other resources which individually provide less than 10 percent of total pumping
energy. If contracts are made with others to purchase power for pumping, give the supplier contract number, and date of contract.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
FERC FORM NO. 1 (REV. 12-03) Page 409
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
GENERATING PLANT STATISTICS (Small Plants)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.Name of Plant
Installed Capacity
(c)(b)(a)
Cost of PlantNet PeakDemand
(d)
YearOrig.Const.Name Plate Rating
(In MW)MW(60 min.)
Net GenerationExcludingPlant Use
(e) (f)
1. Small generating plants are steam plants of, less than 25,000 Kw; internal combustion and gas turbine-plants, conventional hydro plants and 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.
Hydro: 1
2.50 2.3 16,963 3,552,7851937 Clear Lakes 2
8.80 7.3 55,450 9,460,5341912 Thousand Springs 3
4
5
Internal Combustion: 6
5.00 3.0 26 909,2591967 Salmon Diesel (1) 7
8
9
10
(1) Salmon units are classified as standby. 11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO. 1 (REV. 12-03) Page 410
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
GENERATING PLANT STATISTICS (Small Plants) (Continued)
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.(i)(h)(g)(j) (k) (l)
Operation
Exc'l. Fuel
Production Expenses
Fuel Maintenance Kind of Fuel Fuel Costs (in cents
(per Million Btu)
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 AssetRetire. Costs) Per MW
1
34,565 1,421,114 2 125,875
186,324 1,075,061 3 265,566
4
5
6
181,852 7Diesel
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO. 1 (REV. 12-03) Page 411
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
(c)(b)(a)(d)(e)
DESIGNATION
From To
(f)(g)
VOLTAGE (KV)(Indicate whereother than60 cycle, 3 phase)
Operating Designed
Type of
Supporting
Structure
LENGTH (Pole miles)(In the case of underground linesreport circuit miles)
On Structureof LineDesignated
On Structuresof AnotherLine
Number
Of
Circuits
(h)
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.
S Tower 500.00 345.00 85.17 1 1 Borah Midpoint
S Tower 500.00 500.00 1.79 1 2 Boardman Slatt
S Tower 500.00 500.00 0.40 1 3 Summer lake Hemingway
S Tower 500.00 500.00 0.37 1 4 Hemingway Midpoint
5
S Tower 345.00 345.00 226.16 1 6 Jim Bridger Goshen
S Tower 345.00 345.00 76.06 2 7 State Line Midpoint
S Tower 345.00 345.00 27.06 1 8 Kinport Borah
S Tower 345.00 345.00 1 9 Jim Bridger Populus
S Tower 345.00 345.00 1 10 Populus Kinport
S Tower 345.00 345.00 1 11 Jim Bridger Populus
S Tower 345.00 345.00 1 12 Populus Borah
H Wood 345.00 345.00 79.30 1 13 Midpoint Borah #1
H Wood 345.00 345.00 77.58 2 14 Midpoint Borah #2
H Wood 345.00 345.00 2.67 2 15 Adelaide Tap Adelaide
16
H Wood 230.00 230.00 46.14 1 17 Quartz LaGrande
S Tower 230.00 230.00 0.70 2 18 Midpoint Hunt
H Wood 230.00 230.00 56.39 1 19 Brady Antelope
H Wood 230.00 230.00 0.08 1 20 Brady Treasureton
S Tower 230.00 230.00 17.94 2 21 Brady #1 & #2 Kinport
H Wood 230.00 230.00 1.40 1 22 Jim Bridger Point of Rocks
S Tower 230.00 230.00 72.67 1 23 Brownlee Ontario
S P Wood 230.00 138.00 9.91 1 24 Mora Bowmont
H Wood 230.00 138.00 8.75 1 25 Mora Bowmont
H Wood 230.00 230.00 2.79 1 26 Jim Bridger Point of Rocks
SP Steel 230.00 230.00 18.44 1 27 Caldwell 710 Locust
S Tower 230.00 230.00 7.58 1 28 Boise Bench Caldwell
H Wood 230.00 230.00 33.49 1 29 Boise Bench Caldwell
S Tower 230.00 230.00 15.91 2 30 Boise Bench Cloverdale
H Wood 230.00 230.00 1.67 1 31 Boardman Dalreed Sub
SP Steel 230.00 230.00 11.04 2 32 Brownlee 714 Oxbow
H Wood 230.00 230.00 29.97 1 33 Caldwell Ontario
S Tower 230.00 230.00 3.14 1 34 Caldwell Ontario
SP Steel 230.00 230.00 4.44 1 35 Bennett Mtn PP Rattlesnake TS
FERC FORM NO. 1 (ED. 12-87) Page 422
36 TOTAL 4,782.11 11.02 194
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
(c)(b)(a)(d)(e)
DESIGNATION
From To
(f)(g)
VOLTAGE (KV)(Indicate whereother than60 cycle, 3 phase)
Operating Designed
Type of
Supporting
Structure
LENGTH (Pole miles)(In the case of underground linesreport circuit miles)
On Structureof LineDesignated
On Structuresof AnotherLine
Number
Of
Circuits
(h)
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.
H Steel 230.00 230.00 68.17 1 1 Borah Hunt
H Steel 230.00 230.00 36.25 1 2 Danskin Hubbard
SP Steel 230.00 230.00 1.84 1 3 Danskin Hubbard
SP Steel 230.00 230.00 1.30 2 4 Danskin Hubbard
SP Steel 230.00 230.00 5.32 1 5 Danskin Bennett Mtn
SP Steel 230.00 230.00 12.98 1 6 Hemingway Bowmont
SP Steel 230.00 138.00 14.19 1 7 Langley Gulch Galloway Rd
SP Steel 230.00 138.00 2.09 1 8 Galloway Rd Willis Tap
S Tower 230.00 230.00 0.87 1 9 Boise Bench Midpoint #1
H Wood 230.00 230.00 108.41 1 10 Boise Bench Midpoint #1
S Tower 230.00 230.00 1.51 1 11 Brownlee Quartz Jct
H Wood 230.00 230.00 41.30 1 12 Brownlee Quartz Jct
S Tower 230.00 230.00 99.76 2 13 Brownlee Boise Bench #1 & #2
S Tower 230.00 230.00 10.32 2 14 Oxbow Brownlee
S Tower 230.00 230.00 3.49 1 15 Boise Bench Midpoint #2
H Wood 230.00 230.00 102.07 1 16 Boise Bench Midpoint #2
S Tower 230.00 230.00 20.02 2 17 Oxbow Pallette Jct
H Wood 230.00 230.00 24.43 2 18 Pallette Jct Imnaha
S Tower 230.00 230.00 9.05 2 19 Hells Canyon Palette Jct
S Tower 230.00 230.00 102.08 2 20 Brownlee Boise Bench
H Wood 230.00 230.00 106.29 1 21 Boise Bench Midpoint #3
H Wood 230.00 230.00 29.60 1 22 Palette Jct Enterprise
S Tower 230.00 230.00 0.41 1 23 Borah Brady #2
H Wood 230.00 230.00 3.52 1 24 Borah Brady #2
H Wood 230.00 230.00 3.84 1 25 Borah Brady #1
26
H Wood 161.00 161.00 90.69 1 27 Goshen State Line
S Tower 161.00 161.00 2.37 2 28 Don Goshen
H Wood 161.00 161.00 48.42 2 29 Don Goshen
30
H Wood 138.00 138.00 11.18 2 31 American Falls Power Plant Adelaide
S P Wood 138.00 138.00 0.12 2 32 American Falls Power Plant Adelaide
S Tower 138.00 138.00 1.15 2 33 Minidoka Loop Adelaide
S P Wood 138.00 138.00 9.58 2 34 Nampa Caldwell
H Wood 138.00 138.00 54.35 1 35 Upper Salmon Mountain Home Jct
FERC FORM NO. 1 (ED. 12-87) Page 422.1
36 TOTAL 4,782.11 11.02 194
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
(c)(b)(a)(d)(e)
DESIGNATION
From To
(f)(g)
VOLTAGE (KV)(Indicate whereother than60 cycle, 3 phase)
Operating Designed
Type of
Supporting
Structure
LENGTH (Pole miles)(In the case of underground linesreport circuit miles)
On Structureof LineDesignated
On Structuresof AnotherLine
Number
Of
Circuits
(h)
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.
H Wood 138.00 138.00 30.81 1 1 Upper Salmon Cliff
S P Wood 138.00 138.00 2.08 1 2 Eastgate Russet
S Tower 138.00 138.00 1.00 2 3 Brady Fremont
H Wood 138.00 138.00 24.38 2 4 Brady Fremont
S P Wood 138.00 138.00 24.33 2 5 Brady Fremont
H Wood 138.00 138.00 84.74 2 6 King Lower Malad
H Wood 138.00 138.00 66.47 2 7 Emmett Jct Payette
H Wood 138.00 138.00 6.20 1 8 Mountain Home AFB Tap
H Wood 138.00 138.00 73.27 1 9 Ontario Quartz
S Tower 138.00 138.00 1.01 2 10 King American Falls PP
H Wood 138.00 138.00 142.03 1 11 King American Falls PP
S P Wood 138.00 138.00 3.71 1 12 King American Falls PP
H Wood 138.00 138.00 6.19 1 13 Duffin Clawson
H Wood 138.00 138.00 0.33 1 14 American Falls Brady Tie
H Wood 138.00 138.00 5.66 1 15 Upper Salmon A-B King
H Wood 138.00 138.00 125.59 1 16 Upper Salmon B Wells
H Wood 138.00 138.00 73.60 1 17 King Wood River
S P Wood 138.00 138.00 10.31 2 18 Boise Bench Grove
H Wood 138.00 138.00 67.13 1 19 Quartz John Day
H Wood 138.00 138.00 2.79 1 20 Sinker Creek Tap
H Wood 138.00 138.00 2.51 1 21 Mora Cloverdale
S P Wood 138.00 138.00 22.28 1 22 Mora Cloverdale
S P Steel 138.00 138.00 0.96 2 23 Mora Cloverdale
S P Steel 138.00 138.00 3.80 1 24 Stoddard Jct Stoddard Sub
H Wood 138.00 138.00 1.81 1 25 Fossil Gulch Tap
H Wood 138.00 138.00 53.08 2 26 Wood River Midpoint
S P Wood 138.00 138.00 16.69 2 27 Wood River Midpoint
H Wood 138.00 138.00 37.15 1 28 Oxbow McCall
S P Wood 138.00 138.00 2.32 1 29 Oxbow McCall
S P Wood 138.00 138.00 7.47 2 30 Lowell Jct Nampa
S P Wood 138.00 138.00 19.40 1 31 Hunt Milner
H Wood 138.00 138.00 13.49 1 32 Strike Bruneau Bridge
S P Wood 138.00 138.00 18.46 2 33 American Falls Kramer Sub
S P Wood 138.00 138.00 11.72 1 34 Pingree Haven
S P Wood 138.00 138.00 25.21 2 35 Midpoint Twin Falls
FERC FORM NO. 1 (ED. 12-87) Page 422.2
36 TOTAL 4,782.11 11.02 194
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
(c)(b)(a)(d)(e)
DESIGNATION
From To
(f)(g)
VOLTAGE (KV)(Indicate whereother than60 cycle, 3 phase)
Operating Designed
Type of
Supporting
Structure
LENGTH (Pole miles)(In the case of underground linesreport circuit miles)
On Structureof LineDesignated
On Structuresof AnotherLine
Number
Of
Circuits
(h)
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.
S P Wood 138.00 138.00 1.69 1 1 Twin Falls Russett
S P Wood 138.00 46.00 6.17 2 2 Blackfoot Aiken
H Wood 138.00 69.00 57.21 1 3 Peterson Tendoy
S P Wood 138.00 138.00 6.36 1 4 Eastgate Tap Eastgate
S P Steel 138.00 138.00 1.84 2 5 Kimberly Tap Kimberly
H Wood 138.00 138.00 13.10 2 6 Boise Bench Mora
S P Wood 138.00 138.00 0.51 1 7 Bowmont-Caldwell Simplot Sub
S P Wood 138.00 138.00 6.52 1 8 Gary Lane Eagle
S P Steel 138.00 138.00 2.98 9.25 1 9 Locust Grove Blackcat Sub
S P Wood 138.00 138.00 4.02 0.14 1 10 Boise Bench Butler
S P Wood 138.00 138.00 6.73 1 11 Eagle Star
S P Steel 138.00 138.00 3.60 1 12 Karcher Sub Zilog Tap
S P Steel 138.00 138.00 4.02 0.42 1 13 Cloverdale - 712 712 - Wye
S P Steel 138.00 138.00 1.89 1 14 Victory Jct Victory
S P Steel 138.00 138.00 2.94 1 15 Butler Wye
H Wood 138.00 138.00 33.97 1 16 Horseflat Starkey
S P Steel 138.00 138.00 2.23 2 17 Starkey Mccall
H Wood 138.00 138.00 3.80 1 18 Starkey Mccall
S P Steel 138.00 138.00 1.50 1 19 Starkey Mccall
S P Wood 138.00 138.00 17.61 1 20 Starkey Mccall
S P Steel 138.00 138.00 2.78 1 21 Chestnut Happy Valley
138.00 22 Garnet Ward
S P Wood 138.00 138.00 8.89 1 23 McCall Lake Fork
S Steel 138.00 138.00 2.90 24 McCall Lake Fork
S P Steel 138.00 138.00 1.30 1 25 Caldwell Willis
S P Steel 138.00 138.00 1.59 1 26 Caldwell Willis
S P Wood 138.00 138.00 0.87 1 27 Caldwell Willis
S P Steel 138.00 138.00 0.79 2 28 Valivue Tap
S P Steel 138.00 138.00 8.64 1 29 Bowmont Happy Valley
S Tower 138.00 138.00 1.32 2 30 Kinport Don #1
S P Steel 138.00 138.00 2.71 1 31 Donn HOKU
S P Steel 138.00 138.00 0.22 2 32 HOKU Alamed
S P Steel 138.00 138.00 0.23 2 33 HOKU Alamed
S P Steel 138.00 138.00 2.85 1 34 HOKU Alamed
S P Steel 138.00 138.00 5.26 1 35 Rockland Jct Rockland Wind Farm
FERC FORM NO. 1 (ED. 12-87) Page 422.3
36 TOTAL 4,782.11 11.02 194
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
(c)(b)(a)(d)(e)
DESIGNATION
From To
(f)(g)
VOLTAGE (KV)(Indicate whereother than60 cycle, 3 phase)
Operating Designed
Type of
Supporting
Structure
LENGTH (Pole miles)(In the case of underground linesreport circuit miles)
On Structureof LineDesignated
On Structuresof AnotherLine
Number
Of
Circuits
(h)
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.
S P Wood 138.00 138.00 0.07 1 1 King Justice
H Wood 138.00 138.00 0.82 1 2 Twin Falls PP Tap
S P Steel 138.00 138.00 0.20 1 3 American Falls PP Amercian Falls Trans ST
H Wood 138.00 138.00 0.11 1 4 Lower Salmon King Tie
S Tower 138.00 138.00 4.30 2 5 C J Strike Strike Jct
H Wood 138.00 138.00 23.42 1 6 Strike Jct Mountain Home Jct
H Wood 138.00 0.05 1 7 Strike Jct Bowmont
S Tower 138.00 138.00 0.36 1 8 Strike Jct Bowmont
H Wood 138.00 138.00 68.02 1 9 Strike Jct Bowmont
H Wood 138.00 138.00 4.48 2 10 Lucky Peak Lucky Peak Jct
H Wood 138.00 138.00 10.47 1 11 Bliss King
S P Wood 138.00 138.00 1.30 1 12 Milner Deadend Milner PP
H Wood 138.00 138.00 0.95 1 13 Swan Falls Tap
14
15
16
H Wood 115.00 115.00 3.35 1 17 Hines BPA (Harney)
18
19
H Wood 69.00 69.00 167.03 1 20 69 Kv Lines
S P Wood 69.00 69.00 937.02 1 21 69 Kv Lines
22
23
S P Wood 46.00 46.00 408.37 1 24 46 Kv Lines
25
11.02 4,782.11 194 26 Total all lines
27
28
29
30
31
32
33
34
35
FERC FORM NO. 1 (ED. 12-87) Page 422.4
36 TOTAL 4,782.11 11.02 194
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS (Continued)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
COST OF LINE (Include in Column (j) Land,
Size of
Conductor
and Material
Land rights, and clearing right-of-way)EXPENSES, EXCEPT DEPRECIATION AND TAXES
OperationExpenses Maintenance Rents TotalLand Construction andOther Costs Total Cost
(i) (j) (k) (l)(m) (n)(o)(p)Expenses Expenses
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote 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 (l) on the book cost at end of year.
22,084,7851272 ACSR 21,828,404 256,381 1
446,7082X1780 ACSR 446,708 2
835,6621272 ACSR 835,662 3
1272 ACSR 4
5
17,314,2911272 ACSR 16,830,982 483,309 6
11,680,140795 ACSR 11,108,161 571,979 7
6,352,2811272 ACSR 6,008,061 344,220 8
10,157,4471272 ACSR 10,157,447 9
1272 ACSR 10
1,035,1431272 ACSR 1,035,143 11
1272 ACSR 12
13,618,641715.5 ACSR 13,335,498 283,143 13
15,467,494715.5 ACSR 15,402,643 64,851 14
399,394715.5 ACSR 347,946 51,448 15
16
5,500,184795 ACSR 5,437,966 62,218 17
1,007,597715.5 ACSR 998,452 9,145 18
3,524,1461272 ACSR 3,415,845 108,301 19
6,186795 ACSR 6,186 20
988,700715.5 ACSR 969,871 18,829 21
52,7151272 ACSR 51,525 1,190 22
22,218,6282X954 ACSR 20,541,790 1,676,838 23
2,611,179715.5 ACSR 2,197,386 413,793 24
715.5 ACSR 25
214,4221272 ACSR 212,523 1,899 26
10,913,3221590 ACSR 8,775,086 2,138,236 27
9,151,7681272 ACSR 7,403,554 1,748,214 28
715.5 ACSR 29
9,623,7131272 ACSR 6,560,901 3,062,812 30
89,694795 AAC 89,694 31
16,060,644954 ACSR 16,026,470 34,174 32
9,465,0452X954 ACSR 9,228,893 236,152 33
1272 ACSR 34
1,748,0551272 ACSR 1,666,354 81,701 35
FERC FORM NO. 1 (ED. 12-87) Page 423
36 32,046,045 516,707,077 548,753,122 7,400,901 3,369,518 3,284,850 14,055,269
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS (Continued)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
COST OF LINE (Include in Column (j) Land,
Size of
Conductor
and Material
Land rights, and clearing right-of-way)EXPENSES, EXCEPT DEPRECIATION AND TAXES
OperationExpenses Maintenance Rents TotalLand Construction andOther Costs Total Cost
(i) (j) (k) (l)(m) (n)(o)(p)Expenses Expenses
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote 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 (l) on the book cost at end of year.
23,093,5831590 ACSR 22,468,666 624,917 1
15,210,5611590 ACSR 15,210,561 2
1590 ACSR 3
1590 ACSR 4
3,528,0331590 ACSR 3,528,033 5
11,187,6451590 ACSR 9,332,649 1,854,996 6
10,029,0561590 ACSR 9,080,890 948,166 7
1272 ACSR 8
7,125,153715.5 ACSR 6,739,866 385,287 9
715.5 ACSR 10
2,886,643795 ACSR 2,833,575 53,068 11
795 ACSR 12
9,256,921VARIOUS 8,966,987 289,934 13
1,252,3341272 ACSR 1,237,524 14,810 14
14,368,867715.5 ACSR 14,141,042 227,825 15
VARIOUS 16
4,119,4021272 ACSR 4,031,934 87,468 17
1,822,4621272 ACSR 1,651,381 171,081 18
1,296,8171272 ACSR 1,252,130 44,687 19
6,441,971954 ACSR 6,257,154 184,817 20
5,911,660715.5 ACSR 5,663,803 247,857 21
1,951,3171272 ACSR 1,867,303 84,014 22
419,6741272 ACSR 416,606 3,068 23
715.5 ACSR 24
428,5211272 ACSR 421,273 7,248 25
26
664,537250 COPPER 648,382 16,155 27
2,431,762715.5 ACSR 2,343,558 88,204 28
397.5 ACSR 29
30
407,689250 COPPER 381,182 26,507 31
250 COPPER 32
270,559715.5 ACSR 249,232 21,327 33
3,870,714795 AAC 3,200,265 670,449 34
3,587,341795 ACSR 3,539,654 47,687 35
FERC FORM NO. 1 (ED. 12-87) Page 423.1
36 32,046,045 516,707,077 548,753,122 7,400,901 3,369,518 3,284,850 14,055,269
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS (Continued)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
COST OF LINE (Include in Column (j) Land,
Size of
Conductor
and Material
Land rights, and clearing right-of-way)EXPENSES, EXCEPT DEPRECIATION AND TAXES
OperationExpenses Maintenance Rents TotalLand Construction andOther Costs Total Cost
(i) (j) (k) (l)(m) (n)(o)(p)Expenses Expenses
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote 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 (l) on the book cost at end of year.
1,925,848795 ACSR 1,882,280 43,568 1
828,327795 AAC 557,504 270,823 2
4,645,528VARIOUS 4,080,596 564,932 3
VARIOUS 4
VARIOUS 5
3,285,450VARIOUS 3,208,627 76,823 6
2,768,680VARIOUS 2,734,762 33,918 7
8,885397.5 ACSR 6,930 1,955 8
5,238,709VARIOUS 5,204,281 34,428 9
9,231,653715.5 ACSR 9,014,734 216,919 10
715.5 ACSR 11
715.5 ACSR 12
356,0724\0 351,881 4,191 13
96,921954 ACSR 96,921 14
763,930250 COPPER 761,189 2,741 15
3,078,484VARIOUS 3,049,994 28,490 16
3,978,620VARIOUS 3,804,937 173,683 17
1,878,374VARIOUS 1,652,772 225,602 18
2,542,326397.5 ACSR 2,450,153 92,173 19
77,219VARIOUS 77,199 20 20
11,739,188715.5 ACSR 8,615,808 3,123,380 21
VARIOUS 22
795AAC 23
1272 ACSR 24
188,298250 COPPER 187,848 450 25
7,419,720397.5 ACSR 7,070,008 349,712 26
397.5 ACSR 27
2,839,732397.5 ACSR 2,698,198 141,534 28
397.5 ACSR 29
1,668,216715.5 ACSR 1,457,085 211,131 30
1,419,827715.5 ACSR 1,416,503 3,324 31
702,248397.5 ACSR 687,321 14,927 32
1,066,073715.5 ACSR 1,052,339 13,734 33
1,299,567397.5 ACSR 1,281,344 18,223 34
3,141,360VARIOUS 3,086,512 54,848 35
FERC FORM NO. 1 (ED. 12-87) Page 423.2
36 32,046,045 516,707,077 548,753,122 7,400,901 3,369,518 3,284,850 14,055,269
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS (Continued)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
COST OF LINE (Include in Column (j) Land,
Size of
Conductor
and Material
Land rights, and clearing right-of-way)EXPENSES, EXCEPT DEPRECIATION AND TAXES
OperationExpenses Maintenance Rents TotalLand Construction andOther Costs Total Cost
(i) (j) (k) (l)(m) (n)(o)(p)Expenses Expenses
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote 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 (l) on the book cost at end of year.
227,546715.5 ACSR 210,756 16,790 1
543,372715.5 ACSR 529,756 13,616 2
3,839,377397.5 ACSR 3,443,681 395,696 3
2,486,673715.5 ACSR 2,142,718 343,955 4
795 ACSR 5
733,561715.5 ACSR 718,864 14,697 6
49,642795 AAC 49,642 7
2,654,991795 AAC 2,165,954 489,037 8
4,438,9671272 ACSR 3,503,157 935,810 9
873,2921272 ACSR 838,605 34,687 10
3,450,670715.5 ACSR 3,270,853 179,817 11
477,376795 AAC 434,341 43,035 12
2,717,4871272 ACSR 2,577,075 140,412 13
1272 ACSR 14
1,539,907795 ACSR 1,405,436 134,471 15
21,859,795715.5 ACSR 19,385,962 2,473,833 16
715.5 ACSR 17
715.5 ACSR 18
715.5 ACSR 19
715.5 ACSR 20
2,337,8801272 ACSR 2,259,301 78,579 21
40,580 40,580 22
5,014,418715.5 ACSR 4,682,879 331,539 23
24
2,413,4491272 ACSR 2,141,218 272,231 25
795 ACSR 26
795 ACSR 27
351,497795 ACSR 351,497 28
6,705,9611272 ACSR 6,015,350 690,611 29
213,951715.5 ACSR 212,777 1,174 30
4,7741272 ACSR 4,584 190 31
1272 ACSR 32
795 ACSR 33
795 ACSR 34
-16,973795 ACSR -16,973 35
FERC FORM NO. 1 (ED. 12-87) Page 423.3
36 32,046,045 516,707,077 548,753,122 7,400,901 3,369,518 3,284,850 14,055,269
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS (Continued)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
COST OF LINE (Include in Column (j) Land,
Size of
Conductor
and Material
Land rights, and clearing right-of-way)EXPENSES, EXCEPT DEPRECIATION AND TAXES
OperationExpenses Maintenance Rents TotalLand Construction andOther Costs Total Cost
(i) (j) (k) (l)(m) (n)(o)(p)Expenses Expenses
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote 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 (l) on the book cost at end of year.
60,6591590 ACSR 60,659 1
63,322250 COPPER 63,264 58 2
76,560715.5 ACSR 76,560 3
4,406397.5 ACSR 4,406 4
623,189715.5 ACSR 622,115 1,074 5
2,569,755397.5 ACSR 2,563,423 6,332 6
2,516,050715.5 ACSR 2,429,399 86,651 7
715.5 ACSR 8
9
279,488715.5 ACSR 279,481 7 10
1,003,338715.5 ACSR 997,718 5,620 11
186,420715.5 ACSR 183,606 2,814 12
274,396397.5 ACSR 261,511 12,885 13
14
15
16
65,382397.5 ACSR 63,404 1,978 17
18
19
64,085,774VARIOUS 62,432,378 1,653,396 20
VARIOUS 21
22
23
17,665,729VARIOUS 17,471,193 194,536 24
14,055,269 3,284,850 3,369,518 7,400,901 25
548,753,122 516,707,077 32,046,045 14,055,269 3,284,850 3,369,518 7,400,901 26
27
28
29
30
31
32
33
34
35
FERC FORM NO. 1 (ED. 12-87) Page 423.4
36 32,046,045 516,707,077 548,753,122 7,400,901 3,369,518 3,284,850 14,055,269
Schedule Page: 422 Line No.: 9 Column: a
Lines 808 amd 809 are not Idaho Power Company they are the Company portion of investment
into the Populus Station Lines
Schedule Page: 422 Line No.: 10 Column: a
Lines 808 and 809 are not Idaho Power Company they are the Company's portion of investment
into the Populus station lines.
Schedule Page: 422 Line No.: 11 Column: a
Lines 808 and 809 are not Idaho Power Company they are the Company's portion of investment
into the Populus station lines.
Schedule Page: 422 Line No.: 12 Column: a
Lines 808 and 809 are not Idaho Power Company they are the Company's portion of investment
into the Populus station lines.
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINES ADDED DURING YEAR
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
(c)(b)(a) (d) (e)
LINE DESIGNATION
From To
LineLengthinMiles
SUPPORTING STRUCTURE
Type AverageNumber perMiles
CIRCUITS PER STRUCTURE
Present Ultimate
(f) (g)
1. Report below the information called for concerning Transmission lines added or altered during the year. It is not necessary to report
minor revisions of lines.
2. Provide separate subheadings for overhead and under- ground construction and show each transmission line separately. If actual
costs of competed construction are not readily available for reporting columns (l) to (o), it is permissible to report in these columns the
17.70S Pole 1 1 1 Bowmont Happy Valley 8.64
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
8.64 17.70 1 1
FERC FORM NO. 1 (REV. 12-03) Page 424
44 TOTAL
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINES ADDED DURING YEAR (Continued)
Idaho Power Company X
04/15/2015 2014/Q4
Line
No.
(k)(j)(h) (l) (m)
CONDUCTORS
Size Configuration
Voltage
KV
LINE COST
Land and Poles, Towers
and Fixtures Conductors
(n) (p)
Specification and Spacing (Operating)Land Rights and Devices(i)
costs. Designate, however, if estimated amounts are reported. Include costs of Clearing Land and Rights-of-Way, and Roads and
Trails, in column (l) with appropriate footnote, and costs of Underground Conduit in column (m).
3. If design voltage differs from operating voltage, indicate such fact by footnote; also where line is other than 60 cycle, 3 phase, indicate
such other characteristic.
Asset
(o)Retire. Costs
TVSACSR1272 2,630,873 6,705,961 3,384,477 690,611 138 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
2,630,873 3,384,477
FERC FORM NO. 1 (REV. 12-03) Page 425
44 690,611 6,705,961
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according 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).
Adelaide 138.00 345.00 13.80transmission 1
Aiken 13.00 46.00distribution 2
Alameda 13.00 46.00distribution 3
Alameda 13.09 138.00distribution 4
American Falls PP - attended 13.80 138.00transmission 5
American Falls 46.00 138.00 12.47transmission 6
Artesian 13.00 46.00distribution 7
Bannock Creek 13.00 46.00distribution 8
Bennett Mountain Power Plant- attended 18.00 230.00transmission 9
Bennett Mountain Power Plant- attended 4.16 18.00distribution 10
Bethel Court 13.00 138.00distribution 11
Black Cat 13.09 138.00distribution 12
Blackfoot 13.00 46.00distribution 13
Blackfoot 46.00 161.00 12.47transmission 14
Blackfoot 138.00 161.00 12.98distribution 15
Bliss - attended 13.80 138.00transmission 16
Blue Gulch 35.00 138.00distribution 17
Boise Bench - attended 138.00 230.00 13.20transmission 18
Boise Bench - attended 35.00 138.00distribution 19
Boise Bench - attended 69.00 138.00 12.98transmission 20
Boise Bench - attended 138.00 230.00 13.80transmission 21
Boise 13.00 138.00distribution 22
Borah 230.00 345.00 13.80transmission 23
Bowmont 46.00 69.00 6.90distribution 24
Bowmont 35.00 138.00distribution 25
Bowmont 69.00 138.00 12.98transmission 26
Bowmont 69.00 138.00 12.47transmission 27
Bowmont 138.00 230.00 13.80transmission 28
Brady 138.00 230.00 13.80transmission 29
Brady 46.00 138.00 12.47transmission 30
Brady 13.00 69.00distribution 31
Brownlee - attended 13.80 230.00transmission 32
Bruneau Bridge 35.00 138.00distribution 33
Bruneau Bridge 36.20 138.00distribution 34
Buckhorn 35.00 69.00distribution 35
Bucyrus 7.20 46.00distribution 36
Buhl 13.00 46.00distribution 37
Burley Rural 13.00 69.00distribution 38
Butler 13.09 138.00distribution 39
Caldwell 13.00 138.00distribution 40
FERC FORM NO. 1 (ED. 12-96) Page 426
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according 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).
Caldwell 138.00 230.00transmission 1
Caldwell 13.09 138.00distribution 2
Caldwell 69.00 138.00 12.47transmission 3
Caldwell 138.00 230.00 12.47transmission 4
Caldwell 4.16 13.00distribution 5
Canyon Creek 35.00 138.00distribution 6
Canyon Creek 69.00 138.00 12.98transmission 7
Cascade Power Plant - attended 4.60 69.00transmission 8
Cascade 13.10 69.00distribution 9
Cascade 25.00distribution 10
Chestnut 13.00 138.00distribution 11
Clear Lake - attended 2.40 46.00transmission 12
Cliff 46.00 138.00 12.50transmission 13
Cliff 46.00 138.00 12.95transmission 14
Cloverdale 13.00 138.00distribution 15
Dale 4.60 46.00distribution 16
Dale 13.00 46.00distribution 17
Dale 13.00 69.00distribution 18
Dale 36.20 138.00distribution 19
Dale 46.00 138.00 12.47transmission 20
Danskin- attended 18.00 230.00transmission 21
Danskin- attended 138.00 230.00 13.80transmission 22
Danskin- attended 4.16 18.00distribution 23
Danskin- attended 12.00 138.00transmission 24
Danskin- attended 13.80 35.00distribution 25
Don 7.60 138.00distribution 26
Don 13.20 138.00distribution 27
Don 13.00 138.00distribution 28
Don 14.00distribution 29
DRAM 13.09 138.00distribution 30
DRAM 138.00 230.00 13.80transmission 31
DRAM 12.47 138.00distribution 32
Duffin 35.00 138.00distribution 33
Eagle 13.09 138.00distribution 34
Eastgate 138.00distribution 35
Eastgate 13.00 138.00distribution 36
Eckert 36.20 138.00distribution 37
Eden 36.20 138.00distribution 38
Eden 46.00 138.00 12.98transmission 39
Elkhorn 12.47 138.00distribution 40
FERC FORM NO. 1 (ED. 12-96) Page 426.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according 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).
Elkhorn 13.00 138.00distribution 1
Elmore 35.00 138.00distribution 2
Elmore 69.00 138.00 12.50transmission 3
Elmore 69.00 138.00 12.98transmission 4
Emmett 138.00distribution 5
Emmett 69.00 138.00 12.47transmission 6
Falls 13.00 46.00distribution 7
Falls 46.00distribution 8
Filer 13.00 46.00distribution 9
Flat Top 13.00 46.00distribution 10
Flying H 2.40 69.00distribution 11
Fort Hall 13.00 46.00distribution 12
Fossil Gulch 35.00 138.00distribution 13
Fremont 46.00 138.00 12.50transmission 14
Gary 13.09 138.00distribution 15
Gary 13.00 138.00distribution 16
Gem 13.00 69.00distribution 17
Gem 69.00distribution 18
Goodng Rural 13.00 46.00distribution 19
Golden Valley 13.00 69.00distribution 20
Gowen Substation 35.00 138.00distribution 21
Grindstone 35.00distribution 22
Grove 13.09 138.00distribution 23
Grove 13.00 138.00distribution 24
Hagerman 13.00 46.00distribution 25
Hagerman 13.00 69.00distribution 26
Hailey 13.00 138.00distribution 27
Happy Valley 13.09 138.00distribution 28
Haven 35.00 138.00distribution 29
Haven 46.00 138.00transmission 30
Hemingway 230.00 500.00 34.50transmission 31
Hewlett Packard 13.00 138.00distribution 32
Hidden Springs 13.00 138.00distribution 33
Highland 13.00 138.00distribution 34
Hill 13.00 138.00distribution 35
Hillsdale 138.00distribution 36
Hoku 13.80 138.00distribution 37
Homedale 13.00 69.00distribution 38
Horse Flat 138.00 230.00 13.80transmission 39
Horseshoe Bend 35.00distribution 40
FERC FORM NO. 1 (ED. 12-96) Page 426.2
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according 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).
Horseshoe Bend 36.20 69.00distribution 1
Horseshoe Bend 25.00 69.00distribution 2
Huston 13.00 69.00distribution 3
Hulen 13.00 46.00distribution 4
Hunt 138.00 230.00 13.80transmission 5
Hydra 36.20 138.00distribution 6
Island 13.00 69.00distribution 7
Jerome 13.00 138.00distribution 8
Jerome 13.09 138.00distribution 9
Julion Clawson 35.00 138.00distribution 10
Joplin 13.00 138.00distribution 11
Joplin 35.00 138.00distribution 12
Justice 138.00 230.00 13.80transmission 13
Karcher 13.00 138.00distribution 14
Kenyon 13.00 69.00distribution 15
Ketchum 13.00 138.00distribution 16
Kimberly 13.00 138.00distribution 17
Kinport 46.00 161.00 13.20transmission 18
Kinport 138.00 230.00 12.47transmission 19
Kinport 138.00 230.00 13.80transmission 20
Kinport 230.00 345.00 13.80transmission 21
Kramer 35.00 138.00distribution 22
Kramer 36.20 138.00distribution 23
Kuna 13.00 138.00distribution 24
Lake 13.00 69.00distribution 25
Lake Fork 36.20 138.00distribution 26
Lake Fork 69.00 138.00 12.50transmission 27
Lamb 13.00 138.00distribution 28
Langley Gulch- attended 138.00 230.00 13.80transmission 29
Langley Gulch- attended 230.00transmission 30
Langley Gulch- attended 4.16distribution 31
Langley Gulch- attended 4.16 13.00distribution 32
Lansing 13.00 69.00distribution 33
Lincoln 13.09 138.00distribution 34
Linden 13.00 138.00distribution 35
Locust 36.20 138.00distribution 36
Locust 138.00 230.00 13.80transmission 37
Lower Malad - attended 7.20 138.00transmission 38
Lower Salmon - attended 13.80 138.00transmission 39
Map Rock 13.00 69.00distribution 40
FERC FORM NO. 1 (ED. 12-96) Page 426.3
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according 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).
McCall 13.09 13.00distribution 1
McCall 36.20 138.00distribution 2
Meridian 13.00 138.00distribution 3
Micron 13.09 138.00distribution 4
Micron 13.00 138.00distribution 5
Midpoint 138.00 230.00 13.80transmission 6
Midpoint 230.00 345.00 13.80transmission 7
Midpoint 345.00 500.00transmission 8
Midrose 13.09 138.00distribution 9
Milner 69.00 138.00 12.47transmission 10
Milner 46.00 69.00 6.90distribution 11
Milner 35.00 138.00distribution 12
Milner PP - attended 13.80 138.00transmission 13
Moonstone 35.00 138.00distribution 14
Mora 35.00 138.00distribution 15
Mora 36.20 138.00distribution 16
Moreland 13.00 35.00distribution 17
Moreland 13.00 46.00distribution 18
Moreland 35.00 46.00 12.47distribution 19
Mountain Home 13.00 69.00distribution 20
Mountain Home Air Force Base 13.00 69.00distribution 21
Mountain Home Air Force Base 13.00 138.00distribution 22
Nampa 138.00 230.00 13.80transmission 23
Nampa 13.00 138.00distribution 24
New Meadows 36.20 138.00distribution 25
New Plymouth 13.00 69.00distribution 26
Notch Butte 13.09 138.00distribution 27
Orchard 36.20 69.00distribution 28
Orchard 35.00 69.00 12.47distribution 29
Parma 13.00 69.00distribution 30
Parma 35.00 69.00distribution 31
Paul 35.00 138.00distribution 32
Payette 13.00 138.00distribution 33
Pingree 46.00 138.00 12.50transmission 34
Pingree 35.00 138.00distribution 35
Pleasant Valley 35.00 138.00distribution 36
Pocatello 13.00 46.00distribution 37
Poleline 13.09 138.00distribution 38
Populus 345.00transmission 39
Portneuf 35.00 138.00distribution 40
FERC FORM NO. 1 (ED. 12-96) Page 426.4
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according 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).
Portneuf 35.00 46.00distribution 1
Rockford 13.00 46.00distribution 2
Russett 13.00 138.00distribution 3
Sailor Creek 2.40 138.00distribution 4
Sailor Creek 35.00 138.00distribution 5
Salmon 13.00 69.00distribution 6
Salmon 34.50 69.00 12.47distribution 7
Salmon 69.00 12.47distribution 8
Salmon 2.40 13.00transmission 9
Shoshone 13.00 46.00distribution 10
Shoshone 7.20 46.00distribution 11
Shoshone Falls - attended 2.30 46.00transmission 12
Shoshone Falls - attended 6.60 46.00transmission 13
Silver 35.00 138.00distribution 14
Simplot 13.00 138.00distribution 15
Sinker Creek 35.00 138.00distribution 16
Siphon 35.00 138.00distribution 17
South Park 13.00 46.00distribution 18
Star 13.09 138.00distribution 19
Starkey 69.00 138.00 12.47transmission 20
State 13.00 69.00distribution 21
Stoddard 13.00 138.00distribution 22
Strike Power Plant - attended 13.80 138.00transmission 23
Sugar 35.00 138.00distribution 24
Swan Falls - attended 6.90 138.00transmission 25
Taber 13.00 46.00distribution 26
Ten Mile 13.09 138.00distribution 27
Terry 13.09 138.00distribution 28
Terry 13.00 138.00distribution 29
Thousand Springs - attended 7.20 46.00transmission 30
Thousand Springs - attended 2.40 7.00transmission 31
Toponis 33.00 138.00distribution 32
Twin Falls 13.09 138.00distribution 33
Twin Falls 46.00 138.00 12.98transmission 34
Twin Falls PP - attended 7.20 138.00transmission 35
Twin Falls PP - attended 13.20 138.00transmission 36
Upper Malad - attended 7.20 45.00transmission 37
Upper Salmon- attended 7.20 138.00transmission 38
Ustick 13.00 138.00distribution 39
Vallivue 13.09 138.00distribution 40
FERC FORM NO. 1 (ED. 12-96) Page 426.5
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according 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).
Victory 13.00 138.00distribution 1
Victory 13.09 138.00distribution 2
Ware 13.00 69.00distribution 3
Weiser 13.00 69.00distribution 4
Weiser 69.00 138.00 12.47transmission 5
Wilder 13.00 69.00distribution 6
Willis 13.09 138.00distribution 7
Wye 13.00 138.00distribution 8
Wye 13.09 138.00distribution 9
Zilog 13.09 138.00distribution 10
11
12
The above are all State of Idaho 13
14
Montana: 15
Peterson 69.00 230.00 13.20transmission 16
17
Nevada: 18
Valmy - attended 125.00 345.00 24.90transmission 19
Valmy - attended 125.00 345.00 24.90transmission 20
Valmy - attended 24.90 120.00 7.20transmission 21
Valmy - attended 345.00transmission 22
Valmy - attended 345.00transmission 23
Valmy - attended 345.00transmission 24
Valmy - attended 345.00transmission 25
Valmy - attended 345.00transmission 26
Wells 69.00 138.00 13.00transmission 27
28
Oregon: 29
Boardman - attended 24.00 500.00transmission 30
Boardman - attended 7.20 230.00transmission 31
Boardman - attended 7.20 24.00transmission 32
Cairo 13.00 69.00distribution 33
Hells Canyon - attended 13.80 230.00transmission 34
Hells Canyon - attended 0.50 69.00distribution 35
Hines 115.00 138.00 12.47transmission 36
Malheur Butte 34.50 69.00distribution 37
Nyssa 13.00 69.00distribution 38
Ontario 13.00 138.00distribution 39
Ontario 69.00 138.00 12.47transmission 40
FERC FORM NO. 1 (ED. 12-96) Page 426.6
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according 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).
Ontario 138.00 230.00 13.80transmission 1
Ontario 69.00 138.00 12.98transmission 2
Ontario 69.00 138.00 13.09transmission 3
Ore-Ida 13.00 69.00distribution 4
Oxbow - attended 69.00 138.00 13.00transmission 5
Oxbow - attended 13.80 230.00transmission 6
Oxbow - attended 138.00 230.00 13.80transmission 7
Quartz 69.00 138.00 12.50transmission 8
Quartz 138.00 230.00 12.98transmission 9
Quartz 69.00 138.00 12.98transmission 10
Vale 13.00 69.00distribution 11
12
Wyoming: 13
Jim Bridger - attended 230.00 345.00 34.50transmission 14
15
16
17
18
19
Transformers-distribution substations under 10,000 20
KVA 83 unattended. 21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO. 1 (ED. 12-96) Page 426.7
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment 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.
300 2 1
20 2 2
15 1 3
18 1 4
72 1 5
25 1 6
10 1 7
10 1 8
135 1 9
5 1 10
15 1 11
24 1 12
30 2 13
50 3 1 14
80 1 15
69 3 16
15 1 17
254 2 18
42 2 19
75 3 20
240 2 21
67 3 22
450 3 1 23
8 3 24
18 1 25
25 1 26
25 1 27
180 1 28
312 3 29
1 30
1 31
721 5 1 32
18 1 33
24 1 34
20 1 35
6 1 1 36
20 2 37
12 1 38
48 2 39
15 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment 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.
120 1 1
24 1 2
75 3 3
120 1 4
1 5
15 1 6
15 1 7
12 1 8
15 2 9
4 1 10
48 2 11
4 1 12
12 2 1 13
4 1 14
48 2 15
1 16
6 17
1 18
27 1 19
25 1 20
140 1 21
180 1 22
6 1 23
96 2 24
5 1 25
1 26
108 6 3 27
26 1 1 28
80 6 29
118 7 30
160 2 31
17 1 32
36 2 33
38 2 34
24 1 35
18 1 36
18 1 37
24 1 38
15 1 39
8 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment 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.
8 1 1
17 1 2
15 1 3
15 1 4
24 1 5
25 1 6
8 1 7
10 1 8
10 1 9
13 2 10
15 2 11
10 1 1 12
15 1 13
50 3 1 14
20 1 15
17 1 16
8 1 17
10 1 18
15 2 19
10 1 1 20
24 1 21
10 2 22
48 2 23
24 1 24
10 1 25
5 1 26
20 1 27
18 1 28
12 1 29
25 1 30
600 3 1 31
20 1 32
8 1 33
18 1 34
39 2 35
24 1 36
2 37
22 2 38
100 1 39
5 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.2
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment 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.
12 1 1
5 1 2
10 1 3
10 1 4
300 3 5
48 2 6
12 1 7
20 1 8
20 1 9
30 2 10
15 1 11
18 1 12
180 1 13
12 1 14
20 2 15
42 2 16
18 1 17
7 18
180 1 19
180 1 20
600 3 1 21
12 1 22
18 1 23
15 1 24
10 1 25
18 1 26
15 1 27
18 1 28
180 1 29
246 2 30
12 1 31
12 1 32
12 1 33
10 1 34
33 2 35
48 2 1 36
360 2 37
16 1 38
70 4 39
10 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.3
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment 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.
12 1 1
18 1 2
36 2 3
24 2 4
24 2 5
120 1 6
840 2 1 7
750 3 8
24 1 9
75 3 1 10
8 3 1 11
29 2 12
36 1 13
12 1 14
15 1 15
24 1 16
6 1 17
8 1 18
6 3 1 19
15 1 20
1 21
18 1 22
180 1 23
50 3 24
12 1 25
10 1 26
10 1 27
6 1 28
10 3 29
10 1 30
12 1 31
36 2 32
23 3 33
50 3 34
22 2 35
42 2 36
36 2 37
18 1 38
39
18 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.4
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment 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.
1 1
14 2 2
18 1 3
15 2 4
15 1 5
10 1 3 6
10 3 7
2 8
5 2 9
10 1 10
2 3 11
3 1 12
10 1 13
12 1 14
30 2 15
12 1 16
33 2 17
10 1 18
18 1 19
18 1 20
33 2 21
15 1 22
83 3 23
20 2 24
18 1 25
5 1 26
24 1 27
12 1 28
30 2 29
8 1 30
1 31
18 1 32
44 2 33
33 2 34
9 1 35
72 1 36
8 1 37
36 4 38
44 2 39
18 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.5
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment 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.
24 1 1
18 1 2
12 1 1 3
20 2 4
25 1 5
10 1 6
18 1 7
36 2 8
20 1 9
24 1 10
11
12
13
14
15
24 3 1 16
17
18
1 19
1 20
1 21
48 1Line Reactor 22
35 1Line Reactor 23
35 1Line Reactor 24
35 1Line Reactor 25
35 1Line Reactor 26
20 3 1 27
28
29
685 3 30
55 1 31
55 1 32
12 1 33
333 2 1 34
1 1 35
40 1 36
8 3 1 37
20 2 38
38 2 39
25 1 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.6
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
Idaho Power Company X 04/15/2015 2014/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment 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.
240 2 1
50 2 2
1 3
15 1 4
10 3 1 5
244 2 6
100 1 7
15 1 8
100 3 1 9
15 1 10
10 1 11
12
13
703 7 14
15
16
17
18
19
20
334 21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO. 1 (ED. 12-96) Page 427.7
Schedule Page: 426.2 Line No.: 31 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.: 39 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.: 19 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.: 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.: 23 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.: 24 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.: 25 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 Sierra Pacific Power Company, d/b/a NV Energy. Idaho Power has a 50%
share of ownership.
Schedule Page: 426.6 Line No.: 30 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.: 31 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.: 32 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.: 14 Column: a
Jointly owned with PacificCorp. Idaho Power has a 33.3% share of ownership.
Name of Respondent
Idaho Power Company
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2015
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSACTIONS WITH ASSOCIATED (AFFILIATED) COMPANIES
Idaho Power Company X
04/15/2015 2014/Q4
Line
No. Description of the Non-Power Good or Service
Name of
(c)(b)(a)(d)
Associated/AffiliatedCompany
AccountCharged orCredited
Amount
Credited
1. Report below the information called for concerning all non-power goods or services received from or provided to associated (affiliated) companies.
2. The reporting threshold for reporting purposes is $250,000. The threshold applies to the annual amount billed to the respondent or billed toan associated/affiliated company for non-power goods and services. The good or service must be specific in nature. Respondents should notattempt to include or aggregate amounts in a nonspecific category such as "general".3. Where amounts billed to or received from the associated (affiliated) company are based on an allocation process, explain in a footnote.
Charged or
1 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
21 Managerial Expenses 951,135IDACORP, INC. 417420
22 74,887922000
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
FERC FORM NO. 1 (New) Page 429
FERC FORM NO. 1-F (New)
December 31, 2014
ANNUAL REPORT
TDAHOSUPPLEMENTTOFERCFORM'
= H
i,ruLTr€TATE ELEcrRrc coMpANrEs F-"- i;
=t:
:-.i :.3
INDEX i i. : ^; ,
''.' ., i.-r
Page . _-"
Number Title ' ,:/-1 Statement of lncome for the Year <.r
2 Taxes Allocated to ldaho
3 Notes and Accounts Receivable
3 Accumulated Provision for Uncollectible Accounts
4 Receivables from Associated Companies
5 Gain or Loss on Disposition of Property
6 Professional or Gonsultative Services
7-10 Electric Plant in Service
11 Electric Operating Revenues
12-15 Electric Operation and Maintenance Expenses
15 Number of Electric Department Employees
IDAHO SUPPLEf,EiIT
This Page lntentionally Left Blank
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.
lnclude these amounts in columns (c) and (d) totals.
2. Report amounts in account 414, Other Utility Operating lncome, in the same manner as accounts 412 and 413 above.
3. Repoft data for lines 7, 9, and 10 for Natural Gas companies using accounts 4(X.1 , 4U.2, 4U.3, 407 .1 , and 407 .2.
4. Use page 122lor imporlant notes regarding the state ment of income or any account thereof.
5. Give concise explanations conceming unsettled rate proceedings where a contingency exists such that refunds of a
material amount may need to be made to the utility's customers orwhich may result in a material refund to the utility
with respect to power or gas purchases. State for each year affecled the gross revenues or costs to which the contingency
relates and the tax efiects together with an elglanation of retain such revenues or lecover amounts paid with respect
to power and gas purchases.
6. Give concise explanations conceming signifcant amounts of any refunds made or received during the year.
Account
(a)
1
2
3
4
5
6
7
8
I
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
Revenues (400)...............
Expenses
Operation Expenses (401)...............
Maintenance Expenses (4O2)...............
Depreciation Expense (403)...............
Amort. & Depl. of Utility Plant (404-405)......................
Amort. of Utility Plant Acq. Adj. (406)........
Amort. of Property Losses, Unrecovered Plant and
Accretion Expense (41 1 )...............
Regulatory Study Costs (407)...............
Amort. of Convesion Expenses (404............
Regulatory Debits/Gredits (407.3 & 407 .4).. ..... ............
Taxes OtherThan lncome Taxes (408.1).
lncome Taxes - Federal (409.1)............
- Other (409.1)
Provision for Defened lncome Taxes (41 0. 1 & 41 1 . 1 ) Net... ... ... ... .....,
lnvestment Tax Credit Adj. - Net (411.4)...
(Less) Gains ftom Disp. of Utility Plant (41 1.6)...
Losses from Disp. of Utility Plant (4'l 1.7)...
(Less) Gains from Disposition of Allowances (411.8).........
Losses from Disposition of Allowances (41 1 .9)............
TOTAL Utility Operating Expenses (Enter Total of lines 4lhru 221.....-.
Net Utility Operating lncome (Enter Total of line 2 less 24)...............
$ 1,219,568,337 $ 1,185,097,499
744,6',11,224
il,952,478
120,300,338
6,687,969
296,254
29,569,719
6,624,230
't7,355,209
39,767
983,381,958
675,538,535
64,415,077
116,783,035
7,248,578
308,2s8
28,374,3U
10,004,411
5,361,984
53,612,675
960,904,694
$ 236,186,379
STATE OF IDAHO -ALLOCATED
An Original December3l,2014ldaho Power Company
IDAHO SUPPLEMENT Page 1
TAXES ALLOCATED TO IDAHO
Kind of Tax
Taxes Other Than lncome Taxes:
Taxes Charged
Durino Year
Labor Related:F1cA........... $ 13,407,613
FUT4..........
State Unemployment.....
87,691
671,527
PayrollDeduction & Loading... (14,166,830)
Total Labor Related..,.... 0
Property Taxes......... 25,524,590
Kilowaft-hour Tax...........1,127,188Licenses..... 4,686
Regulatory Commission Fees........... 2,688,423
lnigation P1C............. 224,831
Canada Sales Tax... 0
Total Taxes Other Than lncome Taxes........... 29,569,719
Federal lncome Taxes......... (7,055,229)
State lncome Taxes...... 6,624,230
Defened lncome Taxes.........
I nvestment Tax Credit Adjustment - Net..........
17,355,209
39,767
Total Taxes Allocated to ldaho.$ 46,533,696
STATE OF IDAHO . ALLOCATED
An Original December 31, 20110ldaho Power Company
IDAHO SUPPLETIENT Page 2
NOTES AND ACCOUNTS RECEIVABLE
Summary for Balance Sheet
Show separately by footnote the total amount of notes and accounts receivable
ftom direclors, officers, and employees included in Notes Receivable (Account
141) and OtherAccounts Receivable (Account 143)
Line
No.
Accounts
(a)
Balance
Beginning of
Year
(b)
Balance
End of
Year
(c)
1
2
3
4
5
6
7
I
I
10
11
12
13
14
15
16
17
18
19
20
al)$50,208
100,221,798
1't,336,4s2
111,608,458
2,501,686
109,1W,772
$
$
85,040,915
14,677,M1
99,718,3s6
4,650,829
95,67,527
$
s
Customer Accounts Receivable (Account 142)..
Other Accounts Receivable (Account 143).....................
(Disclose any capital stock subscription received)
Tntal
Less: Accumulated Provision for Uncolleclible
Accounts-Cr. (Account 1 44\.........
Total, Less Accumulated Provision for
I lnaallaalihla Aaaar rnlq
ACCUMUIATED PROVISION FOR UNCOLLECTIBLE ACCOUNTS - CR. (Account 144)
1. Report below the information called for conceming this accumulated povision.
2. Erplain any important adjustrnents of subaccounts.
3. Entries with respecl to officers and employees shall not include items for utility seruices.
Line
No.
Item
(a)
Utility
Customers
(b)
MOSe,
Jobbing &
Contract
Work
(c)
Ofiicers
and
Employees
(d)
Gher
(e)
Total
(fl
21
22
23
24
25
26
27
28
29
30
31
32
33
Balance Beg of Year:
Uncolleclible Accts
Uncollectible Damage Claims
Uncollectibe Delivery Business Unit
Balance end of year.....
$ 2,332,388
152,806
16,492
$$$ (402,077"
(9,1601
2,560,380
$ 1,930,311
$ 143,646
$ 2,576,872
$ 2,501,686 $$$ 2,149,143 $ 4,650,829
ldaho Power Company
STATE OF IDAHO
An Original D,ecembsr 31, 2014
IDAHO SUPPLETENT Page 3
ldaho Power Company
STATE OF IDAHO
An Original D,ecember 31, 2014.
RECEIVABLES FROM ASSOCIATED COMPANIES (Accounts 145' 146)
1. Repoft particulars of notes and accounts receivable from associated companies at end of year.
2. Provide separate headings and totals for accounts 145, Notes Receivable ftom Associated Companies, and 1'16'
Accounts Receivable ftom Associated Companies, in addition to a total for the combined accounts.
3. For notes reeivable 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. ll any note was received in satisfaction of an open account, state the period covered by such open account.
S. lnclude in column (0 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.
Line
No.
Particulals
(a)
Balance
Beginning
of Year
(b)
Totals for Year Balance
End of Year
(e)
lnterest
For Year
(f)
Debits
(c)
Credits
(d)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
't8
19
20
21
22
23
24
25
26
27
28
29
30
31
32
Account 145:
$ 2,053,198 $ 2.053,198
Total Account 145.2,053,198 2,053,198
Account 146:
IDACORP, |nc............
Total Account'146..
$ 6,576,23s $ 6,s76,23s $
$$ 6,576,235 $ 6,576,235
IDAHO SUPPLETIENT Page 4
STATE OF IDAHO. TOTAL SYSTEM DATA
GAIN OR LOSS ON DISPOSITION OF PROPERTY (Account 421 .1 and 421 .2)
1. Give a brief description of property creating the gain or loss. lnclude name of party acquiring the property (when
acquired by another utility or associated company) and the date transaclion was completed. ldentiff property
by type; Leased, Held for Future Use, or Nonutility.
2. lndividual gains or losses rclating to property with an original cost of less than $50,000 may be grouped, with the
number of such transac'tions disclosed in column (a).
3. Give the date of Commission approval of joumal entries in column (b), when approval is required. Where approval
is required but has not been received, give explanation following the item in column (a). (See account 102, Utility
Plant Purchased or Sold.)
Line
No.
Description of Property
(a)
ungrnal uost
of Related
(b)
Date Joumal
Entry Approved
(When Required)
(c)
Acr,.421.1
(d)
Aicd..421.2
(e)
1
2
3
4
5
6
7
I
9
10
't1
12
't3
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
lC"in on disposition of
lprooerty:
lWater Management Facility
lCharges incuned in2014 related to
I'sale-disposal of land anticipaed in 2015.
Boise Operations Center charges incuned
in2014 related to Sale.project anticipated
to be completed in 2015.
Total gain.......
$$$
$ 319
5,938
$0 s 6,257
falql laec $0 $0
ldaho Power Company
STATE OF IDAHO
An Original D,ecember 31, 2014
IDAHO SUPPLEMENT Page 5
Irecember 31, 201.3
STATE OF IDAHO - TOTAL SYSTEM DATA
PROFESSIONAL OR CONSULTATIVE SERVICES - ITEMS $1O,OOO AND OVER
29,200
133,007
137,128
10,850
473,831
22,040
40,430
13,395
10,399
10,170
12,942
'1,309,080
45,729
12,400
134,471
82,633
21,504
306,279
14,360
14,227
31,584
953,914
22,856
35,000
21,850
13,685
51,600
729,598
36,713
39,600
137,506
60,620
44,794
31,040
278,106
11,381
223,232
41,824
22j20
100,000
269,620
25,498
nergy Efficiency Services
Business lntelligence Support services
LegalServices
LegalServices
RealEstate
Engineering Services
Management Services
Management Services
Management Services
LegalServices
LegalServices
Management Services
LegalServices
LegalServices
Data Center Management Services
Consulting Services
Management Services
LegalServices
LegalServices
LegalServices
Training Consultants
Management Services
LegalServices
TECHNOLOGIES AND SOLUTIO
Y CONSTRUCTION LLC
ROSHOLT & SIMPSON LLP
BULLARD SM]TH JERNSTEDT WILSON
FORENSICS CORPORATION
DAVIS WRIGHT TREMAINE LLP
ELAM AND BURKE PA
EVANS KEANE
EVERGREEN CONSULTING GROUP, LL
EVERGREEN ECONOMICS, INC.
EXISTBI
IVENS PURSLEY LLP
GREENBERG TRAURIG LLP
HARDESW, REBECCA
HDR ENGINEERING, INC
HONEYWELL INTERNATIONAL INC
INDUSTRIAL HYGIENE RESOURCES,
ISS CORPORATE SERVICES, INC
JOHNSON CONSULTING GROUP
KLARQUIST SPARKMAN LLP
MAINLINE INFORMATION SYSTEMS I
MCDOWELL RACKNER & GIBSON PC
MIRANDE, MICHAEL
NETIO
NIELSEN GROUP INC, THE
OXFORD GLOBAL RESOURCES INC
PAINE HAMBLEN LLP
PARR BROWN GEE & LOVELESS INC
PERKINS COIE LLP
PROFESS]ONAL TRAINING SYSTEMS
RM ENERGY CONSULTING
SCHWABE WILLIAMSON & WYATT
SCOTT & SCOTT LLP
2
3
4
5
6
7
8I
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
Ideho PowBr Gompany
IDAHO SUPPLEMEilT
ldaho Power Compeny
STATE OF IDAHO
An Orlglnal December 31, 201t1
STATE OF IDAHO. TOTAL SYSTEM DATA
PROFESSIONAL OR CONSULTATIVE SERVICES - ITEMS $1O,OOO AND OVER
Seeding & Modeling Services
TETRATECH MA INC
THINK BtG SOLUTIONS INC
TUERI LLC
UNIVERSIW CORPORATION FOR
UNIVERSTW OF IDAHO
, BARKER, KNAUER LLP
47
48
49
50
51
52
53u
55
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
81
82
83
84
85
86
87
IDAHO SUPPLEf,EI{T
ldaho Powsr Company
STATE OF IDAHO
An Origlnal December 3{, 2014
Line
No.
PROFESSIONAL OR CONSULTATIVE SERVICES
]TEMS $5,OOO OR MORE BUT LESS THAN $1O.OOO
PAYEE
PREDOMINANT
I NATURE OF SERV]CE AMOUNT
1
2
3
4
5
o
7
8I
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33u
35
36
37
38
39
40
41
40
41
42
43
44
ENGINEEKING INUUKI-UT(,\ I EU
FIRE CAUSE ANALYSIS
GYNII GILLIAM & ASSOCIATES
JACKSON LEWIS PC
JONES AND SWARTZ PLLC
JONES GLEDHILL FUHRMAN GOURLE\
STEPHAN, I(/ANVIG, STONE & TRAI
STRINDBERG & SCHOLNICK LLC
TOWERS WATSON PENNSYLVANIA IN(
WALDNER LAW OFFICES LLC
Enengeenng serylces
Fire lnvestigation Services
Management Services
LegalServices
LegalServices
LegalServices
Management Services
LegalServices
Energy Efficiency Services
LegalServices
c, 1z+c
7,291
6,153
8,754
6,593
6,213
7,389
6,781
8,900
6,027
45 rOTAL li 69,24C
IOAI{O SUPPLEIEiIT Page 68
STATE OF IOAHO . ALLOCATED
An Original December3l,2014ldaho Power Company
IOAHO SUPPLEMENT
ELECTRIC PLANT lN SERVICE (Accounts 1O'l, 1O2, 103 and 106) (Continued)
Shor in column (f) redassificalions or transhrs within utility plant accounts. lndude also in column
(0 the additions or reduc-tions of primary account classifications arising from distribution of amounts
initially recolded in Account '102. ln shorving the dearance of Account 102, indude in column (e) the
amounts with respect to accumulated provision for depreciation, acquisition adjustments, 6tc., and sho,v
in column (D only the oftet to the debits or cr€dits distdbutsd in column (fl to primary account classifcations.
For Account 399, state the nature and use of plant included in this account and if substantial in amount
submit a supplementary statement shorving subaccount dassification of such plant confurming to the
requirements of these pages.
For each amount comprising the rcported balance and changos in Account 102, state the property purchased
or sold, name of vendor or purchaser, and date of transac{ion. lf proposed joumal entries have been filed
with the Commission as required by the Uniform System of Accounts, give also date of such filing.
ncrlttetilgnE
(d)
ruJUsUlrilF
(e)
r ralNaers
(0
Eno (tr reat
(s)
Lrne
No.
$ s,4s9
28,0/,8,263
28,362,313
(301)
(302)
(303)
I
2
3
4
5
6
7
8I
10
11
12
t3
14
't5
16
17
t8
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33u
3s
36
37
38
39
40
41
42
43
50,41ti,036
6,61 '1,529
(310)
(31 1)
(312)
(313)
(314)
(3r5)
(316)
(317)
Y50.5vU,U5U
(320)
(321')
(322)
(323)
(324)
(325)
(326)
(330)
(331)
(332)
(333)
(334)
(33s)
(336)
(337)
/ 5'l,t / /,6uJ
(340)
(341)
(34.2)
(343)
(u4)
(34s)
(345)
STATE OF IDAHO -ALLOCATED
An Original D,ecember 3{, 2014tdaho Power Company
]DAHO SUPPLETiENT
STATE OF IDAHO -ALLOCATED
An Originalldaho Power Company December 31, 2014
ELECTRIC PI-ANT lN SERVICE (Accounts 1o1,1O2,103 and 106) (Continued)
Ltne
No.
Accounl
(a)
EaEnce ar
Beginning ofyear
(b)
Addltions
(c)
1q
45
46
47
4A
49
50
51
52
53
54
55
56
57
58
59
60
6't
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
81
82
83
84
85
86
87
E8
89
90
91
92
93
94
95
96
TOTAL Other Produc{ion Plant (Enter Total of lines 37 thru 44).......'....-...
TOTAL Production Plant (Enter Total of lines 16, 25, 35, and 45)."'.........
3. TRANSMISSION PI-ANT
inl t .6i aad I aar{ Eliahle
s 55Z,JZU,54U
z,tto,qzItaot
34,555,676
67,099,513
372,391,668
155,126,938
123,60't,400
1E0,079,653
373,698
,'aa/r ril
1359. 1 ) &ss1 petirement Costs ior Transmission Plant... ...... ... ...
TOTAL Transmission Plant (Enter Total of lines 48 thru 57)..........
4. DISTRIBUTION PLANT
'2anl I .6i a..{ I r^d fri^hle
933,224,546,
4,724,U8
31,686,059
190,312,22
217.558,714
117,481,965
45,617,141
204,356,666
452,677,796
54,008,015
70,590,833
2.672,425
4.U1,9U
:365) Ovefi ead Condudors and Devices.............
'aAA\ I ld6ah"nr{ llanr{rrit
,371 ) lnstallations on Customer Premises............,
,372) Leased Property on Customer Premises....................
:373) Str€et Lighting and Signal Systems..
l3z+; 6s*1 Retirement Costs fur Distribution Phnt..........-....
TOTAL Distribution Plant (Enter Total of lines 60 thru 74)......................'.'..
5. GENERAL PLANT
1,396,02l,616
r5,871,40s
98,54't,'t2E
39,150,924
64,833.977
1,827,216
6,889,490
1 1,913,052
12,2il,4'.t6
42,U9,528
5.491.745
,394) Tools, Shop, and Garage Equipment.....................'..
Far rinmaat
398) Miscellaneous EouiDment.
SUBTOTAL (Enter Total of lines 77 thru 86).....................296Uz:z,U61
,399. 1) 4s561 Retirement Costs for General Plant... . .. ... .. . . .. .
TOTAL General Plant (Enter Total of lines 87, EE and 89).
TOTAL (Accounts 1 01 and 1 06)...................
29o,422,461
4,E63,381,630
103) Er@rimental Plant Undassifed...,..................
TOTAL Electric Plant in Service.$ 4,063,361,630
IDAHO SUPPLEIIENT
ldaho Power Company
STATE OF IOAHO -ALLOCATED
An Origanal December3l,2014
ELECTRIC PI-ANT lN SERVICE (Accounts 1o1, 1o2, 103 and 106) (Continued)
Retirements
(d)
Adjustments
(e)
Transfers
(0
E AlaNCE AI
End of Year
(s)
LtrII
No.
(346)
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
58
69
70
7',!
72
73
74
75
76
77
78
79
80
81
E2
8i:l
E4
85
86
a7
88
89
90
91
92
93
94
95
96
li 5JU.555./ZZ
z,z16,t'tz,st3
34,605,711
69,637,54't
382,718,777
161,01 9,362
136,488,28s
187,968,278
373,635
(350)
(3s2)
(3s3)
(354)
(3ss)
(3s6)
(3s7)
(3s8)
(3se)
(35e.1 )
912,411,5lJt
5,051,237
32,1 16,160
195,069,259
222,604,427
1 t9,358,951
46,631,228
215,537,454
475,247,016
55,003,907
77,835,697
2,688,508
4.299.302
(360)
(361)
(362)
(363)
(384)
(36s)
(366)
(367)
(368)
(36e)
(370)
(371)
(372)
(373)
(374)
1,451,443,'t4r
15,870,623
102,467,445
43,942,561
71,O45,176
1,853,706
7,251,3',t1
't2,'t12,1U
13,U2,917
51 ,491,365
5,338,964
(38s)
(3e0)
(3sl)
(3s2)
(3s3)
(3e4)
(3es)
(3e6)
(3e7)
(3e8)
324,11lj,2J2
(ow,
(39e.1)
324,116,252
5,O24,O99,3!16
( ruz,
(102)
(371)
$ 5,UZ4,UU9,3VO
IDAHO SUPPLEIIENT
STATE OF IDAHO . ALLOCATED
An Original D,ecember 31, 201,[ldaho Power Company
ELECTRIC OPERATING REVENUES (Account 400)
1. Report below operating rcvenues 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
accountrs; except that where separate meter readings arc added for billing purposes, one customer should be counted
for each group of meters added. The average number of customers means the average of trvelve figures at the close
of each month.
3. lf previous year (columns (c), (e) and (g), are not derived ftom previously reported ftgures, explain any
inconsistencies in a footnote.
No.
(a)
OPERATING REVENUES
Amount for
Current Year
(b)
Amount for
Previous Year
(c)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
Sales of Electricity
/44O1 Flasidential Salas 481,950,250
436,s88,320
167,602,922
3.976.711
494,516,617
419,209.017
15'1,362,762
3,686,439
(442) Commercial and lndustrial Sales
Small lar Cnmmamial'l/Sea lnctr dl 111
L66 l^r lar{r relrial\IQaa lnetr tr\ /?\
lllAA\ Prthlia Slmel 2n,{ Hiahwav I inhlinn
/4d51 Othar Salac ln Prrhlic Arrlhnriiiec
/ld.Al Salae ln Pqilmade rnr{ Elaihuawe
448) lnterdepartmental Sales...
T6TAI aalac 1,090,'t 18,203
73,741,042
1,068,774,834
52,068,941(447) Sales for Resale - Oppoilunity....Non-Firm Only.
T()TAI Sales nf Flar:lrieitu 1,163,8s9,245
(18,363,613)
1,120,8/,3,775
(18,719,941)(449) Provision for Rate Refunds..........
TOTAL Revenue Net of Provision for Refunds..
Other Operating Revenues
145n1 tr^rf.i1a.l flicnar rnle
1,145,495,632 1,102,123.8U
3,696,703
22,576,0U
47,799,967
3,490,381
23,276,587
56,206,697
/.d(l\ lliamllanaarrc Qanriaa Parranrrac
(453) Sales of Water and Water Porer
(/.6/,1 Flent frnm trleclric Proncrlw
(456) Other Electric Revenues
TOTAL Other Operating Revenues.....74,072,705 82,973,665
TOTAL Elec{ric Ooeratino Revenues.$ 1,219,568,337 $ 1,185,097,499
(1) Commercial and lndustrial sales - Small - under 1,000 l(W and includes all inigation customers.
(2) Commercial and lndustrial sales - Large - 1,000 KVV and over.
IDAHO SUPPLESENT
Page 1l
ELECTRIC OPERATING REVENUES (Account 400) (Continued)
4. Commercial and lndustrial Sales, Accounl442, may be classifred according to the basis of classification
(Small or Commercial, and Large or lndustrial) regularly used by the respondent if such basis of classification
is not generally greater than 1000 Kw of demand. (See Account 442 of lhe Uniform System of Accounts. Explain
5. See page 108, lmportant Changes During Year, for importiant new tenitory 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. lnclude unmetered sales. Provide details of such sales in a footnote.
KILOWATT HOURS SOLD AVERAGE NUMBER OF CUSTOMERS PER MONTH
Line
No.
Amount for
Cunent Year
(d)
Amount for
Previous Year
(e)
Amount for
Current Year
(f)
Number for
Previous Year
(s)
4,784,072,514
5,675,423,865
2,970,925,860
31,654,264
5,167,474,O41
5,835,266,803
2,937,855,436
30,582,103
411,689
79,248
110
2,349
405,il2
78,3y
111
2,177
1
2
3
4
5
6
7
I
I
10
't1
12
13
13,462,076,503 *
2,121,897,891
13,97't,178,383
1,609,051,066
493,396
tt/A
486,'t64
N/A
15,583,974,394 15.580,229.449 493,396 486,164
* lncludes ($6,459,,143) unbilled revenues.
** lncludes (81,551,615) lQl/H relating to unbilled revenues.
Lines 11 through 21 are on an "allocated" basis.
STATE OF IDAHO - ALLOCATED
An Original D,ecember 3t, 2014ldaho Power Company
IDAHO SUPPLETENT
Page lla
ldaho PorerCompany
STATE OF IDAHO . ALLOCATED
An Orlglnal Decomber 31, 2014
ELECTRIC OPEMTION AND MAINTENANCE EXPENSES
ll me amounl lor prevrous year rs not oenveo rom prevrously reponed flgures, explarn rn loomotes.
No.Account
(a,
Cunent Year
(D'
Previous Year
(c)
t.t;ltt:lr
t,:Irlt:IrIreItlraI ,'
120lzr
1,,23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
ssi
nol
41
42
434
45
46
47
48
49
50
1,318,039
149,242,737
8,353,4'r2
1,528,536
9,189,663
507,911
1,460,217
't53,204,6't3
8,450,786
1,66,{,286
9,071,571
333,534
li"nri stoo- Evmncact'- --' ----"-lISOll Staam *nm 6lhar Snrrrmc
Iir """r ra*t st.r- i-".t *r-.
lr"nat ti-.rr^ Erencac
/5(lfi1 Mieallrnaarrc Slaam Pnmr Freneae
li.ori o"-"
lisosi nno*.n."..
I TOTAL Operation (Enter Total of lines 4 thru 12).
lMaintenance
lr",nt rr,.to^onm Srr.atuiei^n .nd Fmina6ri6^
"t tg,14u,z9t I 74,165,007
266,O44
678,123
10,438,403
5,776,736
5,558,967
97,305
610,766
11,912,O'.tz
5,160,756
4,348,&43
l;;, ;i ;",;;;;;; ;;; ;]
lisrzi u","*"""- "r ""u"r ""*Ii"a "i ,or^ro.onm ^f Elar.iri^ pt.nt
litrii u"*r"^*u" si"., pr"nt
I TOTAL Maintenance (Enter Total of Lines 15 thru 19).......
I TOTAL Power Production Expenses-Steam Power (Enter Total of lines 13 and :I B. Nuclear Power GenerationI
lOperationll5l7'l ()ncralian Srrmruician rnrl Fnnimrina
zz,t't6,ztz zz, tzv,qo I
1 92,656,570 r 96,314,4E6
l,.r"i i'I,
lrqroi c^^u^ro ^nd w2tatli.rni**-;,;;*
lr"rri "roo- *^1, att.-. "^,--.,l eesl ,522'l Slaam Tancfamrl-(lr
11523) Flecrric Fvnancac
ll52l.1 Micmlluna^rre Nrr^la.r p^rmr Fh66aac
l(525) Rents.
TOTAL Operation (Enier Total of lines 24 thru 32)
lMaintenance
l{5281 Mri^r"^"nm Srrmruisinn an.l Fndinmrind
(530) Maintenance of Reaclor Plant Equipment.......................
15311 Mainlenanm af Flertric Plrnt
(532) Maintenance of Miscellaneous Nuclear Plant.
TOTAL Power Production Esenses-Nuclear Poriuer (Enter Total of lines 33 and
C. Hydraulic Porver Generation
Operation
1535) Ooemtion Srrncruision rnd Fminmrind 5,456,838
7,004,u8
13,497,028
1,464,659
5,488,290
248,637
5,777,960
5,,f38,310
12,996,334
'l,371,316
4,6"4.9,652
135,586
,5141 lru.lar f^. PMr
15371 Hvdraulic Fnense
{5381 Flectric Fxnansas
/5?Ol Micmllanaar rc lJwdrar rlin Panmr l?anaralian Evnancae
(540) Rents.......
TOTAL Operation (Enter Total of lines 44 thru 49)..JJ,l3Y,/W JU,iftry,lcu
IDAHO SUPPLEHENT
Page 12
ELECTRIC OPEMTION AND MAINTENANCE EXPENSES
ll me amoum tor prevrous year rs not cenveo rom plevrously reponeo figures, explarn rn tootnotes.
No Account
(a)
Cunent Year
(D)
Previous Year
(c)
l:ils+lss
t:;lsalssl:llezleslo+lesleolezlutlos
lro171
72
7g
74
75
zol
,71
78 I
zel
aol
arl
azl
asl
aal
asl
sol
azl
eal
asl
sol
ill
sgl
sal
ssl
s6l
szl
sal
ssl
roo I
ror I
rczl
roe I
II C. Hydraulic Pourer Generation (Continued)
lMaintenance
l/*rt Mo,^ro^onm Qr rrcrui<ian .n.l Fndihaarind 116,975
1,328,245
350,696
2,181,',187
2,445,769
80,247
1,366,715
't,099,550
2,50r,7fi
2,878,078
l;;,i ;;;;;;;,:;;,,-"
l)^r.i ^,l}me ,hr{ l r.lail.vc
/6Ll.l Mainlanrnm af Elar.lria Dlanl
I islsi tr .i.,"rr"* ii r,ai.*u""eous Hydrautic ptant................
I fOfnf- Maintenance (Enter Total of lines 53 thru 57)............
I TOTAL Power Produc{ion Expenses-Hydraulic Power (Enter Total of lines 50 ancI D. Other Pourer Generation
loperation
l1s+e1 Operation Supervision and Engineerins......................
Itqazt r,,ot
4,422,4t2 7,929,346
39,C6Z,ti /1 36,296,503
779,191
43,069,104
3,440,496
866,982
0
1,303,138
51,813,183
3,279,215
560,834
0
l);;( ;;;:;";;-;*.,:anaE,i^n FYhanc.e
liisoi n"ii.
TOTAL Operation (Enter Total of lines 62 thru 66)............44,155,t13 56,956,370
lMaintenance
lr""r t r.,^ro^onea Sr rmruicinn 2n.l Fndinearind 0
36'r,955
82,752
1,332,13',1
95
288,,196
125,473
1,181,596
Elaatria Plant
l(534) Maintenance of Miscellaneous Other Pover Generation Plant.
TOTAL Maintenance (Enter Total of lines 69 thru 72)...................
TOTAL Porer Production Expenses-Other Power (Enter Total of lines 67 and 73
E. Other Porwr Supply Expenses
, /o,oJo 1,595,660
49,932,O11 e6,552,U30
226,605,619
(1,1 8e)
22,805,378
205,462,329
1,343,870
(37,062,415)
(556) System Control and Load Dispatchiru..
(557) Other Expenses.........
TOTAL Other Poruer Supply E eenses (Enter Total of lines 76 thru 78)...............
TOTAL Power Produc{ion Expenses (Enter Total of lines 21 , 41 , 59,74, and 79)
2. TRANSMISSION EXPENSES
Operation
(560) Operation Supervision and Engineering
16Al'l I aart flicn4r*rina
249,409,606 169,743,7E3
5ir1, /uJ,oou /+tiz,9uu,uu5
3,847,645
2,579,291
2,353,313
640,645
5,811,469
17,494
3,144,575
3,408,752
2,751,279
2,301,225
701,222
5,388,536
47,170
2,793,402
6Aa\ l,lrrarhaad
14All I lndamrnrrnd I ino Fy^ancac
r}rharc
(566) Miscellaneous Transmission Expenses
(567) Rents......
TOTAL Operation (Enter Total of lines 83 thru 90)..............................16,394,430 1 ',JYt,6U/Maintenance
162,267
994,016
3,il4,467
3,061,759
1,525
309,657
721,U8
3,456,623
3,435,662
58'l
l67fll Mrinlonrnao af Qlalinn Fdr ri^manl
(572) Maintenance of Underground Lines.........
(573) Maintenance of Miscellaneous Transmission Plant....
, , / (yt,uor,7,924,312
TOTAL Transmission Expenses (Enter Total of lines 91 and 99)........
3. DISTRIBUTION EXPENSES
Operation
i580) Operation Supervision and EngineerinS.................,....
zo,'tcu,.lo4 25,31ti,25U
3,856,280 3,980,89,f
STATE OF IDAHO . ALLOCATED
An Origanal December 31, 20lttldaho Power Company
IDAHO SUPPLETIET{T
Page 13
ELECTRIC OPEMTION AND MAINTENANCE EXPENSES
rl me amount tor prevrouE year rs not oenveo from prevrously reponeo ngures, expErn rn tootnotes.
No.Account
(a)
Cunent Year
(D)
Previous Year
(c)
104
105
106
,t07
108
109
110
11'.|
112
113
114
115
116
117
118
119
120
121
122
123
124
't25
126
127
128
129
130
131
132
133
1U
135 1
136 I
137 |
1s8 I
13e I
140 I
141l
M2l
143 I
1.l./-l
lff1
146 I
147l
r48l
14s I
150 Ilsl I
$21
153 I
I
1,"",',t :':r':'.',:ITo N EXPENSES (continued)
3,500,477
1,139,653
2,908.059
2,489,099
73,399
4,276,734
o+0,974
5,540,895
446,160
3,385,711
1,329,950
2,883,020
2,3[i6,316
70,930
1,267,367
620,736
5,505,368
3s0,339
lii^ri."iri"";;;;-"
lr*^.i ^--*.',ri i.o r.-^oool'---' - --'-'--l/5n l I ln.lam. rrn.l I ine Fmncae
li"*"i ."tr""r] "it,"" """-a""at svstcm Fymnscs
lr^^oi ^r-r.. =l);;;i;;t' - '----- -
l/5881 Mismlhnaarrs Dislrihrdinn Frnenses
li"ooi o-.'.
l' -iiji;iop";; liiil,rot.rorrines 1o3thru 113)
lM"int"n"n".
lrtont ^ro,^ro.onaa Qrrmarician .6d Eh^inaarind
zq.ot t,t lJ z+.1ov,oJa
15,747
0
3,814,699
12,883,895
621,410
142,325
507,517
710,855
386,170
161,580
0
3,691,123
13,428,428
635,953
275,199
511,473
724,350
380,365
t.---,--'-"'--"-lr6ol I M.ihlan.nm nf Sln rr{r rm<
l;;;ri ;;;;;;;""- "t "'"ii" Fd,,inmenrl' 'l/4Oa\ irrinrananm af drrarhaarlt'---''-'--'--"-
l(594) Maintenance of Underground Lines
Itsqsl Mri^toronm of I inc Tanqfomeet' 'l/6(lAl ir.inlahrhM ^f ql6a+ I i^hlih^ and Qiaaal Qrrclamc
(598) Maintenance of Miscellaneous Distribution Plant...
I TOTAL Maintenance (Enter Total of lines 116 thru 124).................
I fOfef- Distribution Expenses (Enter Total of lines 114 and 125)..........
| 4. CUSTOMERACCOUNTS EXPENSES
loperationl/Oll{l Qrraanriaiaa
19,UUZ,O'| /19,6UU,4/U
15,YC+,Jqt 44,569,102
481,778
1,492,5U
r6,030,097
6,316,859
90
469,738
1,312,575
t3,547,108
5,486,585
258
llOO?\ Matar Paar{ina Evmn<as
l/go?l Crr<tnmcr Fl.mrle and Collar:fion Frcn.Fs
(905) Miscellaneous Customer Acoounts Expenses.........
TOTAL Customer Accounts Expenses (EnterTotal of lines 129 thru 133).............
5. CUSTOMER SERVICE AND INFORMATIOML EXPENSES
Operation
/Ofl7r arrnaruician
24,3:21,358 20,616,263
561,496
32,298,865
361,011
658,759
513,764
41,266,485
255,050
555,685
,OOR'I ar rel^ma. Acciel.nB Enancac
IQOOI lnfomatinnrl an.l lnqlnr.-li6nal Fymnses
(91 0) Miscellanoous Customer Service and lnformational Expenses.....
TOTAL Cust. Service and lnformational Expenses (Enter Total of lines 137 thru 1l
6. SALES EXPENSES IOperation Itqi I I sr hFruisinn I
JJ,6UU,1J'I /+z,cYU,9U/+
/0121 f)cmonslralino and Sellinn Frnansas
/O'l ?\ Adu6rtiein^ F%hc6.
(916) Miscellaneous Sales Expenses.
TOTAL Sales Expenses (Enter Total of lines 144 thru 1471.................
7. ADMINISTRATIVE AND GENERAL EXPENSES
Operation
/O?fll Ar{minictrr+iva .^r{ ,aanaal Q.l.ri6a 69,850,602
16,647,453
(26,023,220)
66,097,,148
16,835,064
Q5,698.427)
/O21I(lflina Srrnnliac and Fvnancoc
(Less) (922) Administrative Ereenses Transfened-Credit..
STATE OF IDAHO -ALLOCATED
An Original December 31,201t1ldaho Power Company
IDAHO SUPPLETEilT
Page ltl
ldaho Powsr Company
STATE OF IDAHO . ALLOCATED
An Orlginal December 3{, 20lrl
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
ll me amount lor prevrous year ls nol oenveo rom p]evrously reponeo nguaes, exptatn tn rcomotes.
No.Account
(a)
ntttvutta tgt
Cunent Year
(D)
Previous Year
(c)
1il
155
't56
157
158
159
't60
161
162
163
1il
165
166
167
168
169
| 7. ADMINISTMTIVE AND GENERAL EXPENSES (Continued)
ll023l Orrteidc Saruimc Fmnlawd 4,492,073
3,315,652
5,847,681
59,787,654
0
3,242,013
432,639
4,685,182
168
5,039,591
3,520,294
5,443,509
59,345,081
0
3,601,314
475,U1
4,O59,279
6,257
/O9l.1 Dranarhr
/Q241 lnir rriae anr{ l1amoaac
1026) trmnlavm pan.i^nq lnr{ Flpmf,lq
/O271 Emnahica
(928) Regulatory Commission Expenses.........
/Q2O'l l-)lrnlindc llharaae-l1r
{93O ll Gcncml Advcrti<ina Fvnenmc
IO?O 2l Micmllamare Ganaal Fnanoe
(931) Rents.
TOTAL Operation (Enter Total of lines 15'l thru 144)..llZZt r,6Ut 1i,6,{:z4,45"1
Maintenance
(935) Maintenance of General Plant.7,187,U5 5,027,749
TOTAL Admin and General Ergenses (EnterTotal of lines 16S167).,...............
TOTAL Elec Op and Maint Exp Gotal of 80,'l 00, 126, 1U, 1 4'1,'l 18, I 68)........,
149,44C,t42 't1;,,t52,:zU10
$ 6O9,5tt3,7OZ $ 739,953,612
IDAHO ONLY
NUMBER OF ELECTRIC DEPARTMENT EMPLOYEES
1. I ne oata on numDer ol employees snouE De reponeo lor me payron pen@ enomg neare$ to uctooer 31,
or any payroll penoo enotng 6u oays Delore or atter ucloDer 31.
z. ll me respondent's payron tor me Gponrng penod rnduoes any speoal consmJdton peEonnet, tnduoe
sucn employees on lrne J, ano snow me numDer ol sucn specral construGron employees tn a toomoG.
3. I ne numoer ol employees assqnaDle to me elecmc oepanment trom rornt runc$ons ot comornaoon uurtes
may oe oetermrneo oy estrmate, on me oasrs ol employee equrvaEnts. tinow ure esilmateo numoer or equv-
arent employees annDuEo to me electnc oepanment rom Jornt rundtons.
I Payroll Period Ended (Date).....,........ December3l,December 31 , 201 3
2 Total Regular Full-Time Employees.......
3 Total Part-Time and Temporary Employees.......
4 Total Employees.......
2,O11
20
2,O31
2,010
18
2,028
IDAHO SUPPLEUENT
Pago t5