2013Annual Report.pdf

THIS FILING IS
Item 1: I An lnitial(Original) OR n Resubmission No.
-Submission
I7C- L
iili, ill il: , .i 8' ;tJ
I
FERC FINANCIAL REPORT
FERC FORM No. 1: Annual Report of
Major Electric Utilities, Licensees
and Others and Supplemental
Form 3-Cl: Quarterly Financia! Report
These reports are mandabry under the Federal PowerAct, Sections 3, a(a), 304 and 309, and
18CFR14'|..1 and141.40lO. Failurebreportmayresultincriminal lines,civil penalteand
other sancdions as provided by law. The Federal Energy Regulatory @mmission does not
consider these reports b be of confidential nafure
Form 1 Approved
OMB No.19O2-0O21
(Expires 12131120141
Form 1-F Approved
OMB No.1902-0029
(Expires 1U31120141
Form $Q Approved
OMB No.1902-0205
(Expires 0513112014)
Exact Legal Name of Respondent (Company)
ldaho Power Company
Year/Period of Report
End of 2O13lQ4
FERG FORM No.1/3-Q (REv. 02-041
Deloitte.Deloitte & Touche LIP
lOl South Capitol Blvd.
Suite l700
Boise, lD 83702-7734
U5A
Tel: +l 208 342 9361
Fax: [phone]
www.deloitte.com
INDEPENDENT AUDITORS' REPORT
Idaho Power Company
Boise,Idaho
We have audited the accompanying financial statements of Idaho Power Company (the "Company''),
which comprise the balance sheet - regulatory basis as of Decernber 31,2013, and the related staternents
of income - regulatory basis, retained earnings - regulatory basis, and cash flows - regulatory basis for
the year then ended, included on pages I l0 through 123 ofthe accompanying Federal Enerry Regulatory
Commission Form l, and the related notes to the financial statements.
Management's Responsibility for the Financial Statements
Management is responsible for the preparation and fair presentation of these financial statements in
accordance with the accounting requirernents of the Federal Energy Regulatory Commission as set forth
in its applicable Uniform System of Accounts and published accounting releases; this includes the desigr,
implementation, and maintenance of internal contol relevant to the preparation and fair presentation of
financial statements that are free from material misstaternent, whether due to fraud or error.
Auditors' Responsibility
Our responsibility is to express an opinion on these financial staternents based on our audit. We
conducted our audit in accordance with auditing standards generally accepted in the United States of
America. Those standards require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free from material misstatement.
An audit involves performing procedr:res to obtain audit evidence about the amounts and disclosures in
the financial statements. The procedures selected depend on the auditor's judgment, including the
assessment of the risks of material misstatement of the financial statements, whether due to fraud or error.
In making those risk assessments, the auditor considers internal control relevant to the Company's
prepmation and fair presentation ofthe financial staternents in order to desigrr audit procedures that are
appropriate in the circumstances, but not for the purpose ofexpressing an opinion on the effectiveness of
the Company's internal control. Accordingly, we express no such opinion. An audit also includes
evaluating the appropriateness ofaccounting policies used and the reasonableness ofsigrrificant
accounting estimates made by management, as well as evaluating the overall presentation of the financial
state,ments.
We believe that the audit evidence we have obtained is suflicient and appropriate to provide a basis for
our audit opinion.
Opinion
In our opinion, the regulatory-basis financial statements referred to above present fairly, in all material
respects, the assets, liabilities, andproprietary capital of Idaho Power Company, as of December 31,
2013, and the results of its operations and its cash flows for the year then ended in accordance with the
accounting requirements of the Federal Energy Regulatory Commission as set forth in its applicable
Uniform System ofAccounts and published accounting releases.
Basis of Accounting
As discussed in Note 1 to the financial staternents, these financial statements were prepared in accordance
with the accounting requironents of the Federal Energy Regulatory Commission as set forth in its
applicable Uniform Systan of Accounts and published accounting releases, which is a basis of accounting
other than accounting principles generally accepted in the United States of America. Our opinion is not
modified with respect to this matter.
Restricted Use
This report is intended solely for the information and use of the board of directors and management of the
Company and for filing with the Federal Energy Regulatory Commission and is not intended to be and
should not be used by anyone other than these specified parties
0,1*")fu LuP
February 20,2014
-2-
FERC FORM NO. 1/3.Q:
02 Year/Period of Report
End of 2O13lQ4
01 Exact Legal Name of Respondent
ldaho Power Company
03 Previous Name and Date of Change (if name changed during year)
04 Address of Principal Office at End of Period (Streef, City, State, Zp Code)
1221W ldaho St, P.O. Box 70 Boise, ld 83707-0070
05 Name of Contact Person
Ken Petersen
06 Title of Contact Person
VP, Controller and CAO
07 Address of Contact Person (Street, City, State, Zip Code)
1221W ldaho St, P.O. Box 70 Boise, ld 83707-0070
09 This Report ls
(1) tr An Original (2) ! A Resubmission
10 Date of Report
(Mo, Da, Yr)
041't512014
08 Telephone of Contact
Area Code
[phone]
ANNUAL CORPORATE OFFICER CERTIFICATION
The undersigned officer certifies that:
have examined this report and to the best of my knowledge, information, and belief all stiatements of fact contained in this report are conect statemenE
the business affairs of the respondent and the financial statements, and other financial information contained in this report, conform in all material
to the Uniform System of Accounts.
04 Date Signed
(Mo, Da, Yr)
o4l'1512014
Title 18, U.S.C. 100't makes it a oime for any person to knowingly and willingly to make to any Agency or Department of the United States any
false, fic{itious or fraudulent stratements as to any matter within ib jurisdiction.
FERG FORM No.1/3-Q (REv. 02-041 Page I
Name of Respondent
ldaho Power Company
tnts Keoon ts:(1) 5]Rn Orisinat(2) -A Resubmission
uate ot KeDon
(Mo, Da, Yi)
o411512014
YearPenoo o1 t(epon
End of 20131Q4
LIST OF SCHEDULES (Electric Utility)
Enter in column (c) the terms nnone," "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 "NAn.
Line
No.
Title of Schedule
(a)
Reference
Page No.
(b)
Rema*s
(c)
1 General lnformation 101
2 Control Over Respondent 102
3 Corporations Controlled by Respondent 103
4 Officers 104
5 Directors 105
6 lnformation on Formula Rates 106(a)(b)
7 lmportant Changes During the Year 108-109
8 Comparative Balance Sheet 110-113
I Statement of lncome for the Year 114-117
10 Statement of Retained Eamings for the Year 118-119
11 Statement of Cash Flows 120-',t21
12 Notes to Financial Statements 122-123
13 Statement of Accum Comp lncome, Comp lncome, and Hedging Activities 122(a)(b)
't4 Summary of Utility Plant & Accumulated Provisions for Dep, Amort & Dep 200-201
15 Nuclear Fuel Materials 202-203 N/A
16 Electric Plant in Service 20+207
17 Electric Plant Leased to Others 213
18 Electric Plant Held for Future Use 2'.t4
19 Consfuction Work in Progress-Electric 2',t6
20 Accumulated Provision for Depreciation of Elecfic Utility Plant 219
21 lnvesfnent of Subsidiary Companies 224-225
22 Materials and Supplies 227
23 Allowances 228(ab)-229(ab)N/A
24 Extsaordinary Properly Losses 230 N/A
25 Unrecovered Plant and Regulatory Study Costs 230 N/A
26 Transmission Service and Generation lnterconnection Study Cosb 231
27 Other Regulatory Assets 232
28 Miscellaneous Defened Debits 233
29 Accumulated Defened lncome Taxes 234
30 Capital Stock 250-251
31 Other Paid-in Capital 253
32 Capitral Stock Expense 254
33 Long-Term Debt 256-257
34 Reconciliation of Reported Net lncome with Taxable lnc for Fed lnc Tax 261
35 Taxes Accrued, Prepaid and Charged During the Year 262-263
36 Accumulated Defened lnvestment Tax Credits 266267
FERC FORM NO.1 (ED. r2-e6)Page 2
Name of Respondent
ldaho Power Company
lhrs Keoon ls:(1) 5]An orisinal(2) nA Resubmission
uate ot Reoon
(Mo, Da, Yi)
0411512014
LIST OF SCHEDULES (Electric Utility) (continued)
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
Line
No.
Title of Schedule
(a)
Reference
Page No.
(b)
Remarks
(c)
37 Other Defened Credits 269
38 Accumulated Deferred lncome Taxes-Accelerated Amortization Property 272-273 N/A
39 Accr.rmulated Deferred lncome Taxes-Other Property 27+275
40 Accumulated Deferred lncome Taxes-Other 276-277
41 Other Regulatory Liabilities 278
42 Elecfic Operating Revenues 300'301
43 Regional Transmission Service Revenues (Account 457.1)302 N/A
44 Sales of Electricity by Rate Schedules 304
45 Sales for Resale 310-3'11
46 Electric Operation and Maintenance Expenses 320-323
47 Purchased Power 326327
48 Transmission of Electrici$ for Ohers 32&330
49 Transmission of Electricity by ISO/RTOs 331 N/A
50 Transmission of Elec{ricity by Others 332
51 Miscellaneous General Expenses-Electric 335
52 Depreciation and Amortization of Electric Plant 33&337
53 Regulatory C,ommission Expenses 350-351
54 Research, Development and Demonstration Activities 352-353
55 Distribution of Salaries and Wages 354-355
56 Common Utility Plant and Expenses 356 N/A
57 Amounts included in ISO/RTO Settlement Statements 397 N/A
58 Purchase and Sale of Ancillary Services 398 N/A
59 Monthly Transmission System Peak Load 400
60 Monthly ISO/RTO Transmission System Peak Load 400a N/A
61 Elecbic Energy Account 401
62 Monthly Peaks and Output 401
63 Steam Elecfic Generating Plant Statistics 402403
64 Hydroelecfic Generating Plant Statistics 406-407
65 Pumped Storage Generating Plant Statistics 40&409 N/A
66 Generating Plant Statistics Pages 410411
FERC FORM NO. r (ED. 12-96)Page 3
Name of Respondent
ldaho Power Company
This ReDort Is:(1) 5_1Rn Orisinal(2) f-lA Resubmission
uate ot Keoon
(Mo, Da, Yi)
04115t2014
Yea0Henoo or Kepon
End of 2O13lQ4
LIST OF SCHEDULES (Electric Utility)lued)
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
Line
No.
Title of Schedule
(a)
Reference
Page No.
(b)
Remarks
(c)
67 Transmission Line Statistics Pages 422-423
68 Transmission Lines Added During the Year 424-425
69 Substations 426-427
70 Transactions with Associated (Affiliated) Companies 429
71 Footnote Data 450
Stockholders' Reports Check appropriate box:
I Two copies will be submifted
n ruo annual reportto stockholders is prepared
FERC FORM NO.l (ED.12-96)Page 4
Name of Respondent
ldaho Power Company
This Report ls:
(1) tr An Original
(2) n A Resubmission
Date of Report
(Mo, Da, Yr)
041't512014
Year/Period of Report
End of 2013tQ4
GENERAL INFORMATION
1. Provide name and title of officer having custody of the general corporate books of account and address of
office where the general corporate books are kept, and address of office where any other corporate books of account
are kept, if different from that where the general corporate books are kept.
Ken Peteraen vice President,Controller and CAO, fdaho Power Conpany
t22L w. Idaho Street, P.O. Box 70, Boise, Idaho 83707-0070
2. Provide the name of the State under the laws of which respondent is incorporated, and date of incorporation.
lf incorporated under a special law, give reference to such law. lf not incorporated, state that fact and give the type
of organization and the date organized.
Idalro, ,Iune 30, 1989
3. lf at any time during the year the property of respondent was held by a receiver or trustee, give (a) name of
receiver or trustee, (b) date such receiver or trustee took possession, (c) the authority by which the receivership or
trusteeship was created, and (d) date when possession by receiver or trustee ceased.
Not ApplicabJ.e
4. State the classes or utility and other services furnished by respondent during the year in each State in which
the respondent operated.
Clasa of Uti1ity Service
E].ectric
E].ectric
State
fdaho
Oaegon
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) tr Yes...Enter the date when such independent accountant was initially engaged:(2) E No
FERC FORM No.l (ED.12-87) PAGE 101
Name of Respondent
ldaho Power Company
This Report ls:
(1) tr AnOriginal
(2) tr A Resubmission
Date of Report
(Mo, Da, Yr)
0411512014
Year/Period of Report
End of 2o13lQ4
CONTROL OVER RESPONDENT
1. lf any corporation, business trust, or similar organization or a combination of such organizations jointly held
control over the repondent at the end of the year, state name of controlling corporation or organization, manner in
which control was held, and extent of control. lf control was in a holding company organization, show the chain
of ownership or control to the main parent company or organization. lf control was held by a trustee(s), state
name of trustee(s), name of beneficiary or beneficiearies for whom trust was maintained, and purpose of the trust.
ldaho Power Company is a subsidiary of IDACORP, INC
IDACORP owns 100% of ldaho Power Company's Common Stock.
IDACORP is a public utility Holding Company incorporated effective 10-1-1998
FERC FORM NO. 1 (ED. 12-96)Page 102
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5.1An Orisinal(2) nA Resubmission
Date of Reoort(Mo, Da, Yi)
o4115120't4
Year/Period of Report
End of 20',t3lQ4
CORPORATIONS CONTROLLED BY RESPONDENT
1. Report below the names of all corporations, business trusts, and similar organizations, controlled directly or indirectly by respondent
at any time during the year. lf control ceased prior to end of year, give particulars (details) in a footnote.
2. lf 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. lf 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. lndirect control is that which is exercised by the interposition of an intermediary which exercises direct control.
4. Joint control is that in which neither interest can effectively control or direct action without the consent of the other, as where the
voting control is equally divided between two holders, or each party holds a veto power over the other. Joint control may exist by
mutual agreement or understanding between two or more parties who together have control within the meaning of the definition of
control in the Uniform System of Accounts, regardless of the relative voting rights of each party.
Line
No.
Name of Company Controlled
(a)
Kind of Business
(b)
Percent Voting
Stock Owned
(c)
Footnote
Ref.
(d)
1 Direct Control
2 ldaho Energy Resourc,es Company Coal mining and mineral '1000/o
3 development
4
5
6
7
8
I
10
11
12
13
14
15
't6
17
18
19
20
21
22
23
24
25
26
27
FERC FORM NO. r (ED. 12-96) Page 103
Name of Respondent
ldaho Power Company
This ReDort ls:(1) ElAn orisinal(2) TIA Resubmission
Date of Reoort(Mo, Da, Yi)
04t15t2014
Year/Period of Report
End of 2O13lQ4
OFFICERS
1. Report below the name, title and salary for each executive offlcer 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. lf 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.
Ltne
No.
lifle
(a)
Name ot oflrcer
(b)
Dataryfor Yedr(c)
1
2 Chief Executive Officer J. LaMont Keen (1)715,00(
3
4 President & Chief Executive Officer Danel T. Anderson (2)500,00(
5
b Executive Vice President & Chief Operating Officer Dan Minor 410,00(
7
8 Senior Mce President & General Counsel Rex Blackbum 320,00(
I
10 Senior Mce President, Power Supply Lisa Grow 280,00(
11
12 Senior Mce President, CFO & Treasurer Steven Keen (2)280.00(
13
14 Mce President, Human Resources & Corporate Services Luci McDonald 250,00(
15
16 Vice President & Chief lnformation Officer Dennis Gribble (3)230,00(
17
18 Mce President, Customer Operations Wanen Kline 240,00(
19
20 Mce President, & Chief Risk Officer Lori Smith 225,00(
21
22 Vice President Delivery, Engineering & Construction Vem Porter 220,00(
23
24 Mce President,Controller & Chief Accounting Officer Ken Petersen (2)20s,00(
25
26 Mce President & Chief lnformation Officer Lonnie Krawl (4)200,00(
27
28 Mce President, Regulatory Affairs Gregory Said 195,00(
29
30 Corporate Secretary Patrick Hanington 176,00(
31
32 (1) Retired from position 1213'll2l13
33 (2) Appointed to position 11112014
34 (3) Retired 9/30/2013
35 (4) Appointed to position 101112013
36
37
38
39
40
41
42
43
44
PageFERC FORM NO.1 (ED.12-96)
Name of Respondent
ldaho Power Company
This Reoort Is:(1) 5]Rn orisinal(2t 1--1A Resubmission
uate ot Kepon(Mo, Da, Yr)
o411512014
Year/Period of Report
End of 2O't3lQ4
DIRECTORS
1 . Report below the information called for concerning each director of the respondent who held office at any time during the year. lnclude in column (a), abbreviated
litles of the directors who are officers of the respondent.
2. Designate members of the Executive Committee by a kiple asterisk and the Chairman of the Executive Committee by a double asterisk.
Ltne
No.Name (an&j iue) ot uirector Pnnqpal tslsdless Address
1
2 Judith A. Johansen '1809 Headlee Lane, Lake Oswego, Oregon 97034
3
4 Christine King*"8527 East old Field Rd
5 Scottsdale, Azizona 85266
6
7 Gary Michael *** (5)P.O. Box 1718, Boise, ldaho 83701
I
I Stephen Allred 4642W Dawson Dr., Meridian, ldaho 83646
't0
't1 Jan B. Packwood 900 W. Bogus Mew Drive, Eagle, ldaho 83616
12
13 Darrel T. Anderson President & Chief Executive Office(1)ldaho Power Company,1221 W. ldaho Street,
14 P.O. Box 70, Boise, ldaho 83707-0070
15
16 J. LaMont Keen, Chief Executive Officer'* **'(2)ldaho Power Company,1221 W. ldaho Street,
17 P.O.Box 70, Boise, ldaho 83709-0070
18
19 Joan Smith 2309 S.W. First Avenue, No. 1141, Portland, Oregon 97201
20
2'.1 Robert A. Tinstman "*4433W. Quail Point Court, Boise, ldaho 83703
22
23 Thomas \Mlford 1504 Warm Springs Avenue
24 Boise, ldaho 83712
25
26 Richard Dahl ***60 Laiki Pl.
27 Kailua, Hawaill 96734
28
29 Dennis L. Johnson (3)United Heritage Life lnsurance
30 707 E. United Heritage Ct., Ste 130, Meridian, ldaho 83642
31
32 Ronald W. Jibson (4)Questar Corporation
33 333 South State Stseet, Salt Lake City, Utah 8414t0433
34
35
36 (1) Appointed to the board Sept 19, 2013; President and CEO
37 as of 111120'14
38 (2) Retired 12131113 from ldaho Power
39 (3) Appointed 3121 12013
40 (4) Appointed 911812013
41 (5) Retired May 16,2013
42
43
44
45
46
47
48
FERC FORM NO. 1 (ED.12-9s)Page 105
Name of Respondent
ldaho Power Company
ThiS ReI(1)E
(2)a
ort ls:
An Original
A Resubmission
Date ot KeDon(Mo, Da, Yi)
04115120't4
Year/Period of Report
gn6 o1 2013/Q4
INI-ORMAIION ON FORMULA RAIE!'
FERC Rate Scheduleffariff Number FERC Proceeding
Does the respondent have formula rates?[J ves
ENo
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.
Lrne
No.FERC Rate Schedule or Tariff Number FERC Proceeding
1 FERC Electric Tariff
2
3
4
5
6
7
8
I
10
11
12
13
't4
15
16
17
1€
1
2C
21
22
23
24
2l
26
27
28
2e
3C
31
32
34
35
3€
37
38
3S
4C
41
FERC FORilt NO. r (NEW. 12-08)Page 106
Name of Respondent
ldaho Power Company
This Reoort ls:(1)E An original
(2) Tl A Resubmission
Date ot Report(Mo, Da, Yr)
04115t2014
Year/Period of Report
En6 o1 2013/Q4
INFORMATION ON FORMULA MTES
FERC Rate Scheduleffariff Number FERC Proceeding
Does the respondent file with the Commission annual (or more frequent)
filings containing the inputs to the formula rate(s)?[J Yes
ENo
2. lf yes, provide a listing of such filings as contained on the Commission's eLibrary website
Line
No.Accession No.
Document
Date
\ Filed Date Docket No.Description
Formula Rate FERC Rate
Schedule Number or
Tariff Number
1 20130829-5192 OU29|2O13)ER09-1il1-000 ldaho Power Company'FERC Electric Tariff
2 2013 Annue
3 informational filinr
4 under ER09-1641-00
5
6
7
8
1C
11
't2
't3
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 (NEW. 12-08)Page l06a
Name of Respondent
ldaho Power Company
This Reoort ls:(1)E An Original
(2) n A Resubmission
Date of Reoort(Mo, Da, Yi)
0411512014
Year/Period of Report
En6 o1 2013/Q4
INFORMATION ON FORMULA MTES
Formula Rate Variances
1. lf a respondent does not submit such filings then indicate in a footnote to the applicable Form 1 schedule where formula rate inputs differ from
amounts reported in he Form 1.
2. The footnote should provide a narrative desoiption explaining how the "rate' (or billing) was derived if different from the reported amount in the
Form 1.
3. The foohote 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 he footnote.
Line
No.Page No(s).Schedule Column Line No
1 None
2
3
4
5
6
7
8
I
10
11
12
13
14
15
16
17
t8
1S
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
4'l
42
43
44
FERC FORM NO.1 (NEW.12.08)Page 106b
Name oI Kesponoent
ldaho Power Company
I nrs Kepoft rs:(1) E An Original(2) ! A Resubmission
uare or KeporT
04t1512014
Yearrenoo oI Kepon
End of 20131Q4
IMPORTANT CHANGES DURING THE QUARTERITEAR
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 nNAn where applicable. lf
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. lf acquired without the payment of consideration, state that fact.
2. Acquisition of ownership in other companies by reorganization, meryer, 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. lmportant leaseholds (other than leaseholds for natural gas lands) that have been acquired or given, assigned or sunendered: 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. lmportant extension or reduction of transmission or distribution system: State tenitory 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. lf the important changes during the year relating to the respondent company appearing in the annual report to stockholders are
applicable in every respect and fumish the data required by lnstructions 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
occuned during the reporting period.
14. ln the event that the respondent participates in a cash management program(s) and its proprietary capital ratio is less than 30
percent please describe the significant events or transactions causing the proprietary capital ratio to be less than 30 percent, and the
extent to which the respondent has amounts loaned or money advanced to its parent, subsidiary, or affiliated companies through a
cash management program(s). Additionally, please describe plans, if any to regain at least a 30 percent proprietary ratio.
PAGE 108 INTENTIONALLY LEFT BLANK
SEE PAGE 109 FOR REQUIRED INFORMATION.
FERC FORM NO. r (ED. 12-96)Page l0E
Name of Respondent
ldaho Power Companv
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
0411512014
Year/Period of Report
2013tA4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
?
tr
None
None
None
None
Reroute l-ine into Pine creek substation due to failing structures.Line #447 Remove 1.51 miles of under-buiId to clean up feed to Notch Butte feed.Line #440 Added .71 mi.l-es as under-buiId on l-ine 447 to facil-itate the cleanup ofNotch Butte feed.Line #412 .9 miles were added to the length of this l-ine due to reroute around Emmett
Gun C.l-ub.
L:-ne *202/404/465 Remove 1.13 miles of de-energized J-ine 202, rebuild with new 138Kvline 465. 1.5 miles of line 404 was upgraded and the number changed to tine 465.A]l- work in and out of the nampa substation.Line #248 De-energized 6.9 miles of 69KV line between Nampa substation, Chestnutsubstation down to Lake Shore Drive.Line #205 Removed 2.8 mil-es of de-energrzed l1en from Lansing substation down Statestreet
6. On April 8, 2013, Idaho Power issued $75 million in principal amount of 2.508 first
mortgage bonds, Series I, maturing on April 1-, 2023, and $75 million in principal amountof 4.008 first mortgage bonds, Series I, maturing on April 1, 2043. On October 1, 2073,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 4.252first mortgage bonds. Issuance of the Series I first mortgage bonds in April 2013,
combined with the lssuance of $200 milLion 1n princlpal amount of Series I first mortgage
bonds in August 2010 and $150 million in principal amount of Serj-es f first mortgage bondsin April 201,2, utifized in fu1l the available amount under a registration statement Idaho
Power filed with the U.S. Securities and Exchange Commission (SEC) in May 2010 and under aselling agency agreement executed with ten banks in ,June 2010.
7. None
8. Effective l/05/2013 a 3.08 general wage adjustment was implemented.
9. See pages L23.20 lo 123.21-
10. None
1l- . None
12. None
13. Idaho Power has added Ron Jibson as a director effective 9/L8/201"3. There were also a
number of changes for officers. LaMont Keen President and Chief Executj-ve Officer of fdaho
Power retired effective 1,2/3L/2013. DarreL Anderson will succeed LaMont as President andChief Executive Officer. Other changes on November 2L, 2013 Steve Keen was promoted toSenior Vice President, CFO and Treasurer, Ken Petersen was promoted to Vice President,Controller and Chief Accounting Officer and Naomj- Shankel- was named Assistant Treasurer.
Dennis Gribble Vice president and Chief Information Officer retired 9/30/2073, hissuccessor is Lonnie Krawl.
14. Idaho Power andprograms, (seperateprograms). No money
management proqram.
its unregulated
bank accounts,
has been loaned
parent, IDACORP have seperate cash managementIiquidity facilities, short-term debt and investmentor advanced from Idaho Power to IDACORP through a cash
FORM NO.1 .1 109.1
Name of Respondent
ldaho Power Company
This Report ls:
(1) E An Original
(2) a A Resubmission
Date of Report
(Mo, Da, Yr)
o411512014
Year/Period of Report
End of 2o13tQ4
CoMPAMTTVE BALANCE SHEET (ASSETS AND OTHER DEBTTS)
Line
No.Title of Account
(a)
Ref.
Page No.
(b)
Gurrent Year
End of Quarterfr/ear
Balance
(c)
Prior Year
End Balance
12t31
(d)
1 UTILITY PLANT
2 Utility Plant ('101-106, 1 14)200-201 5,087,492,23(4,922,872,974
3 Construction Work in Progress (107)200-201 327.000.03t 298,470,440
4 TOTAL Utility Plant (Enter Total of lines 2 and 3)5,414,492,26t 5,221,343,414
5 (Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115)200-201 1,940,654,18'1,871,810,171
6 Net Utilitv Plant (Enter Total of line 4 less 5)3,473,838,08t 3,349,533.243
7 Nuclear Fuel in Process of Ref., Conv.,Enrich., and Fab. (120.1)202-203 0
8 Nuclear Fuel Materials and Assemblies-Stock Accounl (1 20.2)0
I Nuclear Fuel Assemblies in Reactor (120.3)0
10 Spent Nuclear Fuel (120.4)0
11 Nudear Fuel Under Capital Leases ('120.6)0
12 (Less) Accum. Prov. for Amort. of Nucl. Fuel Assemblies (120.5)202-203 0
13 Net Nuclear Fuel (Enter Total of lines 7-11 less 12)0
14 Net Utility Plant (Enter Total of lines 6 and 13)3,473,838,08(3,349,533,243
15 Utility Plant Adjustnenb (116)0
16 Gas Stored Underground - Noncurrent (1 1 7)0
17 OTHER PROPERTY AND INVESTMENTS
18 Nonutility Property (1 21 )1.274,12 1.462.166
19 (Less) Accum. Prov. for Depr. and Arnort. (122)0
20 lnvestments in Associated Companies (123)0
21 lnvestment in Subsidiary Companies (123.1)224-225 91.384.57i 84,680,243
22 (For Cost of Account 123.1, See Footnote Page 224, line 421
23 Noncunent Portion of Allowances 228-229 0
24 Other lnvestnents (124)82t 1,518
25 Sinking Funds (125)0
26 Depreciation Fund (126)0
27 Amortization Fund - Federal (127)0
28 Other Special Funds (128)42,271,751 34.391.222
29 Special Funds (Non Maior Onlv) (129)0
30 Long-Term Portion of Derivative Assets (175)288,131 284,782
31 Long-Term Portion of Derivative Assets - Hedges (176)0
32 TOTAL Other Property and lnvestments (Lines 18-21 and 23-31)'t35.219.401 120,819,931
33 CURRENT AND ACCRUED ASSETS
34 Cash and Working Funds (Non-major Only) (130)0
35 Cash (131)66,420.84(17.112.143
36 Special Deposits (1 32-134)3.106.51,0
37 Workinq Fund (135)14.10(39,100
38 Temporary Cash lnvestnents (136)100.00(100,000
39 Notes Receivable (141)50,20r 72,492
40 Customer Accounts Receivable (1 42)100,221,791 67,661,588
4'.|Other Accounts Receirrable (143)1 1.336.45i 20,876,001
42 (Less) Accum. Prov. for Uncollectible Acct.-Credit (144)2,501,68(1,872.855
43 Notes Receivable from Associated Companies (145)1,008,249
44 Accounb Receivable from Assoc. Companies (146)63,847
45 Fuel Stock (151)227 41.546.32i 42,388,239
46 Fuel Stock Expenses Undistributed (152)227 0
47 Residuals (Elec) and Extracted Products ('153)227 0
48 Plant Materials and Operating Supplies (154)227 49,267,70.47,455,954
49 Merchandise (155)227 0
50 Other Materials and Supplies (156)227 0
51 Nuclear Materials Held for Sale (157)202-2031227 0
52 Allowances (158.1 and 158.2)228-229 0
FERC FORM NO. 1 (REV. 12-03)Page 110
Name of Respondent
ldaho Power Company
This Report ls:
(1) tr AnOriginal
(2) tr A Resubmission
Date of Report
(Mo, Da, Yr)
0411512014
Year/Period of Report
End of 2o13lQ4
COMPAMTIVE BALANCE SHEET (ASSETS AND OTHER DEB|TS(pontinued)
Line
No.Title of Account
(a)
Ref.
Page No.
(b)
Current Year
End of Quarterf/ear
Balance
(c)
Prior Year
End Balance
12t31
(d)
53 (Less) Noncunent Portion of Allowances 0
54 Stores Expense Undistributed (1 63)227 4,375,58(3,581,218
55 Gas Stored Underground - Current (164.1)0
56 Liquefied Natural Gas Stored and Held for Processing (164.2-164.3)0
57 Preoavments (1 65)15,204.04t 12,688,220
58 Advances for Gas (166-167)0
59 lnterest and Dividends Receivable (171 )0
60 Rents Receivable (1721 0
61 Accrued Utility Revenues (173)63,506,68(51,448,038
62 Misccllaneous Current and Accrued Assets (174)0
63 Derivative lnstrument Assets (1 75)1,672,361 3,874,959
il (Less) Lono-Term Porlion of Derivative lnstrument Asseb (175)288,131 284,782
65 Derivative lnstrument Assets - Hedqes ('176)0
66 (Less) Lonq-Term Portion of Derivative lnstrument Assets - Hedges (176 0
67 Total Current and Accrued Assets (Lines 34 through 66)354,032,81(266.212.4'.t1
68 DEFERRED DEBITS
69 Unamortized Debt Expenses (18'l )17,183,1 1(17,143,425
70 Exfaordinary Property Losses (1 82.1 )230a 0
71 Unrecovered Plant and Reoulatory Study Costs (182.2)230b 0
72 Other Regulatory Assets (182.3)232 1,036,375,11(1,141,110,726
73 Prelim. Survey and lnvestiqation Charses (Electric) (183)883,871 819,409
74 Preliminarv Nafural Gas Survev and lnvestiqation Charqes 183.1)0
75 Other Preliminary Survey and Investigation Charges (183.2)0
76 Clearino Accounts (1 84)2.147.65t 1,364,037
77 Temporary Facilities (1 85)0
78 Miscellaneous Defened Debits (186)233 45,208,761 53,913,850
79 Def. Losses from Disposition of Utility Plt. (187)0
80 Research, Devel. and Demonstration Expend. (188)352-353 0
81 Unamortized Loss on Reaquired Debt (189)'t 3.860.47:14,921,058
82 Accumulated Deferred lncome Taxes (190)234 246,774.821 316.262,777
83 Unrecovered Purchased Gas Costs (191)0
84 Total Defened Debits (lines 69 through 83)1,362,433,81(1,54s,535,282
85 TOTAL ASSETS (lines 14-16,32,67, and 84)5,325.524,12(5,282,100,867
FERC FORM NO. I (REV.12-O3l Page 111
Name of Respondent
ldaho Power Company
This Report is:
(1) tr An Original
(2) tr A Resubmission
Date of Report
(mo, da, yr)
04t15t2014
Year/Period of Report
end of 20131Q4
CoMPAMTIVE BALANCE SHEET (LtABtLtTtES AND OTHER CREDTTS)
Line
No.Title of Acmunt
(a)
Ref.
Page No.
(b)
Current Year
End of Quarterl/ear
Balance
(c)
Prior Year
End Balance
12t31
(d)
1 PROPRIETARY CAPITAL
2 Common Stock lssued (201)250-251 97,877,031 97,877,03C
3 Prefened Stock lssued (204)250-2s1 c
4 Capital Stock Subscribed (202, 2OS)c
5 Stock Liability for Conversion (203,206)c
6 Premium on Capital Stock (207)7',12,257,43!712,257,435
7 Other Paid-ln Capital (208-21 1)253 0
8 lnstallmenb Received on Capital Stock (212)2s2 0
I (Less) Discount on Capital Stock (213)254 0
10 (Less) Capital Stock Expense (214)254b 2,096,92{2,096,925
't1 Retained Eaminqs Q'15, 21 5.1, 2161 11&119 843,625,02t 752,514,607
12 Unappropriated Undistributed Subsidiary Eamings (216.1)1 18-1 19 88,921,47(82,217,150
13 (Less) Reaquired Capital Stock (217)250-251 0
14 Noncorporate Proprietorship (Non-major onlv) (218)0
15 Acc,um ulated Other Comorehensive I ncom e (2 1 9)1zz(al{0.l -16.553.37!-17,115,669
16 Total Proprietary Capital (lines 2 throush 15)1.724.030,67i 1,625,653.628
17 LONG-TERM DEBT
18 Bonds (221)256-257 1.595.460.00(1,515,460,000
19 (Less) Reaquired Bonds (222)256-257 0
20 Advances from Associated Companies (223)256-257 0
21 Other Lonq-Term Debt (224)256-257 24,139,541 25.203.182
22 Unamortized Premium on Lono-Term Debt (225)0
23 (Less) Unamortized Discount on Long-Term Debt-Debit (226)3,277,59",2,967,860
24 Total Lons-Term Debt (lines 18 thrcush 23)1,616,32'r,952 1.537.695.322
25 OTHER NONCURRENT LIABILITIES
26 Oblisations Under Capital Leases - Noncunent (227)0
27 Accumulated Provision for Property lnsurance (228.1)0
28 Accumulated Provision for lnjuries and Damages (228.2)1.670.69t 5,479,272
29 Accumulated Provision for Pensions and Benefits (228.3)245,780,27i 425,887,098
30 Accumulated Miscellaneous Operating Provisions (228.4)2,771,35t 2,261,891
31 Accumulated Provision for Rate Refunds (229)59,388,81(45,672,853
32 Lono-Term Portion of Derivative lnstrument Liabilities 0
33 Lono-Term Portion of Derivative lnstrument Liabilities - Hedoes 0
34 Asset Retirement Oblioations (230)25.765.3d 22.982,049
35 Total Other Noncurrent Liabilities (lines 26 throuoh 34)335,376,50i 502,283,'t63
36 CURRENT AND ACCRUED LIABILITIES
37 Notes Payable (23'l)0
38 Accounts Payable (232)105,671,10(108,223,362
39 Notes Payable to Associated Companies (233)13,264,181 0
40 Accounts Payable to Associated Companies (234)1,158,06i 252,507
41 Customer Deposits (235)1.428.221 r,966,205
42 Taxes Accrued (236)262-263 15,104,41(8,109,787
43 lnterest Accrued (237)22.834.80t 22,441,369
44 Dividends Declared (238)0
45 Matured Long-Term Debt (239)0
FERC FORM NO. 1 (rev. 12-03)Page 112
Name of Respondent
ldaho Power Company
This Report is:
(1) tr AnOriginal
(2) n A Resubmission
Date of Report
(mo, da, yr)
o411512014
Year/Period of Report
end of 2013/Q4
coMPAMTtVE BALANCE SHEET (LlABlLlTlE S AND OTHER CREDlTShtinuea)
Line
No.Title of Account
(a)
Ref.
Page No.
(b)
Cunent Year
End of Quarterl/ear
Balance
(c)
Prior Year
End Balance
12131
(d)
46 Matured lnterest (240)
47 Tax Collections Pavable (2411 1,444,641 1,905,27e
48 Miscellaneous Cunent and Accrued Liabilities (242)35,788,24:30,534,183
49 Obligations Under Capital Leases-Cunent (243)
50 Derivative lnstrument Liabilities (244)571,74',1,054.644
51 (Less) Lonq-Term Portion of Derivative lnstrument Liabilities
52 Derivative lnstrument Liabilities - Hedges (245)
53 (Less) Long-Term Portion of Derivative lnstrument Liabilities-Hedges
54 Total Current and Accrued Liabilities (lines 37 through 53)197,265,42/174,487,33C
55 DEFERRED CREDITS
56 Customer Advances for Construction (252)9.465.211 13,261,592
57 Accumulated Defened lnvestment Tax Credits (255)266-267 79.121,29 79.896.60!
58 Defened Gains from Disposition of Utility Plant (256)
59 Other Deferred Credits (253)269 12,386,72 17,982,872
60 Other Regulatory Liabilities (254)278 70.377.001 69,401,78(
61 Unamortized Gain on Reaquired Debt (257)
62 Accum. Deferred I ncom e Taxes-Accel, Amort. (281 )272-277
63 Accum. Defened lncome Taxes-Other Property (282)1,143,090,46(1,080,279,41:
64 Accum. Deferred lncome Taxes-Other (283)138.088.87:'t8't,159,151
65 Total Defened Credits (lines 56 through 64)1.452.529.56,1 ,441,981 ,418
bt)TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24,35,54 and 65)5,32s,524,121 5,282,100,867
FERC FORM NO. 1 (rev. 12-03)Page 113
Name of Respondent
ldaho Power Company
This Reoort ls:(1) finn original(2) T'lA Resubmission
Date of Report(Mo, Da, Yr)
0411512014
Year/Period of Report
End of 20131Q4
SI AI EMENT OF INCOME
Quarterly
1 . Report in column (c) the cunent 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 fi) 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. lf 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 mlumnin a similar manner to
a utility department. Spread the amount(s) over lines 2 thru 26 as appropriate. lnclude these amounts in columns (c) and (d) totals.
7. Report amounts in account 414, Other Utility Operating lncome, in the same manner as accounts 412 and 413 above.
Line
No.
Title of Account
(a)
(Ref.)
Page No.
(b)
I oElt
Current Year to
Date Balance for
Quarterffear
(c)
I OIal
Prior Year to
Date Balance for
Quarterffear
(d)
curent 3 Monlhs
Ended
Quarterly Only
No 4th Quarter
(e)
Fnor J Monlns
Ended
Quarterly Only
No 4th Quarter
0
1 UTILITY OPEMTING INCOME
2 Operating Revenues (400)300-301 1,242,1s0,868 1,075,085,87
3 Opeating Expenses
4 Operation Expenses (40'l)320-323 710,93't,08t 596,383,061
5 Maintenance Expenses (402)320-323 67,728,722 74,129,496
6 Depreciation Expense (403)336-337 121,486,191 1 16,1 13,891
7 Depreciation Expense forAsset Retirement Cosb (403.'l)336-337 587,01i 317,07s
8 \mort & Depl. of Utility Plant (404405)336-337 7,611,63,4 7,483,540
I \mort. of Utility Plant Acq. Adj. (406)336-337 -13,255
10 {mort. Property Losses, Unrecov Plant and Regulatory Study Cosb (407)
11 Amort. of Conversion Expenses (407)
12 Regulatory Debib (407.3)s6,17(39,784
13 iLess) Regulatory Credib (407.4)788,738
14 Taxes OtherThan Income Taxes (408.1)262263 30.560.82:30,488,808
15 lncome Taxes - Federal (409.1)262-263 9,918,70(-14,482,226
16 - Oher (409.1)262:263 5,499,764 1,007,613
17 Provision for Defened lncome Taxes (410.'l)234,272-277 138,292,29t 239,208,729
18 (Less) Provision for Defened lncome Taxes-Cr. (41 1.1)2U,272-277 82,501,40!200,111,787
19 lnvestment Tax Crcdit Adj. - Net (41 1.4)266 -775,31i 9,056,202
20 (Less) Gains from Disp. of Utility Plant (41 1.6)6,04:
21 Losses from Disp. of Utility Plant (41 1.7)6,76t
22 (Less) Gains from Disposition of Allowances (411.8)41,30i 201,565
23 Losses from Disposition of Allowances (41 'l .9)
24 Accretion Expense (41 1.'10)322.34t 183,144
25 TOTAL Utility Openating Expenses (Enter Total of lines 4 lhru 24)1,009,677,44(858,813/72
26 Net Util Oper lnc (Enter Tot line 2 less 25) Carry to Pg1 17 ,line27 232,473,42t 216,272,099
FERC FORM NO. 1/3-Q (REV. 02-04)Page 114
Name of Respondent
ldaho Power Company
tnrs Keoon ts:(1) 5]en orlsinat(2) T-'lA Resubmission
Date of ReDort(Mo, Da, Yi)
04t1st2014
Year/Period of Report
End of 2O13lQ4
STATEMENT OF INCOME FOR THE YEAR (Continued)
9. Use page 122lor important notes regarding the shtement of income for any account ftereof.
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 fac'tors whici affect the rights
of the utility to retain sucfr revenues or re@ver amounts paid with respect to power or gas purchases.
1 1 Give concise explanations conceming significant amounts of any refunds made or received during the year resulting from settlement of any rate
proceeding affecting revenues received or costs incuned for power or gas purches, and a summary of the adjustmenb made to balance sheet, income,
and expense accounts.
12.11 any notes appearing in the report to stokholders are applicable to the Statement of lncome, such notes may be induded atpage 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 dranges.
14. Explain in a footnote if the previous year's/quarte/s figures are different ftom that reported in prior reports.
15. lf the columns are insufficient for reporting additional utility departnents, supply he appropriate account titles report the information in a footnote to
this schedule.
ELECTRIC UTILITY GAS UTILITY OTHER UTILITY
Line
No.uurrenl Year Io uale
(in dollars)
(g)
Frevlous Year Io uate
(in dollars)
(h)
Current Year to Date
(in dollars)
(i)
Previous Year to Date
(in dollars)
0)
cunent Yeart0 Date
(in dollan)
(k)
Previous Year to Date
(in dollars)
0)
1,242.150,868 1,075,085,871 2
7't0.93't.086 596,383,061 4
67,728,722 74,',t29,496 5
121.486.191 116.113,891 6
587,012 317,075 7
7,611 ,634 7,483,540 8
-13,255 I
10
11
56,176 39,784 12
788,738 13
30,560.823 30,488,808 14
9,918,700 -14,482,226 15
5,499,764 1,007,613 16
138,292,290 239,208,729 17
82,501,409 200,111,787 18
-775,313 9,056,202 19
6,04ir 20
6,766 21
41,307 201,565 22
23
322,348 183,144 24
1,009,677,440 858,813.772 25
232,473,428 216,272,099 26
FERC FORM NO. t (ED. 12-96)Page 115
Name of Respondent
ldaho Power Company
This Reoort ls:(1) []An orisinal(2) nA Resubmission
Date of Report I Year/Period of Report
!tvt9, o1 vi) I eno or 2013/e4o4t15t2014
STATEMENT OF INCOME FOR THE YEAR (continued)
Line
No.
Title of Account
(a)
(Ref.)
Page No.
(b)
TOTAL uurtent J MonInS
Ended
Quartedy Only
No 4th Quarter
(e)
rnor J MonInS
Ended
Quartedy Only
No 4th Quarter
(f)
Current Year
(c)
Previous Year
(d)
27 Net Utility Openating lncome (Canied fonrvard from page 114)232,473,428 216.272,091
28 Offier lncome and Deduc{ions
29 Other lncome
30 {onutilty Operatinq lncome
31 levenues From Merchandisinq. Jobbino and Contract Work (415)946,897 1,639,354
32 (Less) Cosb and Exo. of Merchandisino, Job. & Contnact Work (4'16)1,079,771 1.634.62C
33 Revenues From Nonutilitv Ooerations (4171 41,993 46,89C
34 flessl Exoenses of Nonutilitv Ooerations (417.,l1 60,48i 276,349
35 Nonoperatinq Rental lncome (4'18)-2,841 -16,185
36 Equity in Eamings of Subsidiary Companies (418.1)119 6,704,32(6,150,725
37 lnterestand Dividend lnome (419)2,426,0U 2,0't8,711
38 Allorance for Ofier Funds Used During Construction (419.1)14,857,58(22.433,417
39 Miscellaneous Nonooeratino lncome (421 I 14,488,86(1,990,23{
40 Gain on Disposition of Property (421.1)-2.441
41 TOTAL 0ther lncome (Enter Total of lines 31 hru 40)38,320,12!32,352,',t771
42 Other lncome Deductions
43 Loss on Disposition of Property (42'1.2)1,917
44 Miscellaneous Amortization (425)
45 Donations (426.1)744,976 717.8971
4A Life lnsurance (426.2)-18,319 -14,0A1
47 Penatties (426.3)428,04i -560,6031
48 Exp. for Certain Civic, Polilical & Related Activities (426.4)1.282.131 't.256.U71
4S Oher Deductions (426.5)8,6ss,953 7.533.7681
50 TOTAL Other lncome Deduclions fiotal of lines 43 thru 49)11,094,700 8,933,3751
51 Taxes Aoolic. to Other lncome and Deductions
52 Taxes Other Than lncome Taxes (408.2)262-263 22,991 24,64(
53 lncome Taxes-Federal (409.2)262-263 1,540,870 .'t02.07t
54 lncome Taxes-Other {409.2)262-263 417,095 -161,21i
55 Provision for Defered lnc. Taxes {410.2)234,272-277 2,4tfi,132 652,95t
56 lLess) Pmvision for Defened lncome Taxes-Cr. (41 1.2)234,272-277 2.173,22C 2,320.96(
57 lnvestnent Tax Crcdit Adi.-Net (41 1.5)
58 fLess) lnvestment Tax Credib (420)
59 TOTAL Taxes on 0,ther lncome and Deduclions (Total of lines 52-58)2,303,868 -1.906.66:
60 Net Other lncome and Deduc{ions (Tobl of lines 41, 50, 59)24,921,561 25,325,461
61 lnterest Charues
62 lnterest on Lono-Term Debt (4271 81,492,149 78,922,05i
63 Amort of Debt Disc. and Exoense (4281 1,609,36{'1 570.0'1(
64 Amortization of Loss on Reaquired Debt (428.1)1,060,585 1.008.75(
65 lLess) Amorl of Premium on Debt.Crcdit (429)
66 (Less) Amorlization of Gain on Reaquired Debt4redit (429.1)
67 lnterest on Debt to Assoc. Companies (430)7.955
68 Olher lnterest Exoense (431)4,146,98i 3,858,10?
69 lLess) Allowance for Bonowed Funds Used Durino Construc-tionCr. (432)7,663,19C 11,929,40{
70 Net lnterest Chages (Tohl of lines 62 thru 69)80,653,84(73,429.52a
71 lncome Before Extraordinary ltems (Total of lines 27, 60 and 70)176,741,14i 168,168.03(
72 Extnaodinary ltems
73 Exbaodinary lncome (434)
74 lLess) Exbaordinary Deductions (435)
75 Net Extaordinary ltems Fobl of line 73 less line 74)
76 lncome Taxes-Federal and O&er {409.3)262-263
77 ixtraordinary ltems AfterTaxes (line 75 less line 76)
78 Net lnmme (Total of line 71 and 77)176,741,143 168,168,03!
FERC FORM NO. 1/3-Q (REV. 02-04)Page 117
Name of Respondent
ldaho Power Company
This ReDort ls:(1) 5]Rn Orisinal(2) l--lA Resubmission
Date ot Keoon
(Mo, Da, Yi)
0411512014
Yearl'enoo oI t{epon
End of 20131Q4
STATEMENT OF RETAINED EARNINGS
1. Do not report Lines 49-53 on the quarterly version.
2. Report all changes in appropriated retained earnings, unappropriated retained eamings, year to date, and unappropriated
undistributed subsidiary eamings for the year.
3. Each credit and debit during the year should be identified as to the retained eamings 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 eamings.
5. List first account 439, Adjustments to Retained Eamings, reflecting adjustments to the opening balance of retained eamings. 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. lf 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. lf any notes appearing in the report to stockholders are applicable to this statement, include them on pages 122-123.
Line
No.
Item
(a)
Contra Primary
\ccount Affected
(b)
Cunent
QuarterA/ear
Year to Date
Balance
(c)
Previous
Quarterl/ear
Year to Date
Balance
(d)
UNAPPROPRIATED RETAINED EARNINGS (Account 21 6)
1 Balance-Beginning of Period
-I
749,111,203 657,027,573
2 Changes
3 Adiustments to Retained Earnings (Account 439)
A
TOTAL Credits to Retained Eamings (Acct. 439)
't(
11
'ti
1
1
1 TOTAL Debits tc Retained Eaminss (Acct. 439)
Balance Transfened from lncome (Account 433 less Account 41 8.1 )170,036.814 162,017,314
1 Appropriations of Retained Eamings (Acct. 436)
1 215.1 -3,256,123 ( 1,193,716)
1
2(
21
22 TOTAL Appropriations of Retained Eamings (Acct. 436)-3,256,123 1,193,716)
2i Dividends Dedared-Prefened Stock (Account 437)
2t
2l
2t
21
2t
2(TOTAL Dividends Dedared-Prefened Stock (Acct. 437)
3(Dividends Declared-Common Stock (Account 438)
3't -78,926,392 ( 68,739,968)
JI
JJ
34
AC
3t TOTAL Dividends Declared-Common Stock (Acct. 438)-78.926.392 68,739,968)
3i Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Eamings
3t Balance - End of Period (Total 1,9,15,16,22,29,36,371 836,96s,502 749,111,203
APPROPRIATED RETAINED EARNINGS (Account 21 5)
FERC FORM NO. 1r3-Q (REV.02-04)Page tl8
Name of Respondent
ldaho Power Company
lhrs Reoon ls:(1) 5]Rn orisinal(2) nA Resubmission
uate ol Keoort
(Mo, Da, Yi)
0411512014
Year/Period of Report
End of 2013tQ4
STATEMENT OF RETAINED EARNINGS
1. Dr
2,F
undi
3.E
- 43(
4.S
5. 1
by cr
6.S
7.S
8.E
recu
9. tf
r not report Lines 49-53 on the quarterly version,
,eport all changes in applopriated retained eamings, unappropriated retained earnings, year to date, and unappropriated
stributed subsidiary earnings for the year.
ach credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436
I inclusive). Show the contra p.rimary account affected in column (b)
tate the purpose and amount of each reservation or appropriation of retained earnings.
ist first account 439, Adjustments to Retained Eamings, reflecting adjustments to the opening balance of retained eamings. Follow
edit, then debit items in that order.
how dividends for each class and series of capital stock.
how separately the State and Federal income tax effect of items shown in account 439, Adjustments to Retained Eamings.
xplain in a footnote the basis for determining the amount reserved or appropriated. lf such reservation or appropriation is to be
rent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated.
any notes appearing in the report to stockholders are applicable to this statement, include them on pages 122-123.
Line
No.
Item
(a)
Contra Primary
\ccount Affected
(b)
Cunent
Quarter/Year
Year to Date
Balance
(c)
Previous
QuarterfYear
Year to Date
Balance
(d)
2C
4C
41
42
43
44
45 TOTAL Appropriated Retained Eamings (Account 215)
APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Account 215.1)
4(TOTAL Approp. Retained Eamings-Amort. Reserve, Federal (Acct. 215.1)6,659,526 3,403,404
41 TOTAL Approp. Retained Eamings (Acct. 215, 215.1) (Total 45,46)6,659,526 3,403,404
4t TOTAL Rehined Earninss (Acct. 21 5, 215.1, 2161(Total 38, 47) (216.1\843,625,028 752,514,607
UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account
Report only on an Annual Basis, no Quarterly
4(Balance.Beginning of Year (Debit or Credit)82,2',t7,150 76,066,425
5(Equity in Eamings for Year (Credit) (Account 418.1 )6,704,329 6,150,725
51 (Less) Dividends Received (Debit)
52
R'Balance-End of Year (Total lines 49 hru 52)88,921,479 82,2',t7lil
FERC FORM NO. lrlQ (REV. 02-1,4)Page 119
Name of Respondent
ldaho Power Company
This ReDort Is:(1) 51An orisinal(2) l-lA Resubmission
uate ot Kepon
(Mo, Da, Yr)
0411512014
STATEMENT OF CASH FLOWS
(1 ) Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) lnclude commercial paper; and (d) ldentify separately such items as
investments, fixed assets, intangibles, etc.
Equivalents at End of Period" with related amounts on the Balance Sheet.
in those aclivities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid.
the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General lnstrction 20; instead provide a reconciliation of the
dollar amount of leases capitalized with the plant cost.
Line
No.
Description (See lnstruction No. 1 for Explanation of Codes)
(a)
Cunent Year to Date
Quarterl/ear
(b)
Previous Year to Date
QuarterfYear
(c)
1 tlet Cash Flow from Operating Activities:
2 tlet lncome (Line 78(c) on page 1 17)176.741,143 1 68,168,039
3 Noncash Charges (Credits) to lncome:
4 Depreciation and Depletion 'tz't,486,191 116,'113,8S1
5 Amortization of Note 1 12,21'.1,778
6
7
8 Deferred lncome Taxes (Net)55,836,1 53 40,671,950
I lnvestment Tax Credit Adjustment (Net)-497,674 5,813,188
10 Net (lncrease) Decrease in Receivables -30,953,272 -1,457,986
11 Net (lncrease) Decrease in lnventory -1,213,152 930,1 36
12 Net (lnoease) Decrease in Allowances lnventory
13 Net lncrease (Decrease) in Payables and Accrued Expenses 12,717,237
14 Net (lnoease) Decrease in Other Regulatory Assets -40,694,556 -42,236,101
15 \,let lnsease (Decrease) in Other Regulatory Liabilities 15,112.871 1 1,230,901
16 iLess) Allowance for Other Funds Used During Construction 14,857,580 22.433.4',17
17 iLess) Undistributed Eamings from Subsidiary Gompanies 6,704,329 6,150,724
't8 Cther (provide details in foohote): Note 2 -31,590,882
19
20
21
22 let Cash Provided by (Used in) Operating Activities (Total 2 thru 21)275,635,280 241,526,208
23
24 3ash Flows from lnvestment Activities:
25 Sonstruction and Acquisition of Plant (including land):
26 Sross Additions to Utility Plant (less nuclear fuel)-227,831,534
27 Gross Additions to Nuclear Fuel
28 Sross Additions to Common Utility Plant
29 Gross Additions to Nonutility Plant
30 iLess) Allowance for Other Funds Used During Construction -14,857,580 11,929,405
31 Cther (provide details in ficohote): Note 3 2,738,701
32
33
34 Sash Outflows for Plant (Totral of lines 26 hru 33)-234.807.962 -237,022,238
35
36 {cquisition of Other Noncunent Assets (d)
37 ,roceeds from Disposal of Noncunent Assets (d)
38
39 lnvestments in and Advances to Assoc. and Subsidiary Companies
40 Oontributions and Advances from Assoc. and Subsidiary Companies
41 )isposition of lnvestments in (and Advances to)
42 {ssociated and Subsidiary Companies
43
44 ,urchase of lnvestment Securities (a)-32,660,820 -7,000,000
45 )roceeds from Sales of lnvestment Securities (a)25,660,820
FERC FORM NO.1 (ED.12-96)Page 120
Name of Respondent
ldaho Power Company
lnts KeDon Is:(1) 5.1Rn orisinal(2) 1-1A Resubmission
uate ol KeDort(Mo, Da, Yi)
0411512014
Year/Period of Report
End of 20131Q4
STATEMENT OF CASH FLOWS
(1 ) Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt (c) lnclude commercial paper; and (d) ldentify separately such items as
investments, fixed assets, intangibles, etc.
Equivalents at End of Period" with related amounts on the Balance Sheet.
in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid.
dollar amount of leases capitalized with the plant cost.
Line
No.
Description (See lnstruction No. 1 for Explanation of Codes)
(a)
Current Year to Date
QuarterA/ear
/b)
Previous Year to Date
Quarter/Year
Ic)
46 -oans Made or Purchased
47 lollections on Loans
48
49 tlet (lncrease) Decrease in Receivables 22,284 22,284
50 {et (lnoease ) Decrease in lnventory
51 Net (lncrease) Decrease in Allowances Held for Speculation
52 Net lncrease (Decrease) in Payables and Accrued Expenses
53 Other (provide details in footnote): Note 4 16.672.022
54
55
56 Net Cash Provided by (Used in) lnvesting Activities
57 Total of lines 34 thru 55)-224,062,823 -227,327,932
58
59 Sash Flows ftom Financing Activities:
60 rroceeds from lssuance of:
61 -ong-Term Debt (b)150,000,00c 150,000,000
62 rrefened Stock
63 lommon Stock 7,500,000
M Other (provide details in footnote):
65
66 Net lncrease in Short-Term Debt (c)
67 Other (provide details in footnote):
68
69
70 Cash Provided by Outside Sources (Total 61 thru 69)150,000,000 157,500,000
71
72 Payments for Retirement of:
73 Long{erm Debt (b)-71,063,636 -101,063,636
74 Preferred Stock
75 Common Stock
76 Other (provide dehils in footnote):-2,298,72e -3,959,067
77
78 Net Decrease in Short-Term Debt (c)
79
80 DiMdends on Prefened Stock
81 Dividends on Common Stock -78,926,392 -68,739,968
82 Net Cash Provided by (Used in) Financing Activities
83 (Total of lines 70 thru 81)-2.288.754 -16.262.671
84
85 Net lncrease (Deoease) in Cash and Cash Equivalents
86 (Total of lines 22,57 and 83)49,283,703 -2,064,39s
87
88 Cash and Cash Equivalents at Beginning of Period 17,251,243 19,315,638
89
90 Cash and Cash Equivalents at End of period 66,534,946 17.251.243
FERC FORM NO.1 (ED.12-96)Pags ,121
Name of Respondent
ldaho Power Companv
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
o4t15t2014
Year/Period of Report
2UvA4
FOOTNOTE DATA
120 Line No.: 5 Column: h
Amortization
Plant
Unamortized debt expense
Unamortized discount
Water rights
Other
Twelve Months Ended
12131t13
7,611,634
2,708,720
258,770
1,042,009
27.411
11,648,544
120 Line No.: 13 Column: b
Cash paid during the period for:
lncome taxes
lnterest (net of amount capitalized)
Cash Flow from Operating Activities (Other)
Pension and postretirement benefit plan expense
Contributions to pension and postretirement benefit plans
Unbilled revenues
Gain on sale of investments and assets
Customer deposits
Accrued lnterest
Other
9,031,086
77,582,508
Twelve Months Ended
12t31113
45,860,740
(33,346,747)
(12,058,648)
(11,678,459)
(3,658,360)
393,435
(3,284,351)
(17,772,390)
120 Line No.:26 Column: b
Non-cash investing activities:
Additions to PP&E in accounts payable 24,246,216
welve Months Ended
Sale of emission allowances and renewable energy certificates 498,473
498,473
120 Line No.: 53 Column: b
Other lnvesting Cash Flows
Disbursements from rabbi trust
Net change in notes receivable from subsidiary
Miscellaneous other investing activities
Twelve Months Ended
12131t13
3,514,193
14,272,430
(63,768)
17,722,855
FERC FORM NO.1 1 450.1
Name ot Respondent
ldaho Power Company
lnrs Hepon ls:(1) El An Original(2) [ A Resubmission
uate ot Ftepon
o4t15t20't4
YeaflPenoo oI Kepon
End of 2013/Q4
NOTES TO FINANCIAL STATEMENTS
1. Use the space below for important notes regarding the Balance Sheet, Statement of lncome for the year, Statement of Retained
Earnings for the year, and Statement of Cash Flows, or any account thereof. Classiff 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 lnternal 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 lnstruction 't 7 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. lf 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 bonowings 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.
P AGE122 INTENTIONALLY LEFT BLANK
SEE PAGE 123 FOR REQUIRED INFORMATION.
FERC FORM NO.I (ED.12-e6)Page 122
Name of Respondent
ldaho Power Comoanv
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
0411512014
Year/Period of Report
20't3/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
IDAIIO POWER COMPAIIY
NOTES TO CONSOLIDATED T'INANCIAL STATEMENTS
1. ST]MMARY OF SIGNIFICANT ACCOT]NTING 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 southem Idaho and
eastem 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 ttre Jim Bridger generating plant owned in part by Idaho Power.
Basis of Reporting
The financial statements include the assets, liabilities, revenues and expenses ofldaho Power and have been prepared in accordance
with ttre accounting requirements of the FERC as set forth in the applicable Uniforrn 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 acaounts for its invesfrnents 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(l) cunent portion oflong-term debt, (2) assets and liabilities for cost ofremoval ofassets, (3) regulatory assets and
liabilities (4) deferred income taxes, (5) income tax expense, (6) non-utility revenues and (7) accrued axes.
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 impainnent 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 ofthe financial statements, and the reported amounts ofrevenues 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, acfual results could differ from those estimates.
System of Accounts
The accounting records ofldaho Power conform to the Uniform System ofAccounts prescribed by the FERC and adopted by the
public utility commissions of Idaho, Oregon, and Wyoming.
Regulation of Utility Operations
Idaho Power's financial statements reflect the effects of the different ratemaking principles followed by the jurisdictions regulating
Idaho Power. The application of accounting principles related to regulated operations sometimes results in Idaho Power recording
expenses and revenues in a different period than when an unregulated enterprise would 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 investrrents that mature within 90 days of the date of
acquisition.
Receivables and Allowance for Uncollectible Accounts
FORM NO.1 123.1
Name of Respondent
ldaho Power Comoanv
This Report is:
(1) X An OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
04t15t2014
Year/Period of Report
20131Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
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 ofhistorical write-offexperience, aging ofaccounts receivable, and an analysis of
specific customer accounts. Adjustrnents are charged to income. Customer accounts receivable balances that remain outstanding after
reasonable collection efforts are written offthrough 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 31,2013 ard20l2. 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 oxposure to commodity price risk
in the electricity and natwal gas markets. All derivative instnrments are recognized as either assets or liabilities at fair value on the
balance sheet unless they are desigrrated as normal purchases and nonnal 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 ofldaho Power's regulatory
accounting mechanisms, Idaho Power records the changes in fair value of derivative instruments related to power supply as regulatory
assets or liabilities.
Revenues
Operating revenues related to Idaho Power's sale ofenergy 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 flruds used during
construction (AFIIDC) related to its Hells Canyon Complex relicensing project. Cash collected under this ratemaking mechanism is
not recorded as revenue but is instead recorded as a regulatory liability.
Property, Plant and Equipment and Depreciation
The cost of utility plant in service represents the original cost of contracted services, direct labor and material, AFUDC, and indirect
charges for engineering, supervision, and similar overhead items. Repair and maintenance costs associated with planned major
maintenance are expensed as the costs are incurred, as are maintenance and repairs of property and replacements and renewals of items
detersrined 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 properly, 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 2.69 percent in 2013 atd2.75 percent
in 2012.
During the period ofconstruction, costs expected to be included in the final value ofthe constnrcted asset, and depreciated once the
asset is complete and placed in service, are classified as consEuction 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 ofsuch costs in customer rates, although there can be no guarantee such recovery would be
granted.
LongJived assets are periodically reviewed for impairment when events or changes in circumstances indicate that the carrying amouut
FERC FORM NO.1 123.2
Name of Respondent
ldaho Power Company
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
0411512014
Year/Period of Report
2013tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
of an asset may not be recoverable. If the sum of the undiscounted expected future cash flows from an asset is less than the carrying
value of the asset, impairment must be recognized in the frnancial statements. There were no material impairments of these assets in
2013 or 2012.
Allowance for Funds Used During Construction
AFUDC represents the cost of financing construction projects with borrowed funds and equity funds. With one exception, as discussed
above for the Hells Canyon Complex relicensing project, cash is not realized currently from such allowance; it is realized under the
ratemaking process over the service life ofthe related property through increased revenues resulting from a higher rate base and higher
deprociation expense. The component of AFUDC attributable to borrowed funds is included as a reduction to total interest expense.
Idaho Power's weighted-average monthly AFIIDC rates for 2013 ard 2012 were 7 .7 percent for both years.
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 norrtalized accounting), deferred tax assets and liabilities are determined based on the differences between
the financial statements and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are
expected to reverse. In general, deferred income tax expense or benefit for a reporting period is recognizsd as the change in deferred
tax assets and liabilities from the beginning to the end ofthe period. The effect ofa change in tax rates on deferred tax assets and
liabilities is recogrized in income in the period that includes the enactrnent 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 adjustnents 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
statcment purposes. Deferred income taxes are provided for other temporary differences unless accounted for using flow-through.
The state ofldaho allows a tlree percent invesfrnent tax credit on qualifying plant additions. Investnent tax credits earned on
regulated assets are deferred and amortized to income over the estimated service lives of the related properties. Credits eamed on
non-regulated assets or invesfuents are recognized in the year eamed.
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.
FERC FORM NO. I 123.3
Name of Respondent
ldaho Power Comoanv
This Report is:
(1) X An OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
o4115t2014
Year/Period of Report
2013tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Federal income tax expense at35o/o statutoryrate
Change in taxes resulting from:
Equity earnings of subsidiary companies
AFUDC
Capitalized interest
Investuent tax credits
Removal costs
C apitalized overhead co sts
C apitalized repair costs
Tax method change - capitalized repairs
State income taxes, net of federal benefit
Other. net
Effective tax rate
Income taxes current:
Federal
State
Total
Income taxes deferred:
Federal
State
Total
2. INCOME TAXES
A reconciliation between the statutory federal income tax rate and the effective tax rate is as follows:
2013
Depreciatiou
(thousands ofdollars)
$ 87,310 $ 70,320
(2,347) (2,153)
(7,882) (12,027')
1,832 5,075
(3,120) (3,267)
(3,527) (2,697)
(8,750) (8,750)
(19,250) (19,250)
4,583 (7,845)
6,970 7,646
14,820 14,3982,076 (8,703)
$ 72,715 $ 32,747
29.1% 163%
Total income tax expense (benefit)
The items comprising income ax (benefit) expense are as follows:
2013 2012
(thousands of dollars)
$ 11,460 $ (14,584)5,917 846
t7,377 (13,738)
56,918 47,069(804) (9,640)
56,1L4 37,429
Uncertain tax positions:
Federal
State
Total
Investment tax credits:
Deferred
Restored
Total
2,344 12,323(3,120) (3,267)(776) 9,056
s 72,7L5 $ 32,74',7Total income tax expense (benefit)
FERC FORM NO. 1 123.4
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(21 A Resubmission
Date of Report
(Mo, Da, Yr)
0411512014
Year/Period of Report
2013lA4
NOTES TO FINANCIAL STATEMENTS (Continued)
The components of the net deferred tax liability are as follows:
Idaho Power
2013 2012
(thousands ofdollars)
Deferred tax assets:
Regulatory liabilities
Deferred compensation
Advanced payments
Tax credits
Net operating losses
Retirement benefits
Other
$ 55,017 $
23,647
23,062
23,642
29,628
69,033
436,837
7t0,482
35,763
7,634
65,810
10,359 10,146
234,388 321,621
55,085
23,463
17,856
21,174
47,351
146,546
406,293
677,795
16,832
5,246
142,270
Total
Deferred tax liabilities:
Property, plant and equipment
Regulatory assets
Power cost adjusfrnents
Fixed cost adjustnent
Retirement benefits
Other 12,267 lg,37l
1,268,793 1,266,797
s 1,034,405 $ 945,176
Total
Net deferred tax liabilities
IDACORP's tax allocation agreement provides that each member of its consolidated group compute its income ta(es on a separate
company basis. Amounts payable or refrrndable are settled through IDACORP. See Note I for further discussion of accounting
policies related to income taxes.
Uncertain Tax Positions
A reconciliation of the beginning and ending amount ofunrecognized tax benefits for Idaho Power is as follows (in thousands of
dollars):
2013 2012
Balance at January l,
Additions for tax positions of the current year
Additions for tax positions of prior years
Reductions for tax positions ofprior years
Settlements with taxins authorities
-$
Balance at December 3l -$
Idaho Power recognizes interest accrued related to unrecognized tax benefits as interest expense and penalties as other expense. Idaho
Power recognized no interest expense or penalties in 2013 or 2012, and there were no accrued interest or penalties as of December 3l
for the same years.
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 2013 for federal and 2010-2013 for Idaho. In May 2009, IDACORP formally entered tlre U.S. Intemal 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 2013, the IRS completed its examination of IDACORP's2012 tax year with no
FERC FORM NO.1 123.5
Name of Respondent
ldaho Power Comoanv
This Report is:
(1) X An OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
04t15120'.t4
Year/Period of Report
20131Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
unresolved income tax issues. IDACORP and Idaho Power believe that they have no material income tax uncertainties for 2013 and
prior tax years.
Tax Accounting Method Changes for Repair-Related Expenditures
In June 2010, Idaho Power completed its evaluation of a tax accounting method change for its 2009 tax year that allows a curront
income tax deduction for repair-related expenditures on its utility assets that are currently capitalized for financial reporting and tax
purposes. In September 2010, Idaho Power adopted this method following the automatic consent procedures with the filing of
IDACORP's 2009 consolidated federal income tax return. The method was subject to audit under IDACORP's 2009 CAP
examination.
In April 2011, IDACORP and the IRS reached an agreement on Idaho Power's tax accounting method change for capitalized repairs.
Accordingly, the IRS finalized the 2009 CAP examination and submitted its report on the 2009 tax year to the U.S. Congress Joint
Committee on Taxation (Joint Committee) for review. The capitalized repairs method is effectively settled and no material income tax
uncertainties remain for the method. As such, Idaho Power recognized $3.4 million of its previously unrecognized tax benefits for this
method in 2011.
On September 13,2013, the U.S. Treasury Deparfinent and U.S. Internal Revenue Service (IRS) issued final regulations addressing the
deduction or capitalization ofexpenditures related to tangible property. The regulations are generally effective for taxable years
beginning on or after January 1,2014.
In connection with the issuance of the regulations, Idaho Power assessed and estimated the impact of a method change associated with
the electric generation property portion of the capitalized repairs method it adopted in fiscal year 2010. The change will be made
pursuant to Revenue Procedure 2013-24 to bring Idaho Power's existing method into alignment with the Revenue Procedure's safe
harbor u it-of-property definitions for electric generation property. Given Idaho Power's intent to make this method change for
generation property, in the third quarter of 2013 it recorded $4.6 million of income tax expense related to the estimated taxable income
for the cumulative method change adjustnent for years prior to 2013. Following the automatic consent procedures provided for in the
Revenue Procedure, Idaho Power will be permitted to adopt this method in either its 201 3 or 2014 tax years with the filing of
IDACORP's consolidated federal income tax retum. The method change will be subject to IRS review as part of IDACORP's CAP
examination.
In tlre third quarter of 2012,Idaho Power completed an income tax accounting method change for its 201I tax year associated with the
electric transmission and distribution property portion (as opposed to the generation property portion described above) ofthe
capitalizedrepairsmethoditadoptedinfiscalyear20l0. Asaresultofthechange,ut20l2IdahoPowerrecordeda$7.8milliontax
benefit related to the filed deduction for the cumulative method change adjustrrent for years prior to 2011. The change was made
pnrsuant to Reveoue Procedure 20ll-43 to bring Idaho Power's existing method into alignment with the Revenue Procedure's safe
harbor unit-of-property definitions for electric transmission and distribution property. Following the automatic consent procedures
provided for in the Revenue Procedure, Idaho Power adopted this method with the filing of IDACORP's 201I consolidated federal
income tax return. The IRS approved the method change prior to the filing of the retum as part of IDACORP's 2011 CAP
examination. The final tangible properfy regulations discussed above are not expected to materially impact this tax accounting
method.
Idaho Power's prescribed regulatory accounting treatnent requires immediate income recogrition for temporary tax differences of this
type. 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 2013 capitalized repairs deduction estimate incorporates the provisions of both method
changes.
Tax Accounting Method Change for Uniform Capitalization
FERC FORM NO.1 1 Page 123.6
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
0411512014
Year/Period of Report
2013tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
In September 2009, the IRS issued Industry Director Directive #5 (IDD), which discusses the IRS's compliance priorities and audit
techniques related to the allocation of mixed service costs in the uniform capitalization methods of electric utilities. Within
IDACORP's 2009 CAP examination, the IRS and Idaho Power worked through the impact the IDD guidance had on Idaho Power's
uniform capitalization method and reached agreement during 2010. The agreement provided that Idaho Power change its uniform
capitalization method to the agreed upon method under the IDD with the filing of IDACORP's 2009 consolidated federal income tax
return. While Idaho Power had an agreement with the IRS for examination and retum filing purposes, the agreement required Joint
Committee approval to be final.
In September 201l, the IRS notified IDACORP that the Joint Committee had completed its review of IDACORP's 2009 tax year and
approved the uniforrn capitalization method agreement. The uniform capitalization method is effectively settled and no material
income tax uncertainties remain for the method. Accordingly, Idaho Power recogni zed $59 .7 million of its previously unrecogni zed tax
benefits for tax years 2009 and prior in 20 I 1 .
3. REGI]LATORYMATTERS
As a regulated utility, many of Idaho Power's fundamental business decisions are subject to the approval of governmental agencies,
including the prices that Idaho Power is authorized to charge for its electric service. These approvals are a critical factor in
determining Idaho Power's results of operations and financial condition.
Regulatory Assets and Liabilities
Regulatory assets represent incurred costs that have been deferred because it is probable they will be recovered from customers
through future rates. Regulatory liabilities represent obligations to make refunds to customers for previous collections, except for the
cost of removal (which represents the cost of removing future electric assets). The following table presents a summary of Idaho
Power's regulatory assets and liabilities (in thousands ofdollars):
FERC FORM NO. 1 123.7
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t'tst2014
Year/Period of Report
2013tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
As of December 31,2013
Description
Remaining
Amortization Earning a Not EarningPeriod Return (1) a Return Total as of December 31,
2013 2012
Regulatory Assets
Income Taxes
Unfunded postretirement benefi ts(2)
Pension expense deferrals(3 )
Energy efficiency progftrm costs(3)
Power supply costs(3)
Fixed cost adjustment(3)
Asset retirement obligations(4)
Mark-to-market liabilities(5)
Other
Varies
2014-2015
2014-2021
45,521
3,694
91,477
19,526
1,992
710,482 $
I16,583
29,587
l'8,026
1,629
1,554
710,482 $ 677,795
116,583 308,85075,108 64,9953,694 17,08591,477 60,68019,526 13,41818,026 15,4111,629 1,0553,546 3,749
Toal $ 162,210 $ 877,861 $ 1,040,071 $ 1,163,038
Regulatory Liabilities
Income taxes
Investrnent tax credits
Deferred revenue-AFUDC(6)
Energy efficiency program costs(3)
Power supply costs(3)
Settlement agreement sharing mechanism(3)
Mark-to-market assets(s)
Other
Varies
2014-2015
-$
38,508
6,686
24
7,602
2,493
55,017 $
79,121
20,483
1,672
977
79,121
58,991
6,696
24
7,602
1,672
3,470
79,897
45,6'13
4,130
17,778
7,151
4,579
2,695
55,017 $ 55,085
Total $ 55,313 $152,270 $212,583 $ 216.988
(1) Eaming a retum includes either interest or a retum on the investment as a component ofrate base at Ore allowed rate ofretum.
(2) Represents the unfunded obligation of Idaho Power's pension and poshetirernent 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-marka assets and liabilities are discussed in Note 15.
(6) es part ofits January 30, 2009 general rate case order, the IPUC allowed Idaho Power to recover AFUDC for the HCC relicensing asset even though the relicensing
process is not yet complete and the relicensing asset has not been placed in service. Idaho Power has collected rwenue in the Idaho jurisdiction for these relicensing
costs, but is deferring revenue recognition ofthe amounts collected until the license is issued and the asset is placed in service under the new lice.nse.
Idaho Power's regulatory assets and liabilities are amortized over the period in which they are reflected in customer rates. In the event
that recovery of Idaho Power's costs through rates becomes unlikely or uncertain, regulatory accounting would no longer apply to
some or all of Idaho Power's operations and the items above may repressnt stranded investnents. If not allowed full recovery of these
items, Idaho Power would be required to write offthe applicable portion, which could have a materially adverse financial impact.
Power Cost Adjustment Mechanisms and Deferred Power Supply Costs
In both its Idaho and Oregon jurisdictions, Idaho Power's power cost adjustnent @CA) mechanisms address the volatility of power
supply costs and provide for annual adjustnents to the rates charged to its retail customers. The PCA mechanisms comnare Idaho
Power's actual and forecast net power supply costs (primarily fuel and purchased power less oFsystem sales) against net power supply
costs currently being recovered in retail rates. Under the PCA mechanisms, certain differences between actual net power supply costs
incurred by Idaho Power and the costs included in retail rates are recorded as a deferred charge or credit on the balance sheets for
future recovery or refund through retail rates. The power supply costs deferred primarily result from changes in wholesale market
prices and transaction volumes, fuel prices, changes in contracted power purchase prices and volumes (including PURPA power
purchases), and the levels of Idaho Power's own hydroelectric and thermal generation.
FORM NO.1 1 123.8
Name of Respondent
ldaho Power Comoanv
This Report is:
(1) X An Originalel A Resubmission
Date of Report
(Mo, Da, Yr)
04t1512014
Year/Period of Report
20131Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Idaho furisdiction Power Cost Adjustment Mechanism.' In the Idaho jurisdiction, the annual PCA adjustnents consist of (a) a
forecast component, based on a forecast of net power supply costs in the coming year as compared to net power supply costs included
in base rates; and (b) a true-up component, based on the difference between the previous year's actual net powor supply costs and the
previous year's forecast. The latter component also includes a balancing mechanism so that, over time, the acfual 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 adjustrnent 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 tbree most recent Idaho PCA rate adjustnents.
Effective $ Change
(millions) Notes
June l, 2013 $ 140.4 The 2013 Idaho PCA rates are offset by $7.2 million of Idaho revenue-sharing related to 2012
finaucial results pursuant to an IPUC order issued :ul^2012 under regulatory settlement
agreements approved in January 2010 and December 201l. The $140.4 million increase in
PCA rates includes the $19.9 million reduction in the revenue sharing amount (described
below) from $27.1 million for the2012-2013 PCA to $7.2 million for the2013-2014 PCA.
June 1, 2012 $ 43.0 The PCA rate increase was offset by $27.1 million to be shared with customers pursuant to
the revenue sharing order described below, resulting in a net rate increase of $15.9 million for
these orders.
Oregon furisdiction Power Cost Adjusfrnent Mechanism.' Idaho Power's power cost recovery mechanism in Oregon has two
components: an annual power cost update (APCID and a power cost adjustnent 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 tbrough 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 ofthe deadband, the PCAM provides for 90/10 sharing ofcosts and
benefits between customers and Idaho Power. However, collection by Idaho Power will occur only to the extent that Idaho Power's
actual retum on equity (ROE) for the year is no greater than 100 basis poinr below Idaho Power's last authorized ROE. A refund to
customers will occur only to the extent that ldaho 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 20 I 3 and 2012 are
summarized in the table that follows.
Year and
Mechanism APCU or PCAM Adjustment
2013 PCAM deferral.
2013 APCU A rate increase of $2.9 million annually took effect June 1,2013.
2012 PCAM Actual net power supply costs were within the deadband, resulting in no deferral.
2012 APCU A rate increase of $l.8 million annually took effect June 1, 2012.
FERC FORM NO. I 1 123.9
Name of Respondent
ldaho Power Comoanv
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t't5t2014
Year/Period of Report
20131Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Idaho Regulatory Matters
2011 ldaho General Rute Case Settlement: OnJune l, 201l, Idaho Power filed a general rate case wittr the IPUC requesting
approximately $82.6 million in additional Idaho jurisdiction annual revenues for collection through base rates. On September 23,
201l, Idaho Power, the IPUC Staff, and other interested parties filed a settlement stipulation with the IPUC resolving most of the key
contested issues in the Idaho general rate case. The settlement stipulation, approved by the IPUC in December 201l, provided for a
7.86 percent authorized overall rate ofreturn on an Idaho-jurisdiction rate base ofapproximately $2.36 billion. The approved
settlement stipulation resulted n a 4.07 percent, or $34.0 million, overall increase in Idaho Power's annual ldaho-jurisdiction base rate
revenues, effective January 1,2012. Neither the settlement stipulation nor the associated IPUC order specified an authorized rate of
return on equity or imposed a moratorium on Idaho Power's filing a general rate case at a future date.
Idaho Power's Idaho jurisdiction base rates were again reset effective in July 2012, following completion of the Langley Gulch power
plant, as described below.
January 2010 kluho Settlement Agreement: In January 2010, the IPUC approved a settlement agreement among Idaho Power, the
IPUC Staff, several of Idaho Power's customers, and other interested parties. Sigrrificant elements of the settlement agreement
included:
o a specified distribution of the reduction in the 2010 PCA that would reduce customer rates, provide up to a $25 million
general increase in annual base rates, and reset base power supply costs for the PCA, effective with the June l, 2010 PCA rate
change;r a provision to share with Idaho customers 50 percent ofany Idaho-jurisdiction earnings in excess ofa 10.5 percent return on
year-end equity in the Idaho jurisdiction (Idaho ROE) in any calendar year from 2009 tlrough 201l; ando a provision to allow the additional amortization of accumulated deferred investnent tax credits (ADITC) if Idaho Powet's
Idaho-jurisdiction rate ofrettrn on year-end equity (Idaho ROE) is below 9.5 percent in any calendar year from 2009 through
20t1.
Because ldaho Power's actual Idaho ROE was between 9.5 and 10.5 percent in 2009 and 2010, the sharing and amortization
provisions of the January 2010 settlement agreement were not triggered. However, recognition of income tax benefits in 2011 had a
significant impact on Idaho Power's actual Idaho ROE and contributed to the triggering of the sharing mechanism for 2011. In
accordance with the terms of the settlement agreement, Idaho Power recorded a$27.1million reduction in revenue and recorded an
associated regulatory liability in 201 l, reflecting 50 percent ofIdaho Power's 201 1 Idaho-jurisdiction earnings above a 10.5 percent
Idaho ROE to be shared with Idaho customers.
December 2011 ldaho Settlement Agreement: The sharing and ADITC amortization provisions of the January 2010 settlement
agreement terrninated on December 31, 201I . On Decemb er 27 , 201I , the IPUC issued an order, separate from the general rate case
proceeding, approving a settlement agreement extending, with modifications, some of the provisions of the January 2010 settlement
agreement. The settlement agreement provided that:
o if Idaho Power's actual 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 3 minimurn p.5 percent Idaho ROE in the applicable year;
r 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 forrn of a rate reduction to become
effective at the time of the subsequent year's PCA adjustnent; ando if Idaho Power's actual Idaho ROE for 2012,2013, or 2014 exceeds 10.5 percent, the amount of Idaho Power's Idaho
jurisdictional eamings exceeding a 10.5 percent Idaho ROE for the applicable year would be allocated 75 percent to Idaho
Power's Idaho customerc as a reduction to the pension regulatory asset and 25 percent to Idaho Power.
The December 201I settlement agreement provides that the return on year-end equity thresholds (9.5 percent, 10.0 percent, and 10.5
percent) will be adjusted prospectively in the event the IPUC approves a change to Idaho Powefs authorized retum on equity as part of
a general rate case proceeding seeking a rate change effective prior to January l, 2015. In consideration for the authority to amortize
additional ADITC described above, the December 2011 settlement agreement provided that Idaho Power would allocate to customers
FERC FORM NO.1 .1 123.10
Name of Respondent
ldaho Power ComDanv
This Report is:
(1) X An OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
04t't5t2014
Year/Period of Report
2013la4
NOTES TO FINANCIAL STATEMENTS (Continued)
as a reduction to the pension regulatory asset 75 percent of Idaho Power's own share of 2011 Idaho jurisdictional eamings over a 10.5
percent Idaho ROE.
Revenue Shartng Under December 2011 Idaho Settlement Agreemenf: The amounts Idaho Power recorded :or^2012 and 2013 for
revenue sharing under the December 201I Idaho regulatory settlement described above were as follows (in millions):
Recorded as Refunds Recorded as a Pre-tax
Year to Customers Charge to Pension Expense
20r3
2012
$7.6
$7.2
$16.s
$14.6
Cost Recovery for Langley Gulch Power Plqnt: On March2, 2|l2,Idaho Power filed an application with the IPUC requesting an
increase in annual Idaho-jurisdiction base rates of$59.9 million for recovery ofldaho Power's investrnent and associated costs for the
Langley Gulch natural gas-fued power plant, which became commercially available in June 2012. Idaho Powe/s application stated
tlrat its estimated invesfrnent in the plant through Jtlllle2012 was approximately $398 million. After the impact of depreciation,
deferred income taxes, amounts currently included in rates, and an Idaho-jurisdictional cost allocation, Idaho Power's application
requested a$336.7 million increase in Idaho-jurisdiction rate base. Idaho Power's requested base rate increase was based on an overall
rate of return of 7.86 percent, as authorized by a prior IPUC order. On June 29,2012, the IPUC issued an order approving a $58.1
million increase in annual Idaho-jurisdiction base rates, effective July l, 2012. The order also provided for a $335.9 million increase
in Idaho rate base.
DeJined Benelit Pension Plqn Contribution Recovery: Idaho Power has made substantial contributions to its defined benefit pension
plan in recent years. Idaho Power defers its Idaho-jurisdiction pension expense as a regulatory asset until recovered from Idaho
customers. AsofDecember3l,2013,IdahoPowet'sdeferralbalanceassociatedwiththeldahojurisdictionwas$72.6million.
Deferred pension costs are expected to be amortized to expense to match the revenues received when conEibutions are recovered
through rates. Idaho Power only records a carrying charge on the unrecovered balance ofcash contributions. In light ofthe substantial
prior and expected future contributions, in March 2011 Idaho Power filed an application with the IPUC requesting an increase in the
amount included in base rates for recovery of the Idaho-jurisdiction portion of Idaho Power's cash contributions to its defined benefit
pension plan from the then-current amount of $5.4 million to approximately $ 17. 1 million annually. On May 19,2011, the IPUC
approved Idaho Power's application, with new rates effective on June l, 2011.
Fixed Cost Adjustment: The Idaho jurisdiction fixed cost adjustnent (FCA) is designed to remove Idaho Power's disincentive to
invest in energy efficiency programs by separating (or decoupling) the recovery of fixed costs from the variable kilowatt-hour charge
and linking it instead to a set amount per customer. The FCA is adjuskd each year to collect, or refund, the difference between the
allowed fixed-cost recovery amount and the actual fixed costs recovered by Idaho Power during the year. The amount of the FCA
recovery is capped at no more than 3 percent ofbase revenue, with any excess deferred for collection in a subsequent year. The
following table summarizes FCA amounts approved for collection in the prior three FCA years:
f,'CAYear Period rates in effect
Annual Amount
(in millions)(l)
2012
20tt
2010
June l, 2013-May 31, 2014
June l, 2012-May 31,2013
June l, 201 l-May 31, 2012
$8.9
$10.3
$9.3
( I ) The amount shown represents the total FCA defened amount. The amount of the change in
the FCA amount for a year is calculated as the difference between the zubject yea/s annual
FCA amount and the prior year's FCA amount.
The defenal for the 2013 FCA was $15.4 million which, pending approval by the IPUC, will be recovered between June l, 2014 and
May 31, 2015.
Energ Effrciency and Demand Response Programs: Idaho Power has implemented and/or manages a wide range of opportunities
for its customers to and demand
FERC FORM NO. 1 12-88) Pase 123.11
Twi efficienc
Name of Respondent
ldaho Power Comoanv
This Report is:
(1) X An OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
04t15t20'.!4
Year/Period of Report
2013/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
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 eamings. The cumulative variance between
expenditures and amounts collected through the rider is recorded as a regulatory asset or liability pending future collection fiom or
obligation to customers. Inthe 2012 PCA filing, $14.7 million of certain demand response program costs were shifted from the rider
mechanism to the PCA mechanism, as these costs are closely related to and directly impact the other power supply costs collected
through the PCA. The December 201I 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.
On April 3,2013,Idaho Power filed an application with the IPUC requesting an order f,rnding Idaho Power's 2012 expenditures of
$25.9 million in energy efficiency rider funds, $6.0 million in custom efficiency program incentives in a regulatory asset account, and
$14.5 million of demand response program incentives included in the 2013 PCA, as prudently incurred demand-side management
program expenses. On December 20,2013, the IPUC issued an order finding all but $0.3 million of such expenses as prudently
incurred, though the IPUC's order does provide Idaho Power with an opporhrnity to re-present $0.2 million of that amount for
subsequent reconsideration. A previous order of the IPUC approved as prudently incurred $42.5 million of 201I expenditures. As of
December3l,20l3,theldahoenergyefficiencyriderbalancewasaregulatoryliabilityof$6.7million. Separately,onJunel2,20l3,
the IPUC issued an order authorizing Idaho Power to recover custom efficiency progfllm incentive payments, including the
then-current regulatory account balance of $14.3 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 exponses in 2013.
Certificate of Public Convenience and Necessigfor Jim Bridger Plant Upgrades: On June 28,20l3,Idaho Power filed an
application with the IPUC requesting that the IPUC issue a Certificate of Public Convenience and Necessity (CPCI.Q related to
selective catalytic reduction (SCR) investnents planned for Jim Bridger coal-fired plant units 3 and 4. Idaho Power's CPCN
application requested that the IPUC provide Idaho Power with authorization and a binding commitnent to provide rate base treatnent
for Idaho Power's share of the SCR investrnent in the amount of approximately $130 million (including AFT DC). Filing of the CPCN
was intended to allow the IPUC to review the prudence of the investment in SCR prior to Idaho Power's incurring the bulk of the
associated costs. On December 2,2013, the IPUC issued an order granting Idaho Power's application for a CPCN. The IPUC,
however, denied the company's additional request for early binding ratemaking treatrnent. The IPUC's order also requires that Idaho
Power submit quarterly reports updating the IPUC on any changes to environmental policy or regulations until such time as the
upgrades are in service, and that the company return to the IPUC if viable alternatives to the SCR upgrades become available.
Cost Recovery for Cessation of Boardman Coal-Fired Operations: In December 2010, the Oregon Environmental Quality
Commission approved a plan to cease coal-fired operations at the Boardman power plant not later than Decemb er 3l , 2020. The plan
results in increased revenue requirements for Idaho Power related to accelerated depreciation expense, additional plant invesunents,
and decommissioning costs. In response to an application filed by Idaho Power, on February 15,2012 the IPUC issued an order
accepting ldaho Power's regulatory accounting and cost recovery plan associated with the early plant shut-down and approving the
establishment of a balancing account whereby incremental costs and benefits associated with the early shut-down will be tracked for
recovery in a subsequent proceeding. On May 17 ,2012, the IPUC issued an order approving a $1.5 million annual increase in
Idaho-jurisdictionbaserates,withnewrateseffectiveJunel,2012. AsofDecember3l,2013,IdahoPower'snetbookvalueinthe
Boardman plant was $21.2 million.
Idaho Depreciation Rate Filings: Idaho Powels advanced metering infrastructure (AMI) project provides the means to automatically
retrieve and store energy consumption inforrnation, eliminating manual meter reading expense. Commencing June l, 2009, the IPUC
approved a rate increase, coincident with a related increase in depreciation expense, allowing Idaho Power to recover the three-year
accelerated depreciation of the existing non-AMI metering equipment and to begin earning a return on its AMI investnent. On April
27,2012, the IPUC approved Idaho Power's February 15,2012 application requesting approval of a $10.6 million decrease in rates for
specified customer classes, effective June l, 2012, as a result of the removal of accelerated depreciation expense associated with
non-AMI metering equipment.
In connection with a depreciation study authorized by Idaho Power and conducted by a third party, on February 15,2Ul2,Idaho Power
filed an application with the IPUC seeking to institute revised depreciation rates for electric plant-in-service, based upon updated
service life estimates and net salvage percentages for all plant assets, and adjust Idaho-jurisdiction base rates to reflect the revised
FERC FORM NO. 1 123.12
Name of Respondent
ldaho Power Company
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
0411512014
Year/Period of Report
20,t3tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
depreciation rates. On May 3 1, 2012, the IPUC issued an order approving a settlement stipulation providing for a $ I .3 million annual
decrease in ldaho-jurisdiction base rates, ef[ective June l, 2012.
Oregon Regulatory Matters
2011 Oregon General Rate Case: OnJluly 29,201l, Idaho Power filed a general rate case and proposed rate schedules with the
OPUC. The filing requested a $5.8 million increase in annual Oregon jurisdictional revenues and an authorized rate of reflrn on
equity of 10.5 percent, with an Oregon retail rate base of approximately $121.9 million. Idaho Power, the OPUC Staff, and other
interested parties executed and filed a partial settlement stipulation with the OPUC on February 1,2012, which the OPUC approved on
February 23,2012. The settlement stipulation provided for a $1.8 million base rate increase, a retum on equity of 9.9 percent, and an
overall rate of retura of 7.757 percent in the Oregon jurisdiction. New rates in conforrnity with the settlement stipulation were
effective March l, 2012.
Cost Recoveryfor Langley Galch Power Plant: 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 Powels Oregon rate base.
Federal Regulatory Matters - Open Access Transmission Tariff Rates
ln2O06,Idaho Power moved from a fixed rate to a fomrula rate for hansmission service provided under its open access transmission
taritr(OATT), which allows transmission rates to be updated annually based on financial and operational data Idaho Power files with
the FERC. Idaho Powe/s OATT rates submitted to the FERC in Idaho Powet's three most recent annual OAft Final Informational
Filings were as follows:
Applicable Period
OATT Rate (per
kW-year)
October 1,2013 to September 30,2014
October 1,2012 to September 30,2013
October l, 201I to September 30,2012
$
$
$
22.80
21.32
19.79
Idaho Power's current OATT rate is based on a net annual transmission revenue requirement of $ I I 8.2 million, which represents Idaho
Power's net cost ofproviding OATT-based transmission service.
FERC FORM NO.1 {2-88 't23.13
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
0411512014
Year/Period of Report
2013tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
4. LONG-TERMDEBT
The following table summarizes Idaho Power's long-term debt at December 3l (in thousands of dollars):
2013 2012
First mortgage bonds:
4.25% Series due 2013
6.025% Series due 2018
6.15% Series due 2019
4.50% Series due 2020
3.40% Series due 2020
2.95% Series &rc2022
2.50% Series &re 2023
6% Series ilre2O32
5.50% Series due 2033
5.50% Series due 2034
5.875% Series due 2034
5.30% Series due 2035
6.30% Series dtrc2037
6.25% Series &re 2037
4.85% Series due 2040
4.30% Series due 2042
4.00% Series due 2043
120,000
100,000
130,000
100,000
75,000
75,000
100,000
70,000
50,000
55,000
60,000
140,000
100,000
100,000
75,000
75,000
70,000
120,000
100,000
130,000
100,000
75,000
100,000
70,000
50,000
55,000
60,000
140,000
100,000
100,000
75,000
Total first mortgage bonds 1T2s,000 1,34s,000
Pollution control revenue bonds:
5.15% Series tua20240')
5.25% Series tue20260)
Variable Rate Series 2000 due2027
49,800
116,300
4,360
49,800
I16,300
4,360
Total pollution control revenue bonds 170,464 170,460
American Falls bond guarantee
Milner Dam note guarantee
Unamortized premium/discount - net
19,885
4,255
(3,278)
1,616,322
(1,064)
1,537,696
(71,064)
19,885
5,318
(2,967)
Total Idaho Power outstanding deb(2)
Current maturities of long-term debt
Total long-term debt 1,615,258 $
(l) Humboldt County and Sweetwater County Pollution Control Reveoue Bonds arc secured by the first mortgage, bringing the total first mortgage bonds outstanding
at December 31,2013 to $1.591 billion.
(2) At December 3l,2Ol3 and2}l2,the overall effective cost ofldaho Power's outstanding debt was 5.19 percent and 5.44 percent, respectively.
At December 31,2013, the maturities for the aggregate amount of Idaho Power long-term debt outstanding were as follows (in
thousands of dollars):
2014 20162015
$ 1,064
2017 2018 Thereafter
1,064 1,064 s 1,064 $ 120,000 s 1,495,344
FORM NO.1 1 123.14
Name of Respondent
ldaho Power Company
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
04115t2014
Year/Period of Report
2013tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Long-Term Debt Issuances, Maturities, and Availability
On April 8,20l3,Idaho Power issued $75 million in principal amount of 2.50% first mortgage bonds, Series I, maturing on April 1,
2023, ard $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 satisff its obligations upon maturity of
$70 million in principal amount of 4.25% fust mortgage bonds. Issuance of the Series I first mortgage bonds in April 2013, combined
with the issuance of $200 million in principal amount of Series I first mortgage bonds in August 2010 and $150 million in principal
amount of Series I first mortgage bonds in April 2012,ualized in full the available amount under a registration statement Idaho Power
filed with the U.S. Securities and Exchange Commission (SEC) in May 2010 and under a selling agency agreement executed with ten
banks in June 2010. In May 20l2,Idaho Power used a portion of the net proceeds of the April 2012 sale of first mortgage bonds to
effect the early redemption in full of its $100 million of 4.75Yo first mortgage bonds due November 2012.
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 uponrequest 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.
ln anticipation of the issuances of the notes described above and 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 ttre 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 banl6 named in the agreement in connection with the potential
issuance and sale from time to time ofup to $500 million aggregate principal amount of fust 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 l, 1937, as
amended and supplemented (Indenture). Also on July 12,z0l3,Idaho Power entered into the Forly-seventh Supplemental lndenture,
dated as of July 1,2013, to ttre Indenture. The Fony-seventh Supplemental lndenture provides for, among other items, the issuance of
up to $500 million in aggregate principal amount of Series J Notes pursuatrt to the Indenture. As of December 3l,ZDl3,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 3l,2013,Idaho Power could issue under its Indenture approximately $1.4 billion of additional first
mortgage bonds based on retired first mortgage bonds and total unfunded property additions. These amounts are fi.uther limited by the
maximum amount of first mortgage bonds set forth in the Indenture.
The mortgage ofthe 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 fust
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 cornmon to properties.
The mortgage ofthe Indenture does not create a lien on revenues or profits, or notes or accounts receivable, contracts or choses in
action, except as pennitted 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 lndenture creates a lieu on the interest of Idaho Power in properly
subsequently acquired, other than excepted properly, subject to limitations in the case of consolidation, merger, or sale of all or
substantially all ofthe assets ofldaho Power. The Indenture requires Idaho Power to spend or appropriate 15 percent ofits annual
gross operating rovenues for maintenance, retfuement, 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 l7 , 20l0,Idaho Power entered into the Forty-fifth Supplemental Indenture, dated as of February l, 2010, to the Indenhre
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, eamings, 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 ttrat Idaho Power's net earnings be at least twice the annual interest requirements on all outstanding debt of
equal or prior ranlq including the bonds that Idaho Power may propose to issue. Under certain circumstances, the net earnings test
FERC FORM NO.1 1 123.15
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
o4t15t2014
Year/Period of Report
20131Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
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. NOTESPAYABLE
Credit Facilities
Idaho Power has a credit facility that may be used for general corporate purposes and commercial paper backup. Idaho Power's credit
facility consists ofa revolving line ofcredit, through the issuance ofloans and standby letters ofcredit, 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 (l) 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 commitnent based on the Idaho Power'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
grants Idaho Power the right to request up to two one-year extensions, in each case subject to certain conditions. In October 2012,
Idaho Power executed the First Extension Agreement with each of the lenders, extending the terrnination date under the credit facility
to October 26,2017. In October 2013, Idaho Power executed the Second Extension Agreement with each of the lenders, extending the
termination date under the credit facility to October 26,2018. No other terms of the credit facility, including the amount of perrnitted
borrowings under the credit agreement, were affected by the extensions.
At December 31,2013, no loans were outstanding under Idaho Power's facility. At December 3l,2013,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 31,2013 and December
3t,2012:
2013 2012
Commercial paper balances:
At the end of year
Average during the year
Weighted-average interest rate
At the end of the year
$ -$ -$ 2,209 $ 3,s78
-% -%
6. COMMON STOCK
Idaho Power Common Stock
Ir20I2,IDACORP contributed $7.5 million of additional equity to Idaho Power. No contributions were made to Idaho Power in
2013. No additional shares of Idaho Power common stock were issued in exchange for the contributions.
Restrictions on Dividends
Idaho Power's ability to pay dividends on its cornmon 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 capitalizatiory as defined
therein, of no more than 65 percent at the end of each fiscal quarter. At December 31,2013, the leverage ratio for Idaho Power was 49
percent. Based on these restrictions, Idaho Power's dividends were limited to $848 million at December 31,2013. There are
FERC FORM NO.1 123.16
Name of Respondent
ldaho Power Companv
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t15t2014
Year/Period of Report
20131o,4
NOTES TO FINANCIAL STATEMENTS (Continued)
additional facility covenants, subject to exceptions, that prohibit or restrict the sale or disposition ofproperty without consent and any
agreements restricting dividend pa)rments to the company from any material subsidiary. At Decembe r 3l,2013,Idaho Power was in
compliance with those covenants.
Idaho Power's Revised Policy and Code of Conduct relating to tansactions 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 3 I ,
2013, Idaho Power's cornmon equity capital was 52 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 IDACOM.
Idaho Power's articles of incorporation contain restrictions on the payment of dividends on its common stock ifpreferred 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 paym.ent 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 curent year earnings or retained
earnings.
In accordance with Section 10(d) of the Federal Power Act, Idaho Power has $6.8 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 Resricted Stock Plan (RSP). These plans are intended to aligrr employee and shareholder
objectives related to IDACORP's long-terrr growth.
The LTICP (for officers, key employees, and directors) permits the grant of nonqualified stock options, restricted stoclg performance
shares, and several other types ofstock-based awards. The RSP permits only the grant ofrestricted stock or performance-based
restrictedstock. AtDecember3l,2Ol3,themaximumnumberofsharesavailableundertheLTICPandRSPwerel,25l,9T9and
15,796, respectively.
Stock Awards: Restricted stock awards have three-year vesting periods and entitle the recipients to dividends and voting rights.
Unvested shares are restricted as to disposition and subject to forfeiture under certain circumstances. The fair value of these awards is
based on the closing market price of common stock on the grant date and is charged to compensation expense over the vesting period,
based on the number ofshares 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 attairunent ofspecific performance
conditions over the three-year vesting period. The performance conditions are two equally-weighted metrics, cumulative eamings per
share (CEPS) and total shareholder retum (TSR) relative to a peer group. Based on the level of attainment of the performance
conditions, the final nurnber of shares awarded can range from zero to I 50 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
targ€ts based on historical retums relative to the peer group. The fair value of this portion of the awards is charged to compensation
expense over ttre requisite service period, provided the requisite service period is rendered, regardless ofthe level ofTSR metric
attained.
FERC FORM NO.1 123.17
Name of Respondent
ldaho Power ComDanv
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
0411512014
Year/Period of Report
2013tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
A summary of restricted stock and performance share activity is presented below. Share amounts represent shares of IDACOM
common stock:
Number of Weighted-Average
Shares Grant Date Fair Value
Nonvested shares at January L,2013
Shares granted
Shares forfeited
Shares vested
3t6,7|t $ 32.32
106,467 42.53(2,087) 38.05(115,107) 29.s2
Nonvested shares at December 31.2013 305,984 $ 36.85
The total fair value of shares vested during the years ended December 31,2013 afi.2012 was $5.0 million and $4.9 million,
respectively. At December 3l,20l3,Idaho Power had $4.8 million of total unrecogaized 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
1.64 years. IDACORP uses original issue and/or treasury shares for these awards.
In 2013, a total of 13,013 shares of IDACORP common stock were awarded to directors of IDACORP and Idaho Power at a grant date
fairvalueof$46.87pershare. Directorselectedtodeferreceiptof6,425ofthese shares,whicharebeingheldasdeferredstockunits
with dividend equivalents reinvested in additional stock units.
Stock Options.. No stock options have been granted since 2006. The remaining unexercised stock option awards were granted with
exercise prices equal to the market value of the stock on the date of grant, with a term of l0 years from the grant date and a five-year
vesting period. The fair value of each option was amortized into compensation expense using graded vesting and, as of December 3 I ,
2013, all compensation costs have been recognized. IDACORP uses original issue and/or treasury shares to satisfu exercised options.
Idaho Power's stock option transactions are summarized below. Share amounts represent shares of IDACORP common stock:
Number of Weighted- Weighted Aggregate
Shares Average
Average Remaining IntrinsicExercise Contractual ValuePrice Term (Years) (000s)
Outstanding at January l, 2013 3,956 $ 29.75 2.05 $ 54
Exercised (2,766) 29.7s
Outstanding at December 31,2013 1,190 $ 29.75 1.0s $ 26
Vested and exercisable at December
31,2013 1,190 $ 29.75 l.os $ 26
The following table presents information about options exercised (in thousands of dollars):
2013 2012
Intrinsic value ofoptions exercised $ 47 $ 36
Cash received from exercises
Tax benefits realized from exercises
82 7719 t4
Compensation Expense: The following table shows the compensation cost recogdzed 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 emFloyees (in thousands of
dollars):
FERC FORM NO. 1 Page 123.18
Name of Respondent
ldaho Power Comoanv
This Report is:
(1) X An OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
04t15t2014
Year/Period of Report
2013tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
2013 2012
Compensation cost
Income tax benefit
4,783 $
1,870
4,577
1,789
No equity compensation costs have been capitalized.
8. COMMITMENTS
Purchase Obligations
At December 3l,20l3,Idaho Power had the following long-term commitrnents relating to purchases of energy, capacity, transmission
rights, and fuel (in thousands of dollars):
201s 2016 2017 2018 Thereafter2014
Cogeneration and power production
Power and transmission rights
Fuel
$ 170,155 $ 175,242 $ 173,982 $ 178,854 $ 186,219 $ 2,660,9544,801 4,815 4,790 4,214 - 1,179 4,739
84,068 35,228 9,888 9,775 9,343 79,869
As of Decemb er 3l , 2013 , Idaho Power ha d 7'7 4 MW nameplate capacity of PURPA-related projects on-line, with an additioual 68
MW nameplate capacity of projects projected to be on-line by the end of 2016. The power purchase contracts for these projects have
terms ranging from one to 35 years. During 2013, Idaho Power purchased2,126,644 megawatt-hours (M\I/h) from these projects at a
cost of $l3l million, resulting in a blended price of $61.75 per MWh. Idaho Power purchased 1,961,208 MWh at a cost of $118
million ur2012.
In addition, Idaho Power has the following long-term commifrnents for lease guarantees, equipment, maintenance and serrrices, and
industry related fees (in thousands ofdollars):
2014 2015 2016 2017 2018 Thereafter
$ 1,357 $ 2,024 $ 1,155 $ 868 $892Operating leases
Equipment, maintenance, and service agreemonts
FERC and other industry-related fees
6t,166 38,632 16,050 4,373 3,813t2,665 12,646 6,802 6,802 6,802
$ 14,536
22,630
34,009
Idaho Power's expense for operating leases was approximately $5.2 million in 2013 and $6.0 million i\2012.
Guarantees
Through a self-bonding mechanism, Idaho Power guarantees its portion of reclamation activities and obligations at BCC, ofwhich
IERCo owns a one-third interest. This guarantee, which is renewed annually with the Wyoming Departnent of Envirorunental Quality,
was $74 million at December 3 l, 2013 , 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. AtDecember 31,2013, the value of the
reclamation trust fund was $67 million. During 2013 the reclamation trust fund distibuted approximately $28 million forreclamation
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 applyng a nominal
surcharge to coal sales in order to maintain adequate reseryes in the reclamation trust firnd. 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 agreemetrts and power purchase and sale agreements that include indernnification provisions relating
to various forrns of claims or liabilities that may arise from the transactions contemplated by these agreements. Generally, a maximum
Name of Respondent
ldaho Power Company
This Report is:
(1) X An OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
0411512014
Year/Period of Report
2013to,4
NOTES TO FINANCIAL STATEMENTS (Continued)
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, 2013,
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
matt€rs 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 issuss have not been well developed, or (c) the matters involve complex or
novel legal theories or a large number ofparties. 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 accrual for loss contingencies is not material to the financial statements as a
whole; however, future accruals could bo material in a given period. Idaho PoweCs determination is based on currently available
information, and estimates presented in financial statements and other financial disclosures involve sigrrificant 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 Califomia and in western wholesale markets during 2000 and 2001
caused numerous purchasers of electricity in those markets to initiate proceedings seeking refunds or other forms of relief and the
FERC to initiate its own investigations. Some of these proceedings remain pending before the FERC or are on appeal to the United
States Court of Appeals for the Ninth Circuit. Idaho Power and IESCo (as successor to 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 from an upstream seller of power based on a finding that its donmstream 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 a portion of a settlement that
provided for waivers of all claims in those proceedings, despite only limited objections from two market participants. Idaho Power and
IESCo petitioned the D.C. Circuit for review of the FERC's decision refusing to approve the waiver provision of the settlement, on the
basis that the FERC failed to apply its established precedents and rules. The petition for review was transferred to the Ninth Circuit
Court of Appeals in June 2013 and remains pending before that court.
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.
Water Rights - Snake River Basin Adjudication
Idaho Power holds water rights, acquired under applicable state law, for its hydroelectric projects. In addition, Idaho Power holds
water rights for domestic, irrigation, commercial, and other necessary purposes related to project lands and other holdings within the
FERC FORM NO. 1 1 123.20
Name of Respondent
ldaho Power Companv
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
0411512014
Year/Period of Report
2013rc4
NOTES TO FINANCIAL STATEMENTS (Continued)
states of Idaho and Oregon. Idaho Power's water rights for power generation are, to varying degrees, subordinated to future upstream
appropriations for irrigation and other authorized consumptive uses. Over time, increased irrigation development and other
consumptive uses within the Snake River watershed led to a reduction in flows of the Snake River. In the late 1970s and early 1980s
these reduced flows resulted in a conflict between the exercise of Idaho Power's water rights at certain hydroelectric projects on the
Snake River and upstream consumptive diversions. The Swan Falls Agreement, signed by Idaho Power and the State of Idaho on
October 25,1984, resolved the conflict and provided a level of protection for Idaho Power's hydropower water rights at specified
projects on the Snake River through the establishment of minimum stream flows and an administrative process governing future
development of water rights that may affect those minimum stream flows. In 1987, Congress enacted legislation directing the FERC to
issue an order approving the Swan Falls settlement together with a finding that the agreem€nt was neither inconsistent with the terms
and conditions of Idaho Power's project licenses nor ttre Federal Power Act. The FERC entered an order implementing the legislation
in March 1988.
The Swan Falls Agreement provided that the resolution and recognition of Idaho Powe/s water rights together with the State Water
Plan provided a sound comprehensive plan for managoment of the Snake River watershed. The Swan Falls Agreement also recognized,
however, that in order to effectively manage the waters of the Snake River basin, a general adjudication to determine the nature, oxtent,
and priority of the rights of all water uses in the basin was necessary. Consistent with that recognition, in 1987 the State of Idaho
initiated the Snake River Basin Adjudication (SRBA), and pursuant to the commencement order issued by the SRBA court that same
year, all claimants to water rights within the basin were required to file water rights claims in the SRBA. Idaho Power has filed claims
to its water rights and has been actively participating in the SRBA since its commencement. Questions conceming the effect of the
Swan Falls Agreement on Idaho Power's water rights claims, including the nature and extent of the subordination of Idaho Power's
rights to upstream uses, resulted in the filing of litigation in the SRBA in2007 between Idaho Power and the State of Idaho. This
litigation was resolved by the Framework Reaffrming the Swan Falls Settlement (Framework) signed by Idaho Power and the State of
Idaho on March 25, 2009. In that Framework, the parties acknowledged that the effective management of Idaho's water resources
remains critical to the public interest of the State of Idaho by sustaining economic growth, maintaining reasonable electric rates,
protecting and preserving existing water rights, and protecting water quality and environmental values. The Framework further
provided that the State ofldaho and Idaho Power would cooperate in exploring approaches to resolve issues ofmutual concern relat:ng
to the management of Idaho's water resources. Idaho Power continues to work with the State of Idaho and other interested parties on
these issues.
One such issue involves the management of the Eastern Snake Plain Aquifer (ESPA), a large underground aquifer in southeastern
Idaho that is hydrologically connected to the Snake River. House Concurrent Resolution No. 28, adopted by ttre Idaho Legislature in
2007, dkected the Idaho Water Resource Board to pursue the development of a comprehensive management plan for the ESPA, to
include measures that would enhance aquifer levels, springs, and river flows on the eastern Snake River plain to the benefit ofboth
agricultural development and hydropower generation. In May of 2007, the Idaho Water Resource Board appointed an advisory
semmi6ss, charged with the responsibility of developing a management plan for the ESPA. Idaho Power was a member of that
committee. In January 2009, the Idaho Water Resource Board, based on the committee's recommendations, adopted a Comprehensive
Aquifer Management Plan (CAMP) for the ESPA. The Idaho Legislature approved the CAMP that same year. Idaho Power is a
member of the CAMP Implementation Committee and continues to work with the Idaho Water Resource Board, other stakeholders,
and the Idaho Legislature in exploring opportunities for implementation of the CAMP management plan.
Idaho Power continues its participation in the SRBA in an effort to ensure that its water rights are protected and that the operation of
its hydroelectric projects is not adversely impacted. While Idaho Power cannot predict the outcome, as of the date of this report Idaho
Power does not anticipate any material modification of its water rights as a result of the SRBA process.
Other Proceedings
Idaho Power is party to legal claims and legal and regulatory actions and proceedings in the ordinary course ofbusiness 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 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 inveshnent for infrastructure and modifications to its electric generating facilities to comply with these
FERC FORM NO.1 123.21
Name of Respondent
ldaho Power Comoanv
This Report is:
(1) X An Originalel A Resubmission
Date of Report
(Mo, Da, Yr)
04t1512014
Year/Period of Report
2013tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
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 defrned 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 2013 and20l2
Idaho Power elected to contribute more than the minimum required amounts in order to bring the pension plan to a more firnded
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 SMSP
2013 2012 2013 2012
Change in projected benelit obligation:
Benefit obligation at January I
Service cost
Interest cost
Actuarial (gain) loss
Benefits paid
Projected benefit obligation at December 3l
Change in plan assets:
Fair value at January I
Actual retum on plan assets
Employer contributions
Benefits paid
Fair value at December 3l
Funded status at end ofyear
Amounts recognized in the statement of financial position consist
of:
Other current liabilities
Noncurrent liabilities
Net amount recopnized
Amounts recognized in accumulated other comprehensive
income consist of:
Net loss
Prior service cost
Subtotal
Less amount recorded as regulatory asset
(4,663) 13,335(23,571) (22,135) (3,515) (3,232)
695,093 767,692 77,773 80,515
460,862 390,081
77,801 48,61630,000 44,300(23,57t) (22,135)
s4s,092 460,862
$ (150,001) $ (306,830) $ (77,773) $ (80,515)
$ - $ - $ (3,90s)$ (3,651)
(150,001) (306,830) (73,868) (76,864)
$ (rs0,"00r) $ (306,830) $ 0737, $ (80Jrs)
$ 767,692 $ 655,439 $31,357 25,57131,830 31,489(112,215) 77,328
$ 120,587 $ 291,966 $642 989
80,515 $ 65,043
2,178
3,258
2,151
3,219
26,102 $
1,077
33,605
l,2gg
121,229 292,955 27,179 34,894
(121,229) (292,955)
FERC FORM NO.1 123.22
Name of Respondent
ldaho Power ComDanv
This Report is:
(1) X An Original(2) A Resubmission
Date of Report
(Mo, Da, Yr)
0411512014
Year/Period of Report
20131Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Net amount recogrr.ized in accumulated other comprehensive income 34,894
Accumulated benefit obligation $ 640,330 s 72,288
As a non-qualified plan, the SMSP has no plan assets. However, Idaho Power has a Rabbi tnrst designated to provide funding for
SMSP obligations. The Rabbi trust holds invesftnents in marketable securities and corporate-owned life insurance. The fair value of
these invesonents was approximately $59.2 million and $50.4 million at December 31,2013 and20l2, respectively, and is reflected in
Investrnents 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 ofassets is equal to the fair value ofthe assets.
Pension Plan SMSP
$-$ 59t^e+s
$ 27,179
$ 70,530
2013 2012 2013
Service cost
Interest cost
Expected retum on assets
Amortization of net loss
Amortization of prior service cost
$ 31,3s7 $ 2s,571 $31,830 3l,489
(3s,75s) (31,737)
I 7,1 l8
347 347
2,178 $
3,2s8
2,840
212
2,151
3,218
1,530
212
Net periodic pension cost 44,897 39,784
Adjustments due to the effects of regulation(l) (9,013) (5,860)
8,488
Netperiodicbenefitcostrecognizedforfinancialreporting$ 35,884$ 33,924$ 8,488$ 7,lll
( I ) Net periodic benefit costs for the pension plan are recogrized for financial reporting based upon the authorization of each regulatory jurisdiction in which Idaho
Power operates. Under IPUC order, income statement recognition of pension plan costs is deferred until costs are recovered through rates. See Note 3 for information
on Idaho Power's revenue sharing mechanism approved by the IPUC, which resulted in additional Idaho pension expense of$16.5 million in 2013 and $14.6 million in
2012.
The follovdng table shows the components of other comprehensive income for the plans (in thousands of dollars):
Pension Plan SMSP
2013 2012 2013 2012
Actuarial gain (loss) during the year
Reclassifi cation adjustnents for:
Amortization of net loss
Amortization of prior service cost
Adjustnent for defened tax effects
Adjustnent due to the effects ofregulation
S 154,261 $ (60,,148) $
l7,l l8
347
(67,136)
(104,590)
4,664 $ (13,335)
2,840 1,530212 212(3,017) 4,532
l4,ll4
347
17,979
28,008
Other comprehensive income recogni2ed sslated to
pension benefit plans -$- $ 4,699 $ (7,061)
In20l4,Idaho Power expects to recognize as components of net periodic benefit cost $7.2 million from amortizing amounts recorded
in accumulated other comprehersive income (or as a regulatory asset for the pension plan) as ofDecember 31,2013, relating to the
pension plan and SMSP. This amount consists of $4.0 million of amortization of net loss and $0.4 million of amortization of prior
service cost for the pension plan, and $2.6 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):
2014 2015 2016 2017 2018 2019-2023
Pension Plan
SMSP
$ 25,473 $ 27,371 $ 29,664 $ 32,133 $ 34,722 g 212,6833,996 4,186 4,213 4,549 25,514
FERC FORM NO.1 1 Page 123.23
Name of Respondent
ldaho Power Comganv
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
0411512014
Year/Period of Report
2013tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
As of December 3l,20l3,Idaho Power's minimum required contribution to the pension plan is estimated to be $1.4 million in20l4,
though Idaho Power plans to contribute at least $20 million to the pension plan during 2014.
Postretirement Benelits
Idaho Power maintains a defined benefit posEetirement 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 l, 1999 have access to the standard medical option at full cost, with no conhibution by
Idaho Power. Benefits for employees who retire after Decemb er 31, 2002 are limited to a fixed amount, which has limited the growth
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):
2013 2012
Change in accumulated benefit obligation:
Benefit obligation at January I
Seryice cost
Interest cost
Actuarial (gain) loss
Benefits paid(1)
72,547 $
1,3 15
2,633
(l 6,788)
(2,366\
66,669
1,292
3,135
3,1 90
(1,729)
Benefit obligation at December 3l 57,341 72,547
Change in plan assets:
Fair value ofplan assets at January I
Actual return on plan assets
Employer contributions( I )
Benefits paid(l)
33,387
6,212
(122)
(2,366\
31,901
3,346
(l3l)
(1,729)
Fair value of plan assets at December 3l 37,lll 33,397
Funded status at end ofyear (included in noncurrent liabilities)$ (20,230) $(39,160)
(l) Contributions and benefirc paid are each net of$3,272 thousand and $3,268 thousand ofplan participant contributions, and $372 thousand and $430 thousand of
Medicare Part D subsidy receipts for 2013 and 2012, respectively.
Amounts recogrized in accumulated other comprehensive income consist of *re following (in thousands of dollars):
2013 2012
Net loss
Prior service cost
(4,974) $
328
15,796
99
Subtotal
Less amount recognized in regulatory assets
Net amount recomized in accumulated other comprehensive income
The net periodic postretirement benefit cost was as follows (in thousands of dollars):
2013
(4,646)15,8954,646 (15,895)s -q _
2012
Service cost
Interest cost
Expected retum on plan assets
Amortization of net loss
Amortization of prior service cost
Amortization of umecogrized transition obligation
1,315 $
2,633
(2,328)
98
(22e)
1,292
3,135
(2,234)
384
(422)
2,040
Net periodic postretirement benefit cost $ 1,489 $ 4,195
FORM NO.1 123.24
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t15t2014
Year/Period of Report
2013tA4
NOTES TO FINANCIAL STATEMENTS (Continued)
The following table shows the components of other comprehensive income for the plan (in thousands of dollars):
2013 2012
Actuarial gain (loss) during the year
Prior service cost arising during the year
Reclassifi cation adjustrnents for:
Amortization of net loss
Amortization ofprior service cost
Amortization of unrecognized transition obligation
Adjustnent for deferred tax effects
Adjustnent due to the effects of regulation
20,673 $
98
(22e)
(8,03 l)
(t2,stt)
(2,09
384
(422)
2,040
(ls3)
219
Other comprehensive income related to postretirement benefit plans -$
It20l4,Idaho Power expects to recognize as a component of net periodic benefit cost $0.2 million from amortizing amounts recorded
in accumulated other comprehensive income as of December 31,2013, relating to the postretirement benefit plan. The entire amount
represents $0.2 million of amortization ofprior service cost.
Medicare Acl.' 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 ofdollars):
201s 2016 2017 2018 2019-2023
Expected benefit payments
Expected Medicare Part D subsidy receipts
3,890 $
430
4,000
470
$ 4,070
510
4,170 $
600
21,290
3,820
$ 4,130 $
550
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
PostretirementSMSP Benelits
Discount rate
Rate of compensation increase(l)
Medical trend rate
Dental trend rate
Measurement date
5.20% 4.20% 5.r0%
4.38% 4.35% 4.s0%
t2/3y2013 t2/3112012 t2l3y20t3
2013 2012 2013 2012 2013 2012
4.15o/o s.t5% 4.20%
4.50%
6.8% 65%s.0% 5.0%
t2/3l/2012 t2l3v20t3 t2l3v20t2
(l) tre ZO t t rate of compensation increase assumption for the pension plan includes an inflation component of 2.75%o plus a 1.63% composite merit increase
componentthatisbasedonemployees'yearsofservice. MeritsalaryincreasesareassumedtobeS.0%foremployeesintheirfirstyearofserviceandscaledownto
in their fortieth year ofservice and beyond.
Name of Respondent
ldaho Power Companv
This Report is:
(1) X An OriginalQ) A Resubmission
Date of Report
(Mo, Da, Yr)
0411512014
Year/Period of Report
2013tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
The following table sets forth the weighted-average assumptions used to determine net periodic benefit cost for all Idaho
Power-sponsored pension and postretirement benefit plans:
Postretirement
Pension Plan SMSP Benefits2013 2012 2013 2012 2013 2012
Discount rate
Expected long-term rate ofreturn onassets 7.75% 7.75% 7.25% 7.25%
Rate of compensation increase 4.38% 4.35% 4.50% 4.50%
4.20% 4.90% 4.ts% 5.10% 4.20% 5.05%
6.8% 65%
5.0% 5.0%
Medical trend rate
Dental trend rate
The assumed health care cost trend rate used to measure the expected cost of health benefits covered by the postretirement plan was
6.8 percent in 2013 and is assumed to decrease gradually to 5.0 percent by 2097. The assumed dental cost trend rate used to measrue
the expected cost ofdental 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 31,2013 (in thousands of dollars):
One-Percentage-Point
Increase Decrease
Effect on total of cost components
Effect on accumulated postretirement benefit obligation
$ 374 $ (273)3,139 (2,415)
Plan Assets
Pension Asset Allocation Policy: The target allocation and actual allocations at December 31,2013 for the pension asset portfolio by
asset class is set forth below.
Actual
Allocation
Target Allocation December 31,
Asset Class 2013
Debt securities
Equity securities
Real estate
Other plan assets
24% 20%54% s7%6% s%t6% t8%
Total t00% t00%
Assets are rebalanced as necessary to keep the portfolio close to target allocations.
The plan's principal inveshent objective is to maximize total retum (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:
o determine if the investuents have the potential to earn the rate of retum assumed in the actuarial liability calculations;o 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
instnrments (equities, real estate, venhre capital) to fund the longer{erm liabilities of the plan; and
FERC FORM NO.1 123.26
Name of Respondent
ldaho Power Companv
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
04115120',t4
Year/Period of Report
2013tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
o maintain a prudent risk profile consistent with ERISA fiduciary standards.
Allowable plan investnents include stocks and stock funds, investnent-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, invesfrnents must be readily
marketable so that an entire holding can be disposed of quickly with only a minor effect upon market price.
Rate-of-return projections for plan assets are based on historical risk/retum relationships among asset classes. The primary measure is
the historical risk premium each asset class has delivered versus the return on l0-year U.S. Treasury Notes. This historical risk
premium is then added to the current leld on l0-year U.S. Treasury Notes. Additional analysis is performed to measure the expected
range of retums, 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 retums to measure the portfolio's exposure to a "worst-case"
market scenario, to determine how much perfonnance could vary from the expected "average" performance over various time periods.
This "worst-case" modeling, in addition to cash flow matshing and diversification by asset class and investuent style, provides the
basis for managing the risk associated with investing porrfolio assets. There were no transfers between levels or material changes in
valuation techniques or inputs during the years ended December 31,2013 and2012.
Fair Yalue of Plan Asseh: Idaho Power classifies its pension plan and postretirement benefit plan invesfinents using the three-level
fair value hierarchy described in Note 15. The foUowing table presents the fair value of the plans' invesfinents 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 sipificant to the fair value measurement of the security.
Level 1 Level 2 Level3 Total
Assets at December 31,2013
Pension olan assets:'f'
Cash and caSt equivalents
Short-termbonds
Long-term bonds
Equity Securities: Large-Cap
Equity Securities: Mid-Cap
Equrry Securities: Small-Cap
Equity Securities: Micro-Cap
Equrty Securities: Intemational
Equrty Securities: Emerging Markets
Equity Securities: Market Neutral
Real estate
Private market invesbnents
Commodities funds
33,030
71,042
23,346
48,998
24,687
19,128
3,523
3,870
$ -$ -$ 33,03011,068 11,06895,336 95,336
71,04223,112 46,458
48,998
22,107 25,630
3,87028,019 28,01933,709 33,709
29,209
-
29,209
$ 255,740 $ 61,728 $ 545,092Total pension assets $ 227,624
Postretirement plan assets(l)75 $ 37,036 $s 37,111
Assets at December 31,2012
Pension plan assets:
Cash and cash equivalents
Short-term bonds
Long-term bonds
Equity Securities: Large-Cap
Equrty Securities: Mid-Cap
7,628 $
57,526
19,944
-$12,373
96,671
16,780
-$7,628
12,373
96,671
57,526
36,724
FERC FORM NO. 1 123.27
Name of Respondent
ldaho Power Companv
This Report is:
(1) X An OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
0411512014
Year/Period of Report
2013lA4
NOTES TO FINANCIAL STATEMENTS (Continued)
Equrty Securities : Small-Cap
Equity Securities: Micro-Cap
Equity Securities: International
Equity Securities: Emerging Markets
Equity Securities: Market Neutral
Real estate
Private market investnents
Commodities funds
36,409
19,923
19,461
3,101
7,675
59,l;
21,370
27,874
30,507
36,409
19,923
78,603
24,471
7,675
27,874
30,507
Total pension assets $ 173,087 $ 229,394 $ 58,381 $ 460,862
Postretirement plan asssls(l)325 $ 33,062 $- $ 33,387
( I ) The postretirement benefits assets are primarily life insurance contracts.
The following table presents a reconciliation of the begirming and ending balances of the fair value measurements using significant
unobservable inputs (kvel 3):
Private
Equity
(s40)
30,507
2,941
89
25,119 $
742
1,271
742
52,905
837
2,658
2,521
(540)
Real
Estate Total
Beginning balance - January 1,2012
Realized gains
Unrealized gains
Purchases
Sales
$ 27,786 $
95
1,387
1,779
Ending balance - December 31,2012
Realized gains
Unrealized gains
Purchases
Sales
Settlements 172
27,874
739
1,579
4,726
(6,899)
58,381
739
4,520
4,815
(6,899)
172
Ending balance - December 31,2013 33,709 $28,019 $61,728
Fair Value Measurement of Level 2 and Level 3 Plan Asset Inpu8:
Level 2 Bonds. Equity Securities. and Level 2 Commodities: These investnents represent U.S. govemment and agency bouds,
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. goverrunent 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 investnents
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
conrmingled fund divided by the number of fund shares outstanding.
Level 2 Postretirement Assets: These assets represent an investnent in a life insurance contact 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 contrachrally equal to the
insurance contact's proportionate share ofthe market value ofan associated invesftnent account held by the insurer. The investments
held by the insurer's investnent account are all instnrments traded on exchanges with readily determinable market prices.
Level 3 Real Estate: Real estate holdings represent invesbnents 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
FERC FORM NO.1 1 123.28
Name of Respondent
ldaho Power Companv
This Report is:
(1) X An Originale) A Resubmission
Date of Report
(Mo, Da, Yr)
0411512014
Year/Period of Report
20131Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
property ronts 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 Investnents: Private market investnents 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 flrnd strategies utilize securities with readily available market prices, while others utilize less
liquid investnent vehicles that are valued based on unobservable inputs including cost, operating results, recent funding activity, or
comparisons with similar investrnent vehicles. Venture capital fund investments are valued by the fund company based on estimated
fair value of the underlying fund holdings divided by the firnd shares outstanding. Some venture capital investments have progressed
to the poi* that they have readily available exchange-based market valuations. Early stage venture invesftnents 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 investrnents furnish annual audited financial statements that are also used to further validate
the inforrration 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 Intemal Revenue Code and that covers
substantially all employees. Idaho Power matches specified percentages of employee contributions to the plan. Matching annual
conkibutions were $7 million in both 2013 and20l2.
Post-employment Benefi ts
Idaho Power provides certain benefits to former or inactive employees, their beneficiaries, and covered dependents after emplolment
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,
2013 and20l2 are $1.9 million and $2.6 million, respectively.
11. PROPERTY, PLAIIT AND EQUIPMENT AtiD JOINTLY-OWIIED 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 20 I 3 ard 2012 (in thousands of
dollars):
2013 2012
Production
Transmission
Diskibution
General and Other
5 2,272,381
974,697
1,459,666
373,658
2.47% $ 2,217,3342.01% 931,403
2.72% 1,411,740
591% 355,29s
Avg Rate
2.360/o
2.02%
2.89%
6A7%
Balance Avg Rate Balance
Total in service
Accumulated provision for depreciation
5,ogo,4o2
(1,940,654)
2.69% 4,915,772
(1,871,810)
In service - net $ 3,139,748 $ 3,043,962
2.7s%
FERC FORM NO.1 1 123.29
Name of Respondent
ldaho Power Comoanv
This Report is:
(1) X An Originalel A Resubmission
Date of Report
(Mo, Da, Yr)
0411512014
Year/Period of Report
2013tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Idaho Power's ownership interest in three jointly-owned generating facilities is included in the table above. Under the joint operating
agreements for these facilities, each participating utility is responsible for financing its share of construction, operating, and leasing
costs. Idaho Power's proportionate share of operating expenses are included in the Consolidated Statements of Income. These
jointly-owned facilities, including balance sheet amounts and the extent of Idaho Power's participation, were as follows at December
31,2013 (in thousands ofdollars):
Utility Construction Accumulated
Plant in Work in Provision for Ownership
Name of Plant Location Service Progress Depreciation o Mw(1)
JimBridgerUnits 14
Boardman
ValmyUnits I and2
Rock Springs, WY $ 560,868
Boardman, OR 79,963
Winnemucca, NV 358,985 21,060 195,016
$ 12,151 $
2,846
284,683
59,806
33
l0
50
771
64
284
(1) Idaho Power's share of nameplate capacity.
IERCo, Idaho Power's wholly-owned subsidiary, is a joint venturer in BCC. Idaho Power's coal purchases from the joint venture were
$79 million and $75 million :rr,2013 atd20l2, respectively.
Idaho Power has contracts to purchase the energy from four PURPA qualified facilities that are 50 percent owned by Ida-West. Idaho
Power's power purchases from these facilities were $9 million each year from20l2 to 2013.
12. ASSET RETIREMENT OBLIGATIONS (ARO)
The guidance relating to accounting for AROs requires that legal obligations associated with the retirement of properly, 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 tle 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 ofthe related asset. If at the end ofthe asset's life, the recorded liability differs
from the actual obligations paid, a gain or loss would be recogrized. As a rate-regulated entity, Idaho Power records regulatory assets
or liabilities instead ofaccretion, depreciation, and gains or losses, as approved by the IPUC. The regulatory assets recorded under
this order do not eam a return on investnent. Beginning June l, 2Ol2,accretion, depreciation, and gains or losses related to the
Boardman generating facility have been exempted from such regulatory treatnent 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 2013, changes in estimates at its
distribution facilities and at the coal-fired generation facilities resulted in a net increase of $2.7 million in the recorded AROs. The
primary cause of the increase in the AROs in 2013 is an increased ARO for an evaporation pond at the Jim Bridger generating facility
due to the identification of additional costs required to decommission the pond.
Idaho Power also has additional AROs associated with its transmission system, hydroeleckic 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 regulated operations of Idaho Power also collect removal costs in rates for certain assets that do not have associated AROs. Idaho
Power is required to redesignate these removal costs as regulatory liabilities. See Note 3 for the removal costs recorded as regulatory
liabilities on Idaho Power's consolidated balance sheet as of December 31,2013 and20l2.
The following table presents the changes in the carrying amount of AROs (in thousands of dollars):
2013 2012
Balance at beginning ofyear 22,982 $
1,041
21,367
984Accretion e
Name of Respondent
ldaho Power Companv
This Report is:
(1) X An OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
04115t2014
Year/Period of Report
2013tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Revisions in estimated cash flows
Liability settled
2,722 1,416(e80) (785)
$ 25,765 $ 22,982
2072
Balance at end ofyear
13. INVESTMENTS
The table below summarizes Idaho Power's invesftnents as of December 3l (in thousands of dollars).
2013
Idaho Power investnents:
Available-for-sale equity securities
Executive deferred compensation plan investnents
Other investnents
s 4l,l 19
1,153
I
31,913
2,4'.78
2
Total Idaho Power investnents 42,273 $34,393
Investments in Equity Securities
Invesfrnents in securities classified as available-for-sale securities are reported at fair value, using either specific identification or
average cost to determine the cost for computing gains or losses. Any unrealized gains or losses on available-for-sale securities are
included in other comprehensive income.
The table below summarizes investnents in equity securities as of December 31,2013 and December 31,2012 (in thousands of
dollars).
December 31. 2013 December 31. 2012
Gross
Unrealized
Gain
Gross
Unrealized
Loss
Fair
Value
Gross
Unrealized
Gain
Gross
Unrealized
Loss
Fair
Value
Available-for-sale securities -$-$4l,l l9 $6,792 S -$31,913
The following table summarizes sales of available-for-sale securities (in thousands of dollars):
2013 2012
Proceeds from sales
Gross realized gains from sales
Gross realized losses from sales
25,66t $
11,637
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 31,2013 and December 31,2012, no securities were in
an unrealized loss position.
14. DERTVATTVE FINANCIAL INSTRT'MENTS
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 commitrnents, 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 reseryes to ensure reliability, and make economic use of temporary surpluses that may
develop.
FERC FORM NO.1 123.31
Name of Respondent
ldaho Power ComDanv
This Report is:
(1) X An OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
04t15t2014
Year/Period of Report
2013tA4
NOTES TO FINANCIAL STATEMENTS (Continued)
All of Idaho Power's derivative instruments have been entered into for the purpose of economically hedging forecasted purchases and
sales, though none ofthese inskuments have been desigrated as cash flow hedges under derivative accounting guidance. Idaho Power
offsets fair value amounts recognized on its balance sheet and applies collateral related to derivative instruments executed with the
same counterparly under the same master netting agreement. Idaho Power does not offset a counterparty's current derivative contacts
with the counterparty's long-term derivative contracts, although Idaho Powet'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 arraugements would
allow for the offsetting of all fransactions 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 forrns ofnon-cash collateral (such as letters ofcredit). These types oftransactions 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 desigrated as hedging instruments for the years ended December 31,
2013 and2012 (nthousands of dollars).
Location of Gain(Loss) on Derivatives Recognized in Income
Gain/(Loss) on Derivatives Recognized in
Income(1)
2013 2012
Financial swaps
Financial swaps
Financial swaps
Financial swaps
Forward contracts
Forward confracts
Forward contracts
Off-system sales
Purchased power
Fuel expense
Other operations and maintenance
O$system sales
Purchased power
(2,637)
947
731
35
185
(le6)
15,104
(6,280)
(6,359)
QY
Fuelexpense 217 (1,755)
( I ) b<cludes umealized gains or losses derivatives, which are recorded on the balance sheet as regulatory assets or regulatory liabilities.
Settlement gaius and losses on electricity swap contracts are recorded on the income statement in offisystem 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 inforrration concenring the determination of fair value for Idaho Power's assets and
liabilities from price risk management activities.
Derivative Instruments Summary
The tables below presents the fair values and locations of derivative instruments not designated as hedging instruments recorded on the
balance sheets and reconciles the gross amounts of derivatives recogrized as assets and as liabilities to the net amounts presented in the
balance sheets at December 31,2013 and2072 (in thousands of dollars).
Asset Derivatives Liability Derivatives
Balance Sheet
Location
GrossFair Amounts
Value Offset
GrossNet Fair Amounts Net
Assets Value Offset Liabilities
December 3lr20l3
Current:
Financial swaps
Financial swaps
Forward contracts
Forward contracts
Long-terrn:
Financial swaps
Forward contracts
Other current assets $
Other current liabilities
Other current assets
Other curent liabilities
Other assets
Other assets
1,451
373
109
189
t26
$ (l7s)
(373)
(28)
$ 1,276 $
109
t7s $ (17s) $1,975 (1,429) <tt
26
s46
161 28 (28)
126
26
FERC FORM NO.1 123.32
Name of Respondent
ldaho Power Companv
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
0411512014
Year/Period of Report
2U3lA4
NOTES TO FINANCIAL STATEMENTS (Continued)
Total $ 2,248 $ (576) $ 1,672 S 2,204 $ (1,632)572
December 31,2012
Current:
Financial swaps
Financial swaps
Forward contracts
Forward contracts
Long-term:
Financial swaps
Forward contracts
Other current assets
Other current liabilities
Other current assets
Other current liabilities
Other assets
Other assets
$ 5,122 $ (1,683) rtt $320 (320)
_lss (4)
96
189
3,439 $ 978- 1,372151 4-)
$ (e78)
(3 le)
(4)
$-
1,053
2
96
189
Total $ s,882 $ (2,007) $ 3,87s $ 2,3s6 $ (1,301) $ 1,0ss
(l)Cunentliabilityandcurrentassetderivativeamountsoffsetinclude$1.1 millionand$0.Tmillionofcollateralreceivableandpayablefortheperiodsending
December 3 l, 2013 and 2012, respectively.
The table below presents the volumes of derivative commodity forward contracts and swaps outstanding at December 3 I , 201 3 and
2012 (nthousands of units).
Pssg!'Eg!!--
Commodity Units 2013 2012
Electricity purchases
Electricity sales
Natural gas purchases
Natural gas sales
Diesel purchases
MWh
MWh
MMBtU
MMBtU
Gallons
89
603
10,804
555
906
40s
1,374
13,477
3,933
834
Credit Risk
At December 3l,2013,Idaho Power did not have material credit risk exposure from financial instruments, including derivatives.
Idaho Power monitors credit risk exposure through reviews ofcounterparty credit quality, corporate-wide counterparty credit exposure,
and corporate-wide counterparty concentration levels. Idaho Power managcs these risks by establishing appropriate credit and
concentration limits on transactions with counterparties and requiring contractual guarantees, cash deposits, or letters of credit from
counterparties or their affiliates, as deemed necessary. Idaho Power's physical power contracts are commonly under Westem 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 ifa counterparty has debt that is downgraded below investnent grade by at least one
rating agency.
Credit-Contingent tr'eatures
Certain of Idaho Power's derivative instruments contain provisions ttrat require Idaho Power's unsecured debt to maintain an
investrnent grade credit rating from Moody's Investors Service and Standard & Poofs Ratings Services. If Idaho Power's unsecured
debt were to fall below investuent 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
inskuments in net liability positions. The aggregate fair value of all derivative instruments with credit-risk-related contingent features
ttrat were in a liability position at December 31,2013, was $2.1 million. Idaho Power posted $4.1 million cash collateral related to this
amount. If the credit-risk-related contingent features underlying these agreements were triggered on December 3l,zDl3,Idaho Power
would have been required to post $10.0 million of cash collateral to its counterparties.
15. FAIR VALUE MEASTJREMENTS
FERC FORM NO.1 123.33
Name of Respondent
ldaho Power Comoanv
This Report is:
(1) X An OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
04t1512014
Year/Period of Report
2013tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Idaho Power has categorized thet 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:
. lrvel 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 the significance of a particular input to the fair value measurement requires judgment. The use of
different market assumptious and/or estimation methodologies may have a material effect on the estimated fair value of assets and
liabilities and their placement within the fair value hierarchy. An item recorded at fair value is reclassified between 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
categoized. There were no transfers between levels or material changes in valuation techniques or inputs during the years ended
December 31, 2013 ard 2012.
The table below presents inforrration about Idaho Power's assets and liabilities measured at fair value on a recurring basis as of
December 31,2013 and2012 (in thousands of dollars).
December 31, 2013 December 31, 2012
Level I Level 2 Level 3 Total Level I Level 2 Level 3
Assets:
Derivatives
Money market funds
Trading securities: Equity securities
Available-for-sale securities: Equity securities
Liabilltles:
Derivatives
$ 1,437
100
1,153
4t,lt9
s46 $
23s $
26$
$-$ t,672 $ 2,201 $ 1,674
100 100
1,153 2,478
4t,rt9 3l,913
$ 3,87s
100
2,478
31,913
$ 1,055-$ s72$ -$1,055$
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) wittt quoted prices in an active market. Natural gas and diesel derivative valuations are
perforrned using New York Mercantile Exchange G.[[N4EX) and ICE pricing, adjusted for location basis, which are also quoted under
NYMEX and ICE pricing. Trading securities consist of employee-directed investnents 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
FORM NO.1 1 Page 123.34
Name of Respondent
ldaho Power Company
This Report is:
(1) X An OriginalQ) A Resubmission
Date of Report
(Mo, Da, Yr)
o411512014
Year/Period of Report
2013/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
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 31,2013 and20l2, using available market information and appropriate valuation methodologies.
December 31. 2013 December 31,.2012
Liabilities:
Long-term debt(l)
Carrying Estimated Carrying Estimated
Amount Fair Value Amount Fair Value
(thousands of dollars)
$ 1,616,322 $ l,600,24g $ 1,537,696 $ 1,819,213
( I ) tong-term debt is categorizd as trvel 2 of the fair value hierarchy, as defined earlier in this Note I 5.
Long-term debt is not traded on an exchange and is valued using quoted rates for similar debt in active markets. Cash and cash
equivalents, deposits, customor and other receivables, notes payable, accounts payable, interest accrued, and taxes accrued are reported
at their carrying value as these are a reasonable estimate of their fair value. The estimated fair values for long-term debt are based
upon quoted market prices of similar issues or the same issues in an inactive market.
16. CHANGES IN ACCTJMT]LATED 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 31,2013 ard20l2 (in thousands of dollars). Items in parentheses indicate reductions to
AOCI.
Unrealized Gains and Defined Benefit
Losses on
Available-for-Sale
Securities Pension Items Total
December 31, 2013
Balance at beginning of period 4,136 $(21,252) $(17,1 l6)
Other comprehensive income before reclassifications
Amounts reclassified out of AOCI
2,951
(7,087)
2,840
1,859
5,791
(5,228)
Net current-period other comprehensive income
Balance at end of period
(4,136)4,699 563
$ (16,553) $(16,553)
December 31,2012
Balance at beginning ofperiod 2,569 $(14,191) $ (11,622)
Other comprehensive income before reclassifications
Amounts reclassified out of AOCI
1,567 (8,122)
1,061
(6,555)
1,061
Net current-period other comprehensive income 1,567 (7,061)(5,494)
Balance at end ofperiod 4,136 $(21,2s2) $(17,1 l6)
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, 2013 and 2012 (in thousands of dollars). Items in parentheses indicate increases to
net income.
Amount Reclassified from
AOCI
Year Ended I)ecember 31,
2013
(11,637) q
2012
Unrealized gains on available-for-sale securities
Realized gain on sale ofsecurities(l)
FERC FORM NO. 1 Page 123.35
Name of Respondent
ldaho Power Company
This Report is:
(1) X An OriginalQ) A Resubmission
Date of Report
(Mo, Da, Yr)
0411512014
Year/Period of Report
2013tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Total before tax
Tax benefit(2)
(|t,637)
4,550
Net of tax
Amortization of defined benefit pension items(3)
Prior service cost
Net loss
(7,087)
2t2 2t22,839 1,530
3,051 1,742
(1,192) (681)
1,859 1,061
(5,228) $1,061
Total before tax
Tax benefit(2)
Net of tax
Total reclassification for the period
(l) The realized gain is included in Idaho Power's consolidated income statements in other income (expense), net.
(2) The tax benefit is included in income tax expense (benefit) in the consolidated income statements ofldaho Power.
(3) Amortization ofthese iterns is included in Idaho Poweds consolidated income statements in other expeirse, net.
17. RELATED PARTY TRANSACTIONS
IDACORP: Idaho Powerperforms corporate functions such as frnancial, legal, and managoment services for IDACORP and its
subsidiaries. Idaho Power charges IDACORP for the costs of these services based on service agreements and other specifically
identifiedcosts. FortheseservicesldahoPowerbilledIDACORP$l.0millionul.20l3and$0.8millionin2012.
Ids-West: Idaho Power purchases all of the power generated by four of Ida-West's hydroelectic projects located in Idaho. Idaho
Power paid $9 million to Ida-West in 2013 and 2012.
FERC FORM NO. 1 (ED.123.36
Name ot Kesponoent
ldaho Power Company
This Reoort ls:(1) 5]An Orisinat(2) nA Resubmission
Date of Reoort(Mo, Da, Yi)
04115t2014
Year/Period of Report
End of 20131Q4
S I AI EMENTS OF AGCUMULATED COMPREHENSIVE NCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
1. Report in columns (b),(c),(d) and (e) the amounts of accumulated other comprehensive income items, on a net-of-tax basis, where appropriate.
2. Report in columns (f) and (g) the amounts of other categories of other cash ffow hedges.
3. For each category of hedges that have been accounted for as "fair value hedges", report the ac@unts affected and the related amounts in a footnote.
4. Report data on a year-to-date basis.
Jn€
No.
Item
(a)
Unrealized Gains and
Losses on Available-
for-Sale Securities
(b)
Minimum Pension
Liability adjustment
(net amount)
(c)
Foreign Currency
Hedges
(d)
Other
Adjustments
(e)
1 Balance of Account 2'19 at Beginning of
Preceding Year 2,569,291 ( 14,191,343)
2 Preceding QtrfYr to Date Reclassifications
from Acct 219 to Net lncome 1,060,888
Preceding QuarterfYear to Date Changes in
Fair Value 1,567,262 ( 8,121,767)
Totral (lines 2 and 3)'1,567,262 ( 7,060,87e)
Balance of Account 21 9 at End of
Preceding Quarter/Year 4,136,553 ( 21,252,2221
Balance of Account 21 9 at Beginning of
Cunent Year 4,136,s53 ( 21,252,222',)
Cunent Qtrf/r to Date Reclassifications
from Acct 219 to Net lncome ( 7,087,026)1,858,601
Current QuarterfYear to Date Changes in
Fair Value 2,950,473 2,840,246
Total (lines 7 and 8)( 4,136,553)4,698,847
1C Balance of Account 21 9 at End of Cunent
QuarterA'ear ( 16,553,37s)
FERG FORM NO. I (NEW 06.02)Page 122a
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 51en orisinat(2) nA Resubmission
Date of Reoort(Mo, Da, Yi)
o4115120'.14
Year/Period of Report
End of 20131Q4
l' t A l EMEN t ti Ut- AUUUMULA t EU ULTMTKETItrNsTVE TNU(,ME, UUMT"KEHENS|VE tNUUMts,, ANU HEUQiTNU AU ilVt ilEs
-tne
No.
Other Cash Flow
Hedges
lnterest Rate Swaps
(0
Other Cash Flow
Hedges
[Specifo]
(s)
Totals for each
category of items
recorded in
Account 219
(h)
Net lncome (Carried
Fonrard from
Page 117 , Line 78)
(i)
Total
Comprehensive
lncome
(i)
1 ( 11,622,Os2)
2 1,060,888
3 ( 6,554,505)
4 ( 5,493,617)168,168.039 162,674,422
5 ( 17,115,669)
€( 17,11s,669)
( 5,228,425)
5,790,719
562,294 176,741,143 177,303,437
1(( 16,s53,375)
FERC FORM NO. I (NEW 06-02)Pase 122b
r\ame or l(esponoenl
ldaho Power Company
I Ilts Kguult t5:(1) 5.1en originat
(21 llA Resubmission
uate (Jr Nepurr I lEarrreiluu (Jt [ep(Jil,(Mo, Da, Yi) I ena or 2o13te4
o4t15t2014
SUMMAT{Y O]. U I ILI I Y PLAN I ANL' ACL;UMULAIE,L' PTIOVISIUNS
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
leport in Column (c) Ure amount for electric function, in column (d) the amount for gas function, in column (e), (f), and (g) report other (specifo) and in
:olumn (h) @mmon function.
Line
No.
Classification
(a)
Total Company for the
Cunent Year/Quarter Ended
(b)
Electric
(c)
1 Utility Plant
2 ln Service
3 Plant in Service (Classified)5,080,401,79!5,080,401,79(
4 Property Under Capital Leases
5 Plant Purchased or Sold
6 Completed Construction not Classifi ed
7 Experimental Plant Unclassified
8 Total (3 thru 7)5,080,401,79S 5,080,401,79(
I Leased to Olhers
10 Held for Future Use 7.090.431 7,090,43'
11 Construction Work in Progress 327,000,03t 327,000.03{
12 Acquisi0on Adjustments
13 Total Utility Plant (8 thru 12)5.414.492.26t s,414,492,26t
14 Accum Prov for Depr, Amort, & Depl 1,940,654,182 1,940,654,'t8i
15 Net Utility Plant (13less 14)3,473,838,08t 3,473,838,08(
16 Detail of Accum Prov for Depr, Amort & Depl
17 ln SeMce:
18 Depreciation 1.919.582,91C 1,919,582,9'l(
19 Amort & Depl of Producing Nat Gas Land/Land Right
20 Amort of Underground Storage Land/Land Rights
21 Amort of Other Utility Plant 2'.t,071,272 2',t,071,271
22 Total ln SeMce (18 thru 21)1,9,rc,654,182 1,940,654,18i
23 Leased to Others
24 Depreciation
25 Amortization and Depletion
26 Total Leased to Others (24 &25)
27 Held for Future Use
28 Depreciation
29 Amortization
30 Total Held for Future Use (28 & 29)
31 Abandonment of Leases (Natural Gas)
32 Amort of Plant Acquisition AdJ
33 Total Acqrm Prcv (equals 14) (22,26,30,31,32)1,940,654,182 1.940,654,r8'
FERC FORM NO. r (ED. 12-89)Pago 200
Name of Respondent
ldaho Power Gompany
This Reoort ls:(1) fiAn Original(2) nA Resubmission
uate ot Keoon
(Mo, Da, Yi)
04115t2014
YearPenoo oI Kepon
End of 20131Q4
ELECTRIC PLANT lN SERVICE (Account 101 , 102, 103 and 106)
1. Report below the original cost of electric plant in service according to the presoibed accounts.
2. ln 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. lnclude in column (c) or (d), as appropriate, corrections of additions and retirements for the cunent 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 he account for accumulated depreciation provision. lnclude also in column (d)
-tne
No.
Ac@unt
(a)
traranceBeginning of Year
(b)
AOOTUOnS
(c)
1 l,INTANGIBLE PLANT
2 (301) Organization 5,703
3 (302) Franchises and Consenb 28.932.48t 566.78€
4 (303) Miscellaneous lntanoible Plant 31.251.01(10.240.022
5 TOTAL lntanoible Plant (Enter Total of lines 2. 3. and 4)60.189.19(10.806.81(
6 2. PRODUCTION PLANT
7 A. Steam Production Plant
I 131 0) Land and Land Riohts 1,707.10(
I 311) Strucfures and lmprovements 147.710.02i 4.482.42a
10 [312) Boiler Plant Equipment 563.349.92t 18,599,13'
11 (313) Enoines and Enoine.Driven Generators
12 (314) Turbooenerator Units 147.772.00t 16.539.67i
13 (31 5) Accessory Electric Equipment 68.199.80t 1.358.42i
14 (316) Misc. Power Plant Equipment 15.717,771 't-329.221
15 (317) Asset Retirement Costs for Steam Production 10.213.514 -167.701
16 TOTAL Steam Production Plant (Enter Total of lines 8 thru 15)9s4.670.15t 42j41.'.t6i
17 B. Nudear Production Plant
18 (320) Land and Land Riqhts
19 (321) Strucfures and lmorovements
20 (322) Reactor Plant Eouioment
21 (323) Turboqenerator Units
22 (324) Accessorv Electric Equipment
23 (325) Misc. Power Plant Eouioment
24 (326) Asset Retirement Costs for Nuclear Production
25 TOTAL Nuclear Produc{ion Plant (Enter Totral of lines 18 thru 24)
26 C. Hydraulic Production Plant
27 (330) Land and Land Riohts 30.842.281 79.141
28 [331) Strucfures and lmDrovements '157 .517.78C 14.815.57r
29 [332) Reservoirs, Dams, and Watenvays 253.144.302 107.09i
30 1333) Water \Mreels. Turbines. and Generators 200,843.534 1.098.35(
31 t334) Accessorv Elechic Eouioment 46.647.411 5.819.53(
32 [335) Misc. Power PLant Equipment 20.291.55S 747.601
33 t336) Roads. Railroads. and Bridqes 8.1 17.613 103,58(
34 t337) Asset Retirement Costs for Hvdraulic Production
35 TOTAL Hydraullc Production Plant (Enter Total of lines 27 thru 34)717.404.48e 22.770.892
36 D. Other Poduction Plant
37 1340) Land and Land Riohts 2,690,00t
38 [341) Structures and lmprovements 133.026.01i 727.92(
39 t342) Fuel Holders. Products. and Accessories 7.987.89€-5,87(
40 1343) Prime Movers 226,810,69t 9,928.61i
41 f344) Generators 73.447.494 -93.97(
42 [345) Accessory Electic Equipment 95.558.34t 1'.12.842
43 1346) Misc. Power Plant Equipment 5.738.614 100,85t
44 34il Asset Retirement Costs for Other Production
45 IOTAL Other Prod. Plant (Enter Total of lines 37 thru 44)545.259.07(10.770.39(
46 TOTAL Prod. Plant (Enter Total of lines 16. 25. 35, and 45)2.217.333.7',!4 75.682.45!
FERC FORM NO. 1 (REV. r2-os)Page 204
Name of Respondent
ldaho Power Company
tnrs KeDon ts:(1) 5]An originat(2) nA Resubmission
Date of ReDort
(Mo, Da, Yi)
o411512014
YearPenoo or Hepon
End of 20131Q4
ELECTRIC PLANT lN 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. lnclude 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 adjustmenb, etc., and show in column (f) only the offset to the debits or credits distributed in column (f) to primary
account classifi cations.
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 1 02, state the property purchased or sold, name of vendor or purchase,
and date of transaction. lf proposed journal entries have been filed with he Commission as required by the Uniform System of Accounts, give also date
Retirements
(d)
Adjustments
(e)
Transfers
(0
Balance at
End plfear
Llne
No.
5.703 2
6,391 29,492,883 3
9.489.42(32,001.618 4
9.495.811 61.500.204 5
1.707.'t0s 8
4.584.702 147.607.74t I
7.263.671 574.685.38€'t0
11
7 .181.677 157.130.004 12
31,703 69,526,524 13
622,615 16.424.38C 14
10.045.80€15
19.684.370 977.126.955 16
18
19
20
21
22
23
24
25
30,921,432 27
312,242 172.021.11C 28
29.63i 253.221.758 29
261.012 201.680.871 30
175,33t 52.291.611 31
40.33i 5.462 21.004.289 32
37.767 8.183.435 33
34
856,334 5,4d2 739.324.506 35
2.690.00€37
133.753.938 38
7.982.028 39
99.723 236.639.588 40
73,353,524 41
95,671,19C 42
5.839.469 43
44
99.723 555.929.743 45
20.640.427 5,462 2.272.381.204 46
FERC FORM NO. I (REV.12-05)Page 205
Name of Respondent
ldaho Power Company
This Reoort ls:(1) $An Original(2) -lA Resubmission
uate or Keoon(Mo, Da, Yi)
o4115t2014
Yeaflrenoo or Kepon
End of 20131Q4
trLtrUrKrU rLANr rN 5EKVIUE (AC@Unt 1Ulr lUZt lUJ ano 1UO) (L;OntnUeO,|
-tne
No.
ACCOUnI
(a)
tsalanceBeginning of Year
(b)
Additlons
(c)
47 3. TMNSMISSION PLANT
48 (350) Land and Land Riohts 35,576,16'51 1,56t
49 (352) Structures and lmprovements 70,136.891 23.51r
50 (353) Station Eouioment 365.354.96i 25.O33.24i
51 (354) Towers and Fixtures 155,095,72t 6.908,88(
52 t355) Poles and Fixtures 120.356.58'l 9.126.771
53 (356) Overhead Conductors and Devices 184.492.O14 3.912.96t
54 1357) Underoround Conduit
55 (358) Underqround Conductors and Devices
56 (359) Roads and Trails 390.26€
57 (359.1) Asset Retirement Costs for Transmission Plant
58 TOTAL Transmission Plant (Enter ToEl of lines 48 thru 57)931.402.602 4s.516.95t
59 4. DISTRIBUTION PLANT
60 (360) Land and Land Riohts 4.775.243 93,25(
61 (361) Strucfures and lmprovements 31.354.167 1.497.00t
62 (362) Station Eouipment 189.664.902 7.531.45(
63 (363) Storase Baftery Equipment
M (364) Poles. Towers, and Fixtures 230.356.00€6.383.56r
65 (365) Overhead Conduc{ors and Devices 124.012.452 3.461.59t
66 (366) Underoround Conduit 46,833,883 -430,20t
67 (367) Underoround Conductors and Devices 197.732.139 10,432,42t
68 (368) Line Transformers 451.211 .644 25.491.01!
69 (369) Services 56.853.354 301.23t
70 (370) Meters 70.932,527 2.819,89r
71 t371) lnstallatlons on Cusbmer Premises 2,865.154 1 10,862
72 (372) Leased Prooertv on Customer Premises
73 (373) Street Liohtino and Sional Svstems 4,505,211 83,63t
74 [374) Asset Retirement Costs for Distribution Plant &t3,63S -109,92i
75 TOTAL Distribution Plant (Enter Total of lines 60 thru 74)1.411.740.321 57.665.811
76 5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT
77 t380) Land and Land Riohts
78 1381) Strucfures and lmorovements
79 [382) Computer Hardware
80 1383) Computer Software
81 1384) Communication Eouioment
82 [385) Mlscellaneous Regional Transmission and Market Operation Plant
83 1386) Asset Retirement Costs for Resional Transmission and Market Oper
84 TOTAL Transmission and Market Operation Plant (Total lines 77 thru 83)
85 O. GENERAL PLANT
86 1389) Land and Land Riohis 16,120.205 461,42(
87 i390) Structures and lmprovemenb 93.653.4s2 9.854.59t
88 (391) ffice Fumiture and Eouipment 42.794.726 7.118.461.
89 (392) Transportation Equipment 64.890.431 6.169,65t
90 (393) Stores Equipment 1.877.A22 31.72i
91 (394) Tools. Shop and Garaqe Equioment 6.465.710 886.60i
92 (395) Laboratory Equipment 12,255,095 544,612
93 (396) Power Ooerated Eouioment 1 1,495.923 1.681.38:
94 (397) Communication Equipment 39.930.187 5.438.171
95 (398) Miscellaneous Eouioment 5.622.282 401.402
96 SUBTOTAL (Enter Total of lines 86 thru 95)295,105,833 32.588,03(
97 (399) Other Tanqible Property
98 (399.1) Asset Retirement Costs for General Plant
99 TOTAL General Plant (Enter Total of lines 96. 97 and 98)295,105,833 32,588.03(
100 TOTAL (Accounts 101 and 106)4.915.771.66€222.260.061
101 (102) Electric Plant Purchased (See lnstr. 8)
102 (Less) (102) Electric Plant Sold (See lnstr. 8)
103 ( 1 03) Exoerimental Plant Undassifi ed
't04 TOTAL Elec'tric Plant in Service (Enter Total of lines 100 thru 103)4.915.771.669 222.260.061
FERC FORM NO.1 (REV. tz-os)Page 206
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5]An original(2) nA Resubmission
uate ol Reoon
(Mo, Da, Yi)
04t1512014
YearPenoo oI Kepon
End of 20131Q4
ELECTRIC PLANT lN SERVICE (Account 101, 102, 103 and 10t Continued)
Retirements
(d)
Adjustments
(e)
Transters
(0
Ealance at
End pffear
Ltne
No.
36.087.730 48
85.325 70,075,081 49
1.911.076 457.97C 388.935.103 50
162.004.612 51
368.1s3 129.115.202 52
316.103 't88.088.876 53
54
55
390.266 56
57
2.680.65i 457,97C 974,696.870 58
9,34t 4.859.147 60
19,774 -10,790 32.820.611 61
480.961 50.424 't96.765.8't6 62
63
1.190.154 235.549.416 64
1.439.28C 126.O34.76A 65
114.064 46.289.611 66
688,287 207.476.284 67
4.82A.448 471.882.211 68
296.165 56.858.427 69
608,97€73,143,443 70
74.455 2,901,563 71
38.361 -38.36'l 72
4.588.84S 73
533,712 74
9.780.277 39,63t 1.459.665_493 75
77
78
79
80
81
82
83
84
1.95(16.579.675 86
580,25(10.79(102.938.s84 87
8.353.281 -661.851 40,898,058 88
3.332.85t 67,727,230 89
78t 1.908.757 90
155,37t 7.'t96.937 9t
487,781 132.75!12.444.641 92
376.03C 12.801.276 93
1.457.582 15,23t 43.926.O12 94
286,86(5.736.818 95
15.032.76a -503,07(312,158,028 96
97
98
15,032,76€-503.07(312.158.028 99
57,629,937 5,080,401,799 100
101
102
103
57.629.93i 5.080,401,799 104
FERC FORM NO.1 (REV. 12-05)
Name ol Respondent
ldaho Power Company
This Reoort ls:(1) 5]Rn orisinat
(21 1--1A Resubmission
uate ol KeDon
(Mo, Da, Yi)
04115t2014
YeazPenoo or Kepon
End of 2O13lQ4
ELECTRIC PLANT HELD FOR FUTURE USE (Account 105)
1. Report separately each property held for future use at end of the year having an original cost of $250,000 or more. Group other items of property held
for future use.
2. For property having an original cost of $250,000 or more previously used in utility operations, now held for fufure 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 transfened to Account 105.
LineNo.
uescflp0on ano Loca0onor eloyertv uale vngtnary rnquqe(
in This Account(b)
uare trxoecreo to oe useoin'uttitv SeMce
EataltE at
End of Year(d)
2 Boise Operations Center 12131t82 655,550
3 Production 109,961
4 Transmission Stations 423,089
5 Transmission Lines 195,489
6 Distribution Stations 1,077.217
Beacon Light Substation 12130l02 465,662
Homedale Substation 2t29t08 109,453
North River Operations Center 1t31tO&2,630,412
1 Line #854 500 Kv 3131lO9 308,066
11
1
1
1 Column B if no date listed it is various
1
1
1
1
1
2t
22 Boise Operations Center '1u31t82 72,785
22 Transmission Stations 199,069
24 Distribution Stations 69,941
2a Homedale Substation u29lo8 217.797
2e Beacon Light Substation 12t30t02 555,940
27
28
29
3C
31
32
33
34
2E
36
37
38
39
4A
41
42
43
44
45
4t
47 Total 7,090,431
FERC FORM NO. r (ED. 12-96)Page 214
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5]An orisinat(2) TIA Resubmission
Date of ReDort(Mo, Da, Yi)
0411512014
Year/Period of Report
End of 2O13lQ4
U(JNS I KUU I t(JN WUKK tN |-K(JLjKE55 - - ELEU I t(U (ACCOUni 1U/)
1. Report below descriptions and balances at end of year of projects in process of construction (1 07)
2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see
Account 107 of the Uniform System of Accounts)
3. Minor projects (5% of the Balance End of the Year for Account 107 or $1,000,000, whichever is less) may be grouped.
Line
No.
Desoiption of Project
(a)
Construction work in progress -
Electric (Account 107)
(b)
1 ROLLUP RELIC COST BROWNLEE 73,623,990
2 ROLLUP RELIC COST HELLS CANYON s0,183,581
3 GATEWAY WEST 5OOKV LINE 23,726,804
4 ROLLUP RELIC COST OXBOW 23,294,385
5 BOARDMAN - HEMINGWAY 5OO KV LI 19,833,927
6 HELLS CANYON RELICENSING OUTSI 17,759,283
7 CIAC LIABILITY RECLASS 8,654,509
8 BRIDGER UNDISTRIBUTED WORK ORD 5,653,210
I VALMY UNDISTRIBUTED WORK ORDER 5,642,006
't0 B2H PERMITTING 1111/2011 & FOR 5,555.755
11 VALMY 98250588 DUST COLLECTOR 3,013,757
12 BROWNLEE TURBINE REFURBISHMENT 2,903,666
13 BOARDMAN 1-1760 SO2 CONTROLS M 2,665,172
14 TFSNlOO3: REPLACE TWO METALCLA 2,661,327
15 VALMY 98301759 V1 UTILITY MACT 2,460,564
16 LEGAL DEPT, LABOR FOR RELICENS 2,214,774
17 B2H TLINE CONSTRUCTION COSTS 2,099,880
18 REL.HCC OREGON REAUTHORIZATION 2,023,191
19 LOWER MALAD TURBINE REPLACEMEN 1.574.233
20 NEW BUILDING PURCHASE - 5701 W 1,s63.64s
21 BRIDGER 2011C038 JB3 SCR SYS D 1,536,442
22 VA1MY98314221 VC CAUSTIC TANK 1,526,976
23 VALMY 98306280 V2 SCRUBBER SPR 1.399.271
24 BRIDGER 2012C71 U2 GSU TRANSFO 1 ,351 ,16s
25 HCC WATERSHED ENHANCEMENT PROG 1,335,925
26 CLEAR LAKES INTAKE AND SPILLWA 1.245.791
27 HBND-041:ALT LINE ROUTE TO GAR 1,'118,782
28 VALMY 98306281\I2 SCRUBBER INLE 1,050,512
29 IPC'SHARE OF BRIDGER-BOMH TAP 1,049.581
30 RELICENSING: BAKER COUNTY SETT 1,030,476
31 IPC'S SHARE OF BRIDGER.KINPORT 1,029,894
32 WDRI-KCHM NEW 138KV 1,024.338
33 IPCOI I2O1,I DOWNTOWI\ CAPITAL 1,014,499
34 BCWO - COMMUNICATION UPGRADES 1,001,441
35 OTHER MINOR PROJECTS UNDER Sl,OOO,OOO 53,177,286
36
37
38
39
40
41
42
43 TOTAL 327,000,038
FERC FORM NO. r (ED.12-E7)Page 216
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5]An orisinal(2) 1-1A Resubmission
Date of Reoort
(Mo, Da, Yi)
04t15t2014
Year/Period of Reporl
End of 20131Q4
ACCUMULATED PR,OVISION FOR IJE,PREGIATION OF ELECTRIC UTILITY PLANT (ACCOUNI 1OE)
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 seryice, 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. ln addition, include all costs included in retirement work in progress at year end in the appropriate functional
classifications.
4. Show separately interest credits under a sinking fund or similar method of depreciation accounting.
Section A. Balances and Changes During Year
No.
I
(a)'".,8i%'
Service(c)
trtq(;ut(j rtanI net(Ifor Future Use(d)
Etffiutg rtanrLeased to Others(e)
Balance Beginning of Year 1,848,861,11:1,848,861,11i
(403) Depreciation Expense 121,486,191 121,486,191
(403.1) Depreciation Expense for Asset
Retirement Costs
587,012 587,0'.t2
(413) Exp. of Elec. Plt. Leas. to Others
Transporhtion Expenses-Clearing 3.478.94!3,478,94!
Other Clearing Accounts
Oher Accounts (Speci!, detrails in botnote):
Fuel Stock 99,'141 99,14'
1(TOTAL Deprec. Prov for Year (Enter Total of
lines 3 thru 9)
125,651,293 125,651,29:
'ti Book Cost of Plant Retired 48,'.122,830 48.122.831
1:Cost of Removal 10,077,893 10,077,89i
1t Salvage (Credit)2,294,255 2,294,25!
1t TOTAL Net Chrgs. for Plant Ret. (Enter Total
of lines 12 thru 14)
s5,906,468 55,906,46{
1(Oher Debit or Cr. ltems (Describe, details in
footnote):
1 CIAC, Reserve Adj and ARO Activity 976,97i 976,971
,|Book Cost or Asset Retirement Costs Retired
1 Balance End of Year (Enter Totrals of lines 1
10, 15, 16, and '18)
1 ,91 9,582,91(1,919,582,91(
Section B. Balances at End of Year Accordlng to Functional Classification
21 Steam Production 532,889,241 532,889,24/
2'Nudear Production
2:,Hydraulic Produc{ion-Conventional 378,129,481 378.129.48',
2i Hydraulic Production-Pumped Storage
2t Other Production 58,193,25i 58,193,25'
2t Transmission 300,179,06(300,179,06(
21 Distibution 543,19',t,781 543,19',1,7&
2i Regional Transmission and Market Operation
2t General 107,000,08(107.000,08(
2(TOTAL (Enter Total of lines 20 thru 28)1,919,582,91(1,919,582,91(
FERC FORM NO.1 (REV. 12-0s)Pase 219
Name o, Respondent
ldaho Power Company
This Reoort ls:(1) fiAn Original(2) 1-'1A Resubmission
uale ot Keoon
(Mo, Da, Yl)
o411st2014
YeailPefloo oI Kepon
End of 2O13lQ4
INVESTMENTS lN SUBSIDIARY COMPANIES (Account 123.
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),(0,(g) and (h)
(a) lnvestment in Securities - List and describe each security owned. For bonds give also principal amount, date of issue, maturity and interest rate.
(b) lnvestment Advances - Report separately the amounts of loans or investment advances which are subject to repayment, but which are not subject to
current setflement. 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 speciffing 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 41 8.1 .
_rne
No.
uescnp[on oT tnveslmenl
(a)
Date Acquired
(b)
Date Of
'"1;1ri"
Amount ot lnvestment at
Beoinnino of Year- (d)-
1 ldaho Energy Resources Company
2 Common Stock 02101174 500
3 Capital contributions 2,462,594
4 Equity in earnings 82,217,149
5
b Subtotal ldaho Energy Resources Company 84,680,243
7
8
I
10
11
12
13
14
15
16
17
18
19
2C
21
22
t:
24
25
2e
27
2e
29
3C
31
32
33
34
35
3€
37
38
2C
40
41
42 [otal CostofAccount 123.1 $ 2,463,0941 TOTAL 84,680,243
FERC FORM NO.I (ED.12-E9)Page 224
Name of Respondent
ldaho Power Company
This Reoort ls:(1) fiAn orisinat(2) l-lA Resubmission
Date of Reoort(Mo, Da, Yi)
04t15t2014
Year/Period of Report
End of 20131Q4
INVESTMENTS lN SUBSIDIARY COMPANIES (Account 123.1) (Continued)
4. For any securities, notes, or accounts that were pledged designate such securities, notes, or ac@unts in a footnote, and state the name of pledgee
and purpose of the pledge.
5. lf 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 invesbnents, including such revenues form securities disposed of during the year.
7. ln column (h) report for each investnent disposed of during the year, the gain or loss represented by the difference between cost of the investnent (or
the other amount at which canied in the books of account if difference from cost) and the selling price thereof, not including interest adjustrnent includible
in mlumn (f).
8. Report on Line 42, column (a) the TOTAL cost of Account 123.1
Equ[y rn ouosrorary
Eaminlsrof Year (0 End gf,Year
Ljatn or Loss rom lnvestrnenl
Disoosed of' (h)
Line
No.
1
500 2
2,462,594 3
6,704,329 88,921,478 4
5
6,704,329 91.3U.572 6
7
8
I
10
11
12
13
14
't5
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
6,704,329 91,3U,572 42
FERC FORM NO.1 (ED.12-Ee)Page 225
Name ot Respondent
ldaho Power Company
This Reoort ls:(1) S]An originat(2) 1--1A Resubmission
uate ot Heoon(Mo, Da, Yi)
0411512014
YearHenoo or Kepon
End of 20131Q4
MATERIALS AND SUPPLIES
1. For Account 154, report the amount of plant materials and operating supplies under the primary functional classifications as indicated in column (a);
estimates of amounts by function are acceptable. ln column (d), designate the department or departments which use the class of material.
2. Give an explanation of important inventory adjustrnents during the year (in a footnote) showing general classes of material and supplies and the
various accounts (operating expenses, clearing accounts, plant, etc.) affected debited or credited. Show separately debit or credits to stores expense
clearing, if applicable.
Line
No.
Account
(a)
Balance
Beginning of Year
(b)
Balance
End of Year
(c)
Department or
Departments which
Use Material(d)
1 Fuel Stock (Account 1 51 )42,388.239 41,546,323 Electric
2 Fuel Stock Expenses Undistributed (Account 152)
3 Residuals and Extracted Products (Account 153)
4 Plant Matedals and Operating Supplies (Account 154)
5 Assigned to - Construction (Estimated)
6 Assigned to - Operations and Maintenance
7 Production Plant (Estimated)15,899,274 16,506,169
I Transmission Plant (Estimated)12,836,658 10,947,716
I Distribution Plant (Estimated)17,335.350 20,538,847
10 Regional Transmission and Market Operation Plant
(Estimated)
11 Assigned to - Other (provide details in footnote)1,384,672 1,274,973
12 TOTAL Account 154 (Enter Total of lines 5 thru 1 1)47.455.954 49.267.705 Electric
13 Merchandise (Account 1 55)
14 Other Materials and Supplies (Account 156)
15 Nuclear Materials Held for Sale (Account 157) (Not
applic to Gas Util)
16 Stores Expense Undistributed (Account 163)3,581,218 4,375,589 Electric
17
18
19
20 TOTAL Materials and Supplles (Per Balance Sheet)93,425,411 95,189,617
FERG FORM NO. r (REV. 12-0s)Page 227
Name of Respondent
ldaho Power Company
This Reoort ls:(1)E] An orisinal
(2) Tl A Resubmission
Date of Reoort(Mo, Da, Yi)
04t1512014
Year/Period of Report
6n6 o1 2013/Q4
Transmission Service and Generation lnterconnection Study Gosts
1. Report the particulars (details) called for conceming the costs incuned and the reimbursements received for performing transmission service and
generator interconnection studies.
2. List each study separately.
3. ln column (a) provide the name of the study.
4. ln column (b) report the cost incurred to perform the study at the end of period.
5. ln column (c) report the account charged with the cost of the study.
6. ln column (d) report the amounts received for reimbursement of the shidy costs at end of period.
7. ln column (e) report the account credited with the reimbursement received for performing the study.
Lrile
No.Description
(a)
Costs lncurred During
Period
(b)
Account Charged
(c)
KelIItuuIselngt tt5
Received During
the Period
(d)
Account Credited\flith Reimbursement
(e)
2 BLACK CANYON SISR 1,160 186623 186623
3 BPAP NETWORK SIS 78318516 2,248 186623 ( 10,000)186623
4 BPAP NETWORK SIS 78862937 2,926 186623 ( 10,000)186623
5 BPAP TRANS s1578225282 4,850 186623 ( 4,850)186623
6
7
8
c
10
11
12
13
14
15
16
17
18
19
20
22 3 NORTH 3 EAST HYDRO GI 408 2,052 186623 ( 2,052)186623
23 ALAMEDA SOLAR CENTER - GI 416 1,739 1 86623 ( 1,000)186623
24 AMALSUGAR PAUL GI 389 186623 ( 2,067)186623
25 BENSON CREEK WINDFARM GI 401 19,630 186623 (58,078)186623
26 BLACK CANYON BLISS HYDRO 186623 500 186623
27 BURNT RIVER #2 PROJECT 251 3,571 186623 186623
28 BURNT RIVER PROJECT 209 8,538 186623 186623
29 DURBIN CREEK WNDFARM GI 402 323 1 86623 677 186623
30 EAGLE VIEW DAIRY GI 390 1 86623 6,199 186623
31 EIGHTMILE HYDRO GI 406 3,863 186623 ( 3,704)'t86623
32 GMND VIEWSOLARTWO GI 369 6,580 186623 24,457 186623
33 GRANDVIEW PV SOLAR FIVE GI 411 s,063 1 86623 ( 1,000)186623
34 GRANDMEW PV SOLAR FIVEA GI 418 2,300 186623 ( 1,000)186623
35 GRANDVIEW SOLAR 3 GI 394 2,177 186623 11,207 186623
36 GRANDVIEW SOLAR 4 GI 395 5,866 186623 ( 3,134)186623
37 GROVE SOLAR CENTER - GI 414 4,102 186623 ( 1,000)1 86623
38 HEAD OF THE U HYDRO GI 409 7,274 186623 ( 21 ,381)186623
39 HORSE CREEK SOLAR CEN 2,171 186623 ( 1,000)186623
40 HYLINE SOLAR CENTER. GI 419 186623 ( 1,000)186623
FERC FORM NO. 1/1-Fr3-Q (NEV1,. 03-07)Page 231
Name of Respondent
ldaho Power Company
tnrs KeDon Is:(1)E An Original
(2) Tl A Resubmission
Date of ReDort
(Mo, Da, Yi)
0411512014
Year/Period of Report
6n66 2013/Q4
Transmission Service and Generation lnterconnection Study Costs (conunued)
LII IT
No.Description
(a)
Costs lnanned During
Period
(b)
Account Charged
(c)
xermoursemenlS
Received During
the Period(d)
Account Credited
With Reimbursement
(e)
2
3
4
5
6
7
8
I
10
11
12
13
14
15
16
17
18
19
20
22 JETT CREEK WINDFARM GI 403 323 '186623 677 186623
23 LITTLE WOOD RIVER RANCH II GI 410 6,629 186623 3,234\186623
24 MAGPIE WIND PROJECT 235 3,6't3 186623 186623
25 MURPHY FLAT WND FARM 21,282 186623 ( 43,814)186623
26 OPEN MNGE SOLAR CENTER - GI 413 750 186623 ( 1,000)186623
27 PROSPECTOR WNDFARM GI 404 323 186623 677 186623
28 SAGEBRUSH SOLAR CENTER. GI 415 u7 186623 ( 1,000)186623
29 SHOSHONE FALLS GI 136 186623 ( 47,512)186623
30 SWAGER FARMS GI#307 186623 8,247 186623
31 TURNER SOLAR CENTER - GI 420 186623 ( 1,000)186623
32 VALE AIR SOLAR CENTER. GI 412 6,333 186623 ( 1,000)186623
33 WLLOW CREEK WNDFARM GI 405 323 186623 677 186623
34
35
3€
31
38
2C
4C
FERC FORM NO. 1r1-Fr3-Q (NEW. 03-07)Page 231.1
Name of Respondent
ldaho Power Company
This ReDort ls:(1) 5]Rn orisinal(2) l-l A Resubmission
uate ot KeDon(Mo, Da, Yi)
0411512014
YearPenoo oI Kepon
End of 20131Q4
OTHER REGULATORY ASSETS (Account 182.3)
1. Report below the particulars (details) called for concerning other regulatory assets, including rate order docket number, if applicable.
2. Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $100,000 which ever is less), may be grouped
by classes.
3. For Regulatory Assets being amortized, show period of amortization.
Line
No.
Description and Purpose of
Other Regulatory Assets
(a)
tsaEnce aI tsegtnntn(
of Cunent
Ouarterffear
(b)
Debits
(c)
CREDITS Balance at end of
Cunent Quarterffear
(0
Written off During the
Quarter /Year Accounl
charged (d)
wmen 0r uunng
the Period Amount
(e)
Asset Retirement Obligations (182341)13,583,873 3,685,134 230 503,19i 16,765,815
2 IPUC Orde# 29414-0PUC Order# 04-585
3
4 ASC 815 Mark to Market - ST (182330)1,054,643 4,552,513 244 3,978,70(1,628,450
€Reoulatorv Unfunded (1 82322)677,795,471 44,058,546 282 1 1,371,61:710,482,403
7 Accum Defened lncome Noncunent
8
c PCA Defenal ldaho - IPUC Order#32821 52,349,48!72,949,308 1823 62,204,98:63,093,814
10 Gmort oeriod 06/14 thru 05/1$ (182323)
1',!
't2 PCA Prior Year Defenal ldaho - IPUC 0rder #32821 ( 20,469,1321 84,36',t,221 van0us 33,473,69(30,418,393
13 (Amort oeriod 06/'ll thru 05/'14) ('182324\
14
15 Fixed Cost Adiusment (FCA) (182302)8,830,2'18 17,193,424 1823 10,592,34t 15.431,297
16 IPUC Order#32505 (amort period 06/14 thru 05/15)
17
18 Prior Year FCA IPUC Order#3281 1 (182309)4,587,404 8,896,36i 400 9,389,28t 4,094,47t
19 (Amort period 6/13 thru 5/14)
20
21 FERC Grid West Expense (182304)27,932 401 27,932
22 ER08$29-000 (amod period 05/08 thru 04/13)
23
24 AOCI lmoact of Unfunded Post Retirement Liability 15.895.315 371,073 228 20,912,41t 4,646,03(
25 IPLJC Ordar#30256 (182306)
26
27 Oreson Pension Expense Capitalized (182339)1,904,385 690,998 401t4073 70,904 2,524,479
28 OPUC Order#10464 (amort period hru 2050)
29
30 Defened Pension Exoense Net of Contributions 12,839,861 43,'t99,94C 1823t228 28,977,144 27.062.657
3'l IPUC Order #30333 (182321)
32
33 AOCl lmpact of Unfunded Pension Liability 292,954,561 228 171,725,97t 121.228,583
34 IPUC Order#30256 (182320)
35
36 PCA Unbilled Forecast IPUC Order#32821 (1823251 401 6,092,28t -6,092,288
37
38 PCAM Oreoon 2008 (182346)6,977,40C 560,90C 7,538.300
39 OPUC 0rder#08-238 &UE277 ( Anortill4 -711h
40
41 PCAM lnterest Reserve 2008 (182329)( 600,2821 421 193,04(-793,327
42 OPUC Order#08-238 &UE277 (Anoft'll14 -7l17l
43
FERC FORM NO. 1/3-Q (REV.02-04)Page 232
Name ot Responc'ent
ldaho Power Company
lhts Heoon ls:(1) fiAn original(2) 5A Resubmission
uale ot Kepon(Mo, Da, Yr)
0411512014
YearHenoo or Kepon
End of z0',tslQ4
OTHER REGULATORY ASSETS (Account 1 82.3)
1 . Report below the particulars (details) called for concerning other regulatory assets, including rate order docket number, if applicable.
2. Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $100,000 which ever is less), may be grouped
by classes.
3. For Regulatory Assets being amortized, show period of amortization.
-tne Desoiption and Purpose of
Other Regulatory Assets
(a)
tsaEnce aI Eegtnntn(
of Cunent
Quarterffear
(b)
Debits
(c)
CREDITS Balance al end of
Cunent Quarterffear
(D
No.Written ofi During the
Quarter ffear Account
charsd (d)
Writen off During
the Period Amount
(e)
1 Excess Power Cost Defenal 2007 (182358)2,403,512 39,131 401t421 2,415,72t 26,91r
2 IPUC Order #09J89 (amoft period 1111 - 1114l.
3
4 2007 EPC lnterest Reserve ('182351)( 1s9,661 151,75(-1.90r
5 IPUC Order #09-189 (amort period 111'l - 1114)
6
7 ldaho Boardman Decomissionino #32549 ('182493)5,816,90i vanous 5,067,163 749,74(
8
I
10 2009 Reom IPUC Order#30914 (182318)461,3'fi 401 230,6se 230,65t
11 (amort period 01/10 thru 1?14)
1
13 OATT Revenue Defened Reserve (182336)1,663.04r 400 688,156 971,88t
14 IPUC Order#30940 (amort period 06/12 thru 5/15)
15
16 ldaho Pension Cash (182327)50,036,08?39,850,900 40'U42',1 44,366,56i 45.520.42(
17 IPUC Order #32248 (amod oeriod 06/1 1 thru 05/1 4)
18
19 FERC Pension Cash (182328)214,461 36,00(401 2s0,461
20 IPUC Order #32248 (amort period 06/1 t hul2l3)
21
22 Excess Power Cost Unbilled Amort (186356)I 137.422'2,262,81C 401 2,261,487 -136,09!
23
24 Cus Eftciency lncentive IPUC Order#32245 (1823171 14,086,201 1,359,81(254 15,446,011
25
26 Cus Efiiciency lncen Res IPUC Order#32245 (1823141 ( e16,465,1,1 68,87(18231421 252,41t
27
28 Lidar Surveys IPUC Order #32426 (182361 )392,442 402 43,60{348,837
29 (amort period 01/12hru 121211
30
31 Bennett Mtr lvlaintenance IPUC Order*32426 224,ffi{402 74,88i 149,773
32 (amoil period 01/12 hru 1215) (182379)
33
34 PCA Unbilled Amortizathn (182316)2,691,2il 34,263,62i 400/401 39,53r,60(-2,576,701
35
36 ldaho Boardman ARO Order#32549 (182393)1,376,05i 403t411 172,001 1,2U,047
37 (amod oedod hru 2020)
38 Lanolev Revenue Accrual Order#12-226 (182398)807,39 64,69(872,0U
3S
40 236,69'440,28t vanous 401,54(275,441
41
42
43
4 TOTAL:1.141,110.72t 365.980.212 470,715,8't(1,036,375,1 19
FERC FORM NO. 1/&Q (REV.02-04)Page 232.1
Name of Respondent
ldaho Power ComDanv
This Report is:
(1) X An Originale) A Resubmission
Date of Report
(Mo, Da, Yr)
0411512014
Year/Period of Report
2013tQ4
FOOTNOTE DATA
Accounts
r_82 300
]-823L2
]-823t3
1,82334
1 82335
182352
182353
L82354
L82362
L82356
182367
182369
1_823'7 7
L823'7'7
18238 0
]-82390
1"8239]-
t82392
t82394
L82395
782396
L82397
]-82399
]-82494
uded in m tems:
FERC FORM NO.1 450.'l
Name oI Kesponoent
ldaho Power Company
This Reoort ls:(1) []An original(2) nA Resubmission
Date of Reoort
(Mo, Da, Yi)
04t'1512014
Year/Period of Report
966 ey 2013/Q4
MISCELLANEOUS DEFFERED DEBITS (Account 186)
1. Report below the particulars (details) called for concerning miscellaneous defened debits.
2. For any deferred debit being amortized, show period of amortization in column (a)
3. Minoritem(1%oftheBalanceatEndofYearforAccountlS6oramountslessthan$100,000,whicheverisless)maybegroupedby
classes.
Line
No.
Description of Miscellaneous
Defened Debits
(a)
Balance at
Beginning of Year
(b)
Debits
(c)
CREDITS Balance at
End of Year
/fl
AC@UnICharqed Amount
(e)
1 Prepaid ROW (186160)738,195 20.121 401 98,48'659.834
2 Rents/Easements Lonq Term
3
4 Advance Prepaid (1 86709)'t _333.94€151 27,411,1.306.535
Coal Rovalties
6
7 Seorritv plan (186720)18.496.667 986.191 1431426 1.367.421 18.115.431
8 Net lnsurance Asset
I
10 American Falls Bond Ref(186722)177,052 401 14.552 162.500
11 (Amort 04/00 - O2l25l
12
13 Prepaid Credit Facility(1 86025)962,06'l 1.140.541 431 1.'195.531 907.07'l
14 (amort period 1Ol12lhru 10117't
15
16 Comoanv Owned (186726)4,149,412 '1,666.83r 426 1.894.60(3.921.641
17 Life lnsurance
18
19 American Falls Water Riohb 12,590,939 401 1,042.00s 11.548.930
20 (amort 01/06 -02125\ (1867271
21
22 Milner Bond Guarantee (186734)5.318.182 253 1,063.63i 4,254.545
23 AmoftO2lO7 -21171
24
25 American Falls - Bond refinance 583,990 401 47.99!535.991
26 (Amort throuqh 02125\( 8677 0)
27
2A Shelf Registration ('186732)160.491 186 22 160,469
29
30 Preoaid Exo (186052)1.148.188 652.19(vanous 962.674 837,710
31 Contract l.T. Lono Term
32
33 Lonq Term {d861211 1.214.665 2281401 28.33r 1.186.330
34 Workers Comoensation
35
36 Power Plant- Valmy (186793)16,495 124 16.618
37
38 Power Plant- Boardman (186794)1.599 1071401 1.sge
39
40 Transmission & Generation 1.222.226 2.360.32(vanous 3.503.00t 79,544
41 Studies ('186623)
42
43 Prepaid Coal LT (186797)5.958.328 151140',1 4.500.00(1.458.328
44
45 1.S05 '1.684.72t vanous 1.629.344 57.289
46
47 Misc. Work in Progress
48 uererlsu Nsguralory vur[]n.
Exoenses (See oaoes 350 - 351 )
49 TOTAL 53,913,85(45,208,766
FERC FORM NO.1 (ED.12-94)Paqe 233
Name of Respondent
ldaho Power Comoanv
This Report is:
(1) X An OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
0411512014
Year/Period of Report
20131Q4
FOOTNOTE DATA
Accounts
L86255
L86946
FERC FORM NO.1 1 450.1
Name of Respondent
ldaho Power Company
This ReDort ls:(1) 5.1Rn Orisinal(2) 1-1A Resubmission
uate ol KeDon
(Mo, Da, Yi)
0411512014
Year/Period of Report
End of 20131Q4
ACCUMULATED DEFERRED INCOME TMES (Account 190)
't . Report the information called for below concerning the respondent's accounting for deferred income taxes.
2. At Other (Specifo), include defenals relating to other income and deductions.
Ltile
No.
uescnpuon ano LocEluon
(a)
rraranEvr l,egrnrn9
(b)
tsalance at Enclof Year
(c)
1 Electric
Other Electric (See footnote)118,958,964
Other (See footnote)106.991,643
TOTAL Electric (Enter Total of lines 2 thru 7)295,182,024 225,950,607
Gas
1(
1
11
1:
1
1 Other
1 TOTAL Gas (Enter Total of lines 1 0 thru 15
1 Other Non Electric See footnote 20.824.214
1 TOTAL (Acct 190) (Total of lines 8, 1 6 and 1 7)316,262,777 246.774.821
Notes
FERC FORM NO.1 (ED.12-88)Page 234
Name of Respondent
ldaho Power Comoanv
This Report is:
(1) X An Originalel A Resubmission
Date of Report
(Mo, Da, Yr)
04t15t2014
Year/Period of Report
20131Q4
FOOTNOTE DATA
Beginning Balance Ending Balance
Federal NOL-Operating
Regulatory Asset-Non Current
Prov for Rate Refund-HC Relicensing (AFUDC)
Deferred ldaho ITC
VEBA-Post Retirem ent Benefits
Stock Based Compensation-FASI 23R
Revenue Sharing
Rate Case Disallowance
Pension Expense-Oregon
Construction Advances
Regulatory Liability-Current
Valmy Union Pacific Contract
Postretirement Benefits-SFAS 1 1 2
CSPP Co-Generator Overpayment
Executive Deferred Compensation
Asset Retirement Obligation (ARO)
Oregon NOL-Operating
Bridger Revenue Deferral
Provision for Rate Refunds
Montana NOL-Operating
Non-VEBA Pension and Benefits
Deferred GBC Federal
Boardman Decommission
Total Other Electric
Regulatory Asset-FASB 1 09
Pension-FAS 158
Minimum Pension Liability
Postretirement Plan-FAS 1 58
TotalOther
Senior Management Security Plan
Micron CIAC-Depr Timing Diff
Federal NOL-Non Operating
Meridian Gold CIAC-Depr Timing Diff
Oregon NOL-Non Operating
Montana NOL-Non Operating
SMSP-Market Change of Rabbi lnvestments
Total Non Electric
45,964,500
4,458,718
17,855,802
13,747,559
9,221,017
3,148,063
2,795,770
2,505,417
1,897,934
3,009,900
1,722,247
884,286
822,852
0
969,904
0
262,521
65,767
8,895
78,812
217,769
24,000
28,544,014
23,538,502
23,062,458
15,346,759
9,962,466
3,532,282
2,972,019
2,389,579
2,204,483
2,059,244
1,826,860
1,083,462
579,781
470,282
450,715
425,053
247,299
191,185
155,600
101,480
82,596
3'l,500
(1 51 .1 31 ) (298.653)
109,509,600 118,958,964
51,285,735
114,530,586
13,641,829
6,214,273
50,788,061
47,394,3',15
10,625,633
(1,816,365)
185,672,424 106,991,643
I
17,720,515
812,600
850,678
64,230
5,037
1,679
19,664,453
574,719
534,662
42,1',!8
6,409
1,9541,626,015 021,080,753 20,824,214
FERC FORM NO.1 1 450.1
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5.1An orisinat(2) 1--1A Resubmission
Date of Reoort(Mo, Da, Yi)
04115t2014
Year/Period of Report
End of 2O13lQ4
CAPITAL STOCKS (Ac,count 201 and 2O4)
1. Report below the particulars (details) called for conceming common and prefened stock at end of year, distinguishing separate
series of any general class. Show separate totals for common and prefened stock. lf 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.
_lne
No.
Class and Series of Stock and
Name of Stock Series
(a)
Number of shares
Authorized by Charter
(b)
Paf or stated
Value per share
(c)
Call Price at
End of Year
(d)
1 Account 201
2 Common Stock all of which is held by 50,000,000 2.54
3 ldaCorp, lnc. and not traded
4 Total Common Stock 50,000,000 2.50
€Account 204 - None
7
I
s
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
FERC FORM NO. I (ED.
'2-91)
Page 250
Name ot Respondent
ldaho Power Company
This Reoort ls:(1) []An Orisinal(2) nA Resubmission
Date of Reoort
(Mo, Da, Yi)
04115t2014
Year/Period of Report
End of 20131Q4
CAPTTAL STOCKS (Account 201 and 2O4) (Continuecl)
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 prefened stock should show the dividend rate and whether the dividends are cumulative or
non-cumulative.
5. State in a footnote if any capital stock which has been nominally issued is nominally outstanding at end of year.
Give particulars (details) in column (a) of any nominally issued capital stock, reacquired stock, or stock in sinking and other funds which
is pledged, stating name of pledgee and purposes of pledge.
OUTSTANDING PER BALANCE SHEET HELD BY RESPONDENT Line
No.\ r vtqr or ilvur ra vutDEI t9[ tg wru tvut r Eu
for amounts held by respondent)AS REACQUIRED STOCK (Account217)IN SINKING AND OTHER FUNDS
snares(e)Amount(0 tinares(s),a(h sihares(i)Amount(i)
39,150,812 97,877,030 2
3
39,150,812 97,877,030 4
5
6
7
8
I
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. t2-EE)Page 251
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5]1Rn orisinal(2) nA Resubmission
Date of Reoort(Mo, Da, Yi)
0411512014
Year/Period of Report
gn6 e; 2013/Q4
u I HtrK t-AtU-tN UAt-t I AL (AC@UntS ZUV-211, lnc.)
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 fte account, as well as total of all accounts for reconciliation with balance sheet, Page 1'12. Add more
columns for any account if deemed necessary. Explain changes made in any account during the year and give he 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 21 1)-Classify amounts included in this account according to captions which, together with brief explanations,
disclose the general nafure of the transactions which gave rise to the reported amounts.
LtneNo.Item(a)AnE)unI
1 Account 208 - Donations received from stockholders - None
2
3 Account 209 - Reduction in par or strated value of Capital Stock - None
4
5 Account 210 - Gain on reacquired Capital Stock - None
6
7
8 Account 211 - Miscellaneous paid-in Capital - None
I
10
11
12
13
't4
15
16
17
18
19
20
21
22
23
24
25
26
27
2A
29
30
31
32
33
34
35
36
37
38
39
40 TOTAL
FERC FORM NO. r (ED.12-E7)Page 253
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5]Rn Orisinat
(21 nA Resubmission
Date of ReDort(Mo, Da, Yi)
o4l't512014
Year/Period of Report
gn6 61 2013/Q4
GAPITAL STOCK EXPENSE (Account 214)
1. Report the balance at end of the year of discount on capital stock for each class and series of capital stock.
2. lf 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 specifo the account charged.
LIlIE
No.
utass ano nenes or >IocK(a)E alance aI Eno ot Year
(b)
1 Common Stock 2,096,925
2
3
4
5
6
7
8
I
10 -xplanation of Changes during the year:
11
12
13
14
15
16
17
18
19
20
21
22 TOTN-2,096,925
FERC FORM NO.1 (ED. 12-87)Page
Name of Respondent
ldaho Power Company (1) E(2) l-
ron ls:
An Original
A Resubmission
uate oI Keoon
(Mo, Da, Yi)
0411512014
Yea0Henoo or Kepon
End of 20131Q4
LONG-TERM DEBT (Account 221, 222, 223 and 224)
1 . Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221 , Bonds,222,
Reacquired Bonds, 223, Advances from Associated Companies, and 224, ather long-Term Debt.
2. ln 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. lnclude 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. ln column (b) show the principal amount of bonds or other long-term debt originally issued.
7. ln 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.
lndicate 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.
-ine
No.
Class and Series of Obligation, Coupon Rate
(For new issue, give commission Authorization numbers and dates)
(a)
Principal Amounl
Of Debt issued
(b)
Tohl expense,
Premium or Discount
(c)
1 Acmunl221:.
2 Firct Mortgage Bonds:
3 4.50% Series due2O2O 130,000.00(1,190,698
4 234,601 D
5
6 5.50% Series due 2033 70,000,00(728,701
7 36,400 D
8
I 6.15% Series Due 2019 100,000.00(1,034,909
10 184,949 D
11
12 3.40olo Series due2O2O 100,000,00(1,159,871
13 498,84t D
14
15 5.30% Series Due 2035 60,000.00(408,411 0
16 3,802,019
17
18 4.25%Series due 2013 70,000,00(641,201
19 372,696 D
20
21 4.00% Series due 2043 75.000.00(742,017
22 193,836 D
23
24 6.00% Series due2O32 100,000,00(1,191.2't6
25 543,244 D
26
27 5.875o/o Series due 2034 55,000,00(-s85,759
28 746,961 D
29
30 5.50% Series due2O34 50.000,000 524,419
31 383,322 0
32
33 TOTAL 1,697,045,00(27,921,281
FERC FORM NO. 1 (ED.12-96)Page 256
Name of Respondent
ldaho Power Company
tnrs KeDon ts:(1) 5]Rn orisinal
(2) 1-1A Resubmission
Date of Reoort
(Mo, Da, Yi)
04t't512014
Year/Period of Report
End of 20131Q4
LONG-TERM DEBT (Account 221,222,223 and 224) (Continued)
10. ldentiff separate undisposed amounts applicable to issues which were redeemed in prior years.
1't. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, Premium
on Debt - Credit.
12. ln 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. lf the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee
and purpose ofthe pledge.
14. lf 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. lf interest expense was incuned 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 Accounl427, interest on
Long-Term Debt and Account 430, lnterest on Debt to Associated Companies.
16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.
Nominal Date
of lssue
(d)
Date of
Maturity
(e)
AMORTIZA''ION PERIOD vuElaltuItu(Totral amount outstandino wihout' reduction for amounts hlld by
resn?.rtrdent)
lnterest for Year
Amount
(i)
Line
No.Date From
(0
Date To
(s)
1
2
11120109 311t20 1'v20l09 3t1t20 130,000,00(5,850,00(3
4
5
05/01/03 04t01133 05/01/03 03/31/33 70,000,00(3,850,00(6
7
8
411tog 4t1t19 411t09 4t1t19 100,000,00(6,150,00(I
10
11
11t1t10 511t2020 1'.v1t10 511t20 100,000,00(3,400,00(12
13
14
x8l26l05 08126135 08126105 08126135 60,000,00(3,180,00(15
16
17
l5/01/03 10101113 05/01/03 09129t13 2.231.25C 18
1(
20
41812013 41112043 418t2013 4t112043 75,000,00(2,191,667 21
22
2i
11115102 't1t15t32 11115102 11t15t32 100,000,00(6,000.00(24
2!
2e
0u1€/o4 o8l16t3/'o8l't6104 08116134 55,000,00(3,231,25(2i
2t
2F
03126104 03115134 03126104 03115134 50,000,00(2.750.00(3(
31
5l
1.619,599,54t 81.492,149 J,J
FERC FORM NO. r (ED. 12-96)
Name of Respondent
Idaho Power Company
This Reoort ls:(1) SllAn original(2) nA Resubmission
uale ol Keoon
(Mo, Da, Yi)
04t15t2014
YeaT!'enoo ol Keport
End of 20131Q4
LONG-TERM DEBT (Account 221,222,223 and 224)
'l . 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, Olher 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. lnclude 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. ln column (b) show the principal amount of bonds or other long-term debt originally issued.
7. ln 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.
lndicate the premium or discount with a notation, such as (P) or (D). The expenses, premium or discount should not be netted.
9. Fumish 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.
-ine
No.
Class and Series of Obligation, Coupon Rate
(For new issue, give commission Authorization numbers and dates)
(a)
Principal Amount
Of Debt issued
(b)
Total expense,
Premium or Discount
(c)
1 4.85% Series Due 2040 100,000,00(1,284,871
2 169,984 D
3
4 6.30% Series due 2037 140,000,00(1,495,799
5 278,367 D
o
7 6.25% Series due2037 100,000,00(1,141,489
8 267,677 D
s
10 Port of Morrow Yariable due 2027 4,360,00(188,545
11 Humboldt Variable due 2024 49,800,00(1,697,856
12 Sweetwater Variable due 2026 116,300,00(3,026,122
13
14 2.50% Series due2023 75,000,00(648,267
15 371,854 D
16
17 6.025o/. Series Due 2018 120,000,00(1,630,120
18
19 4.30% Series Due2O42 75,000,00(802,240
20 49,417 D
21 2.95% Series Due2022 75,000,00(708,490
22 127.607 D
23 Subtotal Account 221 1.665.460,00(27.921.281
24
25 Aemunt222 - Reaquired Bonds
26
27 Account 223: Advances for Associated Companies
28
29 Account 224:
30 Bond Guarantee - American Falls 19,885,00(
31 Note Guarantee - Milner Dam 11 .700,00(
32 Subtotal Ac*ount224 31,585,00(
33 TOTAL 1,697,045,00(27.921,281
FERC FORM NO.1 (ED.12-96) paoe 2s6.i
Name of Respondent
ldaho Power Company
tnrs KeDon ts:(1) []An orisinal(2) nA Resubmission
Date of Reoort
(Mo, Da, Yi)
04115t2014
Year/Period ot Report
End of 20131Q4
LONG-TERM DEBT (Account 221,222,223 and 224) (Continued)
'10. ldentifi 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. ln 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. lf the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee
and purpose ofthe pledge.
14. lf 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. lf interest expense was incuned 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 Accounl42T , interest on
Long-Term Debt and Account 430, lnterest on Debt to Associated Companies.
16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.
Nominal Date
of lssue(d)
Date of
Maturity(e)
AMORTIZATION PERIOD UUTSEIIUIIIU(Total amount outstanilinq without' reduction for amounts hlld byresnTgfent)
lnterest for Year
Amount
fi)
-ine
No.Date Frcm
(fl
Date To
(s)
u15110 8115140 ?/1il10 u15t40 100,000,00(4,850,000 1
2
3
6122lO7 611512037 6t22t07 6115137 140,000,00(8,820,000 4
5
6
10t18t07 10t1512037 10118107 101't5137 100,000,00(6,250.000 7
8
I
)5117t00 02101t27 05t17loo tu01l27 4,360.00(30,241 10
10l2u03 't2lo1t24 11lO1lO3 1U01t24 49.800.00(2.sil.700 11
10/3/06 71'.t5126 10/3/06 7t15126 116,300,00(6,105,750 12
't3
4t8t2013 41112023 41812013 411/2023 75,000,00(1,369,791 14
15
16
7l10lo8 7115118 7l10l08 7115t08 120,000.00(7,230,000 17
18
u13112 411142 4t13t12 4t1142 75,000,00(3,225,000 19
20
4t13t12 411t22 4113112 4t1t22 75,000,00(2,212,500 21
22
1,595,460,00(81,492,149 23
24
25
26
27
28
29
04126100 211125 19.885.00(30
02110t92 4.254,541 31
24,'.t39,541 32
1,619,599.544 81,492,149 33
FERC FORM NO.1 (ED. 12-96)Page 257.1
Name of Respondent
ldaho Power Company
This Reoort Is:(1) []An orisinat(2) 1-1A Resubmission
uate ot h(eoon
(Mo, Da, Yi)
o411512014
Year/Period of Report
End of 20131Q4
RECONCILIATION OF REPORTED NET INCOME WTH TAXABLE INCOME FOR FEDEML INCOME TAXES
1. Report the reconciliation of reported net income for the year with taxable income used in computing Federal in@me tax accruals and show
computation of such tax accruals. lnclude in the reconciliation, as far as practicable, the same detail as fumished on Schedule M-1 of the tax return for
the year. Submit a reconciliation even though there is no tiaxable income for the year. lndicate clearly the nature of each reconciling amount.
2. lf the utility is a member of a group which files a consolidated Federal tax retum, 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 retum. 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 he requirements of
the above instructions. For electronic reporting purposes complete Line 27 and provide the substitute Page in the context of a footnote.
LITIE
No.
Pantqlars (uelarls)
(a)
Amount
(b)
1 {et lncome for the Year (Page 1 17)176,741,143
2
3
4 [axable lncome Not Reported on Books
5
6
7
I
I )eductions Recorded on Books Not Deducted for Retum
10
't1
12
13
14 ncome Recorded on Books Not lncluded in Retum
15
16
17
18
19 )eductions on Retum Not Charged Against Book lncome
20
z'.|
22
23
24
25
26
27 rederal Tax Net lncome 32,666,714
28 ihow Computation of Tax:
29 ientative Tax @35Yo 11,433,350
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
Name of Respondent
ldaho Power ComDanv
This Report is:
(1) X An OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
04t1st2014
Year/Period of Report
2013tQ4
FOOTNOTE DATA
No.:5 Column: b
4OOO.FEDERAL NOL
4OO3-CONSTRUCTION ADVANCES
4OOs-AVOIDED COST
401 O-EM ISSION ALLOWANCES
401 3-CIAC-TAXABLE-ACCT 1 07
4O2l.ENGINEERING FEES.TAXABLE-ACCT 1 07
4o24-RENEWABLE ENERGY CERTIFICATES (REC) SALES
45O6.MERIDIAN GOLD CIAC.DEPR TIMING DIFF
4507-MICRON CIAC-DEPR TIMING DIFF
$ (77,958,875)
(2,716,160)
5,234,452
12,990
6,136,641
192,888
3,877,707
(56,560)
(608,471)
Total $ (65.88s.388)
:261 Line No.:10 Column: b
Total Federal and State taxes deducted on books
5OO1-BAD DEBT EXPENSE
501 O-POSTEMPLOYM ENT BENEFITS.SFASl 1 2
5014-VACATION ACCRUAL TAX ADJ
501 7-INJURIES & DAMAGES
501 g-DEFERRED DIRECTORS FEES
5022-263A CAPITAL IZED OVE RH EADS
5023-PENSION EXPENSE
5o24-NON-DEDUCTIBLE MEALS
5025-MILNER FALLING WATER
5028-OREGON OPERATING PROPERTY TAX ADJ
5033-NON-VEBA PENSION & BENEFITS
5035-PCA EXPENSE
sO43.AMERICAN FALLS-FALLING WATER CONTMCT
5O46.EXECUTIVE DEFERRED COMP-SHORT TERM
5o47-EXECUTIVE DEFERRED COMP-LONG TERM
5o52-AMORTIZATION OF ACCOUNT 181
505}STOCK BASED COMPENSATION-FAS1 23R
5055-OPUC GRID WEST LOANS
5056-FERC GRID WEST EXPENSE
5057-INTERVENER FUNDING ORDERS
5058-FIXED COST ADJUSTMENT
5059.PS & TCOSTS
5O6O-OREGON-PCAM
5061 -PENSION EXPENSE-OREGON
5062-2011 LIDAR SURVEYS DEFERRAL
5063-BENNETT MTN MAINT DEFERRAL
5O64.BRIDGER REVENUE DEFERML
5065-VALMY UNION PACIFIC CONTMCT
5066-BOARDMAN DECOMM ISS ION
5067-ASSET RET| REMENT OBLTGATION (ARO)
5068-CSPP CO.GENEMTOR OVERPAYMENT
5501 -SMSP-INSURANCE COSTS
55o2-SMSP-MARKET CHANGE OF RABBI INVESTMENTS
55o3-EDC-UNREALIZED GAIN/LOSS FROM RABBI TRUST
ssO4.NON-DEDUCTIBLE POLITICAL EXPENSES
5505-SEN IOR MANAGEMENT SECURITY PLAN
551 O-FINES & PENALTI ES-OPERATING.
$ 72,714,908
628,831
(621,745)
(508,193)
19,759
(430,943)
(25,000,000)
3,881,028
500,000
(143,745)
(84,806)
(345,752)
(50,271,584)
219,181
(342,126)
(983,334)
261,992
878,293
14,191
27,932
(68,034)
(6,108,154)
2,492
(367,855)
1,382,793
43,605
74,886
320,903
509,465
(377,341)
587,012
1,202,920
(63,210)
(4,159,138)
(168,146)
961,599
4,972,U5
449,663
FERC FORM NO. 1 450.'l
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Originalel A Resubmission
Date of Report
(Mo, Da, Yr)
o411512014
Year/Period of Report
20131Q4
FOOTNOTE DATA
551 6-NON-DEDUCTIBLE POLITICAL EXP.O&M ACCTS
5517-SMSP-UNREALIZED GAIN/LOSS FROM RABBI TRUST
5531 -MTE CASE DISALLOWANCES
5532-DELIVERY ACCRUALS
100,000
57,419
(296,299)
41,261
(488,028)
: 261 Line No.:15 Column: b
7OOg-PROVISION FOR RATE REFUNDS
701o-PROV FOR RATE REFUND-HC RELICENSING (AFUDC)
701 1 -OATT REVENUE DEFICIENCY
7012-REVENUE SHARING
701 3.LANGLEY REVENUE ACCRUAL
7501-REVERSE EQUIry EARNINGS OF SUBSIDIARIES
7so2-ALLOWANCE FOR OFUDC
7so3-ALLOWANCE FOR BFUDC
7509-SMSP-INSURANCE PROCEEDS
$ (375,254)
(13,317,958)
(688,156)
(45O,8221
46,154
6,704,329
14,857,590
7,663,190
236,094
Total 14,675,157
261 Line No.:20 Column: b
8OO1 -VEBA-POST RETI REMENT BENEFITS
8OO9-DEPR TIM ING DIFF.OPERATI NG
801 6.VEBA-POST RETI RE BENEFITS-MEDICARE PART D
8O2O-CONSERVATION EXPENSES
8027-NEVADA OPERAT]NG PROPERry TAX ADJ
8034-REMOVAL COSTS
8038-OREGON EXCESS POWER COSTS
8041.AMERICAN FALLS REFINANCE-OLD COSTS
8o42-GAIN/LOSS ON REACQUIRED DEBT
8Os7.REORGAN IZATION COSTS
8Osg.SOFTWARE-LABOR COSTS DEDUCTED-ACCT 1 07
SOT2.RELICENSING-LABOR COSTS DEDUCTED-ACCT 1 07
8073-REPAI RS DEDUCTION
8077-PREPAID INSURANCE & OTHER EXPENSES
8079-CUSTOM EFFICIENCY INCENTIVE PAYMENTS
8501 -COLI-INSURANCE COSTS
8504-OREGON NON-OP PROPERTY TAX ADJUSTMENT
870$IPCO-162 (M) $1m THRESHOLD
890 1 -REGULATORY ASSET-CU RRENT
8901 -REGULATORY ASSET-NON CURRENT
89O2.REG U LATO RY LIAB I LITY-CURRENT
89o2-REGULATORY LIABILIW-NON CURRENT
IRS INTEREST EXPENSE
STATE INCOME TAX DEDUCTED ON FEDERAL RETURN
$ (1,976,010)
6,606,415
49,599
(133,592)
(106,412',)
10,076,225
(2,217,5191
(47,999)
(1,060,585)
(230,656)
500,000
1,800,000
55,000,000
(293,520)
(13,169,736)
116,161
14
(119,7231
49,803,642
(48,803,642)
(267,585)
267,585
0
8,233,193
Total 63,025,8s6
FERC FORM NO.1 1 450.2
Name oI i(esponoent
ldaho Power Company
This
(1)
(2)
leoort ls:
5.1Rn Orlginal
nA Resubmission
Date of Reoort
(Mo, Da, Yi)
04t1512014
Year/Period of Report
End of 2O13lQ4
IA)(ES ACCRUEIJ, PR,EPAID AND CHARGED DURING YEAR
1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during
the year. Do not include gasoline and other sales taxes which have been charged to lhe accounts to which the taxed material was charged. lf the
actual, or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts.
2. lnclude on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or acrrued 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. lnclude 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.
-tne
No.
Kind of Tax
(See instruction 5)
(a)
BALANCE AT BEGINNING OF YEAR I axesCharoed
QprinsYear(d)
I axesPaidDurinoYear-(e)
Adjust-
ments
(fl
I axes ,\Gcf,ueq(Account 236)(b)
rreDato I axes
ilnclude in Account 165)
1 Federal:
I lncome 10,546 10,744,02(5,837,537
Social Security - (FOAB)-8 14,188,63(14Js8$44
Unemployment 92,41i 92,412
Subtotal Federal 10,538 25,025,08(20,118,593
State of ldaho:
Property 9,450,196 20,654,39r 21,143,262
Non-Operating 11,534 21,27t 22,173
1 lncome -2,489,982 5,445,05i 3,09s,003
11 KWH 91,860 1,388,52r 1,382,070
1 Unemployment 1 946,35i 946,358
1 Regulatory Commission 2,'.t76,39t 2,1 76,398
14 Business License - Sho Ban 15(150
1 Subtotal ldaho 7,063,609 30,632,15:28,765,4',14
1
17 State of Oregon
18 Property 1,341,027 2.768.25C 2,853,056
1e Non-Operating Property 85C 1,71i 1,727
2C lncome -125,615 212,882 93,729
21 Regulatory Commission 14t,18!164,189
22 Unemployment 53,83(53,839
23 Franchise r93,128 859,27(838,674
24 Subtotal Oregon 67,513 't,34',t,877 4,060.14:4.005,214
25
2e State of Montana:
27 Property 135,376 290,15(280,sso
28 Subtotal Montana 135,376 290,15(280,550
29
30 State of Nevada:
3'l Property 466,735 836,54i 730,130
3i Subtotal Nevada 466,73s 836,54i 730,130
aa
3t State of \Afoming
3t Corporate License 4,58:4,583
3(Property 821,427 1,550,37t 1,596,616
3?Subtotal Wyoming 821,427 1,554,961 1,601,199
3t Other States lncome 11,324 121.57t 4,817
3!Payroll Tax Credit -15,281.24t
4(Canada GST tax -5(1,101
41 TOTAL 8,109,78i 1,808,61i 47.239.30i 55,507,01{-2.68'1
FERC FORM NO.1 (ED. 12-96)Paoe 262
Name of Respondent
ldaho Power Company
lnrs KeDon ls:(1) fiAn Original(2) nA Resubmission
uate ot KeDon
(Mo, Da, Yi)
04t't5t2014
Year/Period of Report
End of 20131Q4
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued)
5. lf any tax (exclude Federal and State income taxes)- @vers more then one year, show the required information separately for each tax year,
identif,ing 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 tiaxes 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 (l) 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.
BALANCE AT END OF YEAR S CHARGED Line
No.( laxes accrueonccolnl zs6)
Prepaio I axes(lnd. in Account 165)
Electric(Account 408.1, 409.1 )
Extraordinary ltems
(eccou2t aoe.s)
ASIUSIIT|ENE IO l1EL
iamings (Account 439)(k)
Other
fl)
1
4,917,038 9,918,700 2
t3 14,188,639 3
92,412 4
4.917.025 24,199,751 825.329 5
7
8,961,328 20.653,660
10,639
-139,933 5,177,565 10
98,3'14 1,388,524 1'.|
946,357 't2
2,176,398 13
150 14
8,930,348 30.342.654 289,499 15
1C
1
1,425,833 2,637,037 18
863 19
-6,462 204,664 20
164.189 21
53,839 22
213,724 859,270 23
207.262 1,426,696 3,918,999 141,144 24
25
2C
144,976 290,150 27
1M,976 290.150 28
29
30
360,323 836,542 31
360,323 836,542 32
33
34
4,583 35
775,189 1.550.378 36
775,189 1,554,961 37
128,086 117,534 38
39
1,524 -56 40
15,104,410 1,787,019 45,979,287 1,260,016 41
FERC FORM NO. I (ED. 12-96)Page
This Page lntentionally Left Blank
Name of Respondent
ldaho Power Comoanv
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
0411512014
Year/Period of Report
20131Q4
FOOTNOTE DATA
Account
Accounbt
Total
t, 540,869
(715,540)
825,329
23A
262 Line No.: 8 Column: I
107Account
2l ,2'78
Account
Account
TotaI
$ 396,1-L4
(L28,627 )
$ 26'7 , 481
4
234
ount
Account 234
Total
74 ,7 58
(6, 540 )
8,218
262 Line No.:38 Column: I
Account 409.2
Account 234
6,224
(2,180)
$ 4,044
This amount is an o set to lines 3, 4, L2 d 22. Eainto various 408.1 accounts. In the same month these
408.1 account. These payroll taxes are then allocated
mont employer payroll
amounts are offset with
back to balance sheet
taxes flowa differentandO&M
accounts based on current month labor charges.
This amount s made o components a erence nt nge rate o currentyearaccrual-s of $2 ,625.
262 Line No.:40 :f
FERC FORM NO.1 450.1
Name or Kesponoent
ldaho Power Company
lhrs Keoon ls:(1) p(1An orisinat(2) llA Resubmission
uate ot tteoon
(Mo, Da, Yi)
0411512014
Year/Period of Report
End of 2O13lQ4
ACCUMUT ATED DEFERRED INVESTMENT TAX GREDITS (Account 255)
Report below information applicable to Account 255. Where appropriate, segregate the balances and transactions by utility and
nonutility operations. Explain by footnote any conection adjustments to the account balance shown in column (g).lnclude in column (i)
the average period over which the tax credits are amortized.
-tne
No.subdfvfions
EarancefarI'e9rnnrng
(b)
Deferred for Year l\ilo@uons IoCurrent Year's lncome Adjustments
(s),\caount t\o.(c),{nount(d)AOCOUnI NO.(e),\tTtounI(0
3%
4%60't,44(59,441
7o/o
10%22,463,42t 1,415,86:
'110/o 1,213,88:26,03(
Other - State 55,617,84(411.4 2,344,2501 41'1.4 1,618,221
TOTAL 79,896,60:2,344,2501 3,119,56:
1(Line6Col A11%
1',
'ti State of ldaho 55,617,M(411.4 2,344,25(4'.t1.4 1,618,221
1
,lt
1t
1t
1i
1
1
2C
21
22
za
24
2!.
2t
2',
2t
3(
3'
5/
3i
3t
3{
3(
3i
3t
3(
4(
41
4t
4.!
4t
42
41
41
4t
FERC FORM NO. r (ED. 12-89)Page
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5]e,n Originat(2) l--lA Resubmission
Date of Reoort
(Mo, Da, Yi)
0411512014
YeaflPenoo ol Kepon
End of 20131Q4
ACCUMULATED DEFERRED INVESTMENT TAx CREDITS (Account 255) (continuecl)
Balance at Endof Year
/h\
Averaoe rEfiouof Allocaiion
to lncome/i'l
ADJUSTMENT EXPLANATION Ltne
No.
1
2
541.998 10.12 3
4
21,047,565 15.87 5
1,187,853 46.64 6
56,343,874 34.37 7
79,121,290 8
I
10
11
56,343,874 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.I (ED.12.89)Paoe 267
Name of Respondent
ldaho Power Company
This Reoort ls:(1) EAn Orisinal(2) nA Resubmission
uate ol Keoon
(Mo, Da, Yi)
0411512014
Yea/Heflod or Kepon
End of 20131Q4
OTHER DEFFERED CREDITS (Account 253)
1. Report below fte particulars (details) called for conceming other defened credits.
2. For any defened credit being amortized, show the period of amortization.
3. Minor items (5% of the Balance End of Year for Account 253 or amounts less than $100,000, whichever is greater) may be grouped by classes.
Line
No.
Desoiption and Other
Deferred Credits
(a)
Balance at
Beginning of Year
(b)
DEBITS
Credits
(e)
Balance at
End of Year
(o
contra
Account(c)
Amount
(d)
1 Smart Grid (253200)4,644,939 107t401 313,305,643 309,560.953 900,249
2
3 Point to Point Trans Study(253201)875,653 242 975,466 999,515 899,702
4
5 FTV (253202)3,666,66(400 400,00c 3,266,666
6 (Amort Period Mar 1998-Feb 2023)
7
I Boardman To Hemingway (253220)851,851 107 8s3,630 1,779
o
10 Sho Ban Trans ROW (253480)232,50(242 15,000 217,500
11 (Amort Period Jan 2005-Dec 2027)
12
13 Milner Falling Water (253953)859.48(186/401 1,063,636 919,891 715,735
14 Amort Period (Feb 1992 -Feb2017l
15
16 Postretirement Benefi ts (253960)2j04.751 401 621,74!1,483,006
17
18 Direc{ors Defened Compensation 4,657,374 't3'l 1.142.62i 711,684 4,226.431
19 (253980-253999)
20
21 Operations Accrual (253550)23z401 50.762 726,74 676,000
22 (amort period 1 year br dues)
23
24 USAF Battery Replacement (253906)1 107 412,21t 412,201
25
26 89,64C various 117,151 28,944 1,432
27
28
29
30
31
32
33
34
35
36
37
38
3S
40
41
42
43
44
45
46
47 TOTAL 17,982,872 318,957,882 313,361,731 12.386.721
FERC FORM NO. t (EO. t2-941 Paoe 269
Name of Respondent
ldaho Power Comoanv
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
0411512014
Year/Period of Report
2013lA4
FOOTNOTE DATA
Accounts included in minor
253042
FERC FORM NO. 1 450.1
Name of Respondent
ldaho Power Company
This Reoort ls:(1) fiAn Odsinal(2) jA Resubmission
Date of Reoort(Mo, Da, Yi)
0411512014
YeaflPenoo ot Kepon
End of 2O13lQ4
ACCUMULATED DEFFERED INGOME Tru(ES - OTHER PROPER,TY (ACCOUNI 262)
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 (Speciff),include deferrals relating to other income and deductions.
-ine
No.
Account
(a)
Balance at
Beginning of Year
(b)
CHANGES DURING YEAR
Amounts Debited
to Account 410.1
(c)
Amounts Credited
to Account 41 1 .1
(d)
Electric 406,282,8sS 35,579,28t 5,025,12t
Gas
4 Other
TOTAL (Enter Total of lines 2 thru 4)35,579,28t 5,025,12t
Non-Operating Property
Other - Regulatory Asset for I 673,996,554
TOTAL Account 282 (Enter Totral of lines 5 thru 't,080,279,413 35,579,28t 5.025.12t
11 Federal lncome Tax 928,084,368 35,276,76t 5.025,12t
12 State lncome Tax 152,195.045 302,51(
1 Local lncome Tax
NOTES
FERC FORM NO. 1 (ED. 12-96)Page 274
Name of Respondent
ldaho Power Company
I nts Keoon ts:(1) 5]An originat(2) ;--'lAResubmission
Date of Report I Year/Period of Report(Mo, Da, Yi) I ena ot 2o1sle4
o411512014
ACCUMULATED DEFEttt(EU INUUME, lA Es - (JIHEK l-KUl'EKl Y (ACCOUnI 262) (Uontnueo)
3. Use footnotes as required.
CHANGES DURING YEAR ADJUSTMENTS
Balance at
End of Year
(k)
Line
No.Amounts Debited
to Account 410.2
(e)
Amounts Credited
to Account 41 1.2
(0
Debits Credits
Acoount
Credited(g)
Amount
(h)
Account
Debited
(i)
Amount
U)
436,837,01 2
3
4
436,837,01 5
6
82 430,03 82 32,686,93:706,253,45r 7
I
430,03;32,686,93:1,'143,090,46(I
360,73!22,188,23.980,163,50:11
69,29t 10,498,691 162,926,96,12
13
NOTES (Continued)
FERC FORM NO. r (ED. t2-96)Page 275
This Page lntentionally Left Blank
Name of Respondent
ldaho Power Companv
This Report is:
(1) X An OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
0411512014
Year/Period of Report
2013tQ4
FOOTNOTE DATA
Account
Depreciation Timing
Diff-Operating
Relicensing-Labor Costs Acct
107
C|AC-Taxable-Acct 107
Valmy Capitalized ltems
Software-Labor Costs 1 07
Fees ln Acct 107
TOTAL
DR
410.2
e
CR
411.2
f
Beginning
Balance
b
Acct
dr
i
33,953,833
(109,2521
305,015
1,429,699
424,062,833
14,385,201
(3,060,909)
198,266
1,567,943
316,318
390,753,887
14,494,453
858,810
274,766
138,254
FERC FORM NO.1 1 450.'l
Name of Respondent
ldaho Power Company
This Reoort ls: I Date of Reoort(1) [lAn orisinal | (Mo, Da, Yi)(2) 1-1A Resubmission | 0411512014
Year/Period of Report
End of 2O13lQ4
AUUUMULAI E,U UEFFEKEU INUUME IAAE!i - L,I HEK (ACA)UNI Z6JI
1. Report the information called for below concerning the respondents accounting for defened income taxes relating to amounts
recrrded in Account 283.
2. For other (Specifu),include defenals relating to other income and deductions.
_tne
No.
Account
/a)
Balance at
Beginning of Year
(b)
CHANGES DURING YEAR
to Acc131t 410.1 to Accolglt 411.1
Other Electric -- See Note 61,579,37i 26,893,284
5
Other - See Note
TOTAL Electic (Totral of lines 3 thru 8)180,386,916 61,579,372 26,893,24
11
12
1:
1
1t
1
,|TOTAL Gas (Totral of lines 11 thru 16)
1 Other - See Note
1 TOTAL (Acct 283) (Enter Total of lines 9, 1 7 and 1 8)181,1 s9,151 61,579,372 26,893,28r
21 Federal lncome Tax 15't,966,147 51,656,10i 22,559,54'.1
22 Strate lncome Tax 29,193.004 9,923,26t 4,333,74i
22 Local lncome Tax
NOTES
FERC FORM NO.1 (ED. 12.96)Draa ,ae
Name of Respondent
ldaho Power Company
This Reoort ls:(1) fiAn Original(2) nA Resubmission
Lrate ot Keoon
(Mo, Da, Yi)
0411512014
YeailHenoO ot Kepon
End of 20131Q4
ACCUMULA] Et' IJEI-ERRTL' INCOMts IAXE,S - O IHEFT (ACCOUNI 283) (CONtiNUCd)
3. Provide in the space below explanations for Page 276 and 277. lnclude amounts relating to insignificant items listed under Other.
4. Use footnotes as required.
CHANGFS DIIRING YtrAFI JUSTMENTS
Balance at
End of Year
(k)
,{nounls Lreotleo
to Account 410,2
Iel
Amounts credited
to Account 411.2
{fl
Debits Credib Line
No.Accountc'?$i"d Amount
(h)
AOOOUntDebited
fi)
Alnounr
fi)
91.67231e 3
4
5
6
7
77,822,73t 45,577,95C 8
77,822,731 137.250.26e 9
't1
'12
13
14
15
't6
17
102,311 35.93(838,607 18
102,311 35,93(77,822,73t 138,088,873 19
85,824 30,14r 65.281,97t 115,836,413 21
16,,t87 5.79'12,540,762 22,252,46A 22
23
NOTES (Continued)
FERC FORM NO. I (ED. 12.96)Paqe 277
Name of Respondent
ldaho Power Companv
This Report is:
(1) X An OriginalQ) A Resubmission
Date of Report
(Mo, Da, Yr)
0411s12014
Year/Period of Report
2013tQ4
FOOTNOTE DATA
No.:3 Column: b
Account(a)
Chanoes durlno Year Ad DT Ad Cr
Beginning
Balance
b
DR
4L0.t
c
CR
411.1
d
DR
4L0.2
e
CR
AtL.2
t.
Acct.
Cr
6
Amt
h
ct
Dr
I
Amti
Ending
Balance
k
Pension Expense
PCA Expense
Conservation ExpensesFixed Cost AdjustmentRegulatoryAsset-Current
Oregon PCAM
Reg Liab-Non Current
Oregon Excess Pwr
Costs
OATT RevenueDeficiency
Rene$rab1e EnergyCertif
Langl-ey RevenueAccrualReorganization Costs
2011 LIDAR Surveys De
Bennett Mtn Maint DefIntervenor Eunding
Orders
OPUC Grid west toans
EERC Grid west ExpEmission Allowances
PS & I CoSIS
Bonus Deferral
DeLivery Accruals
2L , 525 ,21 6
13,515r 780
5,Lt3,619
5,245,619
4,458,7L8
2,493,L34
1,7 22,241
823,508
650 ,767
637 ,337
313, 644
180,350
L53,425
87, 831
56,239
L2,020
LO,9203,L32
974(8,518)
(9,25s1
u, 5bz, 5u1
79,653,676
L , g2g ,2042,7!3,502
25 ,115 , 47 6
143,813
2, 411 ,922
0
1,096,501,
18, 044
26, 599
1, 195
858
9, U55, J4U
5, 533, 957
325,5t9
6.O35.692
Z
1
313, 310
866,939
269,035
515,990
90,L75
L7 ,047
29 ,2"17
5,548
L0,920
5, 078
9'7 4
2,452
16, r.31
20 t232,5L733,169,456
1, 409 , 026
7 ,633,60223,538,502
2 , 636, 947
I ,826 | 860(43,431)
381-,132
2L'7,848
331,688
90,175
136,378
58,554
82,838
6, 4'12(0)
(75r")
(0)
(10,969)
124,5281
TOTAL 50 , 9AO, 226 bL,at9,Jtz zo, 6Y3 , 264 0 0 0 U 9L , 572 ,3L6
Line No.: 8 Column: b
Account(a)
Chanqes clurr-no Year Acl'i Dr AO] Ur
Beginning
Balance
b
DR
410.1
CR
411.1
d
DR
4L0.2
e
CR
4LL.2f
Acct.
Cr
o
Amt
h
Acct
Dri Amti
!.inor.ng
Balance
k
Pension-EAS 158
Postretirement
PIan-FAS 158Unrealized Gai.ns on
Market Sec
114,530,586
6,214,273
2 , 655 ,828
190
190
279
67,136,27r
g, o3o,63g
2,655,g2g
4'l ,394,315
(1,815,366)
0
TOTET 123, 4O0,587 0 0 0 0 17 t822,138 0 45,571,949
EDc-Unrealzd G/L FromRabbit Trust
SMSP-Unrealzd G/L EromRabbi TrustRoyalty fncome
Oregon Non-Op Prop Tax
s during Year
79,228
23,078
5
13,491
22 | 448 122,4481
325,457
337
TOTAL
FERC FORM NO.1 1 450.1
Name o? Kesponoent
ldaho Power Company
I nts Keoort ls:(1) fiRn Originat
(21 l-lA Resubmission
L'ate ol t(eoon
(Mo, Da, Yi)
0411512014
Yearrenoo ol Keport
End of 20131Q4
OTHER REGULATORY .lABlLlTlES (Account 254)
1. Report below the particulars (details) called for concerning other regulatory liabilities, including rate order docket number, if
applicable.
2. Minor items (5% of the Balance in Account 254 at end of period, or amounts less than $100,000 which ever is less), may be grouped
by classes.
3. For Regulatory Liabilities being amortized, show period of amortization.
Line
No.
Desoiption and Purpose of
Other Regulatory Liabilities
(a)
Balance at Begining
of Cunent
QuarterA'ear
(b)
DEBITS
Credits
(e)
Balance at End
of Cunent
QuarterfYear
(0
,\ccoun(
Credited
(c)
Amounr
(d)
1 Market to Market Shoil Term - (254001)4,294,538 175 9,968,30r 7,057,99r 1.3U.221
2 IPUC Order#2866'l
3
4 FAS t33 - Martet to Market - (254203)284,782 115 953,'r3;956,48 288,13:
5 IPUC Order# 28661
6
7 oER 32368-323697 - Q54007 |581,743 131t107 581,741
8 Order# 32368
I
10 Untunded Accum Def lncome Tax (254966)51,285,735 van0us 497.571 50,788,06(
11
12 ldaho DSM Rider(254201)4,0/O,622 vanous 39.410,88'42,056,00 6.685,74t
13 Order#29026
14
15 Oreoon DSM Rider -(2542021 3,914,935)van0us 1,530,661 1,751,41i -3,694,18:
16 Advise #05{3
17
18 Oreoon Solar Pilot - (2540051 1.192.621 vadous 323,10i 917.49 1,787,01i
'ts Order #10-198
20
21 Green Taqs Oreqon (254415)154,393 1823 158,26(26,6E 22,80i
22 Order #11{86
23
24 Reouhtorv Unfunded Accum Def lncome Tax (25'[4191 3,798,916 648,02(1,078,06r 4,n8,951
25
26 Revenue Sharins (2541 0'l )7,1il,n1 't82 17,166,'t 3'17.616.95i 7.602.04:
27 IPUC Oder#32558
28
29 BPA Credit Residential ldaho (254401)549,870 131/400 1,779,191 '1.853.87r 624,55t
30 Advice # 11{3 flD) #11-15 (OR)
31
32 WAQC Carryover (254901)87,631 various 87,63 90,071 90,07r
33 IPUC Order#29505
34
35 ldaho Boardman Decommissinq - (254393)291,189)400 500,3&791,48r
36 IPUC Order#32549
37
38 Oreqon Boardman Decommbsinq - (254394)9s,380 400 23,14r 118.53
39 OPUC Order#12235
40
4 TOTAL 69,401,786 74,035,271 75,010,484 70,377,000
FERC FORM NO. rrlo (REV 02.041 Paoe 27E
Name ot Respondent
ldaho Power Company
This Report ls:(1) EAn Original(2) l--'lAResubmission
Date of Reoort
(Mo, Da, Yi)
04t1512014
Year/Period of Report
End of 20131Q4
OTHER REGULATORY LIABILITIES (Account 254)
'1 . Report below the particulars (details) called for concerning other regulatory liabilities, including rate order docket number, if
applicable.
2. Minor items (5% of the Balance in Account 254 at end of period, or amounts less than $100,000 which ever is less), may be grouped
by classes.
3. For Regulatory Liabilities being amortized, show period of amortization.
Line
No.
Description and Purpose of
Other Regulatory Liabilities
(a)
Balance at Begining
of Current
Quarterf/ear
(b)
DEBITS
Credits
(e)
Balance at End
of Cunent
QuarterfYear
(0
AC@UNI
Credited
(c)
,\mounr
(d)
1 Bridger Depreciation #12-296 -(254800)$8,n4 320,80i 489,02;
2
3
4 112,996 vanous 407,071 374,6 80,54{
5
6
7
I
I
10
11
12
13
14
15
16
't7
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41 TOTAL 69,401,786 74,035,271 7s,010,484 70,377,000
FERC FORM NO. tr3-Q (REV 02-04)Pase 27E.1
Name of Respondent
ldaho Power Comoanv
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
0411512014
Year/Period of Report
201'3lA4
FOOTNOTE DATA
Accounts
254004
254006
254402
254403
254404
2544tL
n minor items:
FORM NO.1 450.1
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5]An Original(2) ;--lA Resubmission
uate ot KeDon
(Mo, Da, Yi)
04t1512014
Year/Period of Report
End of 20131Q4
ELEGTRIC OPERATING REVENUES (Account 400)
1. The following instructions generally apply to the annual version of these pages. Do not report quarterly data in columns (c), (e), (f), and (g). Unbilled revenues and MWH
related to unbilled revenues need not be reported separately as required in the annual version of these pages.
2. Report below operating revenues for each prescribed account, and manufactured gas revenues in total.
3. Report number of customers, columns (0 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. lf increases or decreases from previous period (columns (c),(e), and (g)), are not derived from previously reported figures, explain any incrnsistencies in a footnote.
5. Disclose amounts of $29),000 or greater in a footnote for accounts 451, 456, and 457.2.
-ine
No.
Title of Account
(a)
Operating Revenues Year
to Date Quarterly/Annual
(b)
opeftlting Revenues
Previous year (no Quarterly)
{c)
1 Sales of Electricity
2 (440) Residential Sales 513.914.273 431,555,478
3 (442) Commercial and lndustrial Sales
Small (or Comm.) (See lnstr. 4)436,445,53€375,354,223
Large (or lnd.) (See lnstr. 4)165,918,26€145,054,266
e (444) Public Street and Highway Lighting 3,828,398 3,588,495
7 (445) Other Sales to Public Authorities
8 (446) Sales to Railroads and Railways
I (448) lnterdepartmentral Sales
10 TOTAL Sales to Ultimate Consumers 1.120.106,476 955.552.462
1',l (447) Sales for Resale 54,472,513 61,534,224
12 TOTAL Sales of Electricity 1,174,578,989 1 ,017,086,686
13 (Less) (449.1) Provision for Rate Refunds 18,735,08t 17.809,784
14 TOTAL Revenues Net of Prov. for Refunds 1,155,843.901 999,276,902
15 Other Operating Revenues
16 (450) Forfeited Discounts
17 (451 ) Miscellaneous Service Revenues 3,645,018
18 (453) Sales of Water and Water Power
19 (454) Rent from Electric Property 24,427,451 23,226,450
20 (455) lnterdepartmental Rents
21 (456) Other Electric Revenues 27,882,803
22 (456.1) Revenues from Transmission of Electricity of Others 21,936,38i 21,0s4,698
23 (457.1) Regional Control SeMce Revenues
24 (457.2) Miscellaneous Revenues
25
26 TOTAL Other Operating Revenues 86,306,967 75,808,969
27 TOTAL Electric Operating Revenues 1,242,150,86t 1,075,085,871
FERC FORM NO. lr&Q (REV. 12-0s)Page 300
Name of Respondent
ldaho Power Company
lnrs KeDon ls:(1) fiAn Orisinal(2') ;-1A Resubmission
uate ol Heoon
(Mo, Da, Yi)
0411512014
YearHenoo ot Kepon
End of 2O13lQ4
ELECTRIC OPEMTING REVENUES (Account 400)
respondent if such basis of classification is not generally greater than 1000 Kw of demand. (See Accounl442 of lhe Uniform System of Accounts. Explain basis of classification
in a footnote.)
7. See pages 1 08-1 09, lmportant Changes During Period, for important netv tenitory 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. lnclude unmetered sales. Provide details of such Sales in a footnote.
MEGAWATT HOURS SOLD AVG.NO. CUSTOMERS PER MONTH Line
No.Year to Date Quarterly/Annual
(d)
Amount Previous year (n0 Quarterly)
(e)
Cunent Year (no Quarterly)
(fl
Previous Year (no Quarterly)
(o)
5.365.313 5,039,35r 418,892 413,61(2
6,040,697 5,88'1,58;83,439 82.48!4
3,'t81 ,866 3,132,57i 1',t7 11{5
31.478 31,79t 2,205 2,06(6
7
8
I
14,619,354 14,085,31(504,653 498,282 10
2,183,261 11
16,302,681 16,268,57t 504,653 498,28i 12
13
16,302,681 16,268,57t 504,653 498 14
Line 12, column (b) includes $ 10,892,103 of unbilled revenues.
Line 12, column (d) includes 36,316 M\A/H relating to unbilled revenues
FERC FORM NO. 1/3-Q (REV. 12-0s)Pase 301
Name of Respondent
ldaho Power Companv
This Report is:
(1) X An OriginalQ) A Resubmission
Date of Report
(Mo, Da, Yr)
o4l't512014
Year/Period of Report
2013tQ4
FOOTNOTE DATA
This amount is 1 erent from page 311the Sales for Resale
column G
MWH thatTotal- in
was not
the amount
corrected
of 33in all MWH due to
correction made to svstems.
Service Establishment,/Connection(Incl-udes late and after hourField Coflections ChargesMisc. Under $250,000
Charges
charges )
$ 2,782,491,
266 t 120
516,7 46$ 3,565,357
This consists of :
s cons sts of :
DSM ActivityStand-by-ServlceMisc. items under $250r000
$35,636,570
352,915
388, 288
s36,377,7'13
FERC FORM NO.1 450.1
Name ot Kesponoent
ldaho Power Company
lnrs Keoon ls:(1) 5.1An Orisinal
(21 l-lA Resubmission
Date of Report I Year/Period of Report(Mo, Da, Yi) I eno ot 2o1it14
0411512014
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date ficr Sales for Resale which is reported on Pages 31 0-31 1 .
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. lf 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), he 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.
Ltne
No.
trutItuEI altq I [tE ut ndlE Sqlguute
(a)
tvtYYIt o(Jt(l
(b)
KevEItue
(c)
veraae t\lumDer
of ciB\omers pr}l:i,i#"T[?fb?rd"(0
440 - Residential Sales:
01 - Residential 5,298,721 489,696,04'417,33t 12,69',0.092r
03 - Residential Master Meter 4,49t 392,26(2i 195,56r o.o87i
05-Residential -TOD 28,00(2,473,241 1,53r 18.24i 0.088:
15 - Dusk to dawn lighting 2.701 640,76r 0.237i
Unbilled Revenues 31,371 6,931,67i 0.2201
Other Revenues 13,780,28r
Total 440 s,365,31i 4't8,89'12,80t 0.095{
1(442-Commercial & lndustial Sales
11 07 - General service 161 ,91 t 18,460,73t 30,65(5,28i o.1't4(
1t 09P - General service 468,731 27,726,52t 20t 2,297,701 0.059i
'ti 09S - General service 3,288,901 223,240,95X 32,43(101,38i 0.067(
1t 09T - General service 4,881 315,581 1,628,00(0.064(
1t 15 - Dusk to Dawn Light 4,151 728,59(0.175:
1t 19P - Uniform rate contracts 2,194,79i 't15,466,28(10(20.135.751 0.052(
1',195 - Uniform rate contracts 6,34(369,72(1 6,349,00(0.058i
1 19T - Uniform rate contracts 112,67i 6.413.56(37,557,66i 0.056(
1 24S - lnigation Pumping 2.097,251 157 ,651,251 19,28t 108,73r 0.0751
2t 40 - General service 11,O3t 891,26:85(12,97t 0.080t
2'Special Contracts 866,56,39,897,57(288,854,66i 0.046(
2t Commercial & lndustrial Unbill 5,30',3,983,98t 0.751(
2:l Other Revenues 7 ,217,705
2t Tots,l 442 9,222.56i 83,55(110,37(0.065:
2t
2t 444 - Public Street Lighting:
2i 40 - General service 1,141 92,43t MI 2,541 0.0811
2t 41 - Street lighting 27,85"3,53s,38(1,31(21,261 0.126(
2t 42 - Traffic control lighting 2,84i 164,601 M1 6,36(0.057t
3(Unbilled -361 -23,55i 0.065:
31 Other Revenues 59,53t
3t Tots,l 444 31,47t 3,828,39t 2,20.14,27(0.1211
3:
3t
aa
3(
3;
3t
2(
4(
41 TOTAL BiIIed 14.583.031 1.109.214.37i 504.28.81 0.076
42 I otal unbrlled t<ev.(see lnstr. 6l 36,31(10.892.10:0.299(
43 TOTAL 14,619,35,1,120,'t06,47C 504,65:28,96r 0.076(
FERC FORM NO. I (EO. 12-95)Page 304
Name of Respondent
ldaho Power ComDanv
This Report is:
(1) XAn OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
0411512014
Year/Period of Report
20131Q4
FOOTNOTE DATA
s amountduring thebroken down
s erent from page 30L column B
year where a rate 07 was recorded to 2 in the amount ofresidential account.
schedule.
line
therate
4 due to
Page 301
an erroris
s amounterror during
broken down
FERC account and paqe 304 is b
is different from page column B ne4a
the year where a rate 07by FERC account and page
n the amount o due to
was recorded to the residential account.
304 is by rate schedule.
Page 301
anis
301 Line No.:24 Column: c
FORM NO.1 .1 450.1
Name of Respondent
ldaho Power Company
I nts r(e(1) E(2t T
on ls:
An Original
A Resubmission
Date of Reoort
(Mo, Da, Yi)
0411512014
Year/Period of Report
End of 2O13lQ4
SALES FOR RESALE (Account 447)
'1 . Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. ln 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). ln addition, the reliability of requirements service must
be the same as, or second only to, the supplier's service to its own ultimate consumersi.
LF - for tong-term seryice. "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.9., 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.
lF - 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 ftom a designated generating unit. 'Long-term" means five years or Longer. The availability and reliability of
service, aside ftom transmission constraints, must match the availability and reliability of designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service except that'intermediate-term' means
Longer than one year but Less than five years.
tine
No.
Name of Company or Public Authority
(FooElote Affliations)
(a)
Statistical FERC Rate
Schedule orTariff Number
(c)
AveraoeMonthly Billing
Demand (MW)
(d)
Actual Demand (M\M
Classifi-
cation
(b)
Avenaoe
Vlonthly NCF Deman
(e)
AVeraoeMonthly CPDemanr
(f)
I Arizona Public Service Co.SF WSPP nle nlz nlz
2 Avista Corp.SF WSPP nle nl.nlz
3 Barclays Bank PLC nlz nle nla
4 Black Hills Power lnc.SF WSPP nla nl.nlz
5 Black Hills Power lnc.WSPP nle nle nle
6 Bonneville Power Administration SF WSPP nlz nl.nlz
7 BP Energy Company SF WSPP nle nlz nlz
I Calpine Energy Services, L.P.SF WSPP nle nle nlz
I Cargill Power Markets LLC WSPP nlz nle nle
10 Cargill Power Markets LLC nlz nle nla
11 Cargill Power MarkeF LLC SF WSPP nle nla nlz
12 Citigroup Energy lnc.SF WSPP nlz nle nla
13 Citigroup Energy lnc.nle nl.nlz
14 City of Glendale SF WSPP nlt nle nla
Subtotal RQ 0 c
Subtotal non-RO 0 c
Total 0 0
FERC FORM NO. I {ED. 12.90I Paoe 310
Name of Respondent
ldaho Power Company
tnts Ke(1) E(2',) T
rOII lS:
An Original
A Resubmission
Date of Reoort(Mo, Da, Yi)
0411512014
Year/Period of Report
End of 20131Q4
SALES FOR RESALE (Account 447)(Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service fom 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. ln Column (c), identifo 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 (0. 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 fi). 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,iine24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours
Sold
(q)
REVENUE Total($)
(h+i+j)
ft)
Line
No.Demand Charges
($)
(h)
Energy Charges
($)
(i)
umer unarges
($)
(i)
31,700 825.11(825,1'.!t 1
10s,321 3,805,33r 3,805,33/2
217,584 217,5U 3
35 1,45(1,45(4
1,02(1,02t 5
1 33,1 37 3,804,361 3,804,361 6
12,800 263,20C 263,20(7
79 2,84C 2,84(8
447,121 447,'.t21 9
325,48S 325,48(10
107,775 3,023,51:3,023,51:1'l
16 49€49(12
23.311 23,311 13
31,200 1,231,764 1,231,761 14
0 0 0 0 0
't,683.294 0 53,430,856 1,041,657 54,472,513
1,683,294 0 53,'|i]0,856 1,041,657 il,472,513
FERC FORM NO.1 (ED.12-90)Page 311
Name of Respondent
ldaho Power Company
rnts Ke(1) E(2) T
lort IS:
An Original
A Resubmission
Date of Reoort(Mo, Da, Yi)
0411512014
Year/Period of Report
End of 20'l3lQ4
SALES FOR RESALE (Account 447)
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( i,e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enler 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. ln 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). ln 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.9., 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 sefter can unilaterally get out of the contract.
lF - for intermediate-term firm service. The same as LF service except that "intermediate-term' means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
-ine
No.
Name of Company or Public Authority
(Foohote Affiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Averaoe
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
r,tonr'i]"fi6Fberan
(e)
AVeraoeMonthly CFrDeman<
(0
1 Clatskanie PUD }F WSPP nlz nlz nle
2 Con6tellation Energy Commodities Group,SF WSPP nlz nlz nla
3 Constellation Energy Control & Dispatch WSPP nlz nlt nle
4 EDF Trading North America, LLC SF WSPP nle nli nle
5 EDF Trading North America, LLC WSPP nlz nle nle
6 Eugene Electric Board SF WSPP nlz nlt nlz
7 Exelon Generation Company. LLC SF WSPP nla nlz nla
8 lberdrola Renewables, lnc,.WSPP nle nli nle
I I lberdrola Renewables, lnc.SF WSPP nlz nlt nla
10 lberdrola Renewables, lnc.WSPP nle nlt nlz
11 J.P. Morgan Ventures Energy Corporation SF WSPP nle nlz nle
12 Jeffies Bache nlz nlt nle
13 Los Angeles Department of Water & Power SF WSPP nla nlz nle
14 Macquarie Energy LLC WSPP nlz nlt nle
Subtotal RQ 0 0
Subtotal non-RQ 0 0
Total 0 0
FERC FORM NO, 1 (ED. 12-9OI Paoe 310.1
Name of Respondent
ldaho Power Company
I nts xeport ts:(1) EAn Original(2) llA Resubmission
uate ot Kepon(Mo, Da, Y0
0411512014
YearFenoo ot Kepon
End of 20131Q4
SALES FOR RESALE (Account 447)(Gontinued)
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 ofthe Length ofthe contract and service from designated units ofLess 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-upsn 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. ln Column (c), identifr 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 megawafts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawaft 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 fi). 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
40'l,iine24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours
Sold
(s)
REVENUE Total ($)
(h+i+i)
(k)
Line
No.Demand Charges
($)
(h)
Energy Charges
($)
(i)
umer unarges
($)
Ii'l
22 't,1'l 1,'.!1,1
819 28,00c 28,00(2
3 111 11 3
42,424 1,685,96S 1,685,96(4
-31,26€-31,26r t
3,853 149,01i 149,01;6
110,468 4,549,129 4,549,121 7
54,241 54,24,I
11,492 296,328 25fi,321 I
75 1,275 't,271 10
16,350 471,697 471,691 11
-1,980,404 -1,980,40 12
'175,600 6,993,895 6,993,89r 13
-641,454 -641,451 14
0 0 0 0 0
1,683.294 0 53,430,856 1,041,657 54,472,513
1,6E3,294 0 53,430,E56 1,041,457 il,472,513
FERC FORM NO.1 (ED. t2-90)Page 311'1
Name ol Kespondent
ldaho Power Company
tnts K€(1) E(2) r
DOn ls:
]Rn originat''lA Resubmission
Date of Report(Mo, Da, Yr)
04t1512014
Year/Periocl ot Report
End of 20131Q4
SALES FOR RESALE (Account 447)
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any seftlements 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 afiiliation the respondent has with the purchaser.
3. ln 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). ln addition, the reliability of requirements service must
be the same as, or second only to, the supplie/s service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and nfirm" means that service cannot be intenupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.9., 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.
lF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service except that'intermediate-term" means
Longer than one year but Less than five years.
ine
No.
Name of Company or PublicAuthority
(Footnote Affliations)
(a)
Statistical
Classifi-cation
(b)
FERC Rate
Schedule orTariff Number
(c)
Averaoe
Monthly Billing
Demand (MW)
(d)
Actual Demand (M\M
rrront ii"fiSF=o"r"n
(e)
Averaoe
Monthly CPDemanr
(0
1 Macquarie Energy LLC WSPP nlz nlz nl.
2 Macquarie Energy LLC SF WSPP nli nle nlz
3 Morgan Stanley Capital Group lnc.SF WSPP nlt nle nl.
4 Morgan Stanley Capital Group lnc.WSPP nla nle nlz
5 Nevada Power Company, dba NVEnergy SF WSPP nli nle nlz
6 Noble Americas Gas & Power corp.SF WSPP nli nlz nle
7 NorthWestem Energy WSPP nli nle nle
8 NorthWestem Energy SF WSPP nlt nle nla
I PacifiCorp lnc.SF WSPP nlz nlz nle
10 PacifiCorp lnc.T-7 nli nla nl."
11 Pordand General Electic Company WSPP nla nle nle
12 Porfland General Elecbic Company WSPP nlz nl.nlz
13 Pordand General Electric Company SF WSPP nla nle nla
14 Powerex Corp.WSPP nlt nlz nle
Subtotal RQ 0 0
Subtotal non-RQ 0 0
Total 0 0
FERC FORM NO.1 (ED. 12.90I Paoe 310.2
Name of Respondent
ldaho Power Company
tnts Keoon ts:(1) []Rn Orisinat(2) l-lA Resubmission
Date of Reoort
(Mo, Da, Yi)
0411512014
Year/Period of Report
End of 20131Q4
SALES FOR RESALE (Account447) (Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-deflned 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-upsn 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. ln Column (c), identiff 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 megawaft basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column (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,iine24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours
Sold
(s)
REVENUE Total($)
(h+i+j)
(k)
Line
No.Demand Charges
($)
(h)
Energy Charges
($)
(i)
umer unarges
($)
(i)
7i 7',1
67,403 1,937,592 1,937,59'2
58,802 1,902,934 1,902,93,3
215,58r 215,58t 4
25 65(65(5
800 23,UC 23,641 6
280 5,15C 5,15(7
13,850 644,137 644,13 8
34,702 't.062.479 1.062,47!I
89 2,509 2,50(10
8,57(8,57(11
400 't1,250 11,251 12
18,021 531,15€53't,15(13
2,550 38,675 38,67r 14
0 0 0 0 0
1.683.294 0 53.430,856 1,04't.657 54,472,513
1,683,294 0 53,,|i!0,856 1,041,657 54,472,513
FERC FORM NO. 1 (ED. 12-90)Page 311.2
Name of Respondent
ldaho Power Company
This R€(1) E(2') T
oort ls:
]Rn original
lA Resubmission
uate oI Keoon
(Mo, Da, Yi)
04115t2014
YeaflPenoo ot Kepon
End of 20131Q4
SALES FOR RESALE (Account 447)
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any seftlements 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. ln 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). ln 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 intemrpted for economic
reasons and is intended to remain reliable even under adverse conditions (e.9., 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.
lF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
-ine
No.
Name of Company or Public Authority
(Footstote Affiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule orTariff Number
(c)
Averaoe
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
nvEtdgE
l\/onthly NCF Deman
(e)
AveraoeMonthly CPDeman<
(0
1 Powerex Corp.SF WSPP nli nl."nla
2 PPL EnergyPlus, LLC WSPP nli nle nlz
3 PPL EnergyPlus, LLC WSPP nli nle nlz
4 PPL EnergyPlus, LLC SF WSPP nlt nla nle
5 Puget Sound Energy, lnc.WSPP nlt nlz nla
6 Puget Sound Energy, lnc.SF WSPP nli nle nlz
7 Rainbow Energy Ma*eting Corporation WSPP nlt nle nlz
8 Rainbow Energy Marketing Corporation SF WSPP nle nli nla
I Royal Bank of Canada nli nle nla
10 Seatfle City Light WSPP nli nfi nle
11 Seatfle City Light SF WSPP nli nli nlz
12 Shell Energy North America (US), L.P.WSPP nlz nlz nlt
13 Shell Energy North America (US), L.P.WSPP nle nli nle
14 Shell Energy North America (US), L.P.SF WSPP nlz nla nlz
Subtotal RQ 0 0
Subtotal non-RQ 0 0
Total 0 0
FERC FORM NO. r (ED. 12-90)
Name of Respondent
ldaho Power Company
I nrs KeDon ts:(1) []en orisinat(2) l-lA Resubmission
Date of Reoort
(Mo, Da, Yi)
04t1512014
YeailPenoo ot Kepon
End of 20131Q4
SALES FOR RESALE (Account 447)(Continued)
OS - for other service. use this category only for those servioes 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. ln Column (c), identiff 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
aveftlge 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 megawafts.
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 fi). 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 RC/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,iine24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours
Sold
{o)
REVENUE Total($)
(h+i+j)
ft)
Line
No.Demand Charges(s)
(h)
Energy Charges
($)
(i)
other charges
($)
(i)
6,718 161.82t 161,82t 1
9(9(2
375 3,15(3,15(3
16,469 M4,78t 444,78(4
1,00c 23,10C 23,10(5
7,565 220,41C 220,41(6
9,43t 9,43{7
61,80C 1,659,05'1,659,05i I
-68,35(-68,35(I
350 8,70(8,70(10
1,26e 39.931 39,93 11
166,55(166,55(12
174 4,25C 4.251 13
334,461 10,479,271 10,479,27'14
0 0 0 0 0
1,683,294 0 53,430,856 1.041.657 54,472.513
1,683,294 0 53,'|i}0,856 1,041,657 54,472,513
FERC FORM NO. t (ED. 12-90)Page 311.3
Name of Respondent
ldaho Power Company
(1) E(2\ T!X[ 3;'n'"",
lA Resubmission
Date of Reoort
(Mo, Da, Yi)
04115t2014
Yea[Fenoo oI Kepon
End of 20131Q4
SALES FOR RESALE (Account 447)
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. ln 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). ln 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 intemrpted for economic
reasons and is intended to remain reliable even under adverse conditions (e.9., the supplier must aftempt 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.
lF - for intermediate-term firm service. The same as LF service except that'intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service except that 'intermediate-termn means
Longer than one year but Less than five years.
Jne
No.
Name of Company or Public Authority
(Footnote Afliliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule orTariff Number
(c)
Averaoe
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
AVeraoe
vlonthly NCF Deman
(e)
Averaoe
Monthly CPDemanr
(0
1 Shell Energy North America (US), L.P.WSPP nle nlt nlz
2 Shell Trading Risk Management WSPP nla nle nle
3 Siena Pacific Power Co., dba NV Energy T-7 nle nle nlz
4 Siena Pacific Power Co., dba NV Energy WSPP nle nle nlz
5 Siena Pacific Power Co., dba NV Energy WSPP nla nle nlz
6 Siena Pacific Power Co., dba NV Energy SF WSPP nle nle nla
7 Snohomish County PUD SF WSPP nlz nlz nlz
I Southem Cal Edison WSPP nlz nle nla
I Tenaska Power SeMces Co.WSPP nla nlz nlz
10 Tenaska Power Services Co.SF WSPP nlz nle nla
11 The Energy Authority, lnc.WSPP nle nlt nle
't2 The Energy Authority, lnc.SF WSPP nla nle nlz
13 TransAlta Energy Marketing (U.S.) lnc.WSPP nla nlz nla
14 TransAlta Energy Marketing (U.S.) lnc.SF WSPP nle nle nlz
Subtotal RQ 0
Subtotal non-RQ 0 c
Total 0
FERC FORM NO. I (ED. I2.9OI Paoe 310.4
Name of Respondent
ldaho Power Company
(1) E(2) T
|on ts:
An Original
A Resubmission
Date of Report
(Mo, Da, Yr)
0411512014
YeaflPenoo oI Kepon
End of 20131Q4
SALES FOR RESALE (Account447) (Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups'for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
'Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. ln Column (c), identifo 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
aver€lge monthly billing demand in column (d), the aveft€e 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 (0. 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 mElawatt 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,iine24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours
Sold
(o)
REVENUE Total ($)
(h+i+j)
(k)
Line
No.Demand Charges
($)
(h)
Energy Charges
($)
(i)
other uharges
($)
(i)
-303,62€-303,62(,|
-122,290 -122,291 2
82 2.4X 2,491 a
88,39r 88,39r 4
4,320 103,680 't03,68(5
19,124 702,094 702,O9,6
140 8,300 8,30(7
281 281 8
18('t8!I
2,493 109,091 109,091 10
56i 56'.;11
227,968 8,210,95€8,210,951 12
31,21i 31,212 13
18,902 518,892 518,89'14
0 0 0 0 0
1.683.294 0 53,430,856 1,041 ,657 54.472.513
r,683,294 0 53,430,856 1,041,657 54,472,513
FERC FORM NO. r (ED. 12-90)Page 311.4
Name ol Kesponoenl
ldaho Power Company
lhis R€(1) E(2) T
oort ls:
]Rn original'lA Resubmission
Date of Report(Mo, Da, Yr)
04t1512014
Year/Period of Report
End of 20131Q4
SALES FOR RESALE (Account 447)
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. ln 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). ln addition, the reliability of requirements service must
be the same as, or second only to, the supplie/s service to its own ultimate consumers.
LF - for tong-term seryice. "Long-term" means five years or Longer and "firm' means that service cannot be intemrpted for economic
reasons and is intended to remain reliable even under adverse conditions (e.9., 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.
lF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. 'Long-term'means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
-ine
No.
Name of Company or Public Authority
(Foohote Affiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule orTariff Number
(c)
Averaoe
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
uontni]"fiifl'oe'nan
(e)
AVEIAOEMonthly CPDemant
(0
1 United Materials of Great Falls !F 61 nli nla nle
2 Prior Year Adjustments {D nlz nlz nle
3 Prior Year Write Ofi Recovered qD nlz nla nla
4
5
tt
7
8
9
10
11
12
13
14
Subtotal RQ 0 0
Subtotal non-RQ 0 0
Total 0 0
FERG FORM NO.1 (ED.12.90)Paoe 310.5
Name of Respondent
ldaho Power Company
lhrs Keoon ls:(1) ffinn Originat
(21 nA Resubmission
Date ot Reoort(Mo, Da, Yi)
04115t2014
Year/Period of Report
End of 20131Q4
SALES FOR RESALE (Account 447)(Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them staffng 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. ln Column (c), identi! 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 gpes 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 supplie/s system reaches its monthly peak. Demand reported in columns (e) and (fl 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,iine24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours
Sold
(s)
REVENUE Total($)
(h+i+j)
ft)
Line
No.Demand Charges
(h)
Energy Charges
($)
(i)
umer unarges
($)
li)
14,69:14,69i ,|
2.404 2.40i 2
18,29i 18,29i 3
4
5
6
7
8
I
10
11
12
13
14
0 0 0 0 0
1,683,294 0 53,430,856 1 ,041,657 54,472,513
1,683,294 0 53,430,856 1,041,657 il,472,513
FERC FORM NO.I (ED.12.90)Page 311.5
Name of Respondent
ldaho Power ComDanv
This Report is:
(1) X An Original(21 A Resubmission
Date of Report
(Mo, Da, Yr)
041'1512014
Year/Period of Report
2013tQ4
FOOTNOTE DATA
310 Line No.:3 Column: b
fSDA Master aqreement
Financial- Transmission Losses310 Line No.:9 Column: bFi-nancial Transmi-ssion Losses
fSDA Master Aqreement with CaroilI Power kets date 13 201_1_
ISDA Master Aqreement with CitiGro Ener Inc.Marc
1nn1ng or rat Reserves
ISDA Master Aqreement with EDF Tra Nort Amer ca LLC
Financial Transmi-ssi-on Losses
:310 Line No.:13 Column: b
: 310.1 Line No.: 3 Column: b
: 310.1 Line No.: 5 Column: b
:310.1 Line No.: I Column: b
Prudential- Bache ities (Je ies Bache), LLC Futures Account Document, dated
Financi-al Transmission Losses
Financi-al Transmission Losses
310.1 Line No.: 14 Column:
310.2 Line No.: 1 Column: b
ISDA Master Aoreement with
Non-Firm Sales
310.2 Line No.: 11 Column: b
Fi-nan Transmissi-on
Non-Firm Sales
Non-Firm SaLes
Financial Transmission
Non-Firm Sales
Non-Firm Sales
FinanciaL Transmission Losses
ISDA Master Aqreement with Roval Bank of Canada dated sL 26. 2005
Non-Eirm SaLes
310.3 Line No.: 12 Column: hFinancial Transmi-ssion Losses
310.3 Line No.: 13 Column: b
Non-Firm Sales
FERC FORM NO. I 450.1
Name of Respondent
ldaho Power ComDanv
This Report is:
(1) X An Original(21 A Resubmission
Date of Report
(Mo, Da, Yr)
o4l'1512014
Year/Period of Report
2013tQ4
FOOTNOTE DATA
ISDA Master
novated to Agreement with SheII Energy
Shel-I Tradins Risk Ma t North America dated November 1,,2009 (aII deals
70 /1.3)
Energy North America dated November 1,, 2009 (all310.4 Line No.:2 Column: b
ement L0/L3
ratino reserves
Financial Tran ssi-on Losses
Unit Conti nt Sales
Financia ssion Losses
310.4 Line No.:4 Column: b
310.4 Line No.:8 Column: b
Financia ssion Losses
Pinancia ssion Losses
Einancia
FERC FORM NO.1 Paoe 450.2
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5.1Rn Orisinat(2) 1-1A Resubmission
Date of Reoort(Mo, Da, Yi)
0411512014
Year/Period of Report
End of 2O13lQ4
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
f the amount for previous year is not derived from previously reported ligures, explain in footnote.
ine
No.
Account
(a)
Amount forCunent Year(b)
Amount forPrevious Year(c)
1 1. POWER PRODUCTION EXPENSES
2 A. Steam Power Generation
3 Operation
4 (500) Ooeration Suoervision and Enoineerino 't.524.951 1.402,74i
5 t501) Fuel 160.276.741 134.501.10:
6 (502) Steam Exoenses 8.840.88r 8,279,62i
7 [503) Steam from Other Sources
I ILess) (504) Steam Transfened-Cr.
I t505) Electric ExDenses 1 .741.112 1.539.352
't0 506) Miscellaneous Steam Power Exoenses 9,473,76€8,331.84i
11 [50il Rents 348.322 285.31r
12 (509) Allowances
13 TOTAL Ooeration (Enter Total of Lines 4 thru 12)182.205,783,154.339.97i
14 Maintenance
15 (510) Maintenance Suoervision and Enoineerino 101.6't9 331.35t
16 (511) Maintenance of Structures 637,844 7s9,00i
17 (512) Maintenance of Boiler Plant 12.461.88€12.605.60:
18 (513) Maintenance of Elecbic Plant 5.398.984 5.139.30i
19 (514) Maintenance of Miscellaneous Steam Plant 4.541.443 4.996.61 i
20 TOTAL Maintenance (Enter Total of Lines 15 thru 19)23.141.77e 23.831.882
21 TOTAL Power Production Expenses-Steam Power (Entr Tot lines 13 & 20)205.347.559 178.171.86'1
22 B. Nuclear Power Generation
23 Operation
24 (51il Operation Supervision and Enqineerino
25 (518) Fuel
26 (519) Coolants and Water
27 (520) Steam Expenses
28 (521) Steam ftom Other Sources
29 (Less) (522) Steam Transfened-Cr.
30 (523) Elecfic Exoenses
3'l t524) Miscellaneous Nudear Power Exoenses
32 [525) Rents
33 TOTAL Operation (Enter Total of lines 24 hru 32)
34 Maintenance
35 1528) Maintenance Suoervision and Enoineerino
36 [529) Maintenance of Structures
37 t530) Maintenance of Reactor Plant Equioment
38 f 531) Maintenance of Electric Plant
39 [532) Maintenance of Miscellaneous Nuclear Plant
40 TOTAL Maintenance (Enter Total of lines 35 thru 39)
41 TOTAL Power Produc-tion Exoenses-Nuc. Power (Enf tot lines 33 & 40)
42 Hvdraulic Power Generation
43 Operation
44 1535) Ooeration Supervision and Enqineerinq 6.034.727 7.437.98(
45 1536) Water br Power 5.679.423 7.810.55/
46 i537) Hydraulic Expenses 't3,572.536 12.715.04f'
47 (538) Electric Expenses 1.432.66S 1.376.02t
48 (539) Miscellaneous Hvdraulic Power Generation Exoenses 4.855.7S8 2.634.251
49 (540) Rents 141,597 329,20t
50 TOTAL Operation (Enter Total of Lines 44 thru 49)3'1.716.75C 32.303.071
51 C. Hvdraulic Power Generation (Continued)
52 Maintenance
53 (541 ) Mainentance Supervision and Enoineerinq 83,805 305,07(
54 (542) Maintenance of Structures 1.427.309 1.329.15i
55 (543) Maintenance of Reservoirs, Dams, and Watenrvavs 1.144.299 1.343.401
56 (544) Maintenance of Electric Plant 2,617.21C 3.114.53t
57 (545) Maintenance of Miscellaneous Hydraulic Plant 3.005.68C 3.071.38:
58 TOTAL Maintenance Gnter Total of lines 53 thru 57)8.282.303 9.163.55(
59 TOTAL Power Prcduc'tion Expenses-Hydraulic Power (tot of lines 50 & 58)39,999,053 41.466.621
FERC FORM NO. I (ED. 12-93)Page 320
Name of Respondent
ldaho Power Company
This ReDort ls:(1) []An Orisinat(2) TIA Resubmission
Date ot Reoort(Mo, Da, Yi)
o411512014
Year/Period of Report
End of 2O13lQ4
ELECTRIC OPERATION AND MAINTENANCI EXPENSES (Continued)
lf the amount for orevious vear is not derived from previously reported figures, explain in footnote.
-ine
No.
Account
(a)
Amount forCunent Year
(b)
Amount forPrevious Year
(c)
60 D. Other Power Generation
61 Operation
62 (546) Ooeration Supervision and Enqineering 1.360.91r 't.342.63(
63 '547 Fuel 54.204.94(24,912.21(
64 r548 Generation Expenses 3.427.13(2.'.t67.81(
65 r549 Miscellaneous Other Power Generation Expenses 585,69(403,38(
bb r550 Rents
67 TOTAL Operation (Enter Total of lines 62 thru 66)s9.578.69i 28.826.O4t
68 Maintenance
6S (551 ) Maintenance Suoervision and Enqineerinq 9S
70 (552 Maintenance of Structures 301.287 208.O2t
71 553'Maintenance of Generatinq and Electric Plant 131,162 99,722
72 (554) Maintenance of Misccllaneous Other Power Generation Plant 1.233.98:2.537.68(
73 TOTAL Maintenance (Enter Total of lines 69 thru 72)1.666.531 2.845.43(
74 TOTAL Power Production Expenses-Other Power (Enter Tot of 67 & 73)61.245.22i 31.67't.48;
75 E. Other Power Suoolv Exoenses
76 (555) Purchased Power 214.941.82i 190.640.70t
77 (556) System Control and Load Dispatchins 1.403.451 2,25(
78 (55il Other Exoenses -34.629,98(-57.611.49'
79 TOTAL Other Power Suoolv Exp (Enter Total of lines 76 hru 78)181.715.28t 133.031.46(
80 TOTAL Power Production Expenses (Total of lines 21 , 4'l , 59, 74 & 79)488.307.12(384.341.43!
81 2. TRANSMISSION EXPENSES
82 ODeration
83 r5601 Ooeration Suoervision and Enoineerino 3.560.221 3.580.561
84
85 t561.1 ) Load Dispatcft -Reliability 39,63t 130,631
86 t561.2) Load Disoatclr-Monitor and Operate Transmission Svstem 1.702.334 1.170.321
87 t561.3) Load Dispatch-Transmission Service and Scheduling 1.036.725 1.345.15i
88 [561.4) Schedulino, System Control and Dispatch Services
89 t561.5) Reliabilitv. Planninq and Standards Development
90 |,561.6) Transmission Service Studies
91 [561.7) Generation lnterconnection Studies 94.561 97,74(
92 t561.8) Reliability, Planninq and Standards Development Services
93 1562) Station Exoenses 2.403.451 2.359.492
94 1563) Overhead Lines Expenses 732.402 659.25(
95 f5M)Underqround Lines Expenses
96 (565) Transmission of Elecbicitv bv Others 5.637.27t 6.294.41(
97 i566) Miscellaneous Transmission Exoenses 49.57e 175.70'.1
98 (567) Rents 2.917.52t 3.002.221
99 TOTAL Operation (Enter Totral of lines 83 thru 98)18.173.724 18.815.49t
100 Maintenance
101 (568) Maintenance SupeMsion and Engineering 323.417 48/..81i
102 (569) Maintenance of Structures 7.617
103 (569.1) Maintenance of Computer Hardware 7.491 13.441
104 (569.2) Maintenance of Comouter Software 734.',t8t 749,101
105 (569.3) Maintenanc,e of Communication Equipment 4.564 4.13t
106 (569.4) Maintenance of Miscellaneous Reqional Transmission Plant
107 (570) Maintenance of Station Eouioment 3,610,18i 3.689,46(
'108 (571) Maintenance of Overhead Lines 3.588.427 5.293.22(
109 (572) Maintenance of Underqround Lines
110 (573) Maintenance of Miscellaneous Transmission Plant 60i 't.s3(
111 TOTAL Maintenance (Tohl of lines 101 thru 110)8.276.494 10.235.71(
112 TOTAL Transmission Exoenses fiotal of lines 99 and 11 1 26.450.21t 29.051.21i
FERC FORM NO.1 (ED. 12-93)Page 321
Name or Kesponoent
ldaho Power Company
I nts Keoon ls:(1) []An Original(2) ;-1A Resubmission
uate ol Keoon
(Mo, Da, Yi)
04115t2014
Year/Period of Report
End of 2O13lQ4
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
lf the amount for previous year is not derived from previously reported figures, explain in footnote.
-lne
No.
Account
(a)
Amount forCurrent Year(b)
Amount forPrevious Year(c)
113 3. REGIONAL MARKET EXPENSES
114 Operation
115 (575.1 ) Operation Supervision
116 (575.2) Dav-Ahead and Real-Time Market Facilitation
117 (575.3) Transmission Riohts Market Facilitation
118 t575.4) Capacitv Market Facilitation
119 t575.5) Ancillarv Services Market Facilitation
120 575.6) Market Monitorino and Comoliance
121 [575.7) Market Facilitation, Monitorinq and Compliance Services
122 (575.8) Rents
123 Total Ooeration (Lines 115 thru 122)
124 Maintenance
125 (576.1) Maintenance of Structures and lmprovements
126 (576.2) Maintenance of Comouter Hardware
127 (576.3) Maintenance of Computer Softruare
128 (576.4) Maintenance of Communication Eouioment
129 (576.5) Maintenance of Miscellaneous Market Ooeration Plant
130 Total Maintenance (Lines 125 thru 129)
131 TOTAL Reqional Transmission and Market Op Expns (Total 123 and 130)
132 4. DISTRIBUTION EXPENSES
133 Operation
134 (580) Operation Supervision and Enqineerinq 4.160.84(4.118.84:
135 (581) Load Disoatchino 3.529.34i 3.549.9'tz
136 (582) Station Expenses 1,375.04t 1.157.50t
137 (583) Overhead Line Expenses 3.'.t11.421 3.786.75{
138 (584) Underqround Line Exoenses 2.402.212 1.870.34{
139 (585) Street Liohtino and Sional Svstem Exoenses 74,331 109,63(
140 t586) Meter Exoenses 4.421.678 4,132.811
141 [587) Customer lnstallations Expenses 673.95!642.062
142 t588) Miscellaneous ExDenses 5.754.224 5.622.88t
143 t589) Rents 366.17t 493.171
144 TOTAL Ooeration (Enter Total of lines 134 thru 143)25,869,24(25,483,94(
145 Maintenance
146 t590) Maintenance Suoervision and Enqineerinq 154 Aa4 224.17i
't47 591) Maintenance of Structures
148 1592) Maintenance of Station Eouioment 3,816,291 3.819.88(
149 [593) Maintenance of Overhead Lines 14.492.291 15.554.32(
150 1594) Maintenance of Underqround Lines 645.60(1.O46.52i
151 f595) Maintenance of Line Transformerc 286.874 422,58i
't52 1596) Maintenance of Street Liohtino and Sional Svstems 536,04(568,71f
153 f59il Maintenance of Meters 750.54t 725.951
154 1598) Maintenance of Miscellaneous Distribution Plant 412.97t 529,97'l
155 IOTAL Maintenance (Total of llnes 146 thru 154)21.109,50'l 22.892.14
156 IOTAL Distribution Expenses (Total of lines 144 and 155)46.978.75(48.376.08(
't57 5. CUSTOMER ACCOUNTS EXPENSES
158 Operation
159 (901) SupeMsion 491.36:441.301
160 (902) Meter Readino Exoenses 1.484.232 1.379.74!
161 (903) Customer Records and Collection Exoenses 14.060.13t 13.188.95t
162 (904) Uncollectible Accounb 5.805.414 4.512.fil
163 (905) Miscellaneous Customer Accounts Expenses 271 41i
1U TOTAL Customer Accounts Exoenses (Total of lines 159 thru 163)21.8/.1.41e 19.523.321
FERC FORM NO. 1 (ED. 12-93)Page 322
Name of Respondent
ldaho Power Company
I nts Keoon Is:(1) E:]An original(2) J--1A Resubmission
uate ot i(eoon(Mo, Da, Yi)
0411512014
Yea/Penoo ol Keport
End of 20131Q4
ELtsL; I KIU (JPEI(A I I(JN ANU MAIN I ENANUT
lf the amount for Drevious vear is not derived from previouslv reported fiqures, explain in footnote.
-tne
No.
Account
(a)
Amount forCunent Year(b)
Amount forPrevious Year(c)
165 6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
166 Operation
167 (90il Supervision s31,496 535.71 1
168 (908) Customer Assistiance Exoenses 42.690.734 33,737,48(
169 (909) lnformational and lnstructional Exoenses 264,701 295.58i
170 (910) Miscellaneous Customer Service and lnformational Expenses 574.875 554.02?
171 TOTAL Customer SeMce and lnformation Expenses (Total 167 thru 170)44.061.806 35.122.41t
172 7. SALES EXPENSES
173 Operation
174 (91 1) Suoervision
175 (912) Demonstratino and Sellino Exoenses
176 (913) Adverffsinq Expenses
177 [91 6) Miscellaneous Sales Exoenses
178 TOTAL Sales Exoenses (Enter Total of lines 174 thru 177)
179 8. ADMINISTRATIVE AND GENERAL EXPENSES
180 Operation
181 t920) Administrative and General Salaries 69.143.86S 70.376.741
182 [921) Otrce Supplies and Expenses 17.610.99(18.940.07i
't83 lLess) (922) Adminisfative ExDenses Transfened-Credit 26.882.8d 28,236,01{
184 i923) Outside Services Emoloved 5.271.46!s.177.36
185 (924) Property I nsurance 3.673.48S 3.506.57(
186 (925) lniuries and Damaqes 5.694.39!7.150.89i
187 (926) Emolovee Pensions and BenefE 62.53'.t.128 61,791.24t
188 (92il Franchise Reouirements
't89 (928) Regulatory Commission Expenses 3.975.664 5.692.48(
190 929) (Less) Duplicate Charqes-Cr.
19'l (930.1 ) General Advertisinq Exoenses 496.93€493,05:
192 (930.2) Miscellaneous General Expenses 4.246.37',|4.026.89'1
193 [931) Rents 6,53€17.59{
194 TOTAL Operation (Enter Total of lines 181 thru 193)14s.768.383 148.936.921
195 Maintenance
196 (935) Maintenance of General Plant 5.252.115 5.160.76:
197 TOTAL Administrative & General Expenses (Total of lines 194 and 196)151.020.498 154.097.6&
198 TOTAL Elec Op and Maint Expns (Tohl 80,112.131.156,'164,171,178,197\778.659.808 670.512,55i
FERC FORM NO.1 (ED. 12-93)Page 323
Name ot t(espondent
ldaho Power Company
tnts Ke(1) E(2\ r
Port ls: I Date of Reoort
]nn originat | {tvto, oa, vil
lAResubmission | 0411512014
Year/Period of Report
End of 20131Q4
PUBCHASEO POWER (Account 555)(rncluorng power excnanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. ln 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). ln 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 "firmn means that service cannot be intemrpted for
economic roasons and is intended to remain reliable even under adverse conditions (e.9., 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.
lF - 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 ftom 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 reliabilig of the designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service expect that'intermediate-term" means
longerthan one year but less than five years.
EX - For exchanges of electricig. 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.
Jne
No.
Name of Company or Public Authority
(Footnote Afliliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
AVerage
Monthly NCP Deman
(e)
Average
Monthly CP Deman<
(0
1 Cogeneration and Small Power Producers
2 AgPower Jeromer/Double A Digester -U NA NA NI
3 Allan Ravenscrofl/Malad River -U .488
4 Bennett Creek \Mnd Farm -U NA NA NI
5 Bettencourt DryCreek Biofactory -U NA NA NI
6 Big Sky West Dairy Digester -U NA NA NT
7 Big Wood Canal Company
8 Black Canyon #3 -U NA NA N'
I Jim Knight -U NA NA NI
10 Sagebrush -U NA NA NI
11 Blind Canyon Hydro -U NA NA NI
12 Branchfl ower/Trout Company LU NA {A NI
13 Burley Butte \Mnd Park LU NA {A NI
14 Bypass Limited LU NA NA NI
Total
FERC FORM NO.1 (ED.12-90)Page 326
Name of Respondent
ldaho Power Company
lhis ReDon ls:(1) fiAn Orisinat(2) [-l A Resubmission
uate of Heport(Mo, Da, Yr)
04115t2014
Yea/Henoo ot Kepon
End of 2013/Q4
t uKUt-tAsEu t uwEK(Account5551 (uonunueol(lncludinq power exchanqeS)'
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. ln column (c), identiff 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 (0. 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 supplie/s system reaches its monthly peak. Demand reported in columns (e) and (0
must be in megawatts. Footnote any demand not stated on a megawaft basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawafthours
of power exchanges received and delivered, used as the basis for seftlement. Do not report net exchange.
7. Report demand charges in column fi), 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 seftlement
amount for the net receipt of energy. lf more energy was delivered than received, enter a negative amount. lf 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 eplumn (i) must be reported as Exchange Delivered on Page 401 , line 1 3.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours
Purchased
(s)
POWER EXCHANGES COST/SETTLEMENT OF POWER Line
No.Megawa( Hours
Received(h)
Megawafi nours
Delivered(i)
uemand charges
t?t
Energy unarges
($)
(k)
umer unarges
($)
(t)
I OIal U?Kfl)of Setdement ($)
(m)
1
27,11 2.198.11 2.198.11 2
1,42i 155,67t 101,04r 2s6,72(3
42,38i 2,412,721 2,412,72(4
12,031 945,141 945,14;5
7,99r 336,771 336,77t 6
7
19'15.99 15,99r 8
84r 70,65(70,65(9
80r 67,93t 67,93r 10
2,791 275,',t4,275,141 11
761 59,211 59,211 12
57,741 2,845,05;2,845,05i 13
26,711 1,683,84!1,683,84(14
3,881,,14:310,77C 289,1 1 S 2,815,12t 211,713,11!413,582 214,941,82i
FERC FORM NO. 1 (ED. 12-90)Page 327
Name ot Kesponoent
ldaho Power Company
tnts KeDorI ts:(1) []Rn orisinal(2) l-l A Resubmission
Date of Report(Mo, Da, Yi)
04115t2014
Year/Period of Report
End of 20131Q4
PURCHASED POWER (Account 555)
( lncluding power exchanqes)
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. ln 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). ln addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumefti.
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.9., the supplier must aftempt 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.
lF - for intermediate-term firm service. The same as LF service expect that'intermediate-term* means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service expect that'intermediate-term' means
longer than one year but less than ftve 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.
Jne
No.
Name of Company or Public Authority
(Footnote Affliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (M\M
Average
Vtonthly NCP Deman
(e)
Average
Monthly CP Demanr
(0
1 Camp Reed Wind Park LU NA {A NI
2 Cargill lnc./86 Anaerobic Digester LU NA {A NI
3 Cassia Gulc*r \Mnd Park tU NA {A NI
4 Cassia Wind Farm LU NA {A NI
5 City of Cove, Oregon/Mill Creek LU NA {A NI
6 City of Hailey tU NA {A NI
7 City of Pocatello -U NA !A NI
8 Clear Springs Food lnc.:U NA {A NI
I Clifton E. Jenson/Birchcreek -U .05
10 Cold Springs Windfarm, LLC .U NA {A NI
11 Consolidated Hydro lnc./Enel
12 Barber Dam .U NA {A NI
13 Dietrich Drop -U NA {A NI
14 GeoBon #2 -U NA \,lA NI
Total
FERC FORM NO. r (ED.12-90)Page
Name of Respondent
ldaho Power Company
tnrs KeDon ts:(1) fiAn originat(2) llA Resubmission
Date of Report(Mo, Da, Yr)
04115t2014
Year/Period of Report
End of 20131Q4
PURCHASED POWER(ACCOUNI 555) (CONtiNUEd)(lncludino ooWer excfi anqe3)'
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. ln column (c), identifi 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. lf more energy was delivered than received, enter a negative amount. lf 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.
MegaWatt Hours
Purdrased
(s)
POWER EXCI.IANGES COST/SETTLEMENT OF POWEFI Line
No.Megawatt Hours
Received(h)
Megawa[ Hours
Delivered(i)
uemano unarges
($)
0)
Energy unarges
($)
(k)
umer unarges
($)
(t)
loEll u+K+l)of Setdement ($)
(m)
62,95 5,157,33i 5,157,33i 1
9,11r 744,741 744,74(2
3
24,72',1,070,03,1,070,032 4
3,04r 219,06{219,06(5
8 6,61 6,61'6
1,251 102,28,'t02.2&7
3,501 374,51r 374,51t 8
32i 17.50(16,84r 34.341 I
46,84r 2,796,241 2.796,241 10
11
8,96 559,'18'559,18i 12
1't,99r 788,09r 788,09r 13
2,521 224,34!224,34!14
3,881,44i 310,77(289,1 19 2,815,121 211,713,11 413,581 214,941,82i
FERC FORM NO. 1 (ED. 12-90)Page
Name of Respondent
ldaho Power Company (1) E(2t r
)ort ls:
An Original
A Resubmission
uate ot Keoon
(Mo, Da, Yi)
04t'15t2014
Year/Period of Report
End of 2O13lQ4
PURCHASED POWER (Account 555)(lncluding 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. ln 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). ln 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 nfirmn means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.9., 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.
lF - for intermediate-term flrm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. 'Long-term'means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any seftlements 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.
-ine
No.
Name of Company or Public Authorig
(Footnote Aftliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
Average
Monthly NCP Deman
(e)
,{verage
Monthly CP Demanr
(0
,|Lowline #2 LU NA \A NI
2 Rock Creek #2 LU NA !A N/
3 Confacbrs Power Group lnc./Mile 28 LU NA !A N/!
4 Crystal Springs Hydo LU NA !A NI
5 Curry Catfle Company LU .084
6 David McCollum/Canyon Springs LU NA !A N'
7 David R Snedigar LU NA {A N'
8 Desert Meadow \Mnd Farm LU NA !A NI
I Faulkner Brofiers Hydro lnc.LU NA !A NI
10 Fisheries Development NA \IA N'
11 Fossil Gulch \Mnd LU NA \lA N'
12 G2 Energy Hidden Hollow LU NA \A NI
13 Glenns Ferry Cogen Partners/Magic rU NA \A NI
14 Golden Valley Wind Park -U NA !A NI
Total
FERC FORM NO.1 (ED.12.90)Page 326.2
Name of Respondent
ldaho Power Company
I nts Neport t5:(1) EAn Original(2) l-lA Resubmission
Date of Reoort
(Mo, Da, Yi)
04t15t20't4
Year/Period of Report
End of 20131Q4
t-uKUtlASEU |-UWEK(ACCOUnI bSil (UOnlnUeOl
(l ncluding poWer exchanqeb)'
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. ln column (c), identifo 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 underwhich 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 supplie/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 seftlement. 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 seftlement
amount for the net receipt of energy. lf more energy was delivered than received, enter a negative amount. lf 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.
MegaWatt Hours
Purcfiased
(s)
POWER EXCHANGES COST/SETTLEMENT OF POWER Line
No.Megavva[ nours
Received(h)
Megawatt Hours
Delivered(i)
uemano unarges
8r
Energy unarges
tf,l
uther unarges
t?l
lotal u+K+l)of Setdement ($)
(m)
9,27i 578,471 578,47,.1
5,53r 348,95'348,95'2
4,05r 282,02'282.02'3
9,57 719,151 719,15{4
69,26.791 35,09r 61,88(5
56r 7,98(7,98(6
1,44i 111,07 111,07'7
54,53:3.256,171 3,256,171 8
3,18r 278,771 278,77t 9
1,13:14,86:14,86:10
22,24 1,194,55:1,194,55i 11
20,27:1,1 14,08r 1,114,08(12
-8:3,96:13
3'r,73(1,487,441 1,487,M|14
3,881,,14:310,77(289.1 1 2.815.121 2't1.713.11 413,581 214,941,82i
FERC FORM NO. r (ED.12-90)Page
Name ot Respondent
ldaho Power Company (1) E(2) T
|ort ts;
An Original
A Resubmission
uate oI Kepon(Mo, Da, Yr)
04t1512014
Year/Period of Report
End of 2O13lQ4
FUKUHADtrU I-UWEK (AC@UNT 555I(lncluding 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. ln 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). ln addition, the reliability of requirement service must
be the same as, or second only to, the supplie/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.9., 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 flrm 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.
lF - 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 ftom a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside ftom transmission constraints, must match the availability and reliability of the designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service expect that'intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the abovedefined 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.
-ine
No.
Name of Company or Public Authority
(Footnote Affi liations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
,{verage
Monthly NCP Deman
(e)
Average
Monthly CP Deman(
(0
1 Hammett Hill Wndfarm, LLC .U NA NA M
2 -U NA NA NI
3 High Mesa Energy -U NA NA NI
4 H.K. Hydro Mud Creek S & S LU NA NA Nr'
5 Horeshoe Bend Hydro LU NA NA Nr'
6 Horseshoe Bend \Mnd/United Materials LU NA NA Nr'
7 Hot Springs Wind Farm LU NA NA M
I ldaho Wnds/Sawtooh Wind Project LU NA NA N/a
I JR Simplot Co.LU NA NA Nr'
10 J.M. Miller/Sahko Hydro LU NA \IA Nr'
11 James B. Howell/CHl Elk Creek LU NA NA Nr'
12 John R LeMoyne LU NA NA N/6
13 Kasel & lMtherspoon LU NA NA NI
14 Koyle Hydro lnc.LU NA NA Nr'
Total
FERC FORii NO. r (ED. 12-90)Page 326.3
Name of Respondent
ldaho Power Company
lhis Keoon ls:(1) []Rn Originat(2) l-lA Resubmission
Date of Reoort
(Mo, Da, Yi)
04t1512014
Year/Period ot Report
End of 20131Q4
PUKU|"|AI'EU |-(JWEK{ACCOUnI 5551 (UOn[nUeOt(lncluding poWer exchangeb)'
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. ln column (c), identiff 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 (O), (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 megawafthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (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. lf more energy was delivered than received, enter a negative amount. lf 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.
MegaWatt Hours
Purchased
(s)
POWER EXCHANGES COST/SETTLEMENT OF POWER Line
No.Megavva[ Hours
Received(h)
Megawat Hours
Delivered(i)
Lremano uharges
($)
0)
Energy unarges
fil
umer unarges
t?l
lotEll u+K+l)
of Settlement ($)
(m)
53,27'3.188,69'3,188,69;1
22,50!1,588,66 1,588,66 2
88,97'4.020.',tgi 4,020,19:3
1,48('t42,68 142,681,4
41,66!2,923,741 2,923,741 5
20,30:1.060.281 1,060.28(6
38,791 2,227,88 2,227,881 7
54,261 3,961,70,3,961,70,8
77,09r 3,943,871 3,943,87:I
1,10r 75,12.75,12l.10
3,97:307,38(307,38(11
M1 37,68:37,68i 12
3,21 327,15i 327,15t 13
2,591 289,95r 289,95(14
3,881,44:3',10,77C 289,1 19 2,815,121 211,713,111 413.58,214,941,82:
FERC FORM NO. r (ED. 12-90)Page 327'3
Name of Respondent
ldaho Power Company (1) E(2) T
rort ls:
An Original
A Resubmission
Date of Reoort(Mo, Da, Yi)
o4t1512014
Year/Period of Report
End of 2O'l3lQ4
PURCHASED POWER (Account 555)(lncluding 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. ln 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). ln addition, the reliability of requirement service must
be the same as, or second only to, the supplie/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 intemrpted for
economic reasons and is intended to remain reliable even under adverse conditions (e.9., the supplier must attempt to buy emergency
energy ftom 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.
lF - 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 ftom a designated generating unit. "Long-term" means five years or longer. The availabilig and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service expect that'intermediate-term" means
longerthan 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.
-ine
No.
Name of Company or Public Authority
(Footnote Affi liations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
AVerage
Vonthly NCP Deman
(e)
Average
Monthly CP Deman<
(0
1 Lateral 10 Ventures -U NA \A NT
2 Lemhi Hydro Power Co./Schaffner .U NA \A NI
3 Lime \Mnd -U NA \A NI
4 Little Mac Power Co./Cedar Draw -U NA \lA NI
5 Little Wood River lnigation District -U NA \IA NI
6 Magic Reservoir Hydro -U NA {A NI
7 Mainline \Mndfarm -U NA \IA NI
8 Marco Randre/s lnigaffon lnc.-U NA \IA N'
I -U NA \A N'
10 Milner Dam Wind Pa*-U NA NA N'
11 Mud Creek Write Hydro, lnc -U NA NA N'
12 New Energy One/Rock Creek Diary -U NA NA NI
13 Oregon Trail Wnd Park -U NA NA NI
't4 Owyhee lnigation Disfict
Total
FERC FORM NO. I (ED. 12-90)Page 326.4
Name of Respondent
ldaho Power Company
This Reoort ls:(1) []Rn originat(2) l-lA Resubmission
uate ot KeDon
(Mo, Da, Yi)
04t1512014
YeaflHenoo ot Kepon
End of 20131Q4
PUi<L;HASEU t UWEI((ACCOUnI 555t (Uontnuedl(lncludinq poWer exchanqe's)'
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. ln column (c), identifiT 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 megawafthours
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. lf more energy was delivered than received, enter a negative amount. lf 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 1 0. The total amount in column (h) must be reported as Exchange Received on Page 401 ,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours
Purcfiased
(s)
POWER EXCHANGES COST/SETTLEMENT OF POWER Line
No.Megawafi Hours
Received
(h)
Megawatt Hours
Delivered(i)
Demand Charges
',?l
Energy Unarges
tr]
Other Charges
trt
Totrl o+k+l)of Settlement ($)
(m)
5,s9'394,751 394,75(1
1,14',97,82.97,821 2
6,40r 457,221 4s7.221 3
4,83:349,64:349,64!,4
3,15 276,85i,276,8s{5
56r 194,73i 194,73:6
51,55:3,082,06:3,082,06'7
2,141 164,98'164,98]8
45.231 2,883,721 2,883,721 I
55,88r 2.687,401 2,687,40t 10
371 27,69i 27,69i,11
10,66(536,291 536,29:12
35,65i 1,780,02.1,780.02('t3
14
3,881,44:310,77(289,1 19 2,815,121 211,713,11 413,581 214,941,82i
FERC FORM NO.1 (ED.12-90)Page 327.4
Name of Respondent
ldaho Power Company (1) E(2) r
on ls:
An Original
A Resubmission
uate ol Keoon(Mo, Da, Yi)
0411512014
YearHenoo or Kepon
End of 20'l3lQ4
rurJUHA)trU rUWEK (ACCOUnI C55)(rncluorng power excnanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. ln 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 resouroe planning). ln 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 intem.rpted for
economic reasons and is intended to remain reliable even under adverse conditions (e.9., 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.
lF - 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 fom a designated generating unit. 'Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for intermediate-term service ftom a designated generating unit. The same as LU seMce expect that'intermediate-term' means
longer than one year but less than five yearc.
EX - For exchanges of electricity. Use this category for kansactions 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.
_tne
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
AVera9e
vlonthly NCP Deman
(e)
/{verage
Monthly CP Demanr
(0
1 Mitchell Butte -U NA {A NI
2 Owyhee Dam .U NA {A NI
3 Tunnel #1 .U NA {A NI
4 Paynes Ferry Wind Park -U NA {A NI
5 Pigeon Cove Power -U 1.389
6 Pilgrim Stage StaUon Wind Park -U NA {A NI
7 Pristine Springs lnc #1 -U NA {A NI
I Pristine Springs lnc #3 -U NA {A NI
I Reynolds lnigation Disfic{-U NA {A NI
10 Richard lGster
11 Box Canyon LU NA {A NI
12 Briggs Creek LU NA {A NI
13 Rim Mew Trout Company NA {A NI
14 Riverside Hydro/Mora Drop LU NA {A NI
Total
FERC FORM NO.1 (ED. 12-90)Page 326.5
Name of Respondent
ldaho Power Company
This Report ls: I Date of Reoort(1) $An Orisinal | {uo, oa, vil(2) l-lA Resubmission | 0411512014
Year/Period of Report
End of 20131Q4
PURCHASEU POWEI{(Account 555) tUontinued)(lncludino ooWer exchanoeS)'
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. ln column (c), identiff 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
identifled 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. lf more energy was delivered than received, enter a negative amount. lf 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.
MegaWaft Hours
Purchased
(s)
POWER EXCHANGES COST/SETTLEMENT OF POWER Line
No.Megawa[ Hours
Received(h)
Megawa[ Hours
Delivered
(i)
uemano unarges
',?l
Energy unarges
tfl
umer unarges
t?t
Total 0+k+l)
of Settlement ($)
(m)
2,20'58,36r 58,36r 1
11,431 242,881 242,881 2
3,01 257,45,257.451 3
61,11 5,000,25r 5,000,25(4
8,16r 486,15(367,281 853,43(5
32,30 1,706,721 1.706.721 6
821 49,39:49,39i 7
1,31 70,58;70,58i 8
97r 76,521 76,521 I
10
1,95r 143,77 143,77'11
3,66:274,801 274,801 12
13
3,4d 177.181 177,181 14
3,881,44:310,771 289,1 1(2,815,121 211.713.11 413,582 214.941.82i
FERC FORM NO.1 (ED.12-90)Page
Name of Respondent
ldaho Power Company
I rlts rae(1) E(2) l-
on ts.
An Original
A Resubmission
uate ot KeDon
(Mo, Da, Yi)
04t1512014
YearPenoo or Repon
End of 20131Q4
PURCFJff'ED POWER (AccouAt 555)(rnquorng power excnanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. ln 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). ln addition, the reliability of requirement service must
be the same as, or second only to, the supplie/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.
lF - 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 fiom a designated generating unit. 'Long-term'means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any setUements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the abovedefined 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.
-ine
No.
Name of Company or Public Authority
(Footnote Affi liations)
(a)
Statistical
Classiff-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (M\M
AVCrags
Monthly NCP Deman
(e)
I\verage
Monthly CP Deman<
(0
1 Riverside lnvesfnenb
2 Arena Drop !U NA NA NI
3 Fargo Drop rU NA NA NI
4 Rock Creek #1 Joint Venture -U 1.732
5 Rockland Wnd Pro.iect -U NA NA NI
6 Rupert Cogen Partners/Magic Valley -U NA NA NI
7 Ryegrass \Mndhrm -U NA NA NI
I Salmon Falls \Mnd Park -U NA NA NI
I SE Hazelton A LP -U NA NA NI
10 Shorock Hydro lnc.
11 Shoshone Cspp .U NA NA NI
12 Shoshone #2 -U NA NA NI
13 Snake Rivery Pottery -U NA NA NI
14 -U NA NA NI
Total
FERC FORM NO.1 (ED. 12-90)Page 326.6
Name of Respondent
ldaho Power Company
lhis t{eDon ls:(1) []Rn orisinal(2) [lA Resubmission
Date of ReDort
(Mo, Da, Yi)
04t1512014
Year/Period of Report
End of 20131Q4
t,UKUF|ASEU t-UWEKtAC@Unt 5551 (UOn[nUeOl(lncludinq power exchanoes)'
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. ln column (c), identiff 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 megawafthours 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. lf more energy was delivered than received, enter a negative amount. lf 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 40't, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours
Purchased
(s)
POWER EXCHANGES COST/SETTLEMENT OF POWER Line
No.Megawa[ Hours
Received
(h)
Megawatt Hours
Delivered(i)
Demand Charges
8i
trnergy unarges
($)
(k)
otner Gnarges
tB
I otal U+l(+l)of Settlement ($)
(m)
1
1,21 96,991 96,99t 2
2,83:124,07i 124,07:3
7,00,5s2,50r 408,82i 961,33(4
226,77'13,452,11,13,452,11t 5
79,7'.!5,219,49,5,219,49,6
48,52i 2,891,171 2,891,171 7
62,96'3,419,90:3,419,$:8
23,00'1,580,81 1,580,81:I
10
1,31,'t44,67 144,67t 11
2,03,141,6si 141,65i 12
37t 27,971 27,971 13
27,04i 2,182,29.2,'t82,251 14
3,881,44i 310,77t 289,1 19 2,815,12t 211,7',\3,'.t1t 413.s81 214,941,82i
FERC FORM NO.1 (ED. 12-90)Page 327.6
Name of Respondent
ldaho Power Company (1) E(2t T
rort ts:
An Original
A Resubmission
uate ot Keoon
(Mo, Da, Yi)
04115t2014
YeailHenod ol Kepon
End of 2013/Q4
TUKUI1AI'EU I'UWEK IAC@UNI 555I(lncluding power exchanqes)
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. ln 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). ln 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.9., the supplier must aftempt 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.
lF - for intermediate-term firm service. The same as LF service expect that "intermediate-term' means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service expect that'intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any seftlements 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.
-rne
No.
Name of Company or Public Authority
(Footnote Affi liations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (M\M
r{verdgs
Monthly NCP Deman
(e)
,verage
Monthly CP Demanr
(f)
2 Tasco - Nampa NA {A NI
3 Tasco - Twin Falls NA !A NI
4 Ted S. Sorenson/Tiber Dam LU NA !A NI
5 Thousand Spring \Mnd Park LU NA !A NI
6 Tuana Gulcfi Wind Park LU NA !A NI
7 Tuana Springs Expansion LU NA {A NI
I Twin Falls Energy/Lowline Midway Hydro tU NA {A NI
I Two Ponds Windfarm LU NA !A NI
10 White Water Ranctr LU NA \.lA N'
't1 \Mlliam Arkoosh/LitUewood LU NA \,IA Nr'
12 Wllis and Betty Deveny/Shingle Creek .U NA !A NI
13 .U NA !A Nr'
14 Yahoo Creek \Mnd Park ,U NA !A NT
Total
FERC FORM NO.1 (ED.12-90)Page 326.7
Name of Respondent
ldaho Power Company
I nts Ke(1) E(2t r-
on Is:
An Original
A Resubmission
uate ot KeDon(Mo, Da, Yi)
0411512014
Year/Period of Report
End of 2013lQ4
HUKUHASEU i-(JWEKIAC@UnI Cb5) tUOn[nUeO](lncludino ooWer exchanoeb)'
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. ln column (c), identiff 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 (0
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (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. lf more energy was delivered than received, enter a negative amount. lf 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.
MegaWatt Hours
Purchased
(s)
POWER EXCHANGES COST/SETTLEMENT OF POWER Line
No.Megawatt Hours
Received- (h)
Megawa[ Hours
Delivered
(i)
uemano unarges
((ft
Energy unarges
fi]
umer unarges
t?l
I Otall u+K+l)
of Setdement ($)
(m)
32,38t 1,576,49t 1,836,60!3,413,10i 1
26(6,28r 6,28t 2
3
29,18i 1,553,23r 1,553,23t 4
31,49'1,578,99;1,578,99:5
28,191 1,494,29,1,494,291 6
76,66(4,112,86"4,112,861 7
8,561 528,85t 528,85:8
55,55 3,303,66r 3,303,66t I
69:52,051 52,05(10
2,941 253,83:253,83i 11
921 77.54:77,541 12
26,17i 1,847,16\1,847,16{13
61,80,5,064,82r 5,064,82t 14
3.88't.44:310,77C 289,11 2.815,121 211.713,11 413,5&214.94'.t.82i
FERC FORM NO. r GD. 12-90)Page
Name ot Kesponoent
ldaho Power Company
tnts t
(1)
(2)
DOII IS:
]Rn original
I A Resubmission
Date of Reoort(Mo, Da, Yi)
0411512014
Year/Period of Report
End of 20131Q4
PUBCHASED POWER (Account 555)(rncluorng power excnanges)
1 . Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. ln 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). ln addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumersi.
LF - for long-term firm service. "Long-term" means five years or longer and 'firm" means that service cannot be intem.rpted for
economic reasons and is intended to remain reliable even under adverse conditions (e.9., 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.
lF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term' means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
-rne
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
,\Verage
Monthly NCP Deman
(e)
AVerage
Monthly CP Deman<
(0
1
2
3
4 Other Purchased Power
5 Arizona Public Service Co.SF UVSPP NA NA NI
6 Avista Corp.T-12 NA NA NI
7 Avista Corp.SF WSPP NA NA NI
8 Avista Corp.rVSPP NA NA NI
I Barclays Bank PLC NA NA NI
10 Black Hills Power lnc.SF ,VSPP NA NA NI
't1 Bonneville Power Administration rVSPP NA NA NI
12 Bonneville Power Administration WSPP NA NA NI
13 Bonneville Power Adminishation 3F A/SPP NA NA NI
14 BP Energy Company SF A/SPP NA NA NI
Total
FERC FORM NO.1 (ED.12.90)Page 326.8
Name of Respondent
ldaho Power Company
tnts Keoon ts:(1) []Rn orisinat(2) llA Resubmission
Date of Reoort(Mo, Da, Yi)
0411512014
Year/Period of Report
End of 2O13lQ4
PURCHASED POWER(Account 555) (Continued)(lncludino oower exchanoes)'
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. ln column (c), identifo 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 seryice, 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 (0
must be in megawafts. Footnote any demand not stated on a megawaft basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawafthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column fi), 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. lf more energy was delivered than received, enter a negative amount. lf 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.
MegaWaft Hours
Purchased
(s)
POWER EXCHANGES COST/SETTLEMEN T OF FOWEtt Line
No.Megawat Hours
Received(h)
Megawa[ Hours
Delivered
(i)
uemano unarges
t?t
trnergy unarges
fll
umer unarges
($)
0)
I OEll U+K+l)of Setilement ($)
(m)
-870,91 -870,91i 1
36.261 36.26(2
5,15t 3
4
4,141 165.98i 't65,98r 5
3t 1,231 1,231 6
149,08(5.177.91 5,177,91i 7
333,97'333,97i 8
32.83:,32.831 I
1,071 50,70(50,70(10
578,88 s78,88 11
35 12,36i 12,361 12
78,881 2,736,84 2,736,84',13
62,60(1,409.96i 1,409,96r 14
3,881,44:310,77t 289,11 2,g'.ts,121 211,713,11t 413,58,214,941,82i
FERG FORM NO.1 (ED. 12-90)Page 327'E
Name of Respondent
ldaho Power Company (1) E(2) T
ort t5:
An Original
A Resubmission
Date of Reoort(Mo, Da, Yi)
04t15t2014
Year/Period of Report
End of 20131Q4
|-UKL;HAsEU t-UVVEt( tACmUnt SCCl(lncluding 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 pafi 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). ln 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.9., 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.
lF - for intermediate-term firm service. The same as LF service expect that "intermediate-term' means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service expect that'intermediate-term' means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
-tne
No.
Name of Company or Public Authority
(Footnote Affi liations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tarifi Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
nv(irage
Vlonthly NCP Deman
(e)
nvErage
Monthly CP Demanr
(f)
1 Calpine Energy Services, L.P.SF WSPP NA \,IA NI
2 Cargill Power Markets LLC NA \,IA NI
3 Cargill Power Markets LLC SF WSPP NA !A NI
4 Chelan Co PUD WSPP NA \.lA NT
5 Citigroup Energy lnc.SF WSPP NA !A NI
6 Citigroup Energy lnc.NA {A NI
7 City of Glendale SF WSPP NA {A NT
8 Constellation Energy Commodities Group SF WSPP NA {A Nr'
9 Douglas County PUD WSPP NA VA Nr'
10 EDF Trading North America, LLC SF WSPP NA !A Nr'
11 Eugene Water & Electric Board SF WSPP NA !A Nr'
12 Exelon Generation Company, LLC SF UVSPP NA {A N/o
13 Grant CO Public Utility District*f2 -WSPP NA {A Nr'
14 Grant CO Public Utility District#2 SF WSPP NA \IA NI
Total
FERC FORM NO. 1 (ED. 12-90)Page 326.9
Name of Respondent
ldaho Power Company
I nis Heoon ls:(1) ffinn original(2) l-lA Resubmission
Date of Report
(Mo, Da, Yr)
04t15t2014
Year/Period of Report
End of 20131Q4
l.uKUtlASEU I.UWEK|AC@UnI CCSl {UOnUnUeOt{lncludino DoWer exchanoe3)'
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), identiff 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 fi), 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 seftlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. lf more energy was delivered than received, enter a negative amount. lf 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.
MegaWatt Hours
Purchased
(s)
POWER EXCHANGES COST/SETTLEMENT OF POWER Line
No.Megawa[ Hours
Received(h)
Megawatt Hours
Delivered(i)
uemano unarges
.8t
Energy unarges
($)
(k)
umer unarges
tft
Total (i+k+l)
of SetUement ($)
(m)
17,201 593,88(593,88(1
-'t25,87t -125,87t 2
29,90r 1,274,331 1,274,331 3
1t 56t 56(4
't88,82r 7,428,27"7,428,27i 5
-5,81(-5,8'l(b
2l 1,241 1,241 7
56(20,17 20,17 8
ft ft 9
123,221 5,304,18i 5,304,18i 10
3,80(83,37(83,37(11
11,02.465,56{465,56r 12
1 531 53;13
63(20,951 20,951 14
3,881,44:310,77C 289.'t1(2,815,121 211,713,1'.t!413,581 214.941,82i
FERC FORM NO. r (ED. 12-90)Page 327.5
Name of Respondent
ldaho Power Company (1) E(2) T
rort ts:
An Original
A Resubmission
uate ot Keoon
(Mo, Da, Yi)
04t1512014
Yearf'enoo ot Kepon
End of 2013/Q4
TUKUHA5trU TUWtrK (AC@UNI 55bI(lncluding 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 seftlements 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 afiiliation the respondent has with the seller.
3. ln 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). ln 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 "firmn means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.9., 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
de'ltned as the earliest date that either buyer or seller can unilaterally get out of the contract.
lF - for intermediate-term firm service. The same as LF service expect that 'intermediate-term' means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term' means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the seMce in a footnote for each adjustment.
-ine
No.
Name of Company or PublicAuthority
(Footnote Affi liations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
,{vEragE
Vlonthly NCP Deman
(e)
,uerage
Monthly CP Deman(
(0
1 IBERDROLA RENEWABLES, lnc.SF WSPP NA {A NI
2 J. Aron & Company SF WSPP NA {A NI
3 J.P. Morgan Ventures Energy Corporatio SF WSPP NA !A NI
4 Jefferies Bache NA {A NI
5 Los Angeles Dept Water & Power SF yVSPP NA !A NI
6 Maquarie Cook Power lnc.SF WSPP NA {A NI
7 Macquarie Gook Power lnc.NA {A NI
8 Morgan Stanley Capital Group SF ISDA NA {A NI
I Nevada Power Co, DBA NV Eneqy SF WSPP NA {A NI
10 NextEra Energy Power Marketing, LLC SF ,VSPP NA {A NI
11 Noble Americas Gas&Power Corp SF ttVSPP NA {A NI
12 Northwestem Energy f-7 NA {A NI
13 NorthWestem Energy ISF A/SPP NA {A NI
14 PacifiCorp lnc.r-13 NA \.lA NI
Total
FERC FORM NO.1 (ED. 12-90)Page 326.10
Name of Respondent
ldaho Power Company
tnr
(1)
(2')
<eDort ls:
fiRn originat
[-lA Resubmission
Date of Report(Mo, Da, Yr)
o4115t2014
Year/Period of Report
End of 20131Q4
PURCHASED POWER(Account 555) (Continued)(lncludino Dower exchanoe's)'
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. ln column (c), identiff 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 (0. 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 megawafthours
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. lf more energy was delivered than received, enter a negative amount. lf 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.
MegaWatt Hours
Purchased
(g)
POWER EXCHANGES COST/SETTLEMENT OF POWER Line
No.Megawatt Hours
Received(h)
Megawa[ Hours
Delivered(i)
uemano unarges
,81
Energy uharges
tr]
umer unarges
($)
0)
loEll u+K+l)of Settlement ($)
(m)
29,50r 589,57'589,s7;1
1,201 29,20l,29,20(2
o.3,971 3,97!3
-944,931 -944,93,4
22,03',738,49r 738.49r E
34,80(1,143,60r 1,143,60(b
240.141 240,14,7
6',t,21,2,519,12i 2,519,121 8
2,141 99,801 99,80(o
80(27,521 27,521 10
2,201 57,751 57,75(1'.!
3;'t,21 1,211 12
29t 5,771 5,77(13
25 8,791 8,79(14
3,881,44:310,77(289,1 1 I 2.815.12,211,713,1ft,413,58t 214.941.82i
FERC FORM NO.1 (ED. 12-90)Page 327.10
Name ol Kesponoenl
ldaho Power Company (1) t(2) I
,on ts:
]An Original
lA Resubmission
uate ot KeDon
(Mo, Da, Yi)
041't5t20't4
Yeauf'enoo oI Kepon
End of 2013/Q4
PURCHASED POWER (Account 555)(lncluding power exchanqes)
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. ln 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). ln 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 intenupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.9., 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 eadiest date that either buyer or seller can unilaterally get out of the contract.
lF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
[ine
No.
Name of Company or Public Auhority
(Footnote Affi liations)
(a)
Stratistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
,\Verage
Vlonthly NCP Deman
(e)
,tverage
Monthly CP Deman<
(0
,|PacifiCorp lnc.SF WSPP NA {A NI
2 PacifiCorp lnc.WSPP NA {A NI
3 Portland General Electric Company T-14 NA {A NI
4 Portand General Electic Company SF WSPP NA {A NI
5 Powerex Corp.SF WSPP NA {A NI
6 PPL EnergyPlus, LLC SF WSPP NA {A NI
7 PPL EnergyPlus, LLC WSPP NA {A NI
8 Public SeMce Company of New Mexico SF WSPP NA {A NI
9 Puget Sound Energy, lnc.T-9 NA {A NI
10 Puget Sound Energy, lnc.SF WSPP NA {A NI
11 Rainbow Energy Marketing Corporation SF WSPP NA {A NI
12 Salt River Project SF NA !A NI
13 Seatile City Light WSPP NA \.lA NI
14 SeatUe City Light SF WSPP NA \,IA NI
Total
FERC FORM NO.1 (ED. 12-90)Page 326.11
Name of RBspondent
ldaho Power Company
I his F(eDon ls:(1) fiAn Original(2) l-lA Resubmission
uate oI i<epon
(Mo, Da, Yr)
0411512014
YearHenoo or Kepon
End of 20131Q4
PUKUHASEU I-(JWEK(AC@UNI 555I (UONflNUCOI(lncluding poWer exchanqe3)'
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. ln 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 (0
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawafthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column [), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (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. lf more energy was delivered than received, enter a negative amount. lf 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 , Iine 10. The total amount in column (h) must be reported as Exchange Received on Page 401 ,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line '13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours
Purchased
(s)
POWER EXCHANGES COST/SETTLEMENT OF POWER Line
No.Megawa[ nours
Received(h)
MegaWatt Hours
Delivered(i)
Demand Charges
,8t
Energy unarges
fil
Lrmer unarges
($)
(r)
I OIal UtKtl)of Settlement ($)
(m)
12,57i 354,751 354,752 1
126,21i 126,21i 2
5l 1,80 1,80;3
14,00r 503,01 503,011 4
18,79:1,363,92(1,363,92(5
170,04,5,377,'t0,5.377.101 6
1,281 43,521 43,52(7
18 8,78,8,78;8
6!2,44;2,441 I
26,93(1,090,68i 1,090,68i 10
10,14,367,'l5r 367,15t 11
21,201 941,42,941,421 12
'l 43(43(13
2,761 103,20:'t03,201 't4
3,881,44:310,77C 289.11 2,8',15,121 211,713,11!413,581 214,941,82i
FERC FORM NO. { (ED.12-90)Page 327.11
Name of Respondent
ldaho Power Company (1) E(2) r
rort ls:
An Original
A Resubmission
uate ot HeDon
(Mo, Da, Yi)
04115t2014
Year/Period of Report
End of 2O13lQ4
PURCHASED POWER (Account 555)(lncluding 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. ln 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). ln addition, the reliability of requirement service must
be the same as, or second only to, the supplie/s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firmn means that service cannot be intem.rpted for
economic reasons and is intended to remain reliable even under adverse conditions (e.9., 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.
lF - for intermediate-term firm servico. 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 generaUng unit. "Long-term" ,""n, five years or longer. The availability and reliability of
service, aside ftom transmission constraints, must match the availability and reliability of the designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five yearc.
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.
-ine
No.
Name of Company or Public Authority
(Footnote Affi liations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (M\M
,{verage
Monthly NCP Deman
(e)
,verage
Monthly CP Deman<
(0
1 Shell Energy North America (US), L.P.SF A/SPP NA NA NI
2 Shell Energy North America (US), L.P,NA NA NI
3 Siena Pacific Power Co., dba NV Energ r-55 NA NA NI
4 Siena Pacific Power Co., dba NV Energ SF /VSPP NA NA NI
5 Siena Pacific Power Co., dba NV Energ ,VSPP NA NA NI
6 Snohomish County PUD SF flSPP NA NA NI
7 Tacoma Power flSPP NA NA NI
8 Tacoma Power 3F /VSPP NA NA NI
I Tenaska Power Services Co.JF A'SPP NA NA NI
10 The Energy Authority, lnc.JF A'SPP NA NA NI
11 TransAlta Energy Marketing (U.S.) lnc.iF A'SPP NA NA NI
12 Tri-State Generation & Transmission iF A'SPP NA NA NI
13 Westem Area Power Adminisbation A/SPP NA NA NI
14 Raft River Energy I LLC NA NA NI
Total
FERC FORM NO.1 (ED.12-90)Page
Name of Respondent
ldaho Power Company
I his Keoort ls:(1) fiAn original
(2) llA Resubmission
uate ot HeDon
(Mo, Da, Yi)
0411512014
YearPenoo ol Kepon
End of 20131Q4
t,ut(uFtAsEu t uwEKtAccount 55bl (uonrnueol(lncludino power exchanqe's)'
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. ln column (c), identiff 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 supplie/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. lf more energy was delivered than received, enter a negative amount. lf 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 40'1 ,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours
Purchased
(s)
POWER EXCHANGES COST/SETTLEMENT OF POWER Line
No.Megawa[ nours
Received(h)
Megawatt Hours
Delivered(i)
uemano unarges
($)
U)
Energy unarges
tf,l
Lrmer unarges
($)
(t)
lotal u?Kfl,of Settement ($)
(m)
39,681 883,79r 883,79r 1
-193,01:-193,01:2
4 1,60i 1,60i 3
1,621 68,41l 68,41f 4
4,38'1 4,381 5
or 3,771 3,77C 6
ft 7t 7
1,201 57.18(57,18(I
8,05r 298,',t2t 298,12t I
4,71,173,66',173,661 10
59,70(2,007,261 2,007,262 11
13,11,68{11,68t 12
4',4i 13
77,561 4,777,531 4,777,535 14
3,88'1,44i 3',t0,77(289.11€2,815,121 211,7'.t3,11!413,58t 214,941,82i
FERC FORM NO. r (ED. 12-90)Page 327.12
Name of Respondent
ldaho Power Company
I his F(e(1) E(2) f
cort Is:
]An Original
]A Resubmission
Date of Reoort
(Mo, Da, Yi)
04t1512014
Year/Period of Report
End of 20131Q4
PURCHASED POWER (Account 555)(lncludinq power exchanqes)
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. ln 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). ln 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.9., 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.
lF - for intermediate-term firm service. The same as LF service expect that'intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service expect that'intermediate-term' means
longerthan 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 seftlements 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 ftom designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
-tne
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Ac'tual Demand (M\M
AVerage
Monthly NCP Deman
(e)
Average
Monthly CP Demant
(f)
1 Telocaset Wind Power Parhers LLC -U APP-A NA \,IA Nr'
2 Neal Hot Springs Unit #1 U NA !A N/
3 Net Metering Customers ffi-NA !A NI
4 Oregon SolarCustomers lry-NA \.lA N/6
5 Prior Year AdjustmenE \D
6 Power Exchanges
7 Bonneville Power Adminisbation
ffi
NA !A Nr'
8 EDF Trading North America, LLC NA \IA M
9 NorthWestem Energy NA \,IA NI
10 PadffCorp lnc.NA !A NI
11 Powerex Corp.NA !A NT
12 Siena Pacific Power Co., dba NV Energ NA !A NI
13 Clatskanie PUD EX 153 NA \IA NI
14 Clatskanine PUD AD 153 NA \A N/!
Total
FERC FORM NO. r (ED. 12-90)Page 326.13
Name of Respondent
ldaho Power Company
I nts
(1)
(2)
.(e
ET
|or[ ts;
An Original
A Resubmission
Date of Report
(Mo, Da, Yr)
041't512014
Year/Period of Report
End of 2O13lQ4
PURCHASED POWER(Account 555) (Continued)
{lncludino ooWer exchanoe's)'
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. ln column (c), identifo 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 averclge monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other gpes 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 supplie/s system reaches its monthly peak. Demand reported in columns (e) and (0
must be in megawafts. 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 fi), 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. lf more energy was delivered than received, enter a negative amount. lf the seftlement 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.
MegaWatt Hours
Purchased
(s)
POWER EXCHANGES COST/SETTLEMENT OF POWER Line
No.Megawa[ Hours
Received(h)
MegavYatt Hours
Delivered(i)
uemano unarges
,8i
Energy unarges
($)
(k)
umer unarges
tB
I OEtl U+K+l)
of Setflement ($)
(m)
300,80,16.220.611 16,220,61(1
155,53r 15,509,051 15,509,05:
971 73.21 73,21i 3
64r 20,00 20,001 4
-15.461 -15,46t
6
78,221 7
8
7,272 1,133 I
175,83(251,815 't0
40t 11
7,571 12
48,951 28,60C 13
6i 14
3,881,44i 310,77C 289,11 2,815,12,211,713,1'.t1 413,581 214,941,82i
FERC FORM NO.1 (ED. 12-90)Page 327.13
Name of Respondent
ldaho Power Company
tnrs KeDon ts:(1) []An orisinal(2\ l--lA Resubmission
uale ot KeDon
(Mo, Da, Yi)
0411s12014
YeaflHenoo oI Kepon
End of 2O13lQ4
PURCHASET] POWER (ACcoUnt 555)(lncluding 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. ln 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). ln 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.9., the supplier must aftempt 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.
lF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for intermediate-term service ftom a designated generating unit. The same as LU service expect that "intermediate-term" means
longerthan 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.
-ine
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
AVeragE
Monthly NCP Deman
(e)
AVerage
Monthly CP Demanc
(0
1 Other Transactions NA \A Nr'
2 Acct Valuation-Clatskanie PUD Exchange NA \A NI
3 Demand Response Avoided Energy OS NA !A Nr'
4 Grand Mew Solar Settlement )S NA \.lA Nr'
5 Absorb Dynamis Deposit OS NA \A Nr'
6 Magic West Seftlement OS NA \A Nr'
7
8
I
10
11
12
13
14
Total
FERC FORM NO.1 (ED. 12-90)Page 326.14
Name of Respondent
ldaho Power Company
I nts F(eDon ts:(1) filAn orisinal(2) l-lA Resubmission
Date of Report I Year/Period of Report
(Mo, Da, Yi) I eno ot 2o13te40411512014 I '
PUKUHAiiEtI P.9WEK(Account C55) .(L;ontrnued)ilncluornq power excnanqesl
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. ln column (c), identifi 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 (0. 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 megawafts. 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 seftlement by the respondent. For power exchanges, report in column (m) the seftlement
amount for the net receipt of energy. lf more energy was delivered than received, enter a negative amount. lf 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.
MegaWatt Hours
Purchased
(s)
POWER EXCHANGES COST/SETTLEMENT OF POWER Line
No.Megawa[ Hours
Received
(h)
Megawatt FlouGi
Delivered(i)
Lremand charges
..?t
Energy unarges
trl
umer unarges
($)o
I OIaI U+Ktl)of Settlement ($)
(m)
I
382,26i 382.26i 2
4,203,'.t51 4,203,151 3
-'t00,00(-100,00(4
-150,00(-150,00(5
-1,000,00(-1,000,00(6
7
8
I
10
11
12
13
14
3,881,44:310,771 289,11€2,815,121 211,713,11 413,5U 2',14,941.82i
FERC FORM NO. r (ED. 12-90)Page 327.14
Name of Respondent
ldaho Power Company
This Report is:
(1) X An OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
0411512014
YeariPeriod of Report
2013tQ4
FOOTNOTE DATA
:326.2 Line No.: 5 Column: f
Unavai-1able
: 326.2 Line No.: 10 Column: b
Non Eirm Purchases
:326.3 Line No.:2 Column: a
Ida West a subsidia of IDACORP, has rtial- ownershi of these ects.
Ida West a subsidiar of IDACORP, has rtial ownershi of these ects.326.4 Line No.:9 Column: a
Unavailable
326.5 Line No.:13 Column: b
Non Firm Purchases
1Unavailable
326.6 Line No.:4 Column: f
Unavailable
Ida West, a subsidiary of IDACORP, has partial ownershi of these ro ects.
The Tamarack Energy Partnership demand readingsrecorder provided by Idaho Power Co. The actual are taken
demand is from an enot used
ectronic demain determining the cost
326.6 Line No.:14 Column: a
326.7 Line No.:1 Column: a
of enerov.
Unavailable
326.7 Line No.:1 Column: f
Unavailable
326.7 Line No.:2 Column: b
Non Eirm Purchases
Non Firm Purchases
326.7 Line No.:13 Column: aIda West, a subsidiar of fDACORP, has partial ownershi of these ects
Reversal o rl-or ri-od accrued additional
fnterest riod SES AS
Difference between booked and schedul
se
326.8 Line No.:1 Column: a
326.8 Line No.:2 Column: a
326.8 Line No.:3 Column: a
326.8 Line No.:6 Column: b
Non Firm rcnases
ener
FERC FORM NO.1 1 450.1
Name of Respondent
ldaho Power Comoanv
This Report is:
(1) X An OriginalQ) A Resubmission
Date of Report
(Mo, Da, Yr)
o411512014
Year/Period of Report
20131Q4
FOOTNOTE DATA
326.8 Line No.:9 Column: b
ISDA Master Aqreement with Barcla Bank PLC dated Mardn 2, 20L1
Einancial Transmission Losses
:326.8 Line No.: 11 Column: b
Non Firm Purchases
ISDA Master Asreement
Non Firm Purchases
ISDA Master Aoreement
Non-Firm Purchases
: 326.9 Line No.: 13 Column: b
Non Firm Purchases
326.10 Line No.:4 Column: b
Prudential Bache Commodities, LLC (Jefferies Bache) Futures Account Document, dated
September 4, 2008
326-10 Line No.:7 Column: b
ISDA Master
Non Pirm Purchases
326-10 Line No.: 14 Column: b
Non-Firm Purchases
Financial Transmiss Los ses
326.11 Line No.:3 b
Non Firm Purchases
326.11 Line No.:7 Column: b
Non-Firm Purchases
326.11 Line No.:9 Column: b
Non Firm Purchases
326.11 Line No.:13 Column: b
Non Firm Purchases
ISDA Master Aqreement
Non-Fi-rm Purchases
Financial Transmission
326.12 Line No.:7 Column: b
Non-Firm purchases
Non Firm Purchases
326.13 Line No.:4 Column: b
326.13 Llne No.:7 Column: b
Schedu osses not removed with l-oss transactions
Schedu osses not removed with l-oss transactions
FERC FORM NO.1 1 450.2
This Page lntentionally Left Blank
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
0411512014
Year/Period of Report
20131o,4
FOOTNOTE DATA
326.13 Line No.:9 Column: b
Schedul-ed l-osses not removed with loss transactions
losses not removed with loss transactions
losses not removed with transactions
osses not removed with transactions
FORM NO.1 450.3
Name of Respondent
ldaho Power Company
I his Reoort ls:(1) EAn odginat
(21 nA Resubmission
Date of Reoort(Mo, Da, Yi)
o4t15t2014
Year/Period of Report
End of 20131Q4
MlSSloN OF ELECTRIC_ITY EqR OfHER.$ (Account 456.1)
I nclud ing transactions referred to as'wheelino')
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualirying 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), (O) 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. ln 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 lnstruction for definitions of codes.
lne
No.
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affliation)
(c)
Statistical
Classifi-
cation
(d)
,|Bonneville Power Administration - OTEC Bonneville Power Administration Oregon Trails Electric Coop :NO
2 Bonneville Power Administration - OTEC Bonneville Power Administration Oregon Trails Electric Coop \D
3 Bonneville Power Administration - USBR Bonneville Power Administration United States Bureau of Redamati :NO
4 Bonneville Power Administration - USBR Bonneville Power Administration United States Bureau of Reclamati \D
5 Bonneville Power Administration - PF Bonneville Power Administration Priority Firm Customers :NO
6 Bonneville Power Administration - PF Bonneville Power Administration Priority Firm Customers \D
7 Milner lnigation District United States Bureau of Reclamati Milner lrrigation District )LF
I Cargill Seatfie City Light Bonneville Power Administration )S
I PacifiCorp PacifiCorp West PacifiCorp West :NO
10 PacifiCorp PacifiCorp West PacifiCorp West \D
11 United States Bureau of lndian Afiairs Bonneville Power Adminisbation United States Bureau of lndian Af ls
12 United Materials of Great Falls NorthWestern/Pacifi Corp East ldaho Power Company ]S
13 PacifiCorp PacifiCorp West PacifiCorp West fS
't4 PacifiCorp PacifiCorp West PacifiCorp West \D
't5 BC Hydro Powerex PacifiCorp East NorthWestern/Pacifi Corp East {F
16 BC Hydro Powerex PacifiCorp East PacifiCorp West {F
17 BC Hydro Powerex PacifCorp East ldaho Power Company \tF
18 BC Hydro Powerex PacillCorp East NorthWestem/Pacifi Corp East \,IF
1S BC Hydro Powerex PacifiCorp East Bonneville Power Adminisfation {F
20 BC Hydro Powerex PacifiCorp East Siena Pacific Power !F
21 BC Hydro Powerex NorhWestem/Pacifi Corp East PacifiCorp East !F
22 BC Hydro Powerex NorhWestem/Pacifi Corp East PacifiCorp East 3FP
23 BC Hydo Powerex Norfi Westem/Pacifi Corp East PacifiCorp East !F
24 BC Hydro Powerex NorthWestem/Pacifi Corp East PaciliCorp West \IF
25 BC Hydro Powerex NorthWestem/Pacifi Corp East Bonneville Power Administation !F
26 BC Hydro Powerex NorthWestem/Pacifi Corp East Siena Pacific Power !F
27 BC Hydro Powerex PacifiCorp East PacifiCorp East !F
28 BC Hydro Powerex PacifiCorp East NorthWestern/Pacifi Corp East !F
29 BC Hydro Powerex PacifiCorp East PacifiCorp West \lF
30 BC Hydro Powerex PacifiCorp East ldaho Power Company !F
31 BC Hydro Powerex PacifiCorp East PacifiCorp West !F
32 BC Hydro Powerex PacifiCorp East Bonneville Power Administration !F
33 BC Hydro Powerex PacifCorp East Siena Pacific Power VF
34 BC Hydro Powerex PacifiCorp West PacifiCorp East \F
TOTAL
FERC FORM NO.1 (ED.12-90)Page 328
Name of Respondent
ldaho Power Company (1) E(2) r
on ls:
An Original
A Resubmission
Date of Reoort(Mo, Da, Yi)
04115t2014
Year/Period of Report
End of 2O13lQ4
TRANSMISSION OF ELECTRICITY FOR OTHER,S (ACCOUNI 456XCONtiNUEd)(lncludinq transactions reffered to as'wheelinq') "
5. ln column (e), identiff the FERC Rate Schedule or Tariff Number, On separcte 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. ln column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. ln 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 fi) the total megawatthours received and delivered. '
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(0
Point of Delivery
(Substation or Other
Designation)
(s)
Billing
Demand
(MW)
(h)
TRANSFER OF ENERGY -ine
No.Megawa[ nours
Received(i)
Megawafl Hours
Delivered
0)
341,46(341,461 1
2
294,562 294,561 3
4
1,294,51i 1.294.51i 5
6
Minidoka, ldaho Various in ldaho 9,10r 9.10{7
215,46i 215,46i I
2,151 2,151 I
10
-aGrande, Oregon Various in ldaho 17,811 17,81i 11
JEFF tPco 5.76(5.76(12
,BSN ENPR 't3
JBSN ENPR 14
SORA BPAT.NWvIT 3,241 3,24',15
30RA ENPR 51 5'16
30RA HMVUT 3,38i 3,38i 17
30RA JEFF 131 13'18
]ORA I.AGMNDE 9,051 9,05'19
3ORA M345 6(6(20
BPAT.NWMT BORA 64(at(21
BPAT.NWMT BORA 19,96i 19,96:22
BPAT.NWMT 3RDY 50t 50t 23
BPAT.N\A/MT JBSN 201 201 24
BPAT.NWMT .AGRANDE 3(3(25
BPAT.NIA'MT \4345 67t 67t 20
BRDY 30RA 86t 86!27
BRDY 3PAT,NWMT 2,221 2,22 28
BRDY =NPR 1t It 29
BRDY {MWY 52t 521 30
BRDY JBSN 3(3(31
BRDY SGRANDE 3,79t 3,79,32
BRDY vt345 2,47i 2,47i 33
ENPR 30RA 79,06'i 79,06,34
6,358,85!6,35E,E5!
FERC FORM NO. r (ED. 12-90)Page 329
Name of Respondent
ldaho Power Company
tnts KeDon Is:(1) []nn Orisinat(2\ l-lA Resubmission
Date of Reoort(Mo, Da, Yi)
04t1512014
Year/Period of Report
End of 20131Q4
I RANSMTSSTON UF ELEC I RtC_t I Y FOR OTHEFTS (Account 456,1)(lncludinq transactions refened to as'wheelinq')
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualirying facilities, non-traditional utili$ 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. ln 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 Sell 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-upsn for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General lnstruction for definitions of codes.
lne
No.
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Affliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
1 BC Hydro Powerex PacifiCorp West PacifiCorp East SFP
2 BC Hydro Powerex PacifiCorp West PacifiCorp East !F
3 BC Hydro Powerex PacifiCorp West PacifiCorp West !F
4 BC Hydro Powerex PacifiCorp West Siena Pacific Power {F
5 BC Hydro Powerex NorhWestem/Pacifi Corp East PacifiCorp East {F
6 BC Hydro Powerex NorhWestem/Pacifi Corp East ldaho Power Company {F
7 BC Hydro Powerex NorthWestem/Pacifi Corp East Bonneville Power Administration {F
I BC Hydro Powerex ldaho Power Company PacifiCorp East !F
I BC Hydro Powerex ldaho Power Company PacillCorp East 3FP
10 BC Hydro Powerex ldaho Power Company PacifiCorp East {F
't1 BC Hydro Powerex ldaho Power Company PacifiCorp West VF
12 BC Hydro Powerex ldaho Power Company Siena Pacific Power !F
13 BC Hydro Powerex PacifiCorp West ldaho Power Company {F
14 BC Hydro Powerex PacifiCorp West NorthWestem/Pacif Corp East !F
15 BC Hydro Powerex PacifiCorp West Bonneville Power Administration VF
16 BC Hydro Powerex PacifiCorp West Siena Pacific Power !F
17 BC Hydro Powerex ldaho Power Company Bonneville Power Administration \IF
18 BC Hydro Powerex NorthWestern/Pacifi Corp East NorthWestern/Pacifi Corp East !F
19 BC Hydro Powerex NorthWestem/Pacifi Corp East PacifiCorp East \,IF
20 BC Hydro Powerex NorthWestem/Pacifi Corp East PacifiCorp West !F
21 BC Hydro Powerex NorthWestern/Pacifi Corp East Bonneville Power Adminishation !F
22 BC Hydro Powerex NorthWestem/Pacifi Corp East Siena Pacilic Power \IF
23 BC Hydro Powerex Bonneville Power Adminisbation PacifiCorp East \F
24 BC Hydo Powerex Bonneville Power Administration PacifiCorp East SFP
25 BC Hydro Powerex Bonneville Power Adminishation PacifiCorp East \lF
26 BC Hydro Powerex Bonneville Power Adminisfation PacifiCorp West !F
27 BC Hydro Powerex BonneMlle Power Adminisbation Siena Pacific Power !F
28 BC Hydro Powerex Bonneville Power Adminisfation Siena Pacific Power SFP
29 BC Hydro Powerex Avista PacifiCorp East \F
30 BC Hydro Powerex Avista PacifiCorp West \IF
31 BC Hydro Powerex Avista Sierra Pacific Power \F
32 BC Hydro Powerex Sierra Pacific Power NorthWestern/Pacifi Corp East !F
33 BC Hydro Powerex Sierra Pacific Power PacifiCorp East \,IF
34 BC Hydro Powerex Sierra Pacific Power Bonneville Power Administration \IF
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.1
Name ot Respondent
ldaho Power Company
tnts F(eoon ts:(1) fiAn original(2) [-lA Resubmission
uate oi Keoon(Mo, Da, Yi)
0411512014
YeailHenoo oI Kepon
End of 20131Q4
I T{AN!,MI55IUN (,F ELEU I KIUI I Y FUK (JI FIET(U (ACCOUT(lncludino transactions reffered to as kheelino'I 4COXUOn0nUeO)
5. ln column (e), identiff 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. ln column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. ln 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 megawafts of billing demand that is specified in the flrm transmission service contract. Demand
reported in column (h) must be in megawafts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j) the total megawafthours received and delivered.
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(0
Point of Delivery
(Substation or Other
Designation)
(s)
Billing
Demand
(MW)
(h)
TRANSFER OF ENERGY Line
No.Megawatt Hours
Received(i)
Megawatt Hours
Delivered
0)
:NPR loRA 129,021 129,021 1
:NPR 3RDY 1,141 1,141 2
=NPR ,BSN 4l 4l 3
=NPR \,t345 48'481 4
35HN sRDY 5
3SHN IMWY 9(9(6
GSHN .AGRANDE 1,81i 1,81;7
HMVU/30RA 138,06i 138,06'8
HMWY BORA 77,5!77,53t I
HMIA/Y BRDY OJr 63i 10
HMVVY JBSN 84:84:11
HMVI/Y M345 6,74 6,74,12
5 JBSN HMWY 721 72t 13
5 JBSN JEFF 33(33('t4
JBSN LAGRANDE 87(87!15
JBSN M345 4t 4t 16
JBWT LAGRANDE 12i 12i 17
,EFF BPAT.NWMT 2l 2l 18
JEFF BRDY 2t 2t,19
JEFF JBSN 20
JEFF LAGRANDE 371 37 21
JEFF M345 4i 4:22
.AGRANDE BORA 8,69i 8,69 23
.AGRANDE 3ORA 1,00,1,00i 24
.AGRANDE 3RDY 14i 14i 25
.AGRANDE JBSN 3(3(26
LAGRANDE vr34s 6,90t 6,90r 27
LAGRANDE \r345 10i 101 28
LOLO ]ORA 10(10t 29
LOLO ,BSN 19(19(30
LOLO \,1345 20(201 31
M345 3PAT.NWMT 10(10(32
M345 3RDY 5(E(33
M34s -AGRANDE 81{81r 34
6,3s8,85(6,35E,E5!
FERC FORM NO. r (ED. 12.90)Page 329.1
Name of Respondent
ldaho Power Company
tnts Ke(1) E(2) T
ort ls:
An Original
A Resubmission
Date of Reoort(Mo, Da, Yi)
04t1s12014
Year/Period of Report
End of 20'l3lQ4
il.(ANt VII-OI\JI\ \JT trLtrU I I{IUI I I TUK U INEKDncludinq transactions refened to as'wheelin
cccount 4b6.1 )
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. ln 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 lnstruction for definitions of codes.
-tne
No.
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Afiiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifl-
cation
(d)
1 Black Hills Power PacifiCorp West PacifiCorp East NF
2 Black Hills Power PacifiCorp West Siena Pacific Power NF
3 Bonneville Power Adminstration NorthWestem/Pacifi Corp East Siena Pacific Power NF
4 Bonneville Power Adminstration Bonneville Power Adminisfation Bonneville Power Adminisbation NF
5 Bonneville Power Adminstration Bonneville Power Adminisfation Sierra Pacific Power NF
6 Bonneville Power Adminstration Avista Bonneville Power Administsation NF
7 Bonneville Power Adminstration Avista Siena Pacific Power NF
8 Cargill-Alliant NorhWestem/Pacifi Corp East Siena Paciffc Power NF
I Cargill-Alliant PacifiCorp East NorthWestem/Pacifi Corp East NF
10 Cargill-Alliant PacifiCorp East PacifiCorp West NF
1'l Cargill-Alliant PacifiCorp East PacifCorp West !F
12 Cargill-Alliant PacifiCorp East Bonneville Power Administration {F
13 Cargill-Alliant PacifiCorp East Bonneville Power Adminisbation 3FP
14 Cargill-Alliant PacifiCorp East Siena Pacific Power {F
15 Cargill-Alliant PacifiCorp East Siena Pacific Power SFP
16 Cargill-Alliant NorthWestem/Pacifi Corp East PacifiCorp East !F
17 Cargill-Alliant NorthWestem/Pacifi Corp East PacifiCorp East SFP
18 Cargill-Alliant NorthWestem/PacifiCorp East Bonneville Power Administration \IF
19 Cargill-Alliant NorthWestem/Pacifi Corp East Siena Pacific Power \.lF
20 Cargill-Alliant NorhWestem/Pacifi Corp East Sierra Paciffc Power SFP
21 Cargill-Alliant PacifiCorp East PacifiCorp East !F
22 Cargill-Alliant PacifiCorp East Bonneville Power Adminishation \F
23 Cargill-Alliant PacifiCorp East Siena Pacific Power \lF
24 Cargill-Alliant PacifiCorp East Sierra Pacific Power SFP
25 Cargill-Alliant PacifiCorp West PacifiCorp East \lF
26 Cargill-Alliant PacifiCorp Wesl PacifiCorp East SFP
27 Cargill-Alliant PacifiCorp West Siena Pacific Power NF
28 Cargill-Alliant PacifiCorp West Siena Pacific Power SFP
29 Cargill-Alliant ldaho Power Company Bonneville Power Administration NF
30 Cargill-Alliant PacifiCorp West PacifiCorp East NF
31 Cargill-Alliant PacifiCorp West NorthWestem/Pacifi Corp East NF
32 Cargill-Alliant PacifiCorp West Bonneville Power Administration NF
33 Cargill-Alliant PacifiCorp West Avista NF
34 Cargill-Alliant PacifiCorp West Sierra Pacific Power NF
TOTAL
FERC FORM NO. 1 (ED. 12-90)Page 328.2
Name of Respondent
ldaho Power Company
I nts Keoon ts:(1) []An orisinal(2) l-lA Resubmission
Date ot ReDon
(Mo, Da, Yi)
04t1512014
YeailHenod ot Kepon
End of 20131Q4
II<ANSMISSIUN UT ELEUI KIUI IY I.UK ()IHtsKs (ACCOUII(lncludinq transactions reffered to as'wheelino'l t 45OXUonInUeO)
5. ln column (e), identiff 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. ln column (0, report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. ln 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 0) the total megawatthours received and delivered.
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(0
Point of Delivery
(Substation or Other
Designation)
(s)
Billing
Demand
(MW)
(h)
TRANSFER OF ENERGY Line
No.Megawatt Hours
Received(i)
Megawatt Hours
Delivered(i)
JBSN ]ORA ,|1(1
,BSN !/l345 33;33:2
3PAT.NWMT vl345 2(2t 3
.AGMNDE .AGRANDE 11,01 11,01 4
.AGRANDE M345 16,121 16,121 5
-oLo LAGRANDE 8,58(8,58!6
-oLo M345 2,',t71 2,17,7
ryAT.NWMT M345 431 43(8
]ORA BPAT.NWMT 22'.22t 9
3ORA ENPR 97{97t 10
]ORA JBSN 56{56r 11
sORA -AGRANDE 8,68{8,68r 12
]ORA .AGRANDE 1.07'1,071 13
sORA \,t345 14,08:14,081 14
]ORA \4345 8,34:8,34:15
3PAT.NWMT 3ORA 88i 88:16
lPAT.NWtvlT 30RA 9,47i 9,47i 17
]PAT.N![/MT .AGRANDE 39'39:t8
3PAT.NWMT \4345 1 1,39r 1 1,39,19
]PAT.NWMT \/l345 12,90i 12,90:20
BRDY 30RA 3l 3r 21
BRDY .AGRANDE tt 3,22
BRDY \4345 1.63(1,631 23
BRDY M345 $r 6,24
ENPR 30RA 7,98i 7,98'25
ENPR 30RA 17,66f 17,66r 26
ENPR \4345 3.67t 3,671 27
ENPR u345 8,86t 8,86r 28
IPCOGEN .AGRANDE 5(5l 29
JBSN 3ORA 18;18'30
JBSN ]PAT.NWMT 211 21 31
JBSN -AGRANDE 1,30:1,30:32
JBSN _oLo 1,60(1,601 33
JBSN \,t345 33:331 34
6,358,85t 6,358,85(
FERC FORM NO.1 (ED.12-90)Page
Name of Responclent
ldaho Power Company
lnts Keoon ls:(1) []Rn orlsinat(2) l-lA Resubmission
Date of Report(Mo, Da, Yr)
0411512014
Year/Period of Report
End of 20131Q4
I KAN5MIssI(,N UI- trLtrU I KIUI I Y FUK U I HEKI' (/(lncludinq transactions refened to as \uheelind )count 4bo.1 )
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualirying 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. ln 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 lnstruction for deflnitions of codes.
-ine
No.
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From
(Company of Public Auhority)
(Footnote Affiliation )(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
1 Cargill-Alliant PacifiCorp West Siena Pacific Power SFP
2 Cargill-Alliant NorthWestern/Pacifi Corp East PacifiCorp East \.lF
3 Cargill-Alliant NorthWestem/Pacifi Corp East Siena Pacific Power !F
4 Cargill-Alliant Bonneville Power Administration PacifiCorp East \F
5 Cargill-Alliant Bonneville Power Administration PacifiCorp East {F
o Cargill-Alliant Bonneville Power Administratlon Sierra Pacific Power \F
7 Carsill-Alliant Bonneville Power Administration Sierra Pacific Power 3FP
I Cargill-Alliant Avista PacifiCorp East !F
I Cargill-Alliant Avista PacifiCorp East SFP
10 Cargill-Alliant Avista PacifiCorp West \F
11 Cargill-Alliant Avista Siena Pacific Power \lF
12 Cargill-Alliant Avista Sierra Pacific Power SFP
13 Cargill-Alliant Siena Pacific Power PacifiCorp East \F
14 Cargill-Alliant Sierra Pacific Power PacifiCorp East SFP
15 Cargill-Alliant Siena Pacific Power NorthWestem/Pacifi Corp East !F
16 Cargill-Alliant Sierra Pacific Power PacifiCorp East \IF
17 Cargill-Alliant Siena Pacific Power PacifiCorp West NF
18 Cargill-Alliant Siena Pacific Power PacifiCorp West NF
19 Cargill-Alliant Siena Pacific Power NorthWestem/Pacifi Corp East NF
20 Cargill-Alliant Siena Pacific Power Bonneville Power Administration NF
21 Cargill-Alliant Siena Pacific Power Bonneville Power Administration SFP
22 Cargill-Alliant Sierra Pacific Power Bonneville Power Administration LFP
23 Cargill-Alliant Siena Pacific Power Avista NF
24 Cargill-Alliant Siena Pacific Power Siena Pacific Power NF
25 Cargill-Alliant Siena Pacific Power Sierra Pacific Power SFP
26 Cargill-Alliant Siena Pacific Power Bonneville Power Administration NF
27 Cargill-Alliant ldaho Power Company Bonneville Power Adminiskation SFP
28 lberdrola Energy PacifiCorp East Bonneville Power Adminishation NF
29 lberdrola Energy PacifiCorp East Siena Pacific Power NF
30 lberdrola Energy NorthWestem/Pacifi Corp East PacifiCorp East NF
31 lberdrola Energy NorthWestem/Pacifi Corp East PacifiCorp East NF
32 lberdrola Energy NorthWestem/Pacifi Corp East Sierra Pacific Power NF
33 lberdrola Energy PacifiCorp East PacifiCorp East NF
34 lberdrola Energy PacifCorp East Sierra Pacific Power NF
rOTAL
FERG FORM NO.1 (ED. 12-90)Page 328.3
Name of Respondent
ldaho Power Company
tnts Ke(1) E(2) r
on ts:
An Original
A Resubmission
Date of Report
(Mo, Da, Yr)
0411512014
Year/Period of Report
End of 2O13lQ4
I RANSMISSIUN UF ELEL; I ITIUI I Y F(JT( O I FIETil' (ACCOUNI 4STiXUONI|NUEO)(lncluding transactions reffered to as'wheelinq') "
5. ln column (e), identifu the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which seryice, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. ln column (0, report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. ln 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 megawafts basis and explain.
8. Report in column (i) and (j) the total megawafthours received and delivered.
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(0
Point of Delivery
(Substation or Other
Designation)
(s)
Billing
Demand
(Mw)
(h)
TMNSFER OF ENERGY Line
No.rvregaYYarr n()u15
Received(i)
Megawa[ Hours
Delivered
0)
JBSN vl345 47t 471 1
JEFF 3ORA 2
JEFF vt345 2,69i 2,69 3
.AGRANDE loRA 1,35(1,351 4
IAGRANDE ]RDY 11 11 5
-AGRANDE t1345 27,47t 27,47t o
-AGRANDE v|345 2,86(2,861 7
_oLo ]ORA 6,69i 6,69r 8
_oLo 30RA 2,2s(2,251 9
_oLo JBSN 191 19:10
_oLo M34s 11,21(11,211 1'l
_oLo M345 2,541 2,54,12
-YPK BORA 6,84t 6,84r 13
-YPK BORA 't7.82t 17,821 14
.YPK BPAT.NWMT 31i 31"15
.YPK BRDY 14i 't4i 16
-YPK =NPR 3i 3"17
-YPK JBSN 5(5l 18
-YPK JEFF EI 5l 19
-YPK -AGRANDE 3,231 3,23,20
YPK AGRANDE 21(211 21
tYPK -AGRANDE 19,38(19,381 22
LYPK -oLo 2(2t 23
LYPK \4345 14,451 14,45,24
LYPK \4345 152,341 '152,341 25
M345 .AGRANDE 2l 2l 26
OBBLPR .AGMNDE 80(80r 27
BORA SGRANDE 63(631 28
BORA \,t345 29
BPAT.NWMT 30RA 6:o 30
BPAT.NWMT ]RDY 5(5l 31
BPAT.NWMT vt345 1,23(1,23/,32
BRDY 30RA 5(5l 33
3RDY vI345 5(5(34
6.35E.85!6,358,851
FERC FORM NO. r (ED. 12-90)Page 329.3
Name of Respondent
ldaho Power Company
Ihis Reoort ls:(1) Een orisinat
(21 llA Resubmission
Date of Reoort(Mo, Da, Yi)
o411512014
Year/Period of Report
End of 20131Q4
il-tANt villilituN ut- ELEU I t{tu_t I Y ]-ot( (J.t HERs (Account 456.1)ncluding transactions refened to as'wheelinq')
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualirying 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. ln 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 lnstruction for definitions of codes.
-rne
No.
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
1 Iberdrola Energy PacifiCorp West PacifiCorp East !F
2 lberdrola Energy PacifiCorp West Sierra Pacific Power !F
3 lberdrola Energy ldaho Power Company PacifiCorp East \IF
4 lberdrola Energy ldaho Power Company PacifiCorp East !F
5 lberdrola Energy ldaho Power Company Sierra Pacific Power !F
6 lberdrola Energy Bonneville Power Administration PacifiCorp East \,IF
7 lberdrola Energy Bonneville Power Administration PacifiCorp East !F
I lberdrola Energy Bonneville Power Administration Siena Pacific Power !F
9 lberdrola Energy Avista PacifiCorp East !F
10 lberdrola Energy Avista Sierra Pacific Power \.lF
11 lberdrola Energy Sierra Pacific Power PacifiCorp East \,lF
12 lberdrola Energy Siena Pacific Power Bonneville Power Administration \F
13 Macquarie Energy PacifiCorp East Bonneville Power Administration !F
14 Morgan Shnley Captial Group NorthWestem/Pacifi Corp East PacifiCorp East \F
15 Morgan Stanley Captial Group NorthWestern/Pacifi Corp East Siena Pacific Power !F
16 Morgan Stanley Captial Group PacifiCorp East PacifiCorp East \F
17 Morgan Stanley Captial Group PacifiCorp East Bonneville Power Administration \,IF
18 Morgan Stanley Captial Group PacifiCorp East Sierra Pacific Power !F
19 Morgan Stanley Captial Group NorthWestem/Pacifi Corp East PacifiCorp East \F
20 Morgan Stanley Captial Group NorthWestem/Pacifi Corp East PacifiCorp East \F
21 Morgan Stanley Captial Group NorthWestem/Pacifi Corp East Bonneville Power Administration \F
22 Morgan Stanley Captial Group NorthWestern/Pacifi Corp East Siena Pacific Power \F
23 Morgan Stanley Captial Group PacifiCorp East PacifiCorp East \F
24 Morgan Stanley Captial Group PacifiCorp East NorthWestern/Pacif Corp East \F
25 Morgan Stanley Captial Group PacifiCorp East Bonneville Power Administration !F
26 Morgan Stanley Captial Group PacifiCorp East Sierra Pacific Power \F
27 Morgan Stanley Captial Group PacifiCorp West PacifiCorp East \F
28 Morgan Stanley Captial Group ldaho Power Company PacifiCorp East !F
29 Morgan Stanley Captial Group ldaho Power Company PacifiCorp East SFP
30 Morgan Stanley Captial Group ldaho Power Company PacifiCorp East NF
31 Morgan Stanley Captial Group ldaho Power Company Siena Pacific Power \IF
32 Morgan Stanley Captial Group PacifiCorp West PacifiCorp East NF
33 Morgan Stanley Captial Group PacifiCorp West PacifiCorp East NF
34 Morgan Stanley Captial Group PacifiCorp West Bonneville Power Administration NF
rOTAL
FERC FORM NO. I (ED. 12-90)Page 328.4
Name of Respondent
ldaho Power Company
This Reoort ls:(1) []Rn orisinat(2) l-lA Resubmission
Date of Reoort(Mo, Da, Yi)
o4t15t2014
Year/Period of Report
End of 20131Q4
I KI\NUMINDILJN UF ELtrU I T(IUI I Y T(JK IJ I IIET(U (AC@U](lncludinq transactions reffered to as'wheelinq't 4S6Xcontinued)
5. ln column (e), identiff 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. ln column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. ln column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j) the total megawatthours received and delivered.
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(0
Point of Delivery
(Substation or Other
Designation)
(s)
Billing
Demand
(MW)
(h)
TRANSFER OF ENERGY Line
No.Megawatt Hours
Received(i)
Megawafi Hours
Delivered
0)
:NPR 30RA 1(1!1
=NPR \,t345 60(60(2
IMWY ]ORA 15,92 15,92 3
{MWY 3RDY 63(63(4
.IMWY \/l345 4.98 4,98;5
.AGRANDE ]ORA 13,19(13,19(6
LAGRANDE 3RDY 241 241 7
LAGRANDE vt345 7,29i 7,29',8
LOLO ]ORA 3(3(I
LOLO M345 251 251 10
M34s BORA 15(15(11
M345 LAGRANDE E(E'12
BORA LAGRANDE 6{6r 13
AVAT.NWMT BORA 231 23t 14
AVAT.NWMT M345 97:97:15
30RA BRDY !t !,t 16
30RA LAGRANDE 80r 80,17
3ORA M345 6,29:6,29:18
3PAT.NWMT BORA 2t 2l 19
3PAT.NWI\47 BRDY 1 lt 20
3PAT.NWMT LAGRANDE 8'I 21
]PAT.NWMT M345 1.19t 1,19r 22
3RDY BORA 83{83r 23
3RDY BPAT.NWMT 9(9(24
3RDY LAGRANDE 60;60;25
3RDY M345 2,81(2,81!26
=NPR
BORA 401 40t 27
{M\A/Y BORA 10,13r 10,'l3r 28
lMvu/BORA 't1.271 11,271 29
HMWY BRDY 201 201 30
HMWY \,1345 1.771 1,771 31
5 JBSN 30RA 2,30:2,301 32
JBSN ]RDY 141 141 33
5 JBSN .AGRANDE 151 15r 34
6,358,85!6,358,85!
FERC FORM NO. r (ED.12-90)Page 329.4
Name of Respondent
ldaho Power Company
tnts Keoon ts:(1) []An Original
(21 l-lA Resubmission
Date of Report(Mo, Da, Yr)
04t't5t2014
Year/Period of Report
End of 2O13lQ4
It(ANt VIIJSIIJN \JT ELEU I I(IUI I Y TUK U I HEXN (
ncludinq transactions refened to as'wheelini )count 456.1 )
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 afiiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. ln 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 lnstruction for definitions of codes.
_tne
No.
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Publlc Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
1 Morgan Stanley Captial Group PacifiCorp West Siena Pacific Power \,IF
2 Morgan Stanley Captial Group NorthWestem/Pacifi Corp East PacifiCorp East !F
3 Morgan Stanley Captial Group NorthWestem/Pacifi Corp East PacifiCorp East SFP
4 Morgan Stanley Captial Group NorthWestem/Pacifi Corp East PacifiCorp East !F
5 Morgan Stanley Captial Group NorthWestem/Pacifi Corp East Bonneville Power Administration !F
6 Morgan Stanley Captial Group NorthWestern/Pacifi Corp East Siena Pacific Power !F
7 Morgan Stanley Captial Group Bonneville Power Administration PacifiCorp East !F
8 Morgan Stanley Captial Group Bonneville Power Administration PacifiCorp East VF
I Morgan Stanley Captial Group Bonneville Power Adminishation Avista !F
10 Morgan Shnley Captial Group Bonneville Power Administation Siena Pacific Power !F
't1 Morgan Stanley Captial Group Avista PacifiCorp East !F
'12 Morgan Stanley Captial Group Avista PacifiCorp East !F
13 Morgan Stanley Captial Group Avista Sierra Pacific Power !F
14 Morgan Stanley Captial Group Sierra Pacific Power PacifiCorp East \,lF
15 Morgan Stanley Captial Group Siera Pacific Power NorthWestem/Pacifi Corp East \.lF
16 Morgan Stranley Captial Group Siena Pacific Power PacifiCorp East !F
17 Morgan Stanley Captial Group Siena Pacific Power NorthWestem/Pacifi Corp East \IF
18 Morgan Stanley Captial Group Siera Pacific Power Bonneville Power Administration \F
19 Pacifi corp Power Marketlng PacifiCorp East PacifiCorp West \,IF
20 Pacificoflg Power Marketing PacifiCorp East ldaho Power Company -FP
21 Pacificorp Power Marketing PacifiCorp East Bonneville Power Administsation !F
22 Pacifi corp Power Marketing PacifiCorp East Sierra Pacilic Power !F
23 Pacifi corp Power Ma*eting PacifiCorp East PacifiCorp East !F
24 Pacifi corp Power Marketin g PacifiCorp East PacifiCorp East {F
25 Pacifi corp Power Marketing PacifiCorp East NorthWestem/Pacifi Corp East \F
26 Pacifi corp Power Marketing PacifiCorp East ldaho Power Company \F
27 Pacificorp Power Marketing PacifiCorp West PacifiCorp East \F
28 Pacifi corp Power Marketing PacifiCorp West Bonneville Power Administration \IF
29 Paciffcorp Power Marketing ldaho Power Company Sierra Pacific Power NF
30 Pacifi corp Power Marketing ldaho Power Company Siena Pacific Power SFP
31 Pacifi corp Power Marketing PacifiCorp West ldaho Power Company NF
32 Pacificorp Power Ma*eting ldaho Power Company PacifiCorp East NF
33 Pacificorp Power Marketing ldaho Power Company PacifiCorp East LFP
34 Pacificorp Power Markeling ldaho Power Company PacifiCorp West NF
rOTAL
FERC FORM NO. r (ED.12-90)Page 328.5
Name of Respondent
ldaho Power Company
This Re(1) E(2) r
port ls:
]An Original
lA Resubmission
Date of Report(Mo, Da, Yr)
041't512014
YearPenoo ot Hepon
End of 20131Q4
I T(ANSMISSIUN UF ELEU I KIGI I Y FUT( U I HEI{!, (ACCOT(lncludino transactions reffered to as \rnheelinc
tl 4coxuonunueo)
5. ln column (e), identifo the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations underwhich service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. ln column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. ln 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 megawafts 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 megawafts basis and explain.
8. Report in column (i) and (j) the total megawatthours received and delivered.
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(f)
Point of Delivery
(Substation or Other
Designation)
(s)
Billing
Demand
(MW)
(h)
TRANSFER OF ENERGY Line
No.Megawatt Hours
Received(i)
Megawatt Hours
Delivered
0)
JBSN vt345 1,19t 1,19t ,|
JEFF loRA 118,211 118,211 2
JEFF ]ORA 1,141 1,141 3
JEFF ]RDY 76(76(4
JEFF -AGRANDE 1,141 1,14 5
JEFF v!345 11,55(1't,55t 6
:AGRANDE 30RA 4,371 4,37t 7
-AGRANDE ]RDY 't,05(1,051 I
.AGRANDE _oLo 51 5 I
.AGRANDE M345 11,10i 11,10',10
-oLo ]ORA 2si 25:11
_oLo BRDY 2t 2,12
_oLo M345 1,701 1,70 13
\r345 SORA 221 22 14
\iil345 BPAT.NWtvIT 35t 35:15
vl345 3RDY 7!7l 16
t,t345 JEFF 10(10r 17
vt345 3GRANDE 23(23.18
toRA =NPR
3,10(3,101 19
]ORA (PRT 1,123,10(1,123,101 20
30RA .AGRANDE 3,86i 3,86'21
3ORA M345 771 771 22
]RDY 30RA 131 13,23
]RDY 3RDY 2,431 2,43,24
3RDY GSHN 19(191 25
3RDY (PRT 2,00(2,001 26
ENPR 30RA 190,64t 't90,64r 27
ENPR .AGRANDE 8i 8:28
HMVVY t|345 13t 131 29
HMVVY vt345 't,40t 1.40,30
JBSN (PRT 3t 3,31
JBWT ]RDY 9,26(9,26r 32
JBWT ]RDY 424,26'.1 424,26 33
JBWT =NPR 1,23(1,231 34
6,35E,E5!6,35E,E5!
FERC FORM NO. r (ED. 12-90)
Name ot Kesponoent
ldaho Power Company
I nts l(eoon ts:(1) fiRn Originat(2) flA Resubmission
Date of Reoort(Mo, Da, Yi)
04115t2014
YearlPeriod of Report
End of 20131Q4
I KANi vlloor\-I\ vr ELtrv I r1tvt I T rvtl Lr t ntrr(Dncludino transactions referred to as'wheelin
qccount 4co.1 )
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualiffing 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. ln 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 Sell 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 lnstruction for definitions of codes.
-rne
No.
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
1 Pacificorp Power Marketing ldaho Power Company NorthWestem/Pacifi Corp East \F
2 Pacificorp Power Marketing ldaho Power Company ldaho Power Company -FP
3 Pacificorp Power Marketing ldaho Power Company ldaho Power Company !F
4 Pacificorp Power Marketing ldaho Power Company Bonneville Power Administration !F
5 Pacificorp Power Marketing ldaho Power Company Siena Pacific Power !F
6 Pacifi corp Power Marketing ldaho Power Company NorthWestem/PaciliCorp East VF
7 Pacifi corp Power Markeling Avista PacifiCorp West \,lF
8 Porland General Electric PacifiCorp East NorthWestem/Pacifi Corp East !F
9 Porland General Electric PacifiCorp East ldaho Power Company {F
10 Porland General Electric PacifiCorp East Bonneville Power Administration {F
11 Porland General Electric ldaho Power Company PacifiCorp East !F
12 Podand General Electric ldaho Power Company Siena Pacific Power !F
13 Porland General Electric Bonneville Power Administration PacifiCorp East \,IF
14 Porland General Electric Bonneville Power Adminisfation PacifiCorp East \IF
15 Porland General Electric Bonneville Power Administration Siena Pacific Power \lF
16 Porland General Electric Siena Pacific Power Bonneville Power Administration \F
17 PPL Energy Plus NorthWestern/Pacifi Corp East Bonneville Power Administration \F
't8 PPL Energy Plus Siena Pacific Power PacifiCorp East \lF
19 Rainbow Energy Marketing PacifiCorp East Avista \F
20 Rainbow Energy Marketing PacifiCorp East Siena Paciftc Power \F
21 Rainbow Energy Marketing PacifiCorp West NorthWestem/Pacifi Corp East \F
22 Rainbow Energy Marketing NorthWestem/Pacifi Corp East PacifiCorp West !F
23 Rainbow Energy Marketing NorthWestem/Pacifi Corp East Siena Pacific Power \F
24 Rainbow Energy Marketing Avista PacifiCorp East SFP
25 Rainbow Energy Marketing Avista Siena Pacific Power SFP
26 Shell Energy PacifiCorp East Bonneville Power Administration NF
27 Shell Energy PacifiCorp East Siena Pacific Power NF
28 Shell Energy PacifiCorp East Bonneville Power Administration NF
29 Shell Energy PacifiCorp East Siena Paciflc Power NF
30 Shell Energy PacifiCorp East Siena Padfic Power SFP
31 Shell Energy Idaho Power Company Siena Pacific Power NF
32 Shell Energy ldaho Power Company Bonneville Power Administration NF
33 Shell Energy PacifiCorp West Bonneville Power Administration NF
34 Shell Energy PacifiCorp West Siena Pacific Power NF
rOTAL
FERC FORM NO. I (ED. 12.90)Page 328.6
Name of Respondent
ldaho Power Company
I nts l(eDorl. ts:(1) []Rn Originat(2) llA Resubmission
uate oI Keoon(Mo, Da, Yi)
04t1512014
YeazHenoo ot Hepon
End of 2O13lQ4
I KANSMISSIUN UI- trLtr,U IKIUI I Y TUK U IIIEKs IAC@L
( I ncludi nq transactions reffered to as'wheelinc It 4coxuonlnueo)
5. ln 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. ln column (f), report the
designation for the substation, or other appropriate identiflcation for where energy was received as specified in the contract. ln 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 megawafts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j) the total megawatthours received and delivered.
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(f)
Point of Delivery
(Substation or Oher
Designation)
(g)
Billing
Demand
(MW)
(h)
TRANSFER OF ENERGY Line
No.Megawatt Hours
Received(i)
Megawatt Hours
Delivered
0)
JBWT 3SHN 1,20t 1,201 1
JBWT {MWY 650,12t 650,12r 2
JB!T/T (PRT 255,01(255,01r 3
JBWT .AGRANDE 26,11t 26,111 4
,BWT 14345 5(5t 5
(PRT SSHN 3.41(3,41(6
_oLo :NPR 16,49t 16,49r 7
30RA BPAT.NWMT 10(10(8
]ORA HMWY 171 171 9
toRA LAGRANDE 1,04 1,04 10
{MVVY 30RA 3,82 3,82 11
{MWY \,1345 351 35!12
.AGRANDE 3ORA 1.23 1,23',13
LAGMNDE 3RDY $t $r 14
LAGMNDE \r345 91r 9't,15
M345 .AGRANDE 361 361 16
JEFF .AGRANDE 4(4(17
M345 3RDY 3(3(18
BORA -oLo 40(40(19
BRDY \/t345 10r 10,20
JBSN JEFF 22 22 21
5 JEFF ,BSN 4t 4(22
5 ,EFF vt345 251 25(23
5 -oLo ]ORA 62'62 24
_oLo vt345 12.311 12.311 25
5 3ORA .AGRANDE 6(6t 26
30RA [4345 201 201 27
]RDY LAGRANDE 87t 87t 28
3RDY t\4345 9,54{9,541 29
]RDY M345 13,75t 13,75t 30
IMVST M345 1,85f 1,85t 31
PCOGEN LAGRANDE I 9'32
JBSN LAGRANDE 3(3(33
JBSN M345 231 23"u
6,35E,E5t 6,35E,85!
FERC FORM NO.1 (ED. 12-90)
Name of Respondent
ldaho Power Company (1) E(2t T
ron ls:
An Original
A Resubmission
uate ot Hepon
(Mo, Da, Yr)
04115t2014
YeaflPenoo ot Kepon
End of 2O13lQ4
I KANi yiloolvt\ vr ELEU I Ntlgt I I Tvra v I nEr\o tfncludinq transactions referred to as'wheelind'.;uuuilt +0(,. r
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualiffing 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 lruncate 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. ln 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 Selt 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 lnstruction for definitions of codes.
-tne
No.
Payment By
(Company of Public Authority)
(Footnote AffiliaUon)
(a)
Energy Received From
(Company of Public Authority)
(Foohote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
1 Shell Energy NorthWestem/PaciliCorp East Bonneville Power Administration {F
2 Shell Energy NorlhWestem/Pacifi Corp East Siena Pacific Power \.lF
3 Shell Energy Bonneville Power Administration Siena Pacific Power {F
4 Shell Energy Bonneville Power Administration Siena Pacific Power iFP
5 Shell Energy Avista Siena Pacific Power \,IF
6 Shell Energy Avista Siena Pacific Power iFP
7 Shell Energy Siena Pacific Power Bonneville Power Administration !F
8 Shell Energy Siena Pacific Power NorthWestem/Pacifi Corp East {F
I Shell Energy Siena Pacific Power PacifiCorp East {F
10 Shell Energy Sierra Pacific Power NorthWestern/Pacifi Corp East {F
11 Shell Energy Siena Pacific Power Bonneville Power Adminisfation \,IF
12 Shell Energy ldaho Power Company PacifiCorp East \,IF
't3 Shell Energy ldaho Power Company Bonneville Power Administration !F
14 Shell Energy ldaho Power Company Siena Pacific Power {F
15 Shell Energy ldaho Power Company PacifiCorp Easl {F
16 Shell Energy ,ldaho Power Company Bonneville Power Adminishation {F
17 Sierra Pacific Power Marketing PacifiCorp East Sierra Pacific Power {F
18 Siena Pacific Power Marketing Nor$Westem/Pacifi Corp East Siena Pacific Power {F
19 Siena Pacific Power Ma*eting PacifiCorp East Siena Pacific Power {F
20 Siena Pacific Power Ma*eting PacifiCorp East Siena Pacific Power SFP
21 Sierra Pacific Power Marketing ldaho Power Company Sierra Pacific Power {F
22 Siena Pacific Power Marketing PacifiCorp West Siena Pacific Power {F
23 Siena Paciflc Power Ma*eting NorthWestem/Pacifi Corp East Sierra Pacific Power {F
24 Siena Pacific Power Marketing Bonneville Power Adminisbation Siena Pacific Power {F
25 $iena Pacific Power Marketing Avista Siena Pacific Power !F
26 Sierra Pacific Power Marketing Avista Siena Paciffc Power SFP
27 Sierra Pacific Power Marketing Siena Pacific Power PaciflCorp East !F
28 Siena Pacific Power Marketing Siena Pacific Power PacifiCorp East !F
29 Siena Pacific Power Marketing Siena Pacific Power NorthWestem/Pacifi Corp East \,IF
30 Siena Pacific Power Marketing Siena Pacific Power Bonneville Power Adminisbation {F
31 Southem Califomia Edison Bonneville Power Administration PacifiCorp East !F
32 Tenaska NorthWestern/Pacifi Corp East Avista !F
33 Tenaska PacifiCorp West NorthWestern/Pacifi Corp East {F
34 The Energy Authority NorhWestem/Pacifi Corp East PacifiCorp East !F
rOTAL
FERC FORM NO. r (ED.12-90)Page 328.7
Name of Respondent
ldaho Power Company
(1) E(2\ T
ron ls:
An Original
A Resubmission
uate ol Keoon
(Mo, Da, Yi)
0411512014
YearPenoo ol Kepon
End of 20131Q4
I t<AN!,Mts5t(JN Ur ELtrU r KrUr r Y rUK U r nEKl, (AC@Unt 4SoXUOnUnUeOl(lncludinq transactions reffered to as'wheelino') "
5. ln column (e), identiff the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which seryice, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, 'point to point" transmission service. ln column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. ln 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 0) the total megawatthours received and delivered.
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(f)
Point of Delivery
(Substation or Other
Designation)
(s)
Billing
Demand
(MW)
(h)
TRANSFER OF ENERGY Line
No.Megawatt Hours
Received(i)
Megawatt Hours
Delivered
0)
JEFF .AGRANDE 52(521 1
JEFF \4345 7,34(7,341 2
LAGRANDE \r345 16,08(16,08(3
5 LAGRANDE \r345 1,36i 1,36;4
LOLO v1345 84,261 84,261 5
LOLO vI345 16,14i 16,14:6
LYPK sGRANDE 76(76(7
M345 SPAT.NWMT 1 1 I
M345 ]RDY 10{10t I
M345 ,EFF 'l0t 10r 10
M345 .AGRANDE 2,681 2,68(11
MDSK 3RDY 9(9(12
MDSK .AGRANDE 53"53'13
\4DSK vl345 3(3(14
f,BBLPR 3RDY 6(6(15
CBBLPR .AGRANDE 1,00{1,00r 16
30RA vI345 3,46r 3,46t 17
3PAT.NWMT M345 1,04(1.04(18
3RDY v|345 3,72i 3,72:,19
SRDY [r345 60{60{20
IMV\IY M345 6,53:6,53,21
JBSN M345 2,62:,2,621 22
JEFF M345 5,082 5,08r 23
.AGRANDE M345 2,08(2,08t 24
_oLo M345 18,721 't8,721 25
_oLo M345 22,681 22,681 26
vt34s 30RA 't2t 12t 27
14345 3RDY 47!47t 28
vt345 JEFF 8{8t 29
u345 .AGRANDE 62t 621 30
30RA 30(30(31
]PAT.NW[47 -oLo 7l 7l 32
,BSN AVAT.NWMT 3',i 3i 33
]PAT.NWMT 3RDY 48t Q$t 34
6,358,8s!6,358,85!
FERC FORM NO.1 (ED. 12-90)Page 329.7
Name of Respondent
ldaho Power Company
r nls xe(1) E(2) T
on ts:
An Original
A Resubmission
Date of Reoort(Mo, Da, Yi)
04t1512014
Year/Period of Report
End of 20131Q4
IKAN!'MIssiIUN OF ELECIRICITY FOR OTHERS (I
(lncludinq transactions referred to as'wheelind')count 456.1)
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualirying 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. ln 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 lnstruction for definitions of codes.
Jne
No.
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
1 The Energy Authority Bonneville Power Administration PacifiCorp East NF
2 The Energy Authority Bonneville Power Administration PacifiCorp East NF
3 Transalta Energy Marketing PacifiCorp East NorthWestem/Pacifi Corp East NF
4 Transalta Energy Marketing PacifiCorp East ldaho Power Company \IF
5 Transaltia Energy Marketing PacifiCorp East Bonneville Power Administration \F
6 Transalta Energy Marketing NorthWestern/Pacifi Corp East PacifiCorp East !F
7 Iransalta Energy Ma*eting NorthWestern/Pacifi Corp East PacifiCorp East \F
8 Transalta Energy Marketing NorthWestern/Pacifi Corp East Siena Pacific Power !F
9 Transalta Energy Marketing PacifiCorp East PacifiCorp East \F
10 Transaltia Energy Marketing PacifiCorp East Sierra Pacific Power \F
11 Transalta Energy Marketing ldaho Power Company PacifiGorp East \IF
12 Transaltra Energy Ma*eting ldaho Power Company Siena Pacific Power !F
13 Transalta Energy Ma*eting Bonneville Power Adminisbation PacifiCorp East \F
14 Transalta Energy Marketing Bonneville Power Adminisfation Siena Pacific Power \lF
15 Transalta Energy Marketing Avista Siena Pacific Power !F
16 Transalta Energy Marketing Siena Pacific Power Bonneville Power Administration \F
17 Utah Associated Municipal Power PacifiCorp East Sierra Pacific Power !F
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
TOTAL
FERC FORM NO.1 (ED. r2-e0)
Name of Respondent
ldaho Power Company
tnts }(e(1) E(2\ r
on Is:
An Original
A Resubmission
uate ol Kepon
(Mo, Da, Yr)
0411512014
Year/Period of Report
End of 20131Q4
I KANUMIDDILTN Lrr ELEI/ I l1ltJl I I r\J'a r,r l ntrliD (i\CAgUr
( l ncludin g transactions reffered to as'wheeling't +oor(lJonuilucq,
5. ln column (e), identiff 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. ln column (0, report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. ln column
(g) report the designation for the substation, or other appropriate identiflcation 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 megawafts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j) the total megawatthours received and delivered.
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(0
Point of Delivery
(Substation or Other
Designation)
(s)
Billing
Demand
(MW)
(h)
TMNSFER OF ENERGY Line
No.Megawatt Hours
Received(i)
Megawatt Hours
Delivered
0)
LAGRANDE BORA 14i 14i 1
lAGRANDE BRDY 12(12t 2
BORA BPAT.NWMT 8t 8r 3
30RA HMWY 2,88(2,881 4
30RA LAGRANDE 1,64i 1.64i 5
3PAT.NWI\47 BORA 9(9(6
3PAT.NWMT BRDY s(9(7
3PAT.NWMT M345 14i.14:l 8
3RDY BORA 31 3'I
3RDY M345 4(4t 10
{MUTY BORA 6,70i 6,70i 11
IMVVY M345 1,652 1,65r 12
4GRANDE BORA 8,82{8,82r 13
5 .AGRANDE M345 5,30i 5,30i 14
5 _oLo M345 't2t 121 15
\r345 LAGRANDE 37(37(16
5 30RA M345 17,131 17,13t 17
't8
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
6,35E,E5t 6,358,85!
FERC FORM NO. 1 (ED.12-90)Page 329.E
Name of Respondent
ldaho Power Company
tnts Keoon ts:(1) []An orisinal
(21 [-l A Resubmission
Date of ReDort(Mo, Da, Yi)
o4115t2014
YearlPeriod of Report
End of 2O13lQ4
IRANSMISSION OF ELECTR,ICITY FOR OTHERS (ACcOunt 456) (CONtiNuEd)
(lncludinq transactions reffered to as'wheelinq') ' '
9. ln column (k) through (n), report the revenue amounts as shown on bills or vouchers. ln column (k), provide revenues from demand
charges related to the billing demand reported in column (h). ln column (l), provide revenues from energy charges related to the
amount of energy transferred. ln 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). lf 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 0) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401 , Lines 16 and 1 7, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TMNSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Gharges
($)
(t)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Ltne
No.
1,172,90t -135,451 1.037.449 1
-5,34t -5,348 2
1.336.68(-32,678,1,304,008 3
-3,39:-3,392 4
4.344.81i 345,13C 4,689,942 5
-19,38(-19,386 6
M,75A u,754 7
201,364 20136/.8
7,131 1,33S 8,46e I
-3 -52 10
54,04(54,640 11
5,877 5,87i 12
9,00s 9,009 13
67,248 67,248 14
14,773 14,773 15
232 232 16
15,409 15,409 17
596 596 18
41,178 41,178 19
273 273 20
2,953 2,953 2'.1
90,81S 90,819 22
2,311 2,311 23
937 937 24
't 36 136 25
3,071 3.07'l 26
3,9s4 3,954 27
10,105 10,105 2e
6t 64 2e
2,393 2,393 30
13(13€31
't7,261 't7,261 32
't1,247 't1,247 33
359,723 3s9,72?34
6,EE8,010 15,04E,372 0 21,936,3E2
FERC FORU NO. 1 (ED.12-90)Page
Name of Respondent
ldaho Power Company
I nts i(eDort ts;(1) Ben Originat
(2) llA Resubmission
uate or Keoon(Mo, Da, Yi)
04t15t2014
Year/Period of Report
End of 2O13lQ4
I KANSMI!i!'I(JN UF ELEU I KIUI I Y TUK U I HEK5 (AC@UNT 4CbI (UONTNUEO'(lncludino transactions reffered to as'wheelino') ' '
9. ln column (k) through (n), report the revenue amounts as shown on bills or vouchers. ln column (k), provide revenues from demand
charges related to the billing demand reported in column (h). ln column (l), provide revenues from energy charges related to the
amount of energy transferred. ln 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). lf no monetary seftlement was made, enter zero (1101 1) 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 0) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401 , Lines 1 6 and 17 , respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(t)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Ltne
No.
587,02(587,02(1
5,187 5,187 2
201 205 3
2,193 2,193 4
2i 2a 5
431 431 6
8,26i 8,261 7
628,'.tz(.628,12t I
352,74t 352,74t o
2,87!2,874 10
3,83s 3,83s 11
30,682 30,68i 12
3,284 3,28s 13
1,52S 1,529 14
3,99S 3,99S 15
21t 214 16
56C 560 17
132 132 't8
114 114 19
zi 23 20
1,68€1,688 21
19€196 22
39,541 39,541 23
4,55€4,559 24
64€646 25
164 164 2e
31.422 31,428 27
4M 464 2E
482 482 29
892 892 30
951 951 31
455 455 32
268 26€33
3,721 3,721 34
6,88E,010 15,0'tE,372 0 21,936,3E2
FERC FORM NO. 1 (EO. 12-90)Page 3:10.1
Name of Respondent
ldaho Power Company
tnts Ke(1) E(2) T
Dn ts:
An Original
A Resubmission
uate ot Kepon(Mo, Da, Yr)
0411512014
Yea/Henoo ot Kepon
End of 2O13lQ4
I ltANSMlSSlUN OF ELEU lRlCll Y FOR Ol HERS (Account 456) (Continued)
(lncluding transactions reffered to as'wheelinq') ' '
9. ln column (k) through (n), report the revenue amounts as shown on bills or vouchers. ln column (k), provide revenues from demand
charges related to the billing demand reported in column (h). ln column (l), provide revenues from energy charges related to the
amount of energy transfened. ln 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). lf no monetary settlement was made, enter zero (1 101 1 ) 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 fi) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy L;narges
($)
(t)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Ltne
No.
11 11 1
3,72(3,72C 2
7S 79 3
43,32t $32e
63,42S 63,429 5
33,79t 33,79€
8,554 8,554 7
2,521 2,521 8
1,31!1,31€
5,71!5,715 10
3,312 3,312 11
50,93C 50,930 12
6,284 6,2U 13
82,555 82,555 14
48,907 48,907 15
5,20C 5,200 16
55,531 55,531 17
2,298 2,298 18
66,792 66,792 19
75,ffi2 75,662 20
223 223 21
19S 19S 22
9,59C 9,590 23
375 375 24
46,82C 46,820 25
103,553 103,553 26
21,561 21,561 27
51,985 51,985 28
293 293 29
1,096 1,096 30
1,237 '1,237 31
7,638 7,638 32
9,373 9,37S 33
1,952 't,952 34
6,8EE,o1o 15,04/i.,372 0 21,936,382
PageFERC FORrur NO. r (ED. 12-90)
Name of Respondent
ldaho Power Company
I nts r1e(1) E(2t T
on ls:
An Original
A Resubmission
uate oI Keoon
(Mo, Da, Yi)
04115t2014
Year/Period of Report
End of 2O'l3lQ4
I KANSMISUIUN UT trLE,U I KIUI I Y TUK (, I HtrKU (AC@UNT 4CbI (UONUNUEO I(lncludinq transactions reffered to as \rvheelinol ' '
9. ln column (k) through (n), report the revenue amounts as shown on bills or vouchers. ln column (k), provide revenues from demand
charges related to the billing demand reported in column (h). ln column (l), provide revenues ftom energy charges related to the
amount of energy transfened. ln column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). lf no monetary settlement was made, enter zero (1 101 1) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401 , Lines 16 and '17 , respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy unarges
($)
0)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+1+61
(n)
Lttte
No,
2,781 2,784
4i 47 2
15,81(15,81C
7,96i 7,967 4
68(68€
161,077 161,077 €
16,801 16,801
39,23t 39,235 I
13,22!13,225 o
1,121 1,125 10
65,714 65,714 11
14,911 14,913 12
40,143 40,143 13
104,491 104,491 14
1,82€1,82S 15
83€838 16
188 188 17
292 293 18
322 322 19
18,95€18,958 20
1,26C 1,26€21
113,65€113,659 22
117 117 23
84,730 84,730 24
893,06C 893,060 25
14G 146 26
4,69C 4,690 27
2,543 2,543 28
2C 2A 29
268 268 30
20(20c 31
4,918 4,918 32
20(204 33
20(200 34
6,888,010 15,04E,372 0 21,936,3E2
FERC FORM NO. t (ED. t2-90)Page 330'3
Name of Respondent
ldaho Power Company
I nrs Keoon ts:(1) []nn Orisinat(2) l-l A Resubmission
Date of Report(Mo, Da, Yr)
o411512014
Year/Periocl of Report
End of 20131Q4
IRANSMISSION OF ELEC I RICITY FOR OTHERS (Account 456) (Continuedl
(lncludinq transactions reffered to as \rvheelinq') ' '
9. ln column (k) through (n), report the revenue amounts as shown on bills or vouchers. ln column (k), provide revenues from demand
charges related to the billing demand reported in column (h). ln column (l), provide revenues from energy charges related to the
amount of energy transferred. ln column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). lf no monetary seftlement was made, enter zero (1 1011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and 0) must be reported as Transmission Received and Transmission Delivered for annual report
pumoses only on Page 401 , Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICIW FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(t)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+t+61
(n)
LIIIE
No.
7(7t 1
2,39!2,39!2
63,66t 63,66t 3
2,51(2,s1S 4
19,94i 19,942 5
52,74t 52,74t 6
s6(96(7
29.18C 29,18t I
12C 12t I
1,00(1,00(10
60(60(11
23e 23e 12
19t 19t 13
89:89:14
3,68:3,68:15
16t 166 16
3,04i 3,043 17
23,82t 23,820 18
ol OE 19
53 20
30?307 21
4,52i 4,523 22
3,172 3,172 23
341 341 24
2,29t 2,298 25
10,67(10,670 26
1,544 1,544 27
38,374 38,374 28
42.694 42,693 29
751 757 30
6,722 6,722 31
8,711 8,717 32
53i 537 33
59t 598 34
6,Egg,o1o 'i.5,0&,372 0 21,936,382
FERC FORM NO. I (ED. 12-90)Page
Name of Respondent
ldaho Power Company
I nts i(eoon ts:(1) []An orisinal(2\ llA Resubmission
Date of Reoort(Mo, Da, Yi)
0411st2014
Year/Period of Report
End of 2O13lQ4
I KANSMI|'SIUN UF ELEU I KIUI I Y FUK U I HEKti (ACCOUnI 4CO) (UOn[nUeO'(lncludino transactions reffered to as'wheelino') ' '
9. ln column (k) through (n), report the revenue amounts as shown on bills or vouchers. ln column (k), provide revenues from demand
charges related to the billing demand reported in column (h). ln column (l), provide revenues from energy charges related to the
amount of energy transferred. ln column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). lf no monetary settlement was made, enter zero (1101 1) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and 0) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TMNSMISSION OF ELECTRICITY FOR OTHERS
uemano unarges
($)
(k)
Energy Charges
($)
(t)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+61
(n)
Ll]te
No.
4,523 4,523
447,475 447,478
4,338 4,338
2,877 2,877 4
4,319 4,319
43,74r 43,749 €
16,556 16,55€
3,97 3.974
19:193
42,04t 42,042 'l(
95t 958 1'l
91 91 1
6,43t 6,43S 1
85t 85€14
1.332 1.332 1
281 284 1
37S 37€11
90f 905 1
15,12e 15J.ze 1
2C
18,811 18,814 21
3,77a 3,778 22
652 652 23
11,U2 11,842 24
92t 924 2l
9,73(9,73C 2e
927.542 927.542 27
404 404 2t
662 66'2l
6,831 6,831 3t
16r 165 31
45,052 45,052 32
2,064,11[2,oil,11 33
6,02t 6,02t 34
6,EE8,010 15,0'1E,372 0 21,936,382
FERC FORM NO.1 (ED. 12-90)Page 330.5
Name ol Respondenl
ldaho Power Company
rnts K€(1) E(2) T
on Is:
An Original
A Resubmission
Date of Reoort(Mo, Da, Yi)
0411st2014
Year/Period of Report
End of 20131Q4
I HAN5M|!i!'IUN (JF ELEU I t{lUl I Y FOR O I HERS (Account 456) (Continued)
(lncluding transactions reffered to as'wheelinq') ' '
9. ln column (k) through (n), report the revenue amounts as shown on bills or vouchers. ln column (k), provide revenues from demand
charges related to the billing demand reported in column (h). ln column (l), provide revenues from energy charges related to the
amount of energy transferred. ln column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). lf no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page'401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(t)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Lrne
No.
5,87i 5,87i 1
3,162,994 3,162,993 2
1.240.70t '1.240,70e 3
127,065 127,065 4
272 272 5
16,59C 16,59C 6
80.252 80,252 7
39€39€I
70€708 s
4,143 4,142 10
15,232 15,232 11
1,413 1,4',13 12
4,924 4,924 13
218 215 14
3,63€1
1,465 1.465 16
155 158 17
95 OE 18
1,93C 1,93C 19
502 502 20
1,067 1.067 21
193 193 22
1,25C 1,25e 23
2,997 2,997 24
59,451 s9,451 25
282 282 26
817 817 27
3,57C 3,57C 28
39,004 39,004 29
56,190 56,19(30
7,578 7,57t 31
372 372 32
123 123 33
94e 94t 34
6,88E,010 15,048,372 0 21,936,3E2
FERC FORM NO. r (ED. 12-90)Page 330.6
Name of Respondent
ldaho Power Company
I nts Keoort ts:(1) []An orisinal(2) [-lA Resubmission
uate ot KeDon
(Mo, Da, Yi)
041't5120'14
Yea/Penoo ot Kepon
End of 2O13lQ4
I KANUMIIiIiIUN UF ELEU I KIUI I Y FUK U I NEKS (AC'OUNT 4CbI (UONINUEOI(lncludinq transactions reffered to as'wheelino') ' '
9. ln column (k) through (n), report the revenue amounts as shown on bills or vouchers. ln column (k), provide revenues from demand
charges related to the billing demand reported in column (h). ln column (l), provide revenues ftom energy charges related to the
amount of energy transferred. ln column (m), provide the total revenues ftom all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). lf no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401 , Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(t)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Ltne
No.
2,124 2,124 1
29,981 29,984 2
65,7'li 65,712 3
5,58r 5,584 4
344,22(u4,22C 5
65,94t 6s,945 €
3,141 3,141 7
61 61 8
42(429 o
42!425 10
10,972 'to,972 11
36t 368 12
2.17i 2,173 13
12i 123 14
27C 274 15
4,10I 4,105 16
12,975 12,979 17
3,89i 3,892 18
13,92!13,929 19
2,278 2,275 20
24,4&24,4il 21
9,812 9,812 22
19,02€19,02€23
7,803 7,803 24
70,057 70,057 25
u,877 u,877 26
46€468 27
1,77E 1,77e 28
31€318 29
2,33e 2,339 30
6,243 6,243 31
278 278 32
131 131 33
1,79e 1,79e 34
6,888,010 15,04E,372 0 21,936,382
FERC FORM NO.1 (ED.12-90)Page 330.7
Name of Respondent
ldaho Power Company
I nrs Keoon ts:(1) []An Orisinal(2) l-lA Resubmission
Date ot ReDort(Mo, Da, Yi)
0411512014
Year/Period of Report
End of 20131Q4
IRANSMISSION OF ELECTR,ICITY FOR, OTHERS (Account 456) (Continued)(lncludinq transactions reffered to as'wheelinq) ' '
9. ln column (k) through (n), report the revenue amounts as shown on bills or vouchers. ln column (k), provide revenues from demand
charges related to the billing demand reported in column (h). ln column (l), provide revenues from energy charges related to the
amount of energy transfened. ln column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). lf no monetary settlement was made, enter zero (1 101 1) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401 , Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICIW FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(t)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Ltne
No.
53(53C 1
44t 44!2
37t 37e 3
12,911 12,914 4
7,341 7.347 5
40:403
40i 403
64(64C
't3s 13!
175 17e 1
29,98t 29,98t 11
7,401 7,40'l 12
39,50't 39,501 13
23.74t 23,74e '14
55!55e 15
1,69t 1,69€1
62,48(62,48S 17
1
19
2C
21
22
2?
24
2!
2e
27
28
29
30
31
32
33
34
6,888,010 15,04/8.,372 0 21,936,382
FERC FORM NO.1 (ED.12-90)Page
Name of Respondent
ldaho Power Companv
This Report is:
(1)XAn OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
0411512014
Year/Period of Report
20131Q4
FOOTNOTE DATA
328 Line No.:1 Column: e
328 Line No.:1 Column: h
Access Transmission Tariff, Volume 5, first revision.
The network service agreement between Idaho Power and the Bonneville Power AdministrationELectric Cooperative expj-res September 30, 2028. The billing demandis the customer's demand at the time of Idaho Power Company
strati-on
for the Oregon Trailfor network service
for the USBR expirescustomerrs demand at
transmission svstem ak and varies by month.
ustment to -Ioad ratio share June 2012 thru March 201
The network service agreement between Idaho Power and the Bonneville Power
December 31,2014. The billing demand for network servicethe time of Idaho Power Company transmj-ssion system peak
is the
and variesbv month.
Adiustment to l-oad ratio share June
The network service aqreement etween Ifor the Prioritv Firm Customers exoires S
ru Mar
o Power and the Bonnev Power Adm stration
tember 30, 2008.
ustment to Ratio Share June 2012 thru March 2013.
:328 Line No.:2 Column: h
:328 Line No.:3 Column: h
328 Line No.:4 Column: h
328 Line No.:5 Column: h
328 Line No.:6 Column: h
328 Line No.:7 Column: e
acv contract prior to the Access Transmission Tariff.
contract between I ho Power and the Mi.l-ner Irrigation D strict exp
201_7 .
: 328 Line No.:7 Column: h
The agreement between Idaho Power a the City of Seattle expiresof Seattl-e has re-sold transmission service request to Carg11l and
DecemberCargill 31, 2017 .is now
City
:328 Line No.:9 Column: h
responsible for nt.
e contract between ldaho Power and PacifiCorp - lmnaha exp res on Marchtime of
..L
Idaho Power
Interior, Bureauthe Bureau.
billing demand for network service is the customer's demand at the
Companv transmission svstem k and varies bv month.
Adiustment to Load Ratio S are June thru Marc 13.
Leqacv contract prior to t n Access Transmission Tariff.
The agreement between Idaho Power and the United States Department of the
:328 Line No.:10 Column: h
328 Line No.: 11 Column: e
328 Line No.: 11 Column: h
328 Line No.:12 Column: h
of Indian Affairs j-s subiect to termination 90 davs written notice b
The agreement between ho Power and United Materials o reat Eal.l-s, Inc.expiration date and can be terminated either partv at the time.328 Line No.:13 Column: e
328.5 Line No.:20 Column: h
acv contract prior to the n Access Transmission Tariff.
contract prior to the Open Access Transmission Tariff.
Legacy agreement prov ding OATT-like service, but ed under 454 Fac Iities revenue.
FERC FORM NO.1 1 450.1
Name ot Kesponoent
ldaho Power Company
lnrs KeDon ls:(1) 51en Orisinat(21 -A Resubmission
uate ot KeDon
(Mo, Da, Yi)
0411512014
YeaflHenoo ot Hepon
En6 q1 2013/Q4
TMNSMISSION OF ELECTRICITY BY OTHERS (Account 565)
(lncluding transactions refened to as'kheeling")
1. Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public
authorities, qualirying facilities, and others for the quarter.
2. ln 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. ln column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General lnstructions 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. ln column (e) report the
demand charges and in column (f) energy charges related to the amount of energy transfened. 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. lf 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.
-lne
No.Name of Company or Public
Authority (Footnote Affi liations)(a)
Statistical
Classification(b)
TRANSFER OF ENERG\EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERI
MagawaII-hoursReceived
(c)
rvralgawart-hours
Delivered
(d)
uemanoCharoes($r
(e)
EIIETOVCharoEs($r
(0
umerCharoes($r
(q)
Total Cost of
Tranffission
1 Avista CorpWWP Div NF 24,533 24,533 143,50:143,503
Avish Cory-WWP Div SFP 27s,688 275,688 1,107,251 't,107,259
AD -1',t4 -'t14
4 Bonneville Porver Admin 827,01i 827,013 3,325,332 3,325,332
5 Bonneville PorerAdmin SFP 551 551 631 631
6 OS -1,974 -1,974
7 OS 12,404 12,4M
I OS -20,28t -20,286
s Grant County PUD SFP 43,02'l 43,027 121,44(121,440
10 0s -59:-593
11 OS -1,19i -1,192
12 Northwestem Eneqy 21,301 21,302 199,60(199,600
't3 NorthWesem Eneqy NF 2,521 2,526 14,144 14,144
14 NorlhWestem Enerov SFP 1,017 1,017 5,22i 5,227
15 PacifiCorp lnc.128,264 128,264 877,79(877,796
16 PacifiCorp lnc.NF 17,342 17,342 77,10!77,105
TOTAL 1,367,471.1,367,471 5,706,591 s9,31:5,637,278
FERC FORM NO. tr3-Q (REV.02-04)Page 332
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5]An original(2) 1-1A Resubmission
Date of Report(Mo, Da, Yr)
04t1512014
Year/Period of Report
En6 sg 2013/Q4
I KANNM|5D|UN Ur trLEUIKtUtI Y t Y UIHtrKU (ACCOUnIDOC)
ncluding transactions refened to as "wheeling")
1. Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public
authorities, qualirying facilities, and others for the quarter.
2. ln 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. ln column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General lnstructions 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), (Q and (g) expenses as shown on bills or vouchers rendered to the respondent. ln column (e) report the
demand charges and in column (f) energy charges related to the amount of energy transfened. 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. lf no
monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary seftlement,
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.
-ine
No.Name of Company or Public
Authority (Footnote Affi liations)
Statistical
Classification
(b)
TRANSFER OF ENERG\EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERI
MqgawaII-hoursReceived
(c)
Mqgawa{r-hoursDelivered
(d)
cn6yes
(e)
EneIEVCharots($r(fl
cna6ges
(o)
Total Cost of
Transffission
1 Pacili0om lnc.SFP 2,61(2,6't0 13,938 13,93t
2 OS -'t05 -'t0r
3 os -130,856 -130,85(
4 OS 201 205 .180,981 -180,981
5 Puget Sound Eneryy, lnc SFP 11,48r 1 1,484 15,09S 15,09!
5 Seattle City Light SFP 9,64t 9,645 45,050 4s,05(
7 Siena Pacific Porer Co NF 2,271 2,272 14,851 14,851
8
9
10
11
12
13
14
'15
16
TOTAL 1,367,47r 1,367,479 5,706,591 $9,313 5,637,278
FERC FORM NO. 1/$Q (REV.02-04)Page 332.1
This Page lntentionally Left Blank
Name of Respondent
ldaho Power Comoanv
This Report is:
(1) X An OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
o411s12014
Year/Period of Report
20,t3tQ4
FOOTNOTE DATA
332 :3 Column: a
Unreserved Use Refund
Contract Ex ration Date
Pri-or year adjustment
332 Line No.:6 Column: a
Reserves Provide
Resal-e Transmission
Resale Transmission
Resale Transmission
Contract can be termi-nat
Contract Expiration Date
13 PTP True U
rior notice.332 Line No.:15 Column: b
Unreserved Use Refund
Resa1e Transmission
FERC FORM NO. 1 1 450.'.|
Name or Kesponoenl
ldaho Power Company
rnrs llepon ts:
(1) IXJ An original
(2) l--l A Resubmission
uate oT KeDon(Mo, Da, Yi)
04115120't4
Yea0Fenoo oI Kepon
gn6 o1 2013/Q4
MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Line
No.
Descriotion(a)
Amount
tu)
1 lndustry Associatlon Dues 418,795
2 Nuclear Power Research Expenses
3 Other Experimental and General Research Expenses
4 Pub & Dist lnfo to Stkhldrs...expn servicing outstanding Securities
5 Oth Expn >=5,000 show purpose, recipient, amount. Group if < $5,000 352,652
6 Robert Tinstman 125,185
7 Stephen Allred 68,310
8 Richard Dahl 83,655
I Ronald Jibson 19,305
10 Judith Johansen 38,268
11 Dennis Johnson 47,520
12 Christine King 81,02S
13 Gary Michael 60,5s5
14 Jan Packwood 54,945
15 Joan Smith 77,098
16 Richard Reiten 31,185
17 Thomas Wlford 65,59€
18
19 Associated Taxpayers of ldaho 23,000
20 Association of ldaho Cities 2,300
21 Boston College Center for Corporations 5,00c
22 Corporate Executive Board 41,7s0
23 Easter Oregon Msitors Assoc 1,50C
24 ldaho Association of Commerce and lndustry 14,00(
25 ldaho Assciation of Counties 1,34€
26 ldaho Council of GovermenE 1,00c
27 ldaho ffice of Energy Resources 2,00c
28 ldaho Technology Council 10,00c
29 National Association of Directors 6,175
30 National Hydropower Asswociation 32,507
31 North American Energy Standard 7,000
32 Northwest Power Pool 156,807
33 Paciflc Northwest Utilities 38,869
34 Westem Electricity Coordinating Council 897,334
35 Westem Energy lnstitute 30,280
36 Wyoming Taxpayers Association 1,600
37 Misc Memberships under $1000 (3)875
38
39
40
4'.1
42 Chambers of Commer@ & Other Civic Organizations 131,010
43
44
45
46 TOTAL 4,246,371
FERC FORM NO. I (ED. 12-94)Page 335
Name of Respondent
ldaho Power Comoany
This Report is:
(1) X An OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
04115t2014
YeariPeriod of Report
201310,4
FOOTNOTE DATA
335 Line No.:4RecipientBroadridge Financial- Solutions
CEB
Deutsche Bank
Rate Rel-ated Amortization
Stock Based Compensation
Thompson Financial/CarsonWells Fargo Shareowner Servj-ce
Moody t s
EsourceOperations Accrual
Miscellaneous
Total-
Purpose
Proxy & BulletinMisc ExpenseBroker Fees
Misc ExpenseMisc ExpenseAnalyst Service
Mgmt Services
Mg"mt Services
Mgmt Services
Amount
$ 48,906
41,1,16
33,87 4
230,656
603,819
4'7 ,07299,355
3t,382tl,467
L08,946
6L, 324
$1,31"7,917
FERC FORM NO.1 1 450.1
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5.1An orisinat(2) 1-1A Resubmission
uate or Keoon
(Mo, Da, Yi)
o411512014
YeaflHenoo or Kepon
End of 20131Q4
DEPRECIATIoN AND AMORTIZATION OF ELECTRIC PLANT (Account 403, 404, 405)
(Except amortization of aquisition adjustments)
1. Report in section A for the year the amounts for : (b) Depreciation Expense (Account 403; (c) Depreciation Expense for Asset
Retirement Costs (Account 403.1; (d) Amortization of Limited-Term Electric Plant (Account 404); and (e) Amortization of Other Electric
Plant (Account 405).
2. Report in Section 8 the rates used to compute amortization charges for electric plant (Accounts 404 and 405). State the basis used to
compute charges and whether any changes have been made in the basis or rates used from the preceding report year.
3. Report all available information called for in Section C every fifth year beginning with report year 1971, reporting annually only changes
to columns (c) through (g) from the complete report of the preceding year.
Unless composite depreciation accounting for total depreciable plant is followed, list numerically in column (a) each plant subaccount,
account or functional classification, as appropriate, to which a rate is applied. ldentifo at the bottom of Section C the type of plant
included in any sub-account used.
ln column (b) report all depreciable plant balances to which rates are applied showing subtotals by functional Classifications and showing
composite total. lndicate at the bottom of section C the manner in which column balances are obtained. lf 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). lf 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. lf
composite depreciation accounting is used, report available information called for in columns (b) through (g) on this basis.
4. lf provisions for depreciation were made during the year in addition to depreciation provided by application of reported rates, state at
the bottom of section C the amounts and nature of the provisions and the plant items to which related.
A. Summary of Depreciation and Amortization Charges
-ine
No.Functional Classifi cation
(a)
DeSrreciationExpense(Account 403)(b)
uepreclauon
Expense for Asset
Retirement Costs(Account 403.1)(c)
Limited Term
Electric Plant(Account 404)
Amortization ofOther Elecfic
Plant tcc 405)
Total
(fl
1 lntangible Plant 7,61 1,634 7,61 1,634
Steam Production Plant 23,764,277 587,O12 24.351.289
\uclear Production Plant
{ydraulic Production Plant-Conventional 13,528,92€13,528,926
lydraulic Production Plant-Pumped Storage
Sther Production Plant 16,976,10C 16,976,100
l-ransmission Plant 19,134,69C 't9,134,690
)istribution Plant 38,905,749 38,905,749
Regional Transmission and Market Operation
1(General Plant 9,176,449 9,176,449
1'
1t
Common Plant-Electric
TOTAL 121,486,191 587,012 7,611,634 129,684,837
B. Basis for Amortization Charges
Acct4M Balance 1/1/13(1) 60,000(2) 11,430,888(3) 5,626,910(4) 1s,48'r,590(s) 4,323,796(6) 217,873
(7)
Total 37,'141,058
2013Amortization Balance1213111312,000 48,00054s,446 10,885,442189,418 5,468,5006,562,164 19.158.412287,899 4,035,8978,026 209,U76,680 618,074
Remaining monhs
48
180
7,611,634 40,424,173
(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 Sofhrvare 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
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 51Rn Original(2) -A Resubmission
Date of Report(Mo, Da, Yr)
04t1512014
Year/Period of Report
End of 20131Q4
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
-tne
No.Account No.
la\
Plant Base
(ln Thousands)
E>UItatEU
Avg. Service
Lifelcl
Salvage
(Percent)
Depr. rates
(Percent)
Curve
'Lf'
AVeragE
Remaining
/nl
1 310.20 63:75.0(3.6S R4.0 20.2(
1 31 1.00 147,60t '100.0(-10.0(1.7(s't.0 21.3(
14 ,12.10 81,86(60.0(-5.0(1.41 R3.0 21.8(
1 ,12.20 488,471 60.0(-5.0(2.7i R1.5 20.9(
1e t12.30 4,341 25.0(20.0(2.32 R3.0 7.9(
17 t14.00 157,13(45.0(-5.0(3.1!s1.0 19.4(
18 t15.00 69,52:60.0(1.41 s1.5 19.8(
'ts ]16.00 13,00(45.0(-5.0(3.81 R0.5 19.0(
2A t't6.10 8t 12.O(15.0(8.83 a.o 6.3(
21 t't6.40 24i 12.0(15.0(0.6s 12.0 7.9(
22 ]16.50 8:12.0(15.0(3.1S L2.O 5.1(
23 ]16.60 53:20.0(15.0(6.14 L2.O 18.0(
24 316.70 55(20.0(15.0(1.97 L2.O 14.4(
2!.316.80 1,90(20.0(30.0(2.94 01.0 16.6(
2e 316.90 jt 35.0(15.0(2.4!s1.0 34.7(
2'1 317.00 10,04(
2t Subtotal Steam 976.05t
29 331.00 172,02 100.0(-25.0(2.38 R2.5 33.0(
30 ,32.10 19,46 95.0(-20.0(1.31 s4.0 39.8(
31 ,32.20 228,281 95.0(-20.0(1.65 s4.0 35.6(
32 132.30 5,471 1.44 SQUARE 49.'t(
33 333.00 201,68 80.0(-5.0(1.74 R3.0 32.6(
34 ]34.00 52.291 50.0(-5.0(2.66 R1.5 26.1C
35 135.00 20,32:,95.0(2.23 R2.0 28.1C
36 t35.10 71 15.0(7.63 SQUARE 6.5(
37 t35.20 36r 20.0(5.57 SQUARE 5.3(
3{335.30 24'5.0(12.36 SOUARE 3.3(
?(336.00 8,18:75.0(2.47 R3.0 21.4t
4(Subtotal Hydro 708,40i
41 341.00 133,751 2.91 SOUARE 27.2C
42 342.0O 7,981 50.0(2.97 s2.5 28.5(
4i 343.00 236,64(40.0(3.33 s1.5 25.9(
4t 344.00 73,351 45.0(2.51 s2.0 26.8(
4l 345.00 95,67',50.0(3.26 s1.5 22.6(
4e 346.00 5,83(35.0(3.33 s2.5 24.5t
41 Subtotal Other 553,24(
4t 350.20 31,55i 70.0(1.39 R3.0 58.8(
4!350.22 7t 3.33
5(352.00 70,07t 65.0(-35.0(1.84 R3.0 53.7(
FERC FORM NO.1 (REV. 12-03)Page 337
Name of Respondent
ldaho Power Company
tnrs KeDon ts:(1) 5]en Orisinat(21 1-1A Resubmission
Date of Reoort
(Mo, Da, Yi)
04115t20't4
Year/Period of Report
End of 20131Q4
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
_tne
No.Account No.
/a)
Plant Base
(ln Thousands)
ESUIIta(e(I
Avg. Service
LifeInl
Salvage(Percent)Depr. rates(Percent)Curverlf"Remaining
12 353.00 388,93(s0.0(-5.0(1.9(R1.5 40.7(
1?354.00 162,00r 65.0(-15.0(1.7C s3.0 50.8(
14 355.00 129,11'.60.0(-70.0(2.71 R2.0 43.6(
15 356.00 188,08(65.0(-40.0(2.24 R2.0 48.5(
16 1s9.00 39(65.0(0.7!R2.5 24.0(
17 Subtotal Transmission 970,24(
18 )60.22 at 30.0(3.3:30.0(
1S ]61.00 32,821 65.0(40.0(2.14 R2.5 53.3(
2A ,62.00 196,76(50.0(-5.0(2.0c R1.0 40.2(
21 364.00 235,54(44.0t -45.0(3.08 R1.5 31.3(
zt 365.00 126,03!45.0(-35.0(2.98 R0.5 33.6(
23 366.00 46,29t 60.0c -20.0(1.95 R2.0 44.4(
24 367.00 207,471 46.0(-15.0(2.2e R2.0 35.3(
2l 368.00 471,881 35.0(-3.0(2.58 R1.0 27.O(
2e 36S.00 56,85r 40.0(-40.0(2.55 R2.0 29.5(
27 370.00 14.761 22.01 1.0(3.4e 01.0 17.5(
2A 370.'10 58,37;15.0(6.9€s2.5 13.1(
29 ,71.10 2',12.0(-2.01 2.35 s4.0 9.0(
30 t71.20 2,87t 17.0(-2.O1 't.5'l R1.5 14.7(
31 373.20 4,55(30.0(-25.0(2.41 R1.0 20.6(
Jt 374.OO 53r
3:Subtotal Distribution 1.454.84
3t 390.11 28,4'ti 100.0(-5.0(2.58 s0.5 28.8(
3t 390.12 74,32'55.0(-5.0(1.9(s0.5 44.3t.
3t 390.20 20!35.0(2.12 s3.0 25.7C
31 391.1'l 13,921 20.0(2.88 SQUARE 12.9C
3t 391.20 '19,77t 5.0(11.1i SQUARE 3.2C
3!391.21 7,19 8.0(11.22 L2.0 5.7(
4C 392.10 832 12.0(15.0(7.5(L2.0 8.9(
41 392.30 3,01t 10.0(50.0(1.73 s2.5 3.4C
42 392.40 21,07(12.0(15.0(7.3(L2.O 6.8(
43 392.50 92',1 12.0(15.0(3.5:L2.O 9.0c
44 392.60 31,21(20.0(15.0(4.11 L2.O 13.4C
4E ,s2.70 5,98t 20.0(15.0(3.21 L2.O 12.5C
4e 392.90 4,682 35.0(15.0(2.1t s1.0 24.3C
47 393.00 1,90(25.0(3.3(SQUARE 19.4C
48,394.00 7,191 20.0(4.1i SQUARE 13.3(
49 39s.00 12,44a 20.0(4.24 SQUARE 12.1
5C 196.00 12,W1 20.0(30.0(1.66 01.0 17.6C
PageFERC FORI' NO.I (REV.12-03)
Name of Respondent
ldaho Power Company
This Report ls: I Date of Report(1) [An Orisinal | (Mo, Da, Y0(2) nA Resubmission | 0411512014
Year/Period of Report
End of 20131Q4
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
-rne
No.Account No.
lal
ugPleuraurE
Plant Base(ln Thousands)' tht
EDUrilAtgu
Avo. Service- Life
Salvaoe
(Perce-n0
Deor. rates(Fercent)
MOrtailIy
Curve
'Lf"
nvEragE
Remaining
12 197.10 5,211 15.0(4.2!SOUARE 8.3C
13 ,97.20 28,81 15.0(5.38 SQUARE 9.8C
14 ]97.30 4,10{15.0(5.3'l SQUARE 8.0c
15 ,97.40 5,79r 10.0(7.9C SOUARE 6.5C
16 3S8.00 5.73 15.0(5.20 SQUARE 't0.6c
1i Subtotal General 295,57{
1 Total Plant 4,958,35i
1S
2C
21
22
23
24
25
2e
27
28
29
30
31
32
3:
3t
3t
3(
3i
3t
a(
4(
41
4i
4i
44
4!
4t
41
4t
4!
5C
FERC FORM NO.1 (REV.12-03)
Name of Respondent
ldaho Power Company
tnrs Keoon Is:(1) fiAn Orlsinat
(21 1-1A Resubmission
uate ot Heoon
(Mo, Da, Yi)
0411512014
Year/Period of Reporl
End of 2O13lQ4
REGULATORY COMMISSION EXPENSES
1. Report particulars (details) of regulatory commission expenses incurred during the current year (or incurred in previous years, if
being amortized) relating to format cases before a regulatory body, or cases in which such a body was a party.
2. Report in columns (b) and (c), only the cunent year's expenses that are not defened and the cunent year's amortization of amounts
deferred in previous years.
-ine
No.
Desoiption
(Fumish name of reoulatorv commission or bodv the
dbcket or case numb-er and'a description of the &se)
(a)
Assessed bv
Regulatory
Commission
(b)
EXpenses
of
Utility
(c)
I ot€rlExoense forCuirent Year(b)(llc)
ueTe,Teo
in Account
182.3 atBeginning ofYear
(e)
1 Federal Energy Regulatory Commission:
2 Annual admin charges assessed by FERC 3,325,04{3.325,04t
3
4 Regulatory FERC fees Tru-up -89,43(-89,43C
5
6 General Regulatory Expenses and
7 Various other Dockets 331,69;331,69i
I
I Oregon Hydro - Fees Amortization 158,50'158,50'
10
11 Regulatory Commission Expenses - ldaho
12 lntervenor funding 19,68r 19,68r
13 Rate Case - Misc expenses 16,731 16,73i
14
15 Regulatory Commission Expenses - Oregon
16 Rate Case - Misc expenses 28,24(28,24(
17
18 Other - OPUC
19 uM - 1182 27,07t 27.07t
20 PURPA 71,901 71,901
21 General Regulatory 43,721 43,721
22 Other OPUC expenses 42,48t 42,48t
23
24
25
26
27
28
29
30
31
32
33
34
.E
36
37
38
ec
40
41
42
43
44
45
4e TOTAL 3,483,54{492,111 3,975,66/
FERC FORM NO. r (ED.12-96)Page 350
Name of Respondent
ldaho Power Company
lhrs t{eoort ls:(1) 5]An Original(2) nA Resubmission
Date of Reoort
(Mo, Da, Yi)
0411512014
Year/Period of Report
End of 2013/Q4
REGULATORY COMMISSION EXPENSES (Continued)
3. Show in column (k) any expenses incurred in prior years which are being amortized. List in column (a) the period of amortization.
4. List in column (0, (S), and (h) expenses incurred during year which were charged currently to income, plant, or other accounts.
5. Minor items (less than $25,000) may be grouped.
EXPENSES INCURRED DURING YEAR AMORTIZED DURING YEAR
CURRENTLY CHARGED TO Deferred to
Account 182.3
1i)
uonra
Account
/it
Amount
tk\
ueleneo tnAccount 182.3
End of Year/t'l
_rne
No.ueparuTent
(f)
AlruUlNo.(q)
,{mounI
(h)
ilectric 928 3.325.041 2
3
ilectric 928 -89,43(4
5
6
ilectric 928 331,69;7
8
llectric 928 158,501 I
10
11
Elec-tric 928 19,68t 12
Electric 928 16,732 13
14
15
ilectric 928 28,241 16
17
18
ilectric 928 27,07!19
Ileckic 928 71,901 20
ilecfic 928 43,721 21
ilectric 928 42,481 22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
3,975,6&46
FERC FORM NO.1 (ED. 12-96)Page 351
Name of Respondent
ldaho Power Company
This ReDort ls:(1) 5]Rn Orisinal(2\ nA Resubmission
Date of Reoort(Mo, Da, Yi)
0411512014
Year/Period of Report
End of 20131Q4
KESEAKUFI, UEVELUI-MEN I , ANU UEMUNS I KA I I(JN AU I IVI I IEi'
'1 . Describe and show below costs incurred and accounts charged during the year for technological research, development, and demonstration (R, D &
D) project initiated, continued or concluded during the year. Report also support given to others during the year for jointly-sponsored projects.(ldentify
recipient regardless of affiliation.) For any R, D & 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. lndicate in column (a) the applicable classification, as shown below:
Classifications:
A. Elechic R, D & D Performed lnternally: 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 (Classifo and include items in excess of $50,000.)
c. lntemal combustion or gas turbine (7) Total Cost lncurred
d. Nuclear B. Electric, R, D & D Performed Externally:
e. Unconventional generation ('t) Research Support to the electrical Research Council or the Electric
f. Siting and heat rejection Power Research lnstitute
(2) Transmission
ine
No.
Classification
(a)
Description
(b)
1 ldaho Power did not incur any Research and
2 Development expenditures in 2013.
3
4
5
6
7
8
I
10
11
12
't3
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
FERC FORM NO. 1 (ED. 12-87)Page
Name of Respondent
ldaho Power Company
This Reoort ls:(1) E]An Original(2) 1-1A Resubmission
Date of Report
(Mo, Da, Yr)
0411512014
Year/Period of Report
End of 2O13lQ4
RESEARCH, IJEVELOPME,N I , AND IJE,MONS I RAI ION ACTIVI I IE,S (UONIINUEd)
(2) Research Support to Edison Electric lnstitute
(3) Research Support to Nuclear Power Groups
(4) Research Support to Others (Classifr)
(5) Total Cost lncurred
3. lnclude 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, conosion 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 Acmunt 107, Construction Work in Progress, first. Show in column (f) the amounts related to the acmunt charged in column (e)
5. Show in column (g) the total unamortized acanmulating 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. lf costs have not been segregated for R, D &D activities or projects, submit estimates for columns (c), (d), and (f) with such amounts identified by
"Est."
7. Report separately research and related testing facilities operated by the respondent.
Costs lncurred lntemally
Cune6JYear Costs lncurred Externally
Cunent Year
(d)
AMOUNTS CHARGED IN CURRENT YEAR Unamortized
Accumulation
(s)
Line
No.Account(e)Amount(f)
1
2
3
4
5
6
7
I
I
10
't1
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
FERC FORM NO. r (ED. r2-E7)Page
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5]nn orisinat(2) 1A Resubmission
Date of Reoort(Mo, Da, Yi)
0411512014
Year/Period of Report
End of 20131Q4
DISTRIBUTION OF SALARIES AND WAGES
Report below the distribution of total salaries and wages for the year. Segregate amounts originally charged to clearing accounts to
Utility Departments, Construction, Plant Removals, and Other Accounts, and enter such amounts in the appropriate lines and columns
provided. ln determining this segregation of salaries and wages originally charged to clearing accounts, a method of approximation
giving substantially correct results may be used.
Line
No.
Classification
(a)
Direct Pavroll
Distribution
rb'l
,\ltocauon oIPavroll charoed forCl6arino AcEountsfc)
Total
(cll
3 Production 21,853,91t
4 Transmission 6,662,76(
5 Regional Market
b Distribution 17,845,49t
7 Customer Accounts 9.457,851
8 Customer Service and lnformational 4,734,128
I Sales
10 Administrative and General 44.979.514
1't TOTAL Operation (Enter Total of lines 3 thru 10)105.533.664
13 Production 5,312,500
14 Transmission 3,486,701
15 Reoional Market
16 Distribution 8,303,604
17 Administrative and General 1,000,149
18 TOTAL Maintenance (Total of lines 13 thru 17)18,'t02,954
20 Production (Enter Total of lines 3 and 13)27,166,415
21 Transmission (Enter Tobl of lines 4 and 14)10,149,461
22 Reoional Market (Enter Total of Lines 5 and 15)
23 Distribution (Enter Total of lines 6 and 16)26,149,100
24 Customer Accounts (Transoibe ftom line 7)9,457.8s1
25 Customer Service and lnfonnational (Transcribe ftom line 8)4,734,128
26 Sales (Transcribe from line 9)
27 Administrative and General (Enter Total of lines 10 and 17)45,979,663
28 TOTAL Oper. and Maint. (Total of lines 20 lhru 27)123,636,618 123,636,618
31 Production-Manufactured Gas
32 Production-Nat. Gas (lncluding Expl. and Dev.)
33 Other Gas Suoolv
34 Storaoe, LNG Terminalino and Processins
35 Transmission
36 Distribution
37 Customer Accounts
38 Customer Service and lnformational
39 Sales
40 Adminishative and General
41 TOTAL Operation (Enter Total of lines 31 thru 40)
43 Production-Manufacfu red Gas
44 Production-Natural Gas (lncluding Exploration and Development)
45 Other Gas Suoolv
46 Storaoe. LNG Terminalino and Processino
47 Transmission
PageFERC FORM NO.1(ED. 12-88)
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5]Rn orisinat(2) TIA Resubmission
Date of Reoort(Mo, Da, Yi)
o411512014
Year/Period of Reporl
gn6 6g 2013/Q4
DISTRIBUTION OF SALARIES AND WAGES (Continued)
Line
No.
Classification
/a)
Direct Pavroll
Distribution
(b)
,\lrocallon orPavroll charoed forCl6arino AcEountsYcl
Total
(d)
48 Distribution
49 Administrative and General
50 TOTAL Maint. (Enter Total of lines 43 thru 49)
52 Production-Manufactured Gas (Enter Total of lines 31 and 43)
53 Production-Natural Gas (lncluding Expl. and Dev.) (Total lines 32,
54 Other Gas Supply (Enter Total of lines 33 and 45)
55 Storage, LNG Terminaling and Processing ffotal of lines 31 thru
56 Transmission (Lines 35 and 47)
57 Distribution (Lines 36 and 48)
58 Customer Accounts (Line 37)
59 Customer Service and lnformational (Line 38)
60 Sales (Line 39)
61 Administative and General (Lines 40 and 49)
62 TOTAL Operation and Maint. (Total of lines 52 hru 61)
63 Other Utilitv Deoartments
64 Operation and Maintenance
65 TOTAL All Utility Dept. (Total of lines 28,62, and 64)123,636,618 123,636,618
68 Electric Plant 55,095,63t s5,095,638
69 Gas Plant
70 Other (provide details in foohote):
71 TOTAL Consbuclion (Total of lines 68 hru 70)55,095,63{s5,095,638
72 Plant Removal (By Utility Departments)
73 Elecbic Plant
74 Gas Plant
75 Other (provide details in footnote):
76 TOTAL Plant Removal (Total of lines 73 hru 75)
77 Other Accounts (Specl'&, provide details in fuoflote):
78 Stores Expense 4,888,10i 4,888,107
79 Other Clearino Accounts 3,283,74t 3,283,745
80 Other Work in Prooress 1,937,171 1 ,937,172
81 Paid Absences 22,510,641 22,510,641
82 Preliminary Survey and lnvestioation 14,141 14,149
83 Other AccounE 5,193.282 5,'193,284
84
85
86
87
88
89
90
91
92
93
94
95 TOTAL Other Accounb 37.827.09t 37.827,098
96 TOTAL SALARIES AND WAGES 216,559,352 216,559,354
FERC FORM NO.1 (ED.12.E8)Pass 355
Name of Respondent
ldaho Power Company
lhrs KeDon Is:(1) fien Originat(2) l-lA Resubmission
uate ot Kepon
(Mo, Da, Yr)
04t15t2014
YearPenoo ot Kepon
End of 20131Q4
MONTI.ILY TR,ANSMISSION SYSTEM PEAK LOAD
(1) Report the monthly peak load on the respondenfs transmission system. lf 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 lnstruction for
the definition of each statistical classification.
NAME OF SYSTEM: ldaho power Company
-tne
No.Month
(a)
Monthly Peak
MW - Total
(b)
Day of
Monthly
Peak
(c)
Hour of
Monthly
Peak
(d)
Firm Network
Service for Self
(e)
Firm Network
Service for
Others
(0
Long-Term Firm
Pointto-point
Reservations
(s)
Other Long-
Term Firm
Service
(h)
Short-Term Fkm
Point-to-point
Reservation
(i)
Olher
Service
0)
January 5,031 1 80(4,06{251 56;149
February 4,60'2',80(3,46{211 56i 350
March 4,391 80(3,50(18;56;136
Total for Quader'l 14,021 1't,03(65;'t,101 635
April 4,281 90(3,04;17'.l 567 493
tilay 5,18{1 1 60(3,95r 301 56i 363
June 5,89r 2i 190(4,731 35:56;246
Total for Quarier 2 15,36 11,73!82:1,70'1,102
July 6,13 150(4,99(371 56;199
1(August 5,56 2i 160(4,371 32i 56,297
1 September 5,22 170(4,381 25'56;2:,
1i Totalbr Quarter 3 16,91,13,74t 95r 't,70'51{
1 ocbber 4,24t 1 90(3,17i 18r 56;322
1t llovember 4,28 1,90(3,24/17 56;29i
,|Decofi$er 5,031 190(3,80t 25',56;40(
't(Total for Ouarter 4 13,56r 10,221 61r 1,70'1,0't(
1 Total Year to
Dabffear 59,87i 46,74t 3,05r 6,80 3,271
PageFERC FORM NO. r/3-Q (NEW.07-04)
Name oI Kesponoent
ldaho Power Company
This Reoort ls:(1) ElAn orisinal(2) nA Resubmission
uate or Kepon
(Mo, Da, Yr)
0411512014
Yea7Penoo oI Kepon
gn6 61 2013/Q4
ELECTRIC ENERGY ACCOUNT
Report below the information called for concerning the disposition of electric energy generated, purchased, exchanged and wheeled during the year.
-ine
No.
Item
(a)
MegaWatt Hours
(b)
Line
No.
Item
(a)
MegaWatt Hours
(b)
1 SOURCES OF ENERGY 21 )ISPOSITION OF ENERGY
Generation (Excluding Station Use):22 Sales to Ultimate Consumers (lncluding
nterdepartrnental Sales)
14,619,352
Steam 6,326,86
4 Nuclear 23 lequirements Sales for Resale (See
nstructon 4, page 31 1.)Hydro-Conventional 5,656.36,
lydro-Pumped Storage 24 tlon-Requirements Sales for Resale (See
nstruction 4, page 311.)
1,683,29r
Sther 1,576,50
I -ess Energy for Pumping 25 :nergy Furnished Wthout Charge
c tlet Generation (Enter Total of lines 3
hrough 8)
13,559,721 26 inergy Used by the Company (Elecfic
)ept Only, Excluding Station Use)
10 'urchases 3,881,44:27 lotal Energy Losses 1,157,46(
11 rower Exchanges:28 IOTAL (Enter Total of Lines 22 Through
27) (MUST EQUAL LINE 20)
17.460.11
12 Received 3'.10,771
1:Delivered 289,1 1(
u Net Exchanges (Line 12 minus line 13)21,65'
1t Iransmission For Other $rVheeling)
1 Received 6,358,85(
1 )elivered
1 \et Transmission for Other (Line 16 minus
ine 17)
-2,70i
1 lransmission By Ohers Losses
20 TOTAL (Enter Total of lines 9, 10, 14, 18
rnd 19)
17,460,11
FERC FORM NO. I (ED. t2-90)Page 401a
Name of Respondent
ldaho Power Company
tnts KeDon ts:(1) fiAn Original(2) l-lA Resubmission
Date of Reoort(Mo, Da, Yi)
04115t2014
Year/Period of Report
End of 2O13lQ4
MONTHLY PEAKS AND OUTPUT
1. Report the monthly peak load and energy output. lf the respondent has two or more power which are not physically integrated, fumish the required
information for each non- integrated system.
2. Report in column (b) by month the system's output in Megawaft hours for each month.
3. Report in column (c) by month the non-requirements sales for resale. lnclude 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 (0 the specified information for each monthly peak load reported in column (d).
NAME OF SYSTEM: ldaho Power Company
_rne
No.Month
(a)
Total Monthly Energy
(b)
Monthly Non-Requirments
Sales for Resale &
Associated Losses
(c)
MONTHLY PEAK
Megawatts (Seelnstr.4)
(d)
Day of Month
(e)
Hour
(0
2S January 1 ,521,727 87,925 2.M2 22 8AM
3(February 1,303,296 202,177 2,048,11 8AM
3 March 1,289,0761 2'.t1,377 1,909 4 8AM
3:,April 1,146,697 65,379 1,854 29 ,I1AM
3:May 1,406,880 73,183 2,578 't3 7PM
3t June 1,619,468 61,453 3.201 29 5PM
3{July 1,853,09e 55,351 3,407 2 4PM
3(August 1 ,707,631 50,56s 2,91C 14 6PM
3;September 1,395,01(200,171 2,567 4 5PM
3t October 1,264,201 194,',t14 1,74C 30 9AM
2(November 1.370.1 9(267,036 1,98€22 8AM
4(December 1,582,82'l 2',t4,563 2,482 I 8AM
41 TOTAL 17,460,118 1,683,294
FERC FORi,l NO. 1 (ED. t2-90)Page 401b
Name of Respondent
ldaho Power Comoanv
This Report is:
(1) X An Originalel A Resubmission
Date of Report
(Mo, Da, Yr)
04t15t2014
Year/Period of Report
20131A4
FOOTNOTE DATA
Page
and BPA
328-330
adj usted
Column I ers from Page 401 by 2,103 I'tfrrtrH, reporte or Lucky Peak variat
Energy imbalance schedules on page 401-. The numbers that are shown on pagesare for account 456 wheel-j-ng onIy. However the numbers on page 401 have to befor account 44-l transmission.
FERC FORM NO.1 450.'l
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5]An orisinal(2) aA Resubmission
Date of Report(Mo, Da, Yr)
0411512014
Year/Period of Report
End of 20131Q4
STEAM-ELECTRIC GENERATI NG 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 intemal combustion plants of 10,000 Kw or more, and nuclear plants. 3. lndicate by a footnote any plant leased or operated
as a joint facility. 4. lf net peak demand for 60 minutes is not available, give data which is available, specifuing period. 5. lf any employees attend
more than one plant, report on line 11 the approximate average number of employees assignable to each plant. 6. lf 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 mst
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. lf more than one
fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
Line
No.
Item
(a)
Plant
Name: J,fn Bridger
(b)
Plant
Name: Boardman
(c)
1 Kind of Plant (lnternal Comb, Gas Turb, Nuclear Steam Steam
2 fype of Constr (Conventional, Outdoor, Boiler, etc)Semi-Outdoor Boiler Conventional
4 Year Last Unit was lnstalled 't979 1980
6 Net Peak Demand on Plant - MW (60 minutes)733,61
7 Plant Hours Connected to Load 876C 7254
8 Net Continuous Plant Caoabilitv (Meoawatts)c 0
10 \Mren Limited by Condenser Water c 0
11 Averaqe Number of Emplovees c 0
12 let Generation, Exdusive of Plant Use - KWh 488089800C 328026000
13 Sost of Plant Land and Land Riohts 494358 106610
14 Sfucfu res and lmorovements 67574164 't4291124
15 EouiDment Costs 47555344't 60881 102
16 Asset Retirement Costs 2375172 4075579
17 Total Cost 545997141 79354415
18 lost oer KW of lnstalled Caoacitv fline 17l5) lncludino 708.627C 1236.0501
19 ,roduction Expenses: Oper, Supv, & Enqr 212113 502428
20 Fuel 111039712 6433944
21 Coolants and Water (Nuclear Plants Only)c 0
22 Steam Expenses 5614513 637875
23 Steam From Other Sources c 0
24 Steam Transfened (Cr)c 0
25 Elec{ric Expenses c 0
26 Misc Steam (or Nudear) Power Expenses 7137763 580476
27 Rents 348322 0
28 Allowances c 0
29 Maintenance Supervision and Engineering 4353C 58089
30 Maintenance of Strucfu res c 42751
31 Maintenance of Boiler (or reactor) Plant 7763074 237986
32 Maintenance of Electric Plant 2808721 2009281
33 Maintenance of Misc Steam (or Nuclear) Plant 440089C 't6636
34 Total Production Exoenses 139368642 10519466
35 ExDenses per Nel l(Wtr 0.028€0.0321
36 Fuel: Kind (Coal, Gas, Oil, or Nudear)Coal cil Coal oil
37 Unit (Coal-tons/Oil-banel/Gas-mc'f/Nuclear-indicate)Tons 3anels Tons Banels
38 Quantity (Units) of Fuel Bumed 2661214 7344 0 189136 930
39 Avg Heat Cont - Fuel Bumed (btu/indicate if nudear)9340 140000 0 8352 138800 0
40 Avs Cost of Fuel/unit, as Delvd f.o.b. during year 40.282 153.487 0.000 32.427 128.563 ).000
41 Averaoe Cost of Fuel oer Unit Bumed 41.354 ,4.618 0.000 33.220 133.772 t.000
42 Average Cost of Fuel Bumed per Million BTU 2.196 16.091 0.000 1.959 22.943 1.000
43 Average Cost of Fuel Bumed per K\Mr Net Gen 0.023 ).000 0.000 0.020 0.000 1.000
44 Average BTU per l&Vh Net Generation 10277.000 ).000 0.000 9792.000 0.000 t.000
FERC FORM NO. I (REV. 12-03)Page 402
Name of Respondent
ldaho Power Company
This Rer(1) E(2) f
ort ls:
An Original
A Resubmission
Date of Report
(Mo, Da, Yr)
0411512014
Year/Period of Report
End of 20131Q4
STEAM-ELECTRIC GENEMTING PLANT STATISTICS (Large Plants) (Continued)
9. ltems 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. 1 0. For lC and GT plants, report Operating Expenses, Account Nos.
547 and 549 on Line 25 "Electric Expenses," and Maintenance Ac@unt Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant.' lndicate plants
designed for peak load service. Designate automatically operated plants. 1 1. 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 gasturbine with the steam plant. 12. lf a nuclear power generating plant, briefly explain by
footnote (a) accounting method for cost of power generated induding any excess costs attributed to research and development; (b) types of cost units
used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the
report period and other physical and operating characteristics of plant.
Plant
Name: Valmy
(d)
Plant
Name: Danskln
(e)
Plant
Name: Benneff Mountain
(fl
Line
No.
Steam Gas Turbine Gas Turbine I
Outdoor Conventional Conventional 2
2001 2005 3
1985 2008 2005 4
270.90 172.80 5
261 300 't96 b
7532 1231 540 7
0 261 164 8
0 0 I
0 0 0 10
0 I 5 11
1 1 17937000 200414000 80190000 12
1 106140 402745 0 13
65742458 s887090 1 676601 14
281331744 109272050 60834553 15
3595055 0 0 16
351775397 1 15561885 62511154 17
1240.8303 426.5850 361.7544 18
810416 245070 92035 19
42803085 9568193 3757903 20
0 0 0 21
2588497 0 0 22
0 0 0 23
0 0 0 24
1741112 377365 307498 25
1755527 193702 130520 26
0 0 0 27
0 0 27 28
0 31 99968 29
595094 128760 4772 30
4460826 2154 335369 31
580977 370194 0 32
123918 0 0 33
s5459452 10885469 4728092 34
0.0496 0.0543 0.0590 35
Coal oit Gas Gas 36
Tons Banels MCF MCF 37
642255 13332 0 2029638 0 0 830725 0 0 38
8695 138778 0 1027 0 0 1027 0 0 39
39.321 146.416 0.000 4.7'.!4 0.000 0.000 4.524 0.000 0.000 40
63.52s 146.206 0.000 4.714 0.000 0.000 4.524 0.000 0.000 41
3.653 25.OU 0.000 4.490 0.000 0.000 4.270 0.000 0.000 42
0.038 0.000 0.000 0.048 0.000 0.000 0.470 0.000 0.000 43
10060.000 0.000 0.000 10401.000 0.000 0.000 10639.000 0.000 0.000 44
FERC FORM NO. I (REV. 12-03)Page 403
Name of Respondent
ldaho Power Company
This Reoort Is:(1) 5]Rn orislnal(2) 1A Resubmission
uate ot Kepon(Mo, Da, Yr)
0411512014
YearHenoo oI Kepon
End of 20131Q4
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 intemal combustion plants of 10,000 Kw or more, and nuclear plants. 3. lndicate by a footnote any plant leased or operated
as a joint facility. 4. lf net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. lf any employees attend
more than one plant, report on line 1 I the approximate average number of employees assignable to each plant. 6. lf 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
perunitoffuelburned(Line41)mustbeconsistentwithchargestoexpenseaccounts50land54T(Line42)asshowonLine20. 8. lfmorethanone
fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
Line
No.
Item
(a)
Plant
Name: Langley Gulch
(b)
Plant
Name:
Kind of Plant (lntemal Comb, Gas Turb, Nuclear Gas Turbine
2 fype of Constr (Conventional, Outdoor, Boiler, etc)Conventiona
3 Year Orioinallv Constructed 2012
4 Year Last Unit was lnstalled 2012
5 Iotal lnstalled Cap (Max Gen Name Plate Ratinos-MW)318.45 0.00
6 Net Peak Demand on Plant - MW (60 minutes)30i 0
7 Plant Hours Connected to Load 525C 0
8 Net Continuous Plant Capability (Megawatts)30c 0
9 \A/hen Not Limited by Condenser Water c 0
10 When Limited bv Condenser Water c 0
11 Averaoe Number of Emolovees 1 0
12 Net Generation, Exclusive of Plant Use - l(l/h 129585900C 0
13 Oost of Plant: Land and Land Riqhts 2287261 0
14 Structures and lmprovements 126178288,0
15 Equipment Costs 248481897 0
16 Asset Retirement Costs c 0
17 Total Cost 37694744C 0
18 iost per KW of lnstalled Capacity (line 17l5) lncluding I 183.6943 0
19 ,roduction Expenses: Oper, Supv, & Engr 896202 0
20 Fuel 40866185 0
21 Coolants and Water (Nuclear Plants Onlv)0
22 Steam Expenses 0
23 Steam From Other Sources 0
24 Steam Transfened (Cr)0
25 Electric Expenses 274112e 0
26 Misc Steam (or Nuclear) Power Expenses 1 39367 0
27 Renb 0
28 Allowances 0
29 Maintenance Suoervision and Enoineerino 42 0
30 Maintenance of Structures 72558 0
31 Maintenance of Boiler (or reactor) Plant 78592 0
32 Maintenance of Elecbic Plant 528r'.2(0
33 Maintenance of Misc Steam (or Nudear) Plant 0
34 Total Production Expenses 45322493 0
35 Expenses per Net l(A/tr 0.035(0.0000
36 :uel: Kind (Coal, Gas, Oil, or Nuclear)Gas
37 U nit (Coal-tons/Oil-banel/Gas-mcf/Nuclear-indicate)MCF
38 Quantity UniG) of Fuel Bumed 8967970 )0 0 0
39 Avg Heat Cont - Fuel Bumed (btu/indicate if nuclear)1027 D 0 0 0
40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 4.557 ).000 0.000 0.000 0.000 0.000
41 Averaoe Cost of Fuel oer Unit Bumed 4.557 ).000 0.000 0.000 0.000 0.000
42 Average Cost of Fuel Burned per Million BTU 4.390 ).000 0.000 0.000 0.000 0.000
43 Average Cost of Fuel Burned per KWh Net Gen 0.320 ).000 0.000 0.000 0.000 0.000
44 Averaqe BTU per KWh Net Generation 7107.000 ).000 0.000 0.000 0.000 0.000
FERC FORM NO. I (REV.12-03)Page 402.1
Name of Respondent
ldaho Power Company
This Rer(1) E(2) tr
ort ls:
An Origlnal
A Resubmission
Date of Reoort
(Mo, Da, Yi)
0411512014
Year/Period of Report
End of 2013/Q4
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Larse Plants) (Continued)
9. ltems 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. 1 0. For lC 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." lndicate plants
designed for peak load service. Designate automatically operated plants. 1 1 . 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 ttre gas-turbine with the steam plant, 12. lf a nuclear power generating plant, bilefly explain by
footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units
used for the various components of fuel cost and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the
report period and other physical and operating characteristics of plant.
Plant
Name:
Plant
Name:
Plant
Name:
Line
No.
1
2
3
4
0.00 0.00 0.00 5
0 0 0 6
0 0 0 7
0 0 0 8
0 0 0 I
0 0 0 10
0 0 0 11
0 0 0 12
0 0 0 13
0 0 0 14
0 0 0 15
0 0 0 16
0 0 0 17
0 0 0 18
0 0 0 19
0 0 0 20
0 0 0 21
0 0 0 22
0 0 0 23
0 0 0 24
0 0 0 25
0 0 0 26
0 0 0 27
0 0 0 28
0 0 0 29
0 0 0 30
0 0 0 31
0 0 0 32
0 0 0 33
0 0 0 34
0.0000 0.0000 0.0000 35
36
37
0 0 0 0 0 0 0 0 0 38
0 0 0 0 0 0 0 0 0 39
0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 40
0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 41
0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 42
0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 43
0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 44
FERC FORM NO.1 (REV.12-03)Page 403.1
Name of Respondent
ldaho Power ComDanv
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t't5t2014
Year/Period of Report
2013tQ4
FOOTNOTE DATA
This footnote applies to lines 3 and 4. The Jim Bridger PowerPlant 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, 7974, Unit #2 December 1, 1915,Unit #3 September 1, L976, and Unit #4 November 29, 19'79.
This footnote applies to lines 3 and 4. The Boardman plant
consists of one unit constructed jointly by Portland GeneralEl-ectric Company, Idaho Power Company, and Pacific Northwest
Generating Company, with Idaho Power Company owning 10?. Ihe
402 Line No.:3 Column: c
unit was placed in commercial o ration ust 3, 1980.
nesSa 4. The Valmy plant consistsjointly by Sierra Pacific Power Companywith Sierra owning 1/2 and Idaho owningin commercial operation December 11, 1981
This footnote applies toof two units constructed
and Idaho Power Company,l/2. Unit #1 was placed
403 Line No.:3 Column: d
and Uni-t #2 Mav 21, 1985.
This footnote applj-es tofnformation reflects Idaho
5 and lines
Power Company'
column B.
12 throughs share as
43.
explaj-ned
402 Line No.:5 Column: b
in note for line 3 402
This footnote applies
Informati-on reflects to line 5 an nes 1 through 43.
share as explainedIdaho Power Companyrs
e 4O2 column C
402 Line No.:5 Column: c
in note on line 3
This footnote applies to ]ine 5 and lines 12 through 43.Information refl-ects Idaho Power Company's share as explained
403 Line No.:5 Column: d
in note for line 3 e 403 column D.
This footnoteas operator ofinformation.
applies tothe plant s 9,10, and PacifiCorpwill report this
i 402 Line No.:9 Column: b
This footnote applj-es to anes 11. Portl-and Generathis information.Electric C nv, as o rator will
This ootnote app esof ines 9,10,
re
Power,as operator plant, will Sierra Pacificthis information.to
the
and 1l-
report
403 Line No.:9 Column: d
FERC FORM NO. 1 450.1
Name of Respondent
ldaho Power Company
lnts KeDon ls:(1) fiRn Original(2) 3A Resubmission
uate ol Heoon
(Mo, Da, Yi)
04t15t2014
Year/Period of Report
End of 20131Q4
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. lt 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. lf licensed project, give project number.
3. lf net peak demand for 60 minutes is not available, give that which is available specirying period.
4. lf a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
olant.
Line
No.
Item
(a)
FERC Licensed Project No. 2736
Plant Name: American Falls(b)
:ERC Licensed Project No. 1975
rlant Name: Bliss
(c)
1 Kind of Plant (Run-of-River or Storage)Run-of-River
2 Plant Construction fuDe (Conventional or Outdoor)Outdoor Outdoor
3 Year Orioinallv Constructed 1978 1949
4 Year Last Unit was lnstalled 1S78 1950
5 fotal instralled cap (Gen name plate Rating in MW)92.3C 75.00
6 Net Peak Demand on Plant-Megawatts (60 minutes)94 52
7 Plant Hours Connect to Load 4,891 8,756
I (a) Under Most Favorable Oper Conditions 110 76
't0 (b) Under the Most Adverse Oper Conditions 0 I
11 ryeraqe Number of Emolovees 4 4
12 Net Generation, Exclusive of Plant Use - Kwh 243,830,000 291,809,000
14 Land and Land Riqhts 875,318 768,366
15 Structures and lmprovements '11.772.491 1,083,396
16 Reservoirs, Dams, and Waterways 4,293,07r 8,413,888
17 Eouioment Costs 31,985,16i 8,848,494
18 Roads, Railroads, and Bridges 839,27t 486,477
19 Asset Retirement Costs 0
20 TOTAL cost (Total of 14 thru 19)49,765,335 19,600,621
21 Cost per KW of lnstalled Capacity (line 20 / 5)539.169r 261.3416
23 Ooeration SuDervision and Enoineerino 31 3,1 1(898,744
24 Water for Power 1.260.91t 503,953
25 Hydraulic Expenses 140.851 625,194
26 Electric Expenses 50.1 1(55,216
27 Misc Hydraulic Power Generation Expenses 225,06t 312,980
28 Rents 8t 9,282
29 Maintenance Suoervision and Enoineerino 6,19i 3,817
30 Maintenance of Structures 175,001 35,354
31 Maintenance of Reservoirs, Dams, and Watenivays 5,68!51,201
32 Maintenance of Elec{ric Plant 280,17t 178,533
33 Maintenance of Misc Hydraulic Plant 202,41(143,754
34 Total Production Expenses (otal 23 thru 33)2,659,61:2,818,028
35 Expenses per net KWh 0.0109 0.0097
FERC FORM NO.1 (REV.12-03)Paqe 406
Name of Respondent
ldaho Power Company
This ReDort ls:(1) S]An original(2) nA Resubmission
Date of Reoort
(Mo, Da, Yi)
04115t2014
Year/Period of Report
End of 20'l3lQ4
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC Licensed Project No. 1971
Plant Name: Brownleeld)
FERC Licensed ProjectNo. 2848
Plant Name: Gascade(e)
FERC Licensed Project No. 1971
Plant Name: Oxbow
Tfl
Line
No.
Outdoor Outdoor Outdoor 2
1958 1983 1961 3
1980 1984 1961 4
585.40 12.42 190.0c 5
552 14 207 6
8.760 8,745 8,760 7
747 15 221 9
220 1 202 10
7 2 7 11
1,678,769,000 39,982,000 744,020,000 12
18,092,312 82,'.t42 1,213,449 't4
32,068,242 7.364.154 10,586,70€15
67,073,285 3,145,63(30,435,630 16
57,971,691 12.693.212 18,350,111 17
518,444 122,66t 565,842 18
0 19
175,723,974 23,407,80e 61,151,73t 20
300.1776 1,884.686t 321.851i 2',1
529,568 221.701 274.721 23
260,735 162,004 131.43t 24
1,223,022 606,69S 627,31t 25
2W,462 164,93t 't45,73i 26
966,773 405,97:519,121 27
51,204 6t 8,39r 28
17,852 2,91e 9,02:29
142.426 33,128 320,80(30
223,950 2,102 3,821 31
455,52t 124,45C 138,36(32
634,482 95,76€244,201 33
4,796,00(1,819,742 2,422,941 34
0.002€0.045t 0.0033 35
FERC FORM NO.1 (REV.12-03)Page 407
Name of Respondent
ldaho Power Company
This Reoort ls:(1) p(lAn orisinal(2) nA Resubmission
Date of Reoort(Mo, Da, Yi)
0411512014
YeailPenoo ot Kepoft
End of 2013/Q4
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. lf 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. lf licensed project, give project number.
3. lf net peak demand for 60 minutes is not available, give that which is available specifying period.
{. lf a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
rlant.
Line
No.
Item
(a)
FERC Licensed Project No. 1971
Plant Name: Hells Canyon(b)
:ERC Licensed Project No. 2726
rlant Name: Malad
(c)
2 rlant Construction type (Conventional or Outdoor)Outdoor Outdoor
3 (ear Originally Constructed 1967 1 948
4 fear Last Unit was lnstalled 196i 1 948
5 fotal installed cap (Gen name plate Rating in MW)391.5C 21.77
6 tlet Peak Demand on Plant-Meoawatts (60 minutes)354 23
7 )lant Hours Connect to Load 8,76C 8,677
8 tlet Plant Caoabilitv (in meqawatts)
I (a) Under Most Favorable Oper Conditions 445 25
10 (b) Under the Most Adverse Oper Conditions 137 21
't1 Average Number of Employees 5 2
12 Net Generation, Exclusive of Plant Use - Kwh 1.422.250.00C 144,563,000
14 Land and Land Riohts 1.880.407 205,375
't5 Strucfures and Improvements 2,728,449 2,778,755
16 Reservoirs, Dams, and Waterways 52,738,008 6,262,987
17 Equipment Costs 19,731,257 4,454,070
18 Roads, Railroads, and Bridses 922,781 309,805
19 Asset Retirement Costs c 0
20 TOTAL cost fiotal of 14 thru 19)78,000,902 14,010,992
2'l Cost per lOV of lnstalled Capacity (line 20 / 5)199.236C 643.5917
23 Operation SupeMsion and Engineering 322,558 12s,188
24 Water for Power 157,679 671,591
25 Hydraulic Expenses 750,89€u,329
26 Elec{ric Expenses 208.651 30,460
27 Misc Hvdraulic Power Generation Expenses 565.077 93,997
28 Rents 13.96€0
29 Maintenance Supervision and Engineering 13,38i 3,051
30 Maintenance of Sfudures 97,82C 12,707
31 Maintenance of Reservoirs, Dams, and Watenrvays 378,0S 1 1,088
32 Maintenance of Elecfic Plant 226,451 91,163
33 Maintenance of Misc Hydraulic Plant 456,12t 21',t,875
34 Total Production Expenses (total 23 thru 33)3,190,70€1,335,449
35 Expenses per net l(VVh 0.0022 0.0092
FERC FORM NO.1 (REV.12-03)Paqe 406.1
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5]Rn Orisinat(2) 1A Resubmission
uate ot KeDon
(Mo, Oa, Yi)
0411512014
YearPenoo ot Kepon
End of 20131Q4
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as'Other Power Supply Expenses.'
6. Report as a separate plant any plant equipped with combinations of steam, hydro, intemal combustion engine, or gas turbine equipment.
FERC Licensed Project No. 2055
PlantName: CJStrike(d)
FERC Licensed ProjectNo. 503
Plant Name: Swan Falls(e)
FERC Licensed Project No. 18
Plant Name: Twin Falls
/fl
Line
No.
Run-of-River Run-of-River Run-of-River 1
Outdoor Conventiona Conventional 2
't952 191(1935 3
1952 1 991 1995 4
82.8C 25.0(52.74 5
a 1 36 6
8,759 8,751 5,827 7
91 24 53 I
84 1 50 10
5 4 a 11
358,642,000 108.062.00c 55,373,00(12
5,476,746 't02.678 255,49t 14
9,545,892 25.479,513 '10.962.30(15
10,708,043 13.856,887 7,975,451 16
12,998,664 30.566.685 20.892.s7(17
210,416 835,94€1,917,60!18
0 19
38,939,761 70,841,70!42.003.42i 20
470.2870 2.833.6684 796.424 21
996,276 631,494 248,031 23
407,453 225,11 86,481 24
1,162,353 579,834 135,224 25
48,586 16.332 63,507 26
479,0U 286,528 133,279 27
44,397 6,784 2,628 28
4,112 5,251 2,468 29
65,105 107.31€38,703 30
81,776 72,96€8,289 31
202,9'.10 275,82!67.924 32
90,710 106,391 149,401 33
3,582,762 2,313,842 935,939 34
0.0'100 0.0214 0.016s 35
FERC FORM NO. 1 (REV. 12-03)Page 407.1
Name oI Kesponoent
ldaho Power Company
This Reoort ls:(1) ffiAn Orisinal(2, f]A Resubmission
Date of Reoorl(Mo, Da, Yi)
04t15t20't4
Year/Period of Report
End of 20131Q4
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Large plants are hydro plants of 10,000 Kw or more of inshlled capacity (name plate ratings)
2. lf any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in
r foohote. lf licensed project, give project number.
3. lf net peak demand for 60 minutes is not available, give that which is available specifoing period.
4. lf a group of employees attends more than one generating plant, report on line 11 the approximate averElge number of employees assignable to each
rlant.
Line
No.
Item
{a)
:ERC Licensed Project No. 2777
,lant Name: Upper Salmon
rb)
FERC Licensed Project No. 2779
Plant Name: Shoshone Falls
lc)
1 (nd of Plant (Run-of-River or Storage)Runof-River Run-of-River
2 )lant Construction type (Conventional or Outdoor)Outdoor Conventional
3 Year Originally Constructed 193?1 907
4 Year Last Unit was lnstalled 194i 't921
5 Total installed cap (Gen name plate Ratinq in MW)34.5C 12.50
6 Net Peak Demand on Plant-Meoawatts (60 minutes)3t 14
7 Plant Hours Connect to Load 8,76C 6,061
I (a) Under Most Favorable Oper Conditions 2C 14
't0 (b) Under he Most Adverse Oper Conditions 32 11
11 {verage Number of Employees 2
12 \et Generation, Exclusive of Plant Use - Kwh 188.593.00C M,995,000
14 Land and Land Rishts 20239e 313,328
15 Sbuc,tures and lmorovements 2,037.511 1,257.955
16 Reservoirs, Dams, and Waterways 5,569,171 512,402
17 Equipment Costs 8,793,80€4,678,182
18 Roads, Railroads, and Bridges 29,359 51,383
19 Asset Retirement Costs c 0
20 TOTAL cost fiotd of 14 thru 19)16,632,24a 6,813,250
21 Cost per KW of lnstalled Capacity (line 20 / 5)482.0941 545.0600
23 Operation Supervision and Engineering 370,652 325,551
24 Water for Power 154,204 12'.t,314
25 Hydraulic Expenses 392,54S 260,491
26 Electric Exoenses 107.672 33,536
27 Misc Hydraulic Power Generation Expenses 192,849 196,103
28 Rents c 70
29 Maintenance Supervision and Engineering 5,747 3.211
30 Maintenance of Structures 167,404 38.102
31 Maintenance of Reservoirs, Dams, and Watenivays 195,445 46,966
32 Maintenance of Electric Plant 11 1,10C 167,209
33 Maintenance of Misc Hvdraulic Plant 141,695 91,727
34 Total Production Expenses (total 23 thru 33)1,839.317 1,284,280
35 Expenses per net KVVh 0.0098 0.0198
FERC FORM NO.1 (REV.12-03)Page 406.2
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5]Rn orisinat(2) nA Resubmission
Date of Reoort(Mo, Da, Yi)
0411512014
Year/Period of Report
End of 20131Q4
HYDROELECTRIC GENEMTING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts, Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal mmbustion engine, or gas turbine equipment.
FERC Licensed Project No. 1911
Plant Name: Common Facilities
{d)
FERC Licensed Project No. 2061
Plant Name: Lower Salmon
Iel
FERC Licensed ProjectNo. 2899
Plant Name: Milner
/f\
Line
No.
Run-of-River Run-of-River ,|
Outdoor Conventional 2
194!1992 3
194(1992 4
0.0c 60.0(59.45 5
c 4(37 6
0 8,76(4,834 7
0 6t 61 9
0 6(1 10
0 2 11
0 't94,164,00(52.819.00C 12
114,367 424,42e,138,100 14
40,625,699 2,822,s75 10,353,694 15
13,556,785 6,920,14€17,114,934 16
1.904,696 I,052,877 28,539,419 17
99,051 88,693 501,877 18
0 0 19
56,300,598 18,308,72t 56,648,024 20
0.0000 305.1454 952.8684 21
0 444,132 266,922 23
0 13't.99i 1,378,381 24
6,551,530 212.537 122,619 25
0 65.964 52.409 26
0 220.371 211,13C 27
0 2,14t 2,573 28
0 4,08i 2,035 29
0 84,384 48,50i 30
0 53,57€10,60i 31
0 137.53t 103,043 32
157,357 162.32C 55,851 33
6.708.887 1,519,05€2,254.077 34
0.0000 o.0427 35
FERC FORM NO. I (REV.12-03)Page 407.2
This Page lntentionally Left Blank
Name of Respondent
ldaho Power Comoanv
This Report is:
(1) X An OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
04t1512014
Year/Period of Report
20't3lQ4
FOOTNOTE DATA
American Fal1s
USBR.
generating capacity is
neratinq capacit is deoendent
stream storaqe in Brownl-ee Reservoir
Upstream storaqe in Brown.l-ee eservo]-r
Lower Malad maximum demand 1
nt upon water re eases contro ed by the
water releases controll
, 000 Kw non-coincident.
406 Line No.:1 Column: e
406 Line No.: I Column: f
406.1 Line No.:1 Column: b
:406.1 Line No.: 1 Column: c
FERC FORM NO.1 450.1
Name of Respondent
ldaho Power Company
I nts F(eooft ts:(1) []Rn orisinat(2\ l-'lA Resubmission
uate oI Keoon
(Mo, Da, Yi)
0411512014
Year/Period of Report
End of 20131Q4
GENERATING PLANT STATISTICS (SmaII P|ants)
'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 foohote. lf licensed project,
give project number in footnote.
_ine
No.
Name of Plant
(a)
Year
Orio.
ConEt.
(b)
tnsraileo uaoac{nlame Plate Ratin'
(ln MW)
(c)
Net reaKDemandMW(60,9in.)
Net Generation
Excludino
Plant UsE
(e)
Cost of Plant
(fl
1 Hydro:
2 Clear Lakes 1S37 2.50 2.i 12,31i 1,784,11t
3 Thousand Springs 1912 8.80 7.1 56,18(9,391,28r
4
5
6 lntemal Combustion:
7 Salmon Diesel (1)1967 5.00 4.(3t 909,25(
8
9
10
't1 (1) Salmon units are classified as standby.
12
13
14
15
16
17
18
19
20
2'.1
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
M
45
46
FERC FORM NO. 1 (REV. 12-03)Page 410
Name of Respondent
ldaho Power Company
I nts KeDon ts:(1) []An orisinal(2) llA Resubmission
Date of Report(Mo, Da, Yr)
04t1512014
Year/Period of Report
End of 2O13lQ4
GENERATING PLANT STA -lSTlCS (Small Plants) (Continued)
3. List plants appropriately under subheadings for steam, hydro, nuclear, internal combustion and gas turbine plants. For nuclear, see instruction I 1,
Page 403. 4. lf net peak demand for 60 minutes is not available, give the which is available, speciffing period. 5. lf 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 (lncl Asset
Retire. Costs) Per MW
(s)
Operation
ExCl. Fuel
(h)
Producuon Expenses
Kind of Fuel
&)
Fuel Costs (in cents
(per Million Btu)
fl)
Line
No.Fuel(i)tvratl llEI tat tw(i)
713,648 142,631 73,144 2
1,067,191 '193,242 109,39(3
4
5
b
181,85'Diesel 7
8
I
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO. I (REV. 12.03)Page 411
Name oI Kesponoenl
ldaho Power Company
This ReDort ls:(1) fiAn Original(2) nA Resubmission
uate ot KeDort
(Mo, Da, Yi)
0411512014
Year/Period of Report
End of 2O13lQ4
TRANSMISSION LINE STATISTICS
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121 , Nonutility Property.
5. lndicate 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 lf 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 exfa 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 sfuctures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). ln a footnote, explain the basis of such occupancy and state whether expenses with
respect to such strucfures are included in the expenses reported for the line designated.
Line
No.
IJESIGNAI ION VULIAL'E (KVI(lndicate wherdbther than
60 cvcle. 3 ohase)
Type of
Supporting
Strucfure
(e)
LENGIH(Polemllesl(ln the base.ofundercround linesreportEircuit miles)
Number
of
Circuits
(h)
From
(a)
To
(b)
Operating
(c)
Designed
(d)
UN SIruqUTEof LineDesionated
11)
vU ouuuturesof AnotherLrne
(s)
1 Borah Midpoint 345.01 500.0(S Tower 85.1 1
Boardman Slatt 500.01 500.0(S Tower 1.71 1
Summer lake Hemingway 500.0t 500.0(3 Tower 0.4(1
Hemingway Midpoint 500.01 s00.0(S Tower 0.3i 1
€Jim Bridoer Goshen 345.01 345.0(3 Tower 226.11 1
State Line Midpoint 345.0r 345.0(S Tower 76.0r
I Kinport Borah 345.0r 34s.0(3 Tower 27.11 1
0 Midpoint Borah #1 345.0r 345.0({ Wood 79.3(1
10 Midpoint Borah #2 345.0r 345.0({ Wood 77.51
11 Adelaide Tao Adelaide 34s.01 345.0({ Wood 3.5!
12
13 Quarts LaGrande 230.0r 230.0t '{ Wood 46.2',
14 Midpoint .{unt 230.0r 230.0(S Tower 0.7t
15 Brady Antelope 230.0r 230.0({ Wood s6.4'1
16 Brady Treasureton 230.0(230.0t 'l Wood 0.1
17 Brady#1 &#2 (nport 230.0(230.00 3 Tower 17.94 2
18 Jim Bridoer 'oint of Rocks 230.0r 230.0(I Wood 1.4(1
19 Brownlee Cntario 230.0(230.0(i Tower 72.71
20 Mora 3owmont 138.0(230.0(S P Wood 9.9'1
21 Mora 3owmont 138.0r 230.0(I Wood 8.8:
22 Jim Bridger toint of Rocks 230.0r 230.0('l Wood 2.71
23 Caldwell 710 -ocust 230.0r 230.0(SP Steel 18.5!
24 Boise Bendr Saldwell 230.0r 230.0c ] Tower 7.51
2t Boise Bencfr 3aldwell 230.0r 230.0(J Wood 33.6r
2t Boise Bench lloverdale 230.q 230.tr 3 Tower 15.91
21 Boardman )alreed Sub 230.ff 230.0({ Wood 1.6t
2t Brownlee 714 )xbow 230.fi 230.0t 3P Steel 11.&
2S Caldwell )ntario 230.0r 230.0({ Wood 29.9i
3(Caldwell )ntario 230.01 230.0(J Tower 3.2i 1
31 Bennett Mtn PP latflesnake TS 230.0(230,0(iP Steel 4,41
32 Borah lunt 230.0(230.0({ Steel 68.21 1
Danskin lubbard 230.0(230.0({ Steel 36.2t 1
34 Danskin lubbard 230.0(230.0(3P Steel 1.9(1
35 Danskin Hubbard 230.0t 230.0(iP Steel 1.3(
3€TOTAL 4,779.4 11.0i 190
FERC FORM NO. I (ED. 12-87)Paqe 422
Name of Respondent
ldaho Power Company
This Reoort ls:(1) fiRn Original(2) -A Resubmission
Date of Reoort(Mo, Da, Yi)
o4t15t2014
Year/Period of Report
End of 20131Q4
TRANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. lf 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 lhereof for which the respondent is not the sole owner. lf 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 mafters 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 0) to (l) on the book cost at end of year.
Size of
Conductor
and Material
(i)
COST OF LINE (lnclude in uolumn U) Land,
Land rights, and clearing right-of-way)
EXPENSES. EXCEPT DEPRECIATION AND TAXES
_tne
No.
Land
0)
lonstruction and
Other Costs(k)
Total Cost
(t)
Operation
Expenses(m)
Maintenance
Expenses(n)
Rents
(o)
Total
Exo,e;ses
t272 ACSR 256,38'21,838,86(22,095,24 ,|
tx1780 ACSR 446,701 446,101 2
1272 ACSR 835,66'835,66'3
I272 ACSR 4
5
272 ACSR 483,30!16,830,98'17,314,29'6
'95 ACSR 57'1,97r 11,048,281 1't,620,26(7
272 ACSR 344.221 6,008,06'l 6,352,28'8
15.5 ACSR 283.14 9,470,50:9,753,64(I
'15.5 ACSR 64,85 1s,994,931 16,059,78(10
'15.5 ACSR 51,44 347.941 399,39/11
12
'95 ACSR 62,21;5,440,57i 5,502,79(13
15.5 ACSR 9,14 998,45i 1,007,59i 14
272 ACSR 108,30 3,415,60(3,523,901 15
'95 ACSR 6,18(6,18(16
15.5 ACSR 18,82r 969,871 988,70{17
272 ACSR 1,19r 51,52{52,711 18
rx954 ACSR 1,676,83 20,541,791 22.218.621 19
'15.5 ACSR 413,79i 2,191,381 ?,611,171 20
1s.5 ACSR 2'l
272 ACSR 1,89r 212,52:214,42"22
590 ACSR 2,138,231 8,775,08(10,913,32'23
272 ACSR 213,001 8,575,36(8,788,36(24
'15.5 ACSR 25
272 ACSR 3,062,81:6,567,671 9,630,48r 26
'95 AAC 89,75(89,75(27
r54 ACSR u,17 16,026,47(,l6.060.64'28
rx954 ACSR 236,15i 9,228,89:9,465,041 29
272 ACSR 30
272 ACSR 81,70 1,666,3v 1,748,051 31
590 ACSR 624,91',22,468,661 23,093,s8i 32
590 ACSR 15,210,561 '15,210,561 33
590 ACSR 34
590 ACSR 35
30,423,40(481,134,'.17(511,557,57(7,2',t5,461 3,912,45 18,173,721 29,301,63r 36
FERC FORM NO.1 (ED.12-87)Page 423
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5]An orisinal
(21 f-lA Resubmission
Date of Report(Mo, Da, Yr)
04t't512014
Year/Period of Report
End of 20131Q4
TRANSMISSION LINE STATISTICS
1. Report information conceming transmission lines, mst 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. lndicate 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 lf 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). ln 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.
-tne
No.
UEsI(jNAI IUN V(JLIAGE (KV}(lndicate wherdbther than
60 cvcle.3 ohase)
Type of
Supporting
Structure
(e)
LENS I t1 (rote mlesl(ln the base.ofunderoround lines
report Eircuit miles)
Number
o,f
Circuits
(h)
From
(a)
To
(b)
Operating
(c)
Designed
(d)
uiloofDesi
ucure
-inetnated
f)
vIt ou uutuleSofAnotherLine(s)
1 Danskin Bennett Mtn 230.0r 230.0(3P Steel E2(
2 Hemingway Bowmont 230.0(230.0(SP Steel 13.0i
[anolev Gulch Galloway Rd 138.0(230.0(SP Steel 14.11
4 Gallowav Rd Willis Tap 138.0r 230.0(3P Steel 2.0t
6 Boise Bench Midpoint #1 230.0(230.0(S Tower 0.8i
6 Boise Bench [4idpoint #1 230.0(230.0(i Wood 108.4!
Brownlee Quar2 Jct 230.0(230.0(3 Tower 1.51
8 Brownlee QuarE Jct 230.0r 230.0({ Wood 41.3r
o Srownlee Boise Bench #1 &#2 230.0(230.0(3 Tower 99.7(
1(Cxbow Brownlee 230.0r 230.0(S Tower 10.4(
11 3oise Bench Midpoint#2 230.0r 230.0(3 Tower 3.4(
12 Boise Bench Midpoint#2 230.0r 230.0(I Wood 102.0i
1i Oxbow Pallette Jct 230.0r 230.0(3 Tower 20.0[
14 Pallette Jct lmnaha 230.0(230.0('{ Wood 24.4i
1 Hells Canyon 2alette Jct 230.0(230.0(S Tower 9.&2
1 Brownlee 3oise Bench 230.0r 230.0(S Tower 102.51 2
1 Boise Bench Midpoint #3 230.0r 230.0(I Wood 106.3(I
1 Palette Jct interprise 230.0r 230.0(I Wood 29.6(I
1 Borah Sradv#2 230.0r 230.0(3 Tower 0.41 1
2C Borah *adv#2 230.01 230.0({ Wood 3.5(1
21 Borah 3radv #1 230.0r 230.0(I Wood 3.8,;1
22
23 Goshen State Line 't61.0r 161.001H Wmd 90.6(,|
24 Don Goshen 't61.0t 161.0(S Tower 2.3i
2a Don Goshen 16't.01 161.001H Wood 48.41
2t
27 American Falls Power Plant {delaide 138.0r 138.0({ Wood 11.2i
2E American Falls Power Plant {delaide 138.0r 138.0(S P Wood 0.1i
2S Minidoka Loop \delaide 138.0r 138.0(3 Tower I .'t:
3C Nampa 3aldwell 138.0r 138.0(S P Wood 9.5{
31 Upper Salmon Vountain Home Jct 138.0r 138.0(H Wood 54.4:,1
32 Upper Salmon Stiff 't38.01 138.00 { Wood 30.81 1
ta Eastgate lusset '138.0r '138.00 S P Wood 2,0{1
34 Brady :remont 138.0r 138.00 i Tower 1.0(
,E Brady --remont 138.0r 138.00 'l Wood 24.3i
36 TOTAL 4,779.31 11,0i,190
FERC FORM NO. r (ED.12-E7)Page 422.1
Name of Respondent
ldaho Power Company
tnrs Keoon ts:(1) 5.1Rn Orisinat(2) 1-1A Resubmission
Date of Reoort
(Mo, Da, Yi)
o411512014
Year/Period of Report
End of 20131Q4
TRANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. lf 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. lf 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 thereol 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 a@ounts affected. Specifo whether lessor, @-owner, or
other party is an associated company.
9. Designate any hansmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns 0) to (l) on the book cost at end of year.
Size of
Conductor
and Material
(i)
uus I uF LINE (tnquoe rn uorumn u, Lano,
Land rights, and clearing right-of-way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES
No.
Land
0)
lonstruction and
Other Costs(k)
Total Cost
(t)
Operation
Expenses
(m)
Maintenance
Expenses
(n)
Rents
(o)
Total
Exo,Tpes
590 ACSR 3.528.03:3,528,03:1
590 ACSR 1,854,99r 9,284,27'1 1,139,26i 2
590 ACSR 948,16(9,080,89(10,029,0s(3
272 ACSR 4
'15.5 ACSR 385,28;6,638,37'7,023,661 5
'15.5 ACSR 6
'95 ACSR 53,06 2,833,57r 2,886,64i 7
'95 ACSR 8
/ARIOUS 289,93 9.010,83(9,300,77:I
1272 ACSR 14,81r 1,237,521 1,252,33,10
'15.5 ACSR 227,82t 14,413,'191 14,641,01(11
/ARIOUS 12
272 ACSR 87,46i 2,168,76;2,256,23.13
272 ACSR 171,08 1,540,81t 't,711,89r 14
272 ACSR 44,68'.1,252,',t31 1,296,81 15
r54 ACSR 184,81'6,257,',t51 6,44't,97''16
'15.5 ACSR 247,85'5,655,75i 5,903,6't(17
272 ACSR 84,01,'t,881,21(1,965,23(18
272 ACSR 3,061 416,601 419,67 19
'15.5 ACSR 20
272 ACSR '10,06,3'r1,341 321,4'l 21
22
I5O COPPER 16,151 648,38:664,53i 23
15.5 ACSR 76,04'1,735,84:'t,811,88,24
r97.5 ACSR 25
26
I5O COPPER 26,50i 339,39,365,90'27
I5O COPPER 28
'15.5 ACSR 21,32\249,23i 270,55!29
'95MC 654,75 3,234,06r 3,888,811 30
'95 ACSR 47,68 3,539,6t 3,587,34 31
'95 ACSR 43,56 1,085,981 1,1 29,55;32
'9sMC 270.82 557,50,828,32;33
/ARIOUS 564,93 3.795,84r 4,360,7i 34
IARIOUS 35
30,423,40r 481,134,17(51 1,557,57(7,215,451 3,912,45 18,173,721 29,301,63r 36
FERC FORM NO.1 (ED.12-E7)Page 423.1
Name of Respondent
ldaho Power Company
This Reoort ls: I Date of Reoort(1) fiRn orisinal I tuo, oa, vi)(2) J-1A Resubmission | 0411512014
Year/Period of Report
End of 20131Q4
TRANSMISSION LINE STATISTICS
1 . Report information conceming transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Acrounts. 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 ProperV.
5. lndicate 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 lf 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 (0 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; mnversely, 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). ln a footnote, explain the basis of such occupancy and state wheher expenses with
respect to such structures are included in the expenses reported for the line designated.
Line
No.
L'ESIGNAI IUN VULIA(jE (KVI(lndicate wherdbther than
60 cvcte.3 ohase)
Type of
Supporting
Structure
(e)
LENti tH il-Ote milesl(ln the Case.ofunderoround lines
report 6rcuit miles)
Number
of
Circuits
(h)
From
(a)
To
(b)
Operating
(c)
Designed
(d)
of LineDesigrated
vlt ouuuluteSof AnotherLine
(s)
1 Brady Fremont 138.0 138.0(S P Wood 24.3i
King Lower Malad 138.0 138.0(I Wood 84.7',
Emmett Jct Payette 138.0 138.0({ Wood 66.4r
Mountain Home AFB Tao 138.0 138.0(I Wood 6.21
Ontario QuarE 138.0 138.0(I Wood 73.41
Kinq American Falls PP 138.0 138.0(S Tower 1.0'
King American Falls PP 138.0r 138,0({ Wood 't42.4
King American Falls PP 138.0 't38.0r 3 P Wood 3,7
Duffin 3lawson 138.0r 138.0C I Wood 6.2:,
1 American Falls 3rady Tie '138.0 138.0(I Wood 0.31
11 Uooer Salmon A-B (ng 138.0 138.0C I Wood 5.6(
1 Uooer Salmon B /[ells 138.01 138.0({ Wood 125.5!
1 Kins y1/ood River 138.0 138.0('l Wood 73.71
14 Boise Bench 3rove 138.0 138.0(i P Wood 10.51
1 Quartr John Day 138.0 138.0(l Wood 67.3:
1 Sinker Creek Tap t38.0r 138,0t { Wood 2.81
1i Mora 3loverdale 138.0 138.0(I Wood 2.5
1 Mora lloverdale 138.0 138.0(i P Wood 22.21
1 Mora Cloverdale 138.0 138.0t 3 P Steel 0.9(
2C Stoddard Jct Stoddard Sub 138.0 138.0t S P Steel 3.8r
21 Fossil Gulch Tap 138.0 '138.0t { Wood 1.9t
22 Wood River \4idpoint 138.0 138.0({ Wood 53.01
23 Wood River Midpoint 138.0 138.0(3 P Wood 16.61
24 Oxbow McCall 't38.0 138.0('{ Wood 37.1
2a Oxbow McCall 138.0 138.0(S P Wood 2,3i
2e Lowell Jct Nampa 't38.0 138.0(3 P Wood 7.5
27 Hunt Milner 138.0 138.0(S P Wood 19.4r
2t Strike Bruneau Bridqe 138.0 138.0(I Wood 13.5r
29 American Falls Kramer Sub 138.0 138.0(S P Wood 18,4r
3C Pingree Haven 138.0 138.0(S P Wood 11.7i I
31 Midpoint Twin Falls 138.0 138.0(S P Wood 25.2"
32 Twin Falls Russett 138.0 138,0(S P Wood 1,71 1
J.:Blackfoot Aiken 46.0 138.0(3 P Wood 6.1
34 Peterson Tendoy 69.0 138.0({ Wood 57.2:1
.E Eastgate Tap Eastgate 138.0 138.0(S P Wood 6.3t 1
36 TOTAL 4,779.31 11.01 190
FERC FORM NO.1 (ED.12-E7)Pase 422.2
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 6.1Rn Orisinal(2) 1-1A Resubmission
uate ot Keoon
(Mo, Da, Yi)
04t15t2014
YeailHenoo ol Kepon
End of 20131Q4
TRANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. lf 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 mlumn (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. lf 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 stiatement explaining the
anangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of @-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and ac@unts affected. Specifo 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. Specif, whether lessee is an associated company.
10. Base the plant cost figures called for in columns (i) to (l) on the book cost at end of year.
Size of
Conductor
and Material
(i)
uuS l uF LINE (lnquoe ln uolumn u, Lano,
Land rights, and clearing right-of-way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES
_tne
No.
Land
(i)
Construction and
Other Costs(k)
Total Cost
(t)
Operation
Expenses(m)
Maintenance
Expenses(n)
Rents
(o)
Total
Exne;ses
ARIOUS 1
ARIOUS 76,82i 2,300,94r 2,377,77i 2
ARIOUS 33,91r 2,736,64:2,770,561 3
97.5 ACSR 1,95r 6,93(8,88{4
ARIOUS 34,421 5,088,7'11 5,123,141 5
,I5.5 ACSR 2't6,91 8,549,03:8,765,95i 5
15,5 ACSR 7
15.5 ACSR 8
f\0 4,'t9'309,8s;314,04r I
)54 ACSR 96,92'96,92 10
I5() COPPER 2,74 121,99'124,73:1'l
/ARIOUS 28,49 3,062,13'3,090,62 12
/ARIOUS 173,68 3,826,17',3,999,86r 't3
/ARIOUS 225,60 1,652,77"1,878,37 14
197.5 ACSR 92,17 2,362,411 2,454,58!15
/ARIOUS 2t 77,191 77,21 16
'15.5 ACSR 3,123,381 8,203,10t 't1,326,48r 17
/ARIOUS 18
'95AAC 19
272 ACSR 20
I5O COPPER 451 187,84t 188,29r 2t
r97.5 ACSR 349,71 7,017,821 7,367,53r 22
197.5 ACSR 23
197.5 ACSR 109,89r 2.469,07!2,578,97r 24
r97.5 ACSR 25
1s.5 ACSR 2'.t1,13 1,448,291 1,659,42r 26
'15.5 ACSR 3,32,1,416,50:'t.419.821 27
r97.5 ACSR 't4,92 620,41"63s,331 28
"15.5 ACSR 13,73,1,051,321 1,065,051 29
r97.5 ACSR 18,22i 1,2U,241 1,302,46r 30
/ARIOUS 54,Mr 3,086,51'3,141,36(31
'15.5 ACSR 16,791 206,15{222,941 32
15.5 ACSR 13,61t 530,271 543,89(33
i97.5 ACSR 395,69t 3,449,97i 3,84s,66!34
r15.5 ACSR 343,95r 2jU,311 2,478,261 35
30,423,40(481,134,170 51 1,557,57(7,215,461 3,912,4s 18,173,77 29,301,631 36
FERC FORM NO.1 (ED.12-87)Page 423.2
Name of Respondent
ldaho Power Company
This ReDort ls:(1) 5]An orisinal(2) 1A Resubmission
Date of Report(Mo, Da, Y0
04t1512014
Year/Period of Report
End of 2013/Q4
TRANSMISSION LINE STATISTICS
1 . Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
5. lndicate 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 lf 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 (0 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). ln 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.
-rne
No.
DESIGNATION VULIAUE IAVT(lndicate wherdbther than
60 cvcle. 3 ohase)
Type of
Supporting
Structure
(e)
LENUtntFOtemilest(ln the base-ofunderoround Iinesreport Eircuit miles)
Number
of
Circuits
(h)
From
(a)
To
(b)
Operating
(c)
Designed
(d)
un5ofDesi
uclure.inenated
)
vIt oUucturesof AnotherLrne(s)
1 Kimberlv Tao (imberly 138.01 138.00 i P Steel 1.8t
2 Boise Benctt Vlora 138.01 '138.0c { Wood 13.'tr
Bowmont-Caldwell Simplot Sub 138.01 138.00 i P Wood 0.5'I
Gary Lane iagle 138.0t 138.00 i P Wood 6.3 1
Locust Grove 3lackcat Sub 138.0t 138.00 i P Steel 9.2t 2.9{
Boise Bench 3utler 138.0t 138.0C i PWood 0.1r 4.01 I
Eagle Star 138.0(138.00 i P Wood 6.3 1
Karcher Sub Zilos Tap 138.0t 138.00 i P Steel 3.6(I
Cloverdale - 712 712 - \ltlve ,l38.0r 't38.00 i P Steel 0.4:,4.0i,I
1 Mctory Jc{/ictory 138.0r 138.00 i P Steel 1.9(I
11 Butler Nye 138.0t 't38.00 i P Steel 2.91 1
Horseflat Sta*ey 138.01 138.00 I Wood 33.9i 1
1 Shrkey Vlccall 138.0t 138.00 i P Ste€l 2.01
,|Starkey Mccall 138.0t 138.00IH Wood 3.8(1
1 Starkey Vlccall 138.01 138.00 i P Sbd 1.5(
1 Starkey Vlccall 138.0r 138.00 i P Wood 17.6
1 Chestnut lappy Valley 138.0t 138.00 i P Steel 2.71 I
1 Gamet Ward 138.m
1 McCall Lake Fork 138.0t 138.00 i P Wood 8.8(1
2C McCall Lake Fork 138.0t '138.ffi1S Steel 2.9(
21 Caldwell Willis 138.0r 138.00 i P Sbel 't.3(1
22 Caldwell tl/illis 138.01 138.00 i P Sbd 1.s(1
23 Caldwell Wllis 138.01 138.00 i P Wood 0.8;I
24 Valivue Tao 138.0t 138.00 i P SEd 0.8(
2!Bowmont Happy Valley 138.01 138.00 i P Steel
2t Kinport Don #1 138.01 138.00 i Tower 1.3:
21 Donn HOKU 138.0t 138.00 i P Steel 2.7/1
2E HOKU Alamed 138.0 138.00 i P Steel 0.2i
29 HOKU Alamed 138.01 138.00 ] P Steel 0.2i
3C HOKU Alamed 138.01 138.00 i P Steel 2.8r
31 Rockland Jc-t Rockland \Mnd Farm 138.01 138.00 i P Steel 5.2!I
s/Kins Justice 138.01 138.00 i P Wood 0.1
aa Twin Falls PP Tap 138.01 138.00 { Wood 0.8,I
3A American Falls PP Amercian Falls Trans ST 138.01 138.00 i P Steel 0.3i ,|
2E Lower Salmon King Tie 138.01 138.00 { Wood 0.1 1
36 TOTAL 4179.31 11.02 190
FERC FORM NO. 1 (ED. 12-87)Page 422.3
Name of Respondent
ldaho Power Company
This Reoort ls:(1) E]An Original(2) ;--1A Resubmission
Date of Report(Mo, Da, Yr)
04115t2014
Year/Period of Report
End of 2O13lQ4
TRANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. lf 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. lf such property is leased fom 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, @-owner, or
other party is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns U) to (l) on the book cost at end of year.
Size of
Conductor
and Material
(i)
t/L.rD I Ur LlNtr (lnquoe ln lJolumn U, LanQ
Land rights, and clearing right-of-way)
EXPENSES. EXCEPT DEPRECIATION AND TAXES
-ine
No.
Land
0)
lonsfuction and
Other Costs(k)
Total Cost
(l)
Operation
Expenses(m)
Maintenance
Expenses
(n)
Rents
(o)
Total
Exo,e;ses
,95 ACSR 1
'15.5 ACSR 14,69 637,27i 651,97(2
'95MC 49,64i 49,64:3
'95MC 489,03:2.177,341 2,666,38t 4
272 ACSR 935,721 3,601,83r 4,537,55!5
272 ACSR 34,68;838,60r 873,291 5
'15.5 ACSR 179,81 3,047,20t 3,227,021 7
'95MC 43,031 434,341 477,371 I
272 ACSR 140,41 2,577,07!2,717,48i I
272 ACSR 10
'95 ACSR 134,47 1.405.431 1,539,90;11
'15.5 ACSR 2,473,83:,18,402,1'l 20,875,95i 12
1s.5 ACSR 13
15.5 ACSR 14
15,5 ACSR 15
'15,5 ACSR 16
t272 ACSR 78,57.1,821,92'1,900,501 17
40,58t 40,58r 18
15.5 ACSR 331,53!4,682,87r 5,014,41 19
20
272 ACSR 272,23'2,'.t41,211 2,413,441,21
'9s ACSR 22
'95 ACSR 23
'95 ACSR 427,761 427,76.24
272 ACSR 671,13r 671,13r 25
15.5 ACSR 1,17,212,77i 2'13,95'26
272 ACSR 19 39t 58r 27
272 ACSR 28
'95 ACSR 29
'95 ACSR 30
,95 ACSR -16,97 -16,97 31
590 ACSR 60,6s(60,65!32
I5O COPPER 5,63,26'63,32'33
'15.5 ACSR 76,56(76,56(34
197.5 ACSR 4,40t 4,40(35
30,423,40(481,134,170 511,557,57(7,215,461 3,912,45'18,173,721 29,30't,63r 36
FERC FORM NO. I (ED. r2-E7)Page 123.3
Name ot Kesponoent
ldaho Power Company
lnrs KeDon ls:(1) E]An Original(2) -A Resubmission
uate ot Repon
(Mo, Da, Yr)
o411512014
YeazHenoo ot Kepon
End of 2O'l3lQ4
TRANSMISSION LINE STATISTICS
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substration 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 whici plant costs are included in Account 121, Nonutility Property.
5. lndicate 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 lf a transmission line has more than one type of supporting structure, indicate he 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 (0 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 pardy owned structures in column (g). ln a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line
No.
UEsIL,NAIIUN vultAuE lNvt(lndicate wherdbther than
60 cvcle. 3 ohase)
Type of
Supporting
Structure
(e)
LENGTH (Pole miles)(ln the tase-ofunderoround linesreport Eircuit miles)
Number
of
Circuits
(h)
From
(a)
To
(b)
Operating
(c)
Designed
(d)DegJ
UCIl.TE
-inenated
r)
vt I ou uutulEsof AnotherLine
(g)
1 C J Strike Strike Jct 138.0 138.00 i Tower 4.3(
Strike Jc{Vlountain Home Jct 138.01 138.00 I Wood 23.4t 1
Strike Jct Bowmont 138.00 J Wood 0.0!1
Strike Jct Bowmont 138.01 138.00 i Tower 0.3(1
Skike Jct Bowmont 138.01 138.001H Wood 68.2 1
Luckv Peak Luckv Peak Jct 138.01 138,001H Wood 4.4t
Bliss (ng 138.0i 138.00lH Wood 10.4i
Milner Deadend Milner PP 138.0r 138.00 ; PWood 1.3(
Swan Falls Tap 138.0i 138,001H Wood 1.0(,|
1
11
12
1 Hines BPA(Hamey)115.0r 115.00 { Wood 3.3r 1
14
15
1€69 Kv Lines 69.01 69.001H Wood 167.0:1
,|69 Kv Lines 69.0r 69,0C i P Wood 938.2'
1€
1€
2C 46 Kv Lines 46.0i 46.0C i P Wood 408.8:
21
22 Total all lines 4,779.31 11.0:'t9(
23
24
2E
2e
27
2e
29
3C
31
32
33
34
35
36 TOTAL 4,779,31 11.02 190
FERC FORM NO. r (ED. 12-87)Page
Name of Respondent
ldaho Power Company
This Report Is:(1) []An Original(2) 51A Resubmission
Date of Reoort
(Mo, Da, Yi)
0411512014
YeaflHenoo or Kepon
End of 20131Q4
TRANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. lf 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. lf such properly 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 he operation of, furnish a succinct stiatement 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. Specifu whether lessor, @-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.
1 0. Base the plant cost figures called for in columns (D to (l) on the book cost at end of year.
Size of
Conductor
and Material
(i)
uus I ul- LlNtr (lnquoe rn uolumn u, Lano,
Land rights, and clearing right-of-way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES
-lne
No.
Land
(i)
Sonstruction and
Other Costs(k)
Total Cost
o
Operation
Expenses
(m)
Maintenance
Expenses
(n)
Rents
(o)
Total
Exo,e;ses
'15.5 ACSR 1.07,624,09t 625,171 1
i97.5 ACSR 4,35r 2,2%,211 2.300,57 2
'15.5 ACSR 86,65'2,027,141 2,113,791 3
,15.5 ACSR 4
5
15.5 ACSR 279,48'279,48t 6
15.5 ACSR 5,62(997,711 1,003,33r 7
15.5 ACSR 2,81,183,60(186,42r 8
r97.5 ACSR 12,88t 261,51 274,391 I
10
1',!
12
r97.5 ACSR 1,971 63,40'65,38:13
14
15
/ARIOUS 1,644,17i 56,843,38(58,487,5&16
/ARIOUS 17
18
19
/ARIOUS 194,53r 15,653,'t7;15,847,7li 20
7,215,46'3,912,451 2,917,52t 14,045,441 21
30,423,401 481,'134,171 51 1,557,57(7,215,46'3,912,451 2,917,52t 14,045,441 22
23
24
25
26
27
28
29
30
31
32
33
34
35
30,423.44 481JU,17(51 1,557,57(7,215,46'3,912,45 2,917,521 14,045,44r 36
FERC FORM NO.1 (ED.12-87)Page 423.4
Name of Respondent
ldaho Power Company
This Reoort Is:(1) 5]An orislnal(2) T-1A Resubmission
Date of Reoort(Mo, Da, Yi)
04t15t2014
Year/Periocl of Report
End of 20131Q4
TRANSMISSION LINES ADDED DURING YEAR
1. Report below the information called for concerning Transmission lines added or altered during the year. lt 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. lf actual
costs of competed construction are not readily available for reporting columns (l) to (o), it is permissible to report in these columns the
Line
No.
LINE UE5IUNAIIUN Length
tnMiles
(c)
sUI'I.'UK I INL' S I KUU I UKE UIKUUI I:i I-EK 5I KUU I UII
From
(a)
To
(b)
Type
(d)
Numbeiper
Miles
(e)
Present
(0
Ultimate
(s)
No lines were added in 2013
1
11
1
1
1
1t
1
1
,|
1
2(
2'
Z/
2i
2t
2t
2t
2i
2t
2l
3(
31
3:,
3i
3t
a,
3(
3i
3t
2(
4(
41
4i
4i
44 TOTAL
FERC FORM NO.1 (REV.12-03)Page
Name of Respondent
ldaho Power Company
This R(1) t(21 I
eDort ls:
1]An Original
1A Resubmission
uate ot Reoon
(Mo, Da, Yi)
04t15t2014
YearPenoo or Kepon
End of 20131Q4
-RANSMISSION LINES ADDED DURING YEAR (Continued)
costs. Designate, however, if estimated amounts are reported. lnclude 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. lf 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.
CONDUCT )RS Voltage
KV
(oo111tins)
LINE (]OSI Line
No.Size
rh)
Specification
(i)
Confiouration
and Spacing(i)
Land and
Land,Rights
Poles, Towers
and Fixtures(m)
Conductors
and Devices(n)
Asset
Retire. Costs(o)
Total
(o)
1
4
't(
11
12
1:
1
I
1
1
1
1
2(.
2'l
zt
2i
24
2!
2t
21
2t
2e
3C
31
J2
33
34
2E
3€
37
3t
2C
4C
41
42
4i,
44
FERC FORM NO. I (REV.12-03)Page 425
Name of Respondent
ldaho Power Company
Ihis Reoort ls:(1). BAn original(2) l-lA Resubmission
uate ot tteDon(Mo, Da, Yi)
0411512014
Year/Period of Report
End of 20131Q4
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. lndicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unaftended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
-tne
No.Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (ln MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 Adelaide transmission 345.0('138.0(13.8(
2 Aiken distribution 46.0(13.0(
3 Alameda distribution 46.0(13.0(
4 Nameda distribution 138.0(13.0(
5 American Falls PP - attended transmission 138.0(13.8(
6 American Falls transmission 't38.0(46.0(12.41
7 Artesian distribution 46.0(13.0(
8 Bannock Creek distribution 46.0(13.0(
I Bennett Mountain Power Plant- attended transmission 230.0(18.0(
10 Bennett Mountain Power Plant- attended distribution 18.0(4.1(.
11 Bethel Court distribution 't38.0(13.0(
12 Black Cat distribution 138.0(13.0(
13 BlacKoot distribution 46.0(13.0(
14 Blackfoot fansmission 16't.0(46.0(12.4t
15 Blackfoot diskibution 161.0(138.0(12.9t
16 Bliss - attended transmission r38.0(13.8(
't7 Blue Gulc*r disiribution 138.0(35.0(
18 Boise Bench - attended transmission 230.0(138.0(13.2(
19 Boise Bench - attended Cistribution 't38.0(35.0(
20 Boise Bench - attended transmission 138.0(69.0(12.9t
21 Boise Bench - attended transmission 230.0(138.0(13.8(
22 Boise Cistribution 138.0(13.0(
23 Borah transmission 345.0(230.0(13.8(
24 Bowmont Cistribution 69.0(46.0(6.9(
25 Bowmont Cistribution 138.0(35.0(
26 Bowmont transmission 138.0(69.00 12.91
27 Bowmont transmission 138.0(69.00 12.41
28 Bowmont transmission 230.0(138.00 13.8(
29 Brady Cistribution 46.0(13.00
30 Brady transmission 230.0(138.00 13.8(
31 Brady bansmission 138.0(46.00 12.41
32 Brady Cistribution 69.0(13.00
33 Brownlee - attended transmission 230.0(13.80
34 Bruneau Bridge Cishibution 138.0(35.00
35 Buckhom Cistribution 69.0(35.00
36 Bucyrus distribution 46.0(7.20
37 Buhl Cistribution 46.0(13.00
38 Burley Rural Cistribution 69.0(13.00
39 Bufler distribution 138.0(13.0€
40 Caldwell distribution 138.0(13.0C
FORM NO.1 (ED. 12-96)Page
Name of Respondent
ldaho Power Company (1) E(2') f
rort ls:
An Original
A Resubmission
uale ot Kepon
(Mo, Da, Yr)
04115t2014
YeailHenoo ot Kepon
End of 20131Q4
SUESTATIONS (Continued)
5. Show in columns (l), (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. Speciff in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation NUmoer or
Transformers
ln Service
Io)
NUmOer or
Spare
Transformers
/h)
CONVERSION APPAMTUS AND SPECIAL EQUIPMENT Line
No.(ln Service) (ln MVa)
tfl
Type of Equipment
/i)
Number of Units
(i)
Total Capacity
(ln MVa)/k!
30c
2C 2
15 1 3
18 t 4
72 1 5
25 1 6
10 ,|I
10 1 8
135 1 9
1 't0
1 11
2t 1 1Z
3(2 13
5(3 ,|14
8(1 15
6S 3 '16
1t 1 1t
254 2 18
42 19
7a 20
24C 21
67 22
45C .)1 23
,2 24
1€1 25
2a 1 26
2E I 27
18C 1 2A
4 29
312 30
1 31
1 32
721 1 33
30 34
20 1 35
6 1 1 36
2A 37
12 1 38
48 39
15 1 40
FERC FORM NO.1 (ED.12-96)Page 427
Name of Respondent
ldaho Power Company
I nts Keoon ts:(1) ffiRn Originat(2) l-l A Resubmission
Date of Reoort(Mo, Da, Yi)
o411512014
Year/Period of Report
End of 2013/Q4
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. lndicate 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).
_tne
No.- Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (ln MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
,|Caldwell transmission 230.0(138.00
2 Caldwell distribution 138.0(13.09
3 Caldwell transmission 't38.0(69.00 12.47
4 Caldwell transmission 230.0(138.00 12.47
5 Caldwell distribution 13.0(4.16
6 Canyon Creek distribution 138.0(35.00
7 Canyon Creek tsansmission 138.0(69.00 12.9e
8 Cascade Power Plant - attended transmission 69.0(4.60
o Cascade distribution 69.0(13.1(
10 Cascade distribution 25.0(
11 Cheshut distribution 138.0(13.0(
12 Clear Lake - attended transmission 46.0(2.4(
13 ctiff transmission 138.0(46.0(12.5(
14 ctiff transmission 138.0(46.0(12.9!
't5 Cloverdale distribution 138.0(13.0(
16 Dale distribution 46.0(4.6(
17 Dale distribution 46.0(13.0(
18 Dale distribution 69.0('13.0(
19 Dale distribution 138.0(36.2(
20 Dale transmission 138.0(46.0(12.4-t
2'l Danskin- attended transmission 230.0(18.0(
22 Danskin- attended transmission 230.0(138.0(13.8(
23 Danskin- attended Cistribution 18.0(4.1t
24 Danskin- attended kansmission 138.0(12.O(
25 Danskin- attended :listribution 35.0(13.8(
26 Don listribution 138.0(7.6(
27 Don iistribution 138.0(13.2(
28 Don Cistribution 138.0(13.0(
29 Don Cistribution 14.O(
30 DRAM distribution 138.0(13.0(
31 DRAM transmission 230.0(138.0(13.8(
32 DRAM distribution 138.0(12.41
33 Duffin distribution 138.0(35.0(
34 Eagle distribution 138.0(13.0(
35 Eastgate distribution 138.0(
36 Eastgate distribution 138.0(13.0(
37 Eckert distribution 138.0(36.2(
38 Eden distribution 138.0(36.2(
39 Eden transmission 138.0(46.0(12.9t
40 Elkhom distribution 138.0(12.41
FERG FORM NO. r (ED.12-96)Page 426.'l
Name of Respondent
ldaho Power Company
This ReDort ls:(1) []en originat(2\ [--lA Resubmission
Date of ReDort
(Mo, Da, Yi)
04t15t2014
YearHenoo ol Kepon
End of 2O13lQ4
SUBS'I ATIONS (Continued)
5. Show in columns (l), (j), and (k) special equipment such as rotary conve(ers, 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. Specifo in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(ln Service) (ln MVa)
Tfl
Number oi
Transformers
ln Service
(o'l
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.Type of Equipment
/i)
Number of Units
til
Total Capacity
(ln MVa)(k)
120 1 1
24 I 2
75 3
120 1 4
1 5
15 1 tl
1 7
1 1 E
1t 2 o
1 10
4E
I 12
1 1 13
4 1 14
4e 15
1 't6
€17
1 1U
21 1 19
25 1 20
140 1 21
180 1 22
1 23
9(2 24
1 25
1 26
10€27
2e 1 1 28
67 29
118 30
160 31
17 1 32
36 33
3t 34
2t 1 35
1 36
1 1 37
2t ,|38
1 1 39
1 40
FERC FORM NO. I (ED.12-96)Page 427.1
Name of Respondent
ldaho Power Company
tnls Ke(1) E(2) T
ON IS:
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
04115120'14
Year/Period of Report
End of 20131Q4
SUBSTATIONS
1 . Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3, Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. lndicate 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).
-ine
No.Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (ln MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 Elkhorn distribution 138.0(13.00
2 Elmore distribution 138.0(35.00
3 Elmore transmission 138.0(69.00 12.5C
4 Elmore transmission 138.0(69.00 12.98
5 Emmett distribution 138.0(
6 Emmetl hansmission 138.0(69.00 12.47
7 Falls distribution 46.0(13.00
8 Filer distribution 46.0(13.00
I Flat Top distribution 46.0(13.00 13.0(
10 Flying H distribution 69.0(2.40
11 Fort Hall diskibution 46.0(13.00
12 Fossil Gulch distribution 138.0(35.0(
13 Fremont transmission 138.0(46.0C 12.5t
14 Gary distribution 't38.0(13.0€
15 Gary distribution 138.0(13.0C
16 Gem distribution 69.0(13.0(
17 Gem distribution 69.0(
18 Goodng Rural distribution 46.0(13.0(
19 Golden Valley distribution 69.0(13.0(
20 Gowen Substration distribution 138.0(35.0(
21 Grindstone distribution 35.0(
22 Grove distribution 138.0(13.0!
23 Grove distribution 138.0(13.0(
24 Hagerman distribution 46.0(13.0(
25 Hagerman distribution 46.0(13.0(32.O(
26 Hailey distribution 138.0(13.00
27 Happy Valley distribution 138.0(13.09
28 Haven distribution 138.0(35.00
29 Haven transmission 138.0(46.00
30 transmission 500.0(230.00 34.5(
31 Hewlett Packard distribution 138.0(13.00
32 Hidden Springs distribution 138.0(13.00
33 Highland distribution 138.0(13.00
34 Hiil distribution 138.0(13.0C
35 Hillsdale distribution 138.0(
36 Hoku distribution 138.0(13.8C
37 Homedale distribution 69.0(13.0C
38 Horse Flat transmission 230.0(138.0t 13.8(
39 Horseshoe Bend Cistribution 35.0(
40 Horseshoe Bend Cistribution 69.0(36.2C
FERC FORM NO. I (ED. 12-96)Pase 426.2
Name of Respondent
ldaho Power Company
tntsl
(1)
(2)
eoon ts:
{Rn originat
lA Resubmission
Date of Report
(Mo, Da, Yr)
04115t2014
Year/Period of Report
End of 20131Q4
SUBSI ATIONS (Continued)
5. Show in columns (l), (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. Speciff in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of
Transformers
ln Service
(o)
NUmDer oI
Spare
Transformers
/h'l
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.(ln Service) (ln MVa)
{fl
Type of Equipment
fi)
Number of Units
(i)
Total Capacity
(ln MVa)(k)
8 1
17 1 2
1 1 3
I 4
2t 1 5
2!1 6
7
1 ,|6
I
1 2 10
1 1
I 1 12
5C 3 ,|13
2C 1 14
17 1 15
I 1 16
1C 1 17
4E 2 IE
1C 1 1 19
24 1 20
5 21
48 2 22
24 1 23
10 1 24
,|25
20 1 26
18 1 27
't2 1 26
2!1 29
60(30
2C 1 31
1 32
1 1 33
2C 2 34
24 1 35
36
22 2 37
100 ,|38
5 ,|39
12 1 40
FERC FORM NO. I (ED. 12.96)Page 427.2
Name of Respondent
ldaho Power Company
I nts xe(1) E(2\ T
on ls:
An Original
A Resubmission
Date of Reoort(Mo, Da, Yi)
04t15t2014
Year/Period of Report
End of 20131Q4
SUBSTATIONS
1. Report below the information called for conceming 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. lndicate 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).
-tne
No.Name and Location of Substation
(a)
Character of Subshtion
(b)
VOLTAGE (ln MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 Horseshoe Bend distribution 69.0(25.0(
2 Huston distribution 69.0(13.0(
3 Hulen distribution 46.0(13.0(
4 Hunt transmission 230.0(138.0(13.8(
5 Hydra distribution 138.0(36.2(
6 lsland distribution 69.0(13.0(
7 Jerome distribution 138.0(13.0(
8 Jerome distilbution 138.0(13.0S
I Julion Clawson distribution 138.0(35.0(
10 Joplin distribution 138.0(13.0(
11 Joplin distribution 138.0(35.0(
12 Justice transmission 230.0(138.0(13.8(
13 Karcher Cistribution 138.0(13.0(
14 Kenyon Cistribution 69.0(13.0(
15 Ketchum Cistribution 138.0(13.0(
16 Kimberly iistribution 138.0(13.0(
17 Kinport transmission 161.0(46.0(13.2(
18 Kinport hansmission 230.0(138.0(12.4-l
19 Kinport transmission 230.0(138.0(13.8C
20 Kinport hansmission 345.0(230.0(13.8(
21 Kramer Jistribution 138.0(35.0(
22 Kramer Cistribution 138.0(36.2(
23 Kuna Cistributlon 138.0(13.0(
24 Lake Cistribution 69.0(13.00
25 Lake Fork Cistribution 138.0(36.2(
26 Lake Fo*transmission 138.0(69.00 12.5C
27 Lamb iistribution 't38.0(13.0(
28 Langley Gulch- attended kansmission 230.0(138.0(13.8C
29 Langley Gulch- attended bansmission 230.0(
30 Langley Gulch- attended Cistribution 4.16
31 Langley Gulch- attended Cistibution 13.0(4.16
32 Lansing Cistribution 69.0(13.00
33 Lincoln Cisbibution 138.0(13.09
34 Linden Jistribution 138.0(13.00
35 Locust Cistribution 138.0(36.20
36 Locust fansmission 230.0(138.00 13.8C
37 Lower Malad - attended transmission 138.0(7.20
38 Lower Salmon - attended transmission 138.0(13.80
39 Map Rock distribution 69.0(13.00
40 McCall Cistribution 13.0(13.09
FERC FORM NO.1 (ED.12-96)Page 426.3
Name of Respondent
ldaho Power Company
tnts Ke(1) E(2) r
|on ts:
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
0411512014
Year/Period of Report
End of 20131Q4
SUBS'ATIONS (Continued)
5. Show in columns (l), (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. Speciff in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation NumDer ot
Transformers
ln Service
(o)
NUmDer oI
Spare
Transformers
(h)
CONVERSION APPAMTUS AND SPECIAL EQUIPMENT Line
No.(ln Service) (ln MVa)
(fl
Type of Equipment
(i)
Number of Units
(i)
Total Capacity
(ln MVa)(k)
5 1
10 1 2
10 1 3
300 4
48 5
1 1 6
2(7
2C 1 8
3(2 I
'tr 1 10
1 1
18(1 12
1 1 13
2C 2 14
42 15
1 1 l6
17
18C 1 1E
18C 1 1g
600 1 20
12 1 21
18 1 22
15 ,|23
10 1 24
18 1 25
15 1 26
18 1 27
't80 1 2E
24t 2 29
1 ,|30
1 I 3'l
1 1 32
1 I 33
J.:2 34
48 2 35
36C 2 36
't8 ,|37
70 4 38
10 1 39
12 't 40
FERC FORM NO.1 (ED. 12-96)
Name ot Kesponoenl
ldaho Power Company
tnts Keooft ts:(1) []Rn Orisinat(2) l-lA Resubmission
uate ot Keoon(Mo, Da, Yi)
0411512014
Year/Period of Report
End of 20131Q4
SUBSTATIONS
1 . Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. lndicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the pager summarize according to function the capacities reported forthe individual stations in
column (f).
-tne
No.Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (ln MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 McCall distribution 138.0(36.2C
2 Meridian distribution 138.0(13.0C
3 Micron distribution 138.0(13.0€
4 Micron distribution 't38.0(13.0C
5 Midpoint transmission 230.0(138.00 13.8C
6 Midpoint transmission 345.0(230.00 13.8(
7 Midpoint hansmission 500.0(345.0C
8 Midrose distribution 138.0(13.0S
9 Milner transmission 138.0(69.00 12.47
10 Milner distribution 6S.0(46.00 6.9C
11 Milner distribution 138.0(35.00
12 Milner PP - attended transmission 138.0(13.80
13 Moonstone distribution 138.0(35.00
't4 Mora distribution 138.0(35.00
15 Mora distribution 138.0(36.20
16 Moreland distribution 35.0(13.00
17 Moreland distribution 46.0(13.00
18 Moreland distribution 46.0(35.00 12.4i
19 Mountain Home distribution 69.0(13.00
20 Mountain Home Air Force Base distribution 69.0(13.00
21 Mountain Home Air Force Base distribution 138.0(13.00
22 Nampa transmission 230.0(138.00 13.8(
23 Nampa distribution 138.0(13.00
24 New Meadows distribution 138.0(36.20
25 New Plymoutr distribution 69.0(13.00
26 Notch Bufte distribution 138.0(13.09
27 Orchard distribution 69.0(36.20
28 Orchard distribution 69.0(35.00 12.4i
29 Parma Cistribution 69.0(13.00
30 Parma distribution 69.0(35.00
31 Paul Cistribution 138.0(35.00
32 Payette Cistribution 138.0(13.00
33 Pingree transmission 138.0(46.00 12.5(
34 Pingree Cistribution 138.0(35.00
35 Pleasant Valley Cistribution 138.0(35.00
36 Pocatello Cistribution 46.0('t3.00
37 Poleline Cistribution 138.0(13.0€
38 fansmission 345.0(
39 Porheuf Cistribution 138.0(35.0C
40 Portneuf Cistribution 46.0(35.0C
FERC FORM NO. r (ED. 12-96)Page 426.4
Name of Respondent
ldaho Power Company
I nts Keoon ts:(1) []nn orisinat(2) l-lA Resubmission
uate oI Repon
(Mo, Da, Yr)
04t't5t2014
YeaflHenoo or Kepon
End of 20131Q4
SUBSTATIONS (Continued)
5. Show in columns (l), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Speciff in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation NumDer oI
Transformers
ln Service
(o)
NUmDer or
Spare
Transformers
/h)
CONVERSION APPAMTUS AND SPECIAL EQUIPMENT Line
No.(ln Service) (ln MVa)
(fl
Type of Equipment
/i)
Number of Units
1i)
Total Capacity
(ln MVa)/kt
1 1 1
3€2
24 3
24 4
't2c 1 5
84C 1 6
750 1 7
24 1 I
100 4 I
8 1 10
29 2 11
36 1 12
12 13
1 'l 14
2t 1 15
1 16
1 17
3 1 18
1 1 19
I zo
1 1 21
't8c 1 22
5C 23
12 1 24
1 1 25
1C 1 26
1 2t
1C 28
1C 1 29
12 1 30
36 31
23 32
5C 33
22 34
42 35
36 36
18 1 37
3E
18 ,|39
1 40
FERC FORM NO.1 (ED.12-96)Page 427.4
Name ot Kesponoent
ldaho Power Company
tnts t(eoofi ts:(1) []en originat(2) l-lA Resubmission
Date of Report(Mo, Da, Yr)
0411s12014
Year/Period of Report
End of 20131Q4
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
-lne
No.Name and Location of Substiation
(a)
Character of Substation
(b)
VOLTAGE (ln MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 Rockford distribution 46.0(13.0C
2 Russeft distribution 138.0(13.0C
3 Sailor Creek distribution 138.0(2.4A
4 Sailor Creek distribution 138.0(35.0C
5 Salmon distribution 69.0(13.00
6 Salmon distribution 69.0(34.50 12.4-t
7 Salmon distribution 69.0(12.4i
I Salmon transmission 13.0(2.40
I Shoshone distribution 46.0(13.00
10 Shoshone distribution 46.0(7.24
11 Shoshone Falls - attended transmission 46.0(234
12 Shoshone Falls - attended transmission 46.0(6.60
13 Silver distribution 138.0(35.00
't4 Simplot distribution 138.0(13.00
15 Sinker Creek distribution 138.0(35.00
16 Siphon Cistribution 138.0(35.00
17 South Park Cistribution 46.0(13.00
18 Star distribution 138.0(13.09
19 Starkey transmission 138.0(69.00 12.4i
20 State distribution 69.0('t3.00
21 Stoddard distribution 138.0(13.00
22 Strike Power Plant - attended fansmission 138.0(13.80
23 Sugar distribution 138.0(3s.00
24 Swan Falls - aftended kansmission 138.0(6.90
25 Taber distribution 46.0(13.00
26 Ten Mile distribution 138.0(13.0S
27 Terry distribution 138.0(13.09
2A Terry distribution 138.0(13.00
29 Thousand Springs - attended bansmission 46.0(7.24
30 Thousand Springs - attended transmission 7.0(2.44
31 Toponis distribution 138.0(33.00
32 Twin Falls diskibution 138.0(13.0S
33 fwin Falls bansmission 138.0(46.00 12.9t
34 Twin Falls PP - aftended transmission 138.0(7.24
35 Iwin Falls PP - attended fansmission 138.0(13.24
36 Upper Malad - attended transmission 45.0(7.24
37 Upper Salmon- attended transmission 138.0(7.24
38 Ustick distribution 't38.0(13.00
39 Vallivue distribution 138.0(13.0S
40 Mctory distribution 138.0(13.00
FERC FORM NO.1 (ED. 12-96)Page 426.5
Name of Respondent
ldaho Power Company
I nts Keoort ts:(1) fiRn orlginat(2) llA Resubmission
Date of Reoort
(Mo, Da, Yi)
04115t2014
Year/Period of Report
End of 2O13lQ4
SUBS ATIONS (Continued)
5. Show in columns (l), (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 othenrvise 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. Speciff in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation NUmDer or
Transformers
ln Service
(o)
NUmOer or
Spare
Transformers
{h)
CONVERSION APPARATUS AND SPECIAL EOUIPMENT Line
No.(ln Service) (ln MVa)
(fl
Type of Equipment
/i)
Number of Units
{il
Total Capacity
(ln MVa)
{k)
14 2 1
18 1 2
15 2 3
15 ,|4
10 1 5
t0 3 6
2 7
2 8
1 1 I
3 10
1 11
1 1 12
12 1 13
3C 14
12 1 15
33 16
10 1 1l
18 1 18
18 1 19
33 2t)
15 1 21
8:22
2(23
1 1 24
1 25
2t 1 26
,|,|zl
3(28
1 29
1 30
1 I 31
44 2 32
J.:2 33
34
72 1 35
1 36
3€4 37
44 2 3E
18 I 39
24 1 40
FERC FORM NO.1 (ED. 12-96)Page 427.5
Name of Respondent
ldaho Power Company
I nts Keoort ts:(1) ffiRn originat(2) llA Resubmission
uate oI Keoon
(Mo, Da, Yi)
0411512014
YeaflFenoo or Kepon
End of 20131Q4
SUBSIATIONS
1. Report below the information called for conceming 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. lndicate 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).
-rne
No.Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (ln MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 Mctory distribution 138.0(13.0S
2 Ware distribution 69.0(13.0C
3 Weiser distribution 69.0(13.00
4 Weiser transmission 138.0(69.00 12.47
5 Wilder distribution 69.0(13.0C
6 Willis distribution 138.0(13.0S
7 tlfue distribution 138.0(13.00
8 \Afe distribution 138.0(13.0€
I Zilog distribution 138.0(13.0S
10
11
12 The above are all State of ldaho
13
14 Montana:
15 Peterson transmission 230.0(69.0C 13.2(
16
17 Nevada:
18 tmnsmission 345.0(125.0C 24.9C
19 transmission 345.0(125.0C 24.9C
20 transmission 120.0(24.9t 7.2t
21 transmission 345.0(
22 transmission 345.0(
23 transmission 345.0(
24 transmission 345.0(
25 transmission 345.0(
26 Wells transmission 138.0(69.0(13.0(
27
28 Oregon:
29 hansmission 500.0(24.O(
30 fansmission 230.0(7.2(.
31 transmission 24.0(7.2(
32 Cairo distribution 69.0(13.0(
33 Hells Canyon - attended transmission 230.0(13.8(
34 Hells Canyon - attended distribution 69.0(0.5(
35 Hines transmission 138.0(1'15.00 12.4i
36 Malheur Butte distribution 69.0(34.50
37 Nyssa distribution 69.0(13.00
38 Ontario distribution 13E.0(13.00
39 Ontario transmission 138.0(69.00 12.41
40 Ontario transmission 230.0('t38.00 13.8(
FERC FORM NO.1 (ED.12-96)Page 426.6
Name of Respondent
ldaho Power Company
tnrs Ke(1) E(2) T
on rs:
An Original
A Resubmission
Date of Report
(Mo, Da, Yr)
04t15t2014
Year/Period of Report
End of 20131Q4
SUBSI ATIONS (Continued)
5. Show in columns (l), 0), and (k) special equipment such as rotary converters, rectifiers, condensersr 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. Speciff in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Subshtion NumDer ol
Transformers
ln Service
(o)
NUmOer oI
Spare
Transformers
(ht
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.(ln Service) (ln MVa)
(fl
Type of Equipment
fi)
Number of Units
lit
Total Capacity
(ln MVa)(k)
18 I 1
12 1 1 2
2A 3
25 1 4
10 1 5
18 1 tt
3(2 7
2C 1 6
2t 1 I
10
12
13
14
3C 3 1 15
16
17
1 16
1 19
1 20
Line Reacto 4t 21
Line Reactor 3I 22
Line Reactor a,23
Line Reacto 2a 24
Line Reacto 3{25
2(1 26
27
28
68t 29
EI 1 30
ca 1 31
1 I 32
50(33
1 1 34
4(.1 35
1 36
2C 37
3t 38
2!1 1 39
24C 40
FERC FORM NO. r (ED. 12-e6)Page 427.6
Name of Respondent
ldaho Power Company
tnts KeDort ls:(1) ffiRn Originat(2) l-'l A Resubmission
Date of Report(Mo, Da, Yr)
04t1512014
Year/Period of Report
End of 2O13lQ4
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. lndicate 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 (fl.
-tne
No.Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (ln MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 Ontario transmission 138.0(69.0C 12.9t
2 Ontiario transmission 138.0(69.0C 13.0(
3 Ore-lda distribution 69.0(13.0C
4 Oxbow - attended transmission 138.0(69.0(13.0(
5 Oxbow - aftended transmission 230.0(r3.8C
6 Oxbow - attended transmission 230.0(138.0C 13.8(
7 QuarE bansmission 138.0(69.0C 12.5(
I QuarE transmission 230.0(138.0C 12.91
I Quarts transmission 138.0(69.0C 12.9t
10 Vale distribution 69.0(13.0C
11
12 Wyoming:
13 transmission 345.0(230.0c 34.5(
14
15
16
17
18
19 Transformersdishibution 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. I (ED. 12-96)Page 426.7
Name of Respondent
ldaho Power Company
I nts F(eDoft ts:(1) []An original(2) [-lA Resubmission
uate ot Reoon
(Mo, Da, Yi)
0411512014
YeaflPenoo ot Kepon
End of 20131Q4
SUBS ATIONS (Continued)
5. Show in columns (l), (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 othenvise 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. Specifo in each case whether lessor, co-owner, or other pafi is an associated company.
Capacity of Substation Number ol
Transformers
ln Service
(o)
NUmOer or
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.(ln Service) (ln MVa)
(fl
Type of Equipment
(i)
Number of Units
/i)
Total Capacity
(ln MVa)ft)
5(2 1
1 2
1 1 3
1
.)1 4
2M 5
100 1 6
15 1 7
100 ,|E
15 1 I
10 1 10
11
12
703 13
14
15
16
17
18
19
35€20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
3E
39
40
FERC FORM NO. r (ED.12-96)Page 127.7
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t15t2014
Year/Period of Report
20131Q4
FOOTNOTE DATA
PacifiCorp has a nterest in certain high-voltage transmission related andinterconnection e u.L nt located at Idaho Power's Hemingwav Station.
20.82 interest n certaj-n high-voltage transmission reIdaho Power has ainterconnection e
ated and
426.4 Line No.:38 Column: a
ioment l-ocated at PacifiCorprs ul-us station.
,JointIy owned with Sierra Pacific Power Company,a NV Energy. I Power
426.6 Line No.:18 Column: a
share of ownershi
Jointly owned with Sierra Pacific Power Company,d//a NV Energy. fdaho Power has a
426.6 Line No.: 19 Column: a
share of ownershi
Jointly owned with Sierra Pacific Power Company, d/b/a NV Energy. Idaho Power has a 508share of ownershi
Jointly owned wi-t erra Pac Power Company,NV Energy. Idaho Power has a 508
:426.6 Line No;20 Column: a
:426.6 Line No.:21 Column: a
share of ownersh
Jointly owned with erra Paci Power Company, d NV Energy.ho Power
426.6 Line No.: 22 Column: a
share of ownershi
Joj-ntly owned wi-th Sierra Pacific Power Company,NV Energy.Power
426.6 Line No.: 23 Column: a
share of ownershi
Jointly owned with S erra Pacific Power Company, d NV Energy. Idaho Power has a 508
426.6 Line No.: 24 Column: a
share of ownershi
Jointly owned with Sierra Pacific Power Company,Energy. I ho Power has a
426.6 Line No.: 25 Column: a
share of ownenshi
Jointly wi-th Portlan General Electric,
BCS, LLC. Idaho Power has a 108 share of the
Power
j ointly
Resources Cooperative
owned capacity. 1009
and BAof the
Leasi-ng
capaci-ty
:426.6 Line No.:29 Column: a
is reported.
Jointly owned with Portland
BCS, LLC. Idaho Power has a
General Electric,103 share of the
Resources Cooperative
owned capacity. 1008
Power
j oint Iy and BAof the
Leaslngcapacity
:426.6 Line No.:3O Column: a
is reoorted.
Jointly owned with Portland
BCS, LLC. Idaho Power has a
Genera ectric,
108 share of the
Power
j ointty Resources Cooperative BA Leasing
owned capacity. 1008 of the capacity
426.6 Line No.:31 Column: a
is reported.
Jointly owne wit Paci cCorp. Idaho Power has a 33.38 share of ownership.
426.7 Line No.: 13 Column: a
FERC FORM NO.1 1 450.1
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5]1an orisinat(2) nA Resubmission
Date of Reoort
(Mo, Da, Yi)
04115t2014
Year/Period of Report
End of 20131Q4
TRANSACTTONS WtrH ASSOCTATED (AFFTLIATED) COMPANTES
1. Report below the information called for conceming all non-power goods or services received ftom or provided to associated (affiliated) companies.
2. The reporting threshold for reporting purposes is $250,000. The threshold applies to the annual amount billed to the respondent or billed to
an associated/affiliated company for non-power goods and services. The good or service must be specific in nature. Respondents should not
attempt to include or aggregate amounts in a nonspecific category such as 'general",
3. Where amounts billed lo oireceived ftom the associated (affiliated) @mpany are based on an allocation process, explain in a footnote.
Line
No.Desoiption of the Non-Power Good or Service
(a)
Name of
Associated/Affiliated
Company
(b)
Account
Charged or
Credited
(c)
Amount
Charged or
Credited
(d)
2
3
4
5
o
7
8
I
10
11
12
13
14
15
'16
17
18
19
21 Managerial Expenses IDACORP,INC.41742C 578,132
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
FERC FORM NO.l (New)
FERC FORM NO. l-F (New)
Page 429
December 31, 2013
ANNUAL REPORT
IDAHO SUPPLEMENT TO FERC FORM 1
MULTI.STATE ELECTRIC GOMPANI ES
Page
Number
1
2
3
3
4
5
6
7-10
11
12-15
15
Title
Statement of lncome for the Year
Taxes Allocated to ldaho
Notes and Accounts Receivable
Accumulated Provision for Uncollectible Accounts
Receivables from Associated Companies
Gain or Loss on Disposition of Property
Professional or Consultative Services
Electric Plant in Service
Electric Operating Revenues
Electric Operation and Maintenance Expenses
Number of Electric Department Employees
IDA}IO SUPPLEi'ENT
STATE OF IDAHO . ALLOCATED
An Original December 31, 2013ldaho Power Company
STATEMENT OF INCOME FOR THE YEAR
1. Report amounts for accounts 412 and 413, Revenue and Expenses from Utility Plant Leased to Others, in another utility
column (i,k,m,o) in a similar manner to a utility department. Spread the amount(s) over lines 01 thru 24 as appropriate.
lnclude these amounts in columns (c) and (d) totals.
2. Report amounts in account 414, Other Utili$ Operating lnmme, in the same manner as ac@unts 412 and 413 above.
3. Report data for lines 7, 9, and 10 for Natural Gas companies using accounts 404.1, 404.2, 404.3, 4Ol .1, and 407.2.
4. Use page 1221or imporlant notes regarding the state ment of in@me or any account thereof.
5. Give concise explanations concerning unsetded rate proceedings where a contingency exists such that refunds of a
material amount may need to be made to he utility's customers or which may result in a material refund to the utility
with respect to power or gas purchases. State for each year affected the gross revenues or costs to which the contingency
relates and the tax effects together with an explanation of retain such revenues or re@ver amounts paid with respect
to power and gas purchases.
6. Give concise explanations conceming significant amounts of any refunds made or received during the year.
Line
No.
Account
(a)
(Ref.)
Page
No.
(b)
TOTAL
Cunent Year Previous Year
(c) (d)
1
2
3
4
5
6
7
8
9
't0
1'l
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
UTILITY OPERATING INCOME
Operating Revenues (400)........11
15
15
2
2
2
2
2
$ 1,185,097,499 s 1,024,679,001
Operating Expenses
675,538,535
64,415,077
1 16,783,035
7,248,578
308,258
28,374,334
'10,004,41 I
5,361,984
53,612,675
(742,193)
960,904,694
565,759,812
70,598,724
1 I 1,567,695
6,972,931
176,276
28,M6,377
(13,715,294:
971,298
37,421,156
8,684,'t57
816,883,'133
/r'nll
Dlqnt lnnA-Afi6\
Amort. of Utility Plant Acq. Adj. (406)........
Amort. of Properly Losses, Unrecovered Plant and
Aaaratian Evnanca /rl I 'l \
Paar rlafnnr Qtr rlrr frnctc /4O71
Aalla+aar l'lahi+c/I^rar{itc lA ', ',. t An', l\
Tawac Alhar Than lnaama Tavac /4OA I I
f1+har /.4nO
Provision for Defened lncome Taxes (410.1 & 411.1) Net
l^r,ac+66^+ f6v Fran{i+ Arli - trlat /1'l'l 1\
(Less) Gains from Disp. of Utility Plant (41 1.6)....
I aecac fram l'ticn nf I ltilih, plrnf /4'l'l 7l
nio^^aili^^ af Allmranaac /Il I al
I aceac frnm l\icaacilinn nf Allnunaae /1'l'l O\
TOTAL Utility Operating Expenses (Enter Total of lines 4 thru22).....
Net Utility Operating lncome (Enter Total of line 2 less 24)... .. . ... ... ..$ 224,192,804 $ 207,795,868
IDAHO SUPPLEMENT Page 1
STATE OF IDAHO - ALLOCATED
An Original December 31, 2013ldaho Power Company
TAXES ALLOCATED TO IDAHO
Kind of Tax
Taxes Other Than lncome Taxes:
Taxes Charged
Durino Year
Labor Related:F1cA........... $ 13,563,499FUTA.......... 88,340
State Unemployment.......956,129
Payroll Deduction & Loading.... (14,607,969)
Total Labor Related........ 0
Propefi Taxes.......... 24,856,888
Kilowatt-hour Tax...........
Licenses.....
1,125,510
4,533
Regulatory Commission Fees............ 2,176,398
211,059
Canada Sales Tax.... (54)
Total Taxes Other Than lncome Taxes........... 28,374,3U
Federal lncome Taxes.......... 10,004,411
State lncome Taxes....... 5,361,984
Deferred lncome Taxes.......... 53,612,675
lnvestment Tax Credit Adjustment - Net.......... (742,193)
TotalTaxes Allocated to ldaho.$ 96,611,212
IDAHO SUPPLEMENT Page 2
ldaho Power Company
STATE OF IDAHO
An Original December 31,2013
NOTES AND ACCOUNTS RECEIVABLE
Summary for Balance Sheet
Show separately by footnote the total amount of notes and acrcounts receivable
from directors, officers, and employees included in Notes Receivable (Account
141) and Other Accounts Receivable (Account 143)
Line
No.
Accounts
(a)
Balance
Beginning of
Year
(b)
Balance
End of
Year
(c)
1
2
3
4
5
b
7
8I
10
11
12
't3
14
15
16
17
18
19
20
$72,492
67,661,588
20,876,001
88,610,081
1,872,855
86,737,226
$
$
$s0,208
100,221,798
1 1,336,452
1 1 't,608,458
2,501,686
109,106,772
$
$
(lrrcinmer A^mrnis Fleneivahle (Aaarrln,t 142\
Other Accounts Receivable (Account 143)........................
(Disclose any capital stock subsoiption received)
Tnlal
Less: Accumulated Provision for Uncollectible
Accounts-Cr. (Account 1 44)..........
Total, Less Accumulated Provision for
Notes Receivable - Account 141: (at 12-31-13)
Directors, officers, and employees -
Other Accounts Receivable - Account 143: (at 12-31-13)
Directors, officers, and employees
ACCUMULATED PROVISION FOR UNCOLLECTIBLE ACCOUNTS - CR. (Account 144)
1. Report below the information called for conceming ftis accumulated provision.
2. Explain any important adjustnents of subaccounts.
3. Entries with respect to officers and employees shall not include items for utility services.
Line
No.
Item
(a)
Utility
Customers
(b)
Mdse,
Jobbing &
Contract
Work
(c)
Officers
and
Employees
(d)
Other
(e)
Total
(0
21
22
23
24
25
26
27
28
29
30
31
32
33
Bal. beginning ofyear
Prov. for uncollectibles
fnr rrcar
$ 1,872,855 $$$ 628,831 $ 2.501.686
Accounts written off........
Coll. of accounts
wriftan aff
Adjustments (explain)..........
Balance end of year..............$ 1,872,855 U u $ 628,631 $ 2.501.686
IOAHO SUPPLET'IENT Page 3
ldaho Power Gompany
STATE OF IDAHO
An Orlginal December 31,2013
RECEIVABLES FROM ASSOCIATED COMPANI ES (Accounts'1 45, 1 46)
1. Report particulars of notes and accounts reccivable from associated companies at end of year.
2. Provide separate headings and totals for a@ounts 145, Notes Receivable from Associated Companies, and 146,
Accounts Receivable from Associated Companies, in addition to a total for he combined accounE.
3. For notes receivable list each note separately and state purpose for whicfr received. Show also in column
(a) date of note, date of maturity and interest rate.
4. lt any note was received in satisfaction of an open account, state he period covered by such open account.
5. lndude in column (f) interest recorded as income during the year, including interest on accounts and notes
held at any time during the year.
6. Give particulars of any notes pledged or discounted, also of any collateral held as guarantee of payment
of any note or ac@unt.
Line
No.
Particulars
(a)
tsalan@
Beginning
of Year
(b)
Totals for Year Balance
End of Year
(e)
lnterest
For Year
(0
Debits
lc)
Credits
(d)
I
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
28
29
30
31
32
Account 145:
ItrOaa\$ 1,008,249 $ 24,651,093 $ 25,659,342 $
Total Account 145
Account 146:
IDACORP, |nc.....
Total Account 146.
1,008,249 24,651,093 25,659,342
$63,847 $ s,228,147 $ s,291,994 $
$ 63,847 $ 5.224.147 $ 5,291,994 ut
IDAHO SUPPLEMENT Page 4
STATE OF IDAHO. TOTAL SYSTEM DATA
cAlN OR LOSS ON DISPOSITION OF PROPERTY(Account421.1 and421.2l
1. Give a brief desoiption of property oeating the gain or loss. lnclude name of party acquiring the property (when
acquired by another utility or associated company) and the date tansaction was completed. ldentify property
by type; Leased, Held for Future Use, or Nonutility.
2. lndividual gains or losses relating to property with an original cost of less than $50,000 may be grouped, with the
number of such fansactions disclosed in column (a).
3. Give the date of Commission approval of journal enfies in column (b), when approval is required. \A/here approval
is required but has not been received, give explanation following he item in column (a). (See account 102, Utility
Plant Purchased or Sold.)
Line
No.
Desoiption of Property
(a)
ungrnar uosl
of Related
(b)
uate Joumal
Entry Approved
(\/vhen Required)
(c)
Acct421.'l
(d)
Acct421.2
(e)
1
2
3
4
5
6
7I
I
10
't'l
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
Gain on disposition of
property:
Water Management Facility
Water Management Facility
Charges incuned in 2013 related to
saledisposal of land anticipaed in 2014.
$ 1,950 $(250)
378
$ 1,950 $128
Hillsdale Substation
fotal loss....
$9,347 $ 1,917
$ 9,347 $ 1,917
ldaho Power Company
STATE OF IDAHO
An Orlginal December 31,2013
IDAHO SUPPLEITIENT Page 5
ldaho Power Company December 31, 2013
STATE OF IDAHO -TOTAL SYSTEM DATA
PROFESSIONAL OR CONSULTATIVE SERVICES . ITEMS $1O,OOO AND OVER
2
3
4
5
o
7
8I
10
11
12
13
14
15
16
17
18
19
20
2',1
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
REE TECHNOLOGIES AND SOLUTIO
BANDUCCI PLLC
JOHNSON &ASSOCIATES
BANDUCCI WOODARD SCHW
BARKER, ROSHOLT & SIMPSON LLP
FINANCIAL SOLUTIONS
SMITH JERNSTEDT WILSON
GROUP INC, THE
FORENSICS CORPORATION
TE OFFICE INSTALLATIONS
& R INTERNATIONAL, LTD
DAVIS WRIGHT TREMAINE LLP
DC ENGINEERING, PC
DELOITTE TAX LLP
ELAM AND BURKE PA
EMC CORPORATION
EVERGREEN CONSULTING GROUP, LL
EXPERIS IT SERVICES US, LLC
FRONTIER HISTOR]CAL CONSULTANT
& ASSOCIATES INC
ENBERG TRAURIG LLP
ELL ]NTERNATIONAL INC
INDUSTRIAL HYGIENE RESOURCES,
INTER-FLUVE, INC.
CORPOMTE SERVICES,INC
ENVIRONMENTAL INC
CONSULTING GROUP
AND SWARTZPLLC
SPARKMAN LLP
RACKNER & GIBSON PC
Energy Effi ciency Services
Energy Efficiency Services
LegalServices
LegalServices
Software Consultant Services
Equipment Services
Services
Management Services
LegalServices
LegalServices
Environmental Services
Environmental Services
Environmental Services
Environmental Services
Management Services
Environmential Services
LegalServices
LegalServices
Legal Services
LegalServices
't24,564
14,6',16
133,265
16,982
183,313
42,824
691,823
72,638
16,701
39,220
49,400
15,918
34,68't
51,845
12,070
75,000
232,846
20,772
11,342
109,019
1,562,172
17,745
54,016
14,195
54,000
179,037
151,506
19,905
153,900
96,550
31,186
11,251
41,672
398,088
94,924
159,551
11,861
34,000
47,025
35,248
33,325
10,942
1,158,111
IDAHO SUPPLEMENT
ldaho Power Company
STATE OF IDAHO
An Orlginal December 31,2013
STATE OF IDAHO. TOTAL SYSTEM DATA
PROFESSIONAL OR CONSULTATIVE SERVICES - ITEMS $1O,OOO AND OVER
ILLER & CHEVALIER CHARTERED
LSEN GROUP INC, THE
DYNAMICS CORPOMTION
HAMBLEN LLP
BROWN GEE & LOVELESS INC
TMINING SYSTEMS
BLUESHIELD OF IDAHO
ENERGY CONSULTING
ABE WILLIAMSON & WYATT
BUTLER LLP
TEPTOE & JOHNSON LLP
K BIG SOLUTIONS INC
KKER ENGINEERING INC
ENERGY SERVICES
CORPORATION FOR
UNIVERSIry OF ARIZONA
UNIVERSITY OF IDAHO
VAN NESS FELDMAN
ALDNER LAW OFFICES LLC
ATERSHED SCIENCES INC
YTURRI& ROSE& BURNHAM& BENTZ
Efficiency Services
ngineering Services
Seeding Modeling Services
eather Research & Forecast
36,439
40,516
199,038
71,155
133,039
16,082
360,000
22,214
11,246
333,738
60,867
47,698
18,514
236,470
96,635
185,545
163,200
13,736
143,356
51,480
14,720
55,239
94,430
245,077
37,284
399,907
284,695
12,587
49,338
39,727
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
81
82
83
84
85
86
87
IDAHO SUPPLE]TEI{T
ldaho Power Company
STATE OF IDAHO
An Orlginal December 31, 2013
Line
No.
PROFESSIONAL OR CONSULTATIVE SERVICES
ITEMS $5.OOO OR MORE BUT LESS THAN $1O.OOO
PAYEE
PREDOMINANTI NATURE OF SERVICE AMOUNT
I
2
3
4
5
o
7
8I
10
11
12
13
14
15
16
't7
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
40
41
42
43
44
Et trt{Ltr, E Et(LtN, l\r\uil\g, I Ur1NI \J
STEPHAN, KVANVIG, STONE & TRAI
CTAARCHITECTS
SUNRISE ENG]NEERING INC
GJORDING & FOUSER, PLLC
R R DONNELLEY
NEW YORK STOCK EXCHANGE I
HERITAGE ENVIRONMENTAL CONSUL
RIVERSIDE TECHNOLOGY INC
GALE CONTRACTOR SERVICES
JONES GLEDHILL FUHRMAN GOURLE\
TOWERS WATSON PENNSYLVANIA IN(
EVANS KEANE
AMERICAN ARBITMTION ASSOCIATI
Legar Dervrces
LegalServices
Architect Services
Engineering Services
LegalServices
Management Services
Management Services
Environmental Services
Management Services
Management Services
LegalServices
Management Services
LegalServices
Legal Services
o,uo'l
5,166
6,000
6,406
6,482
6,646
7,500
7,605
7,709
7,783
8,328
8,400
8,804
9,750
4b I(,IAL u ]ul ,o59
IDAHO SUPPLEMENT Page 68
STATE OF IDAHO - ALLOCATED
An Orlglnal Docember 31, 2013ldaho Power Company
IDAHO SUPPLEMENT
ELECTRIC PLANT lN SERVICE (Accounts 10'1, 102, 103 and 106) (Continued)
Show in column (f) reclassifications or transfers within utility plant accounts. lnclude also in column
(f) the additions or reductions of primary account classiflcations arising from distribution of amounts
initially recorded in Account 102. ln showing the clearance of Account 102, include in column (e) the
amounts with respect to accumulated provision for depreciation, acquisition adjustments, etc., and show
in column (0 only the offset to the debits or credits distributed in column (f) to primary account classifications.
For Account 399, state the nature and use of plant included in this account and if substantial in amount
submit a supplementary statement showing subaccount classification of such plant conforming to the
requirements of these pages.
For each amount comprising the reported balanco and changes in Account 102, state the properly purchased
or sold, name of vendor or purchaser, and date of transaction. lf proposed joumal entries have been filed
with the Commission as required by th€ Uniform System of Accounts, give also date of such filing.
l{euremenrs
(d)
AgJUStrnEnts
(e)
I ranslers
(f)
Eno or lear
(s)
Ltne
No.
$ 5,459
28,240,806
30,634,533
(301)
(302)
(303)
I
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
cd,oou, /vo
1 0,1 30,379
(310)
(311)
(312)
(31 3)
(314)
(315)
(316)
(31 7)
Y.ro,1oo,4du
(320)
(321)
(322)
(323)
(324\
(325)
(s26)
(s30)
(331)
(332)
(333)
(334)
(335)
(336)
(337)
/rU /,93i/.b5U
(340)
(341 )(u2)
(343)
(344)
(345)
(345)
STATE OF IDAHO - ALLOCATEO
An Origlnal December 31,2013ldaho Powor Company
IOAHO SUPPLEMENT
STATE OF IDAHO . ALLOCATED
An Orlginal December 31, 2013ldaho Power Company
ELECTRIC PLANT lN SERVICE (Accounts 101,102,103 and 106) (Continued)
No.
Account
(a)
9atatrug ct
Beginning of year
(b)
Additions
(c)
.+.+
456
47
,{8
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
81
82
83
84
85
86
87
88
89
90
91
92
93
94
95
96
(J.+O' MISC. rower rranl EqUrPmenI..,....,........
TOTAL Other Production Plant (Enter Total of lines 37 thru zt4).................
TOTAL Production Plant (Enter Total of lines 16, 25, 35, and 45)..............
3. TMNSMISSION PLANT
l35n\ | an.{ ,n.l I an.l Flidhte
U 5Z3.J14.UUU
z,126,I1U,ti14
34,144,330
67,313,466
350,618,551
't48,853,601
115,4f,0,123
177,042,541
374,559
/1521 StnrcJr
(356) Overhead Conductors and Devices.
/q47\ I lnd6mr6r rhd linndr rit
/?54\ I lnr{amrnr rnr{ Cnru{r rnlnrc and I)atrinac
'?5q\ El^..|c ^n.l Trrile
(359.1) Asset Retirement Costs for Transmission Plant...... ..- ,..... .
TOTAL Transmission Plant (Enter Total of lines zE thru 57).........
4. DISTRIBUTION PLANT
/tArll I anr{ an/ I anr{ Piahlc 4,640,1/t5
&,231,294
183,519,214
212,624,1',t5
1 15,863,070
rm,149,139
't94,586,898
433,676,693
53,989,312
68,386,405
2,636,2155
4,292,528
1A.' \ Srn
/1^rl Sl.ti6n tr
liAil Slaraaa B.ttetu Fdilihmenl
?AA\Onnr{,ril
[367) Underground Conductors and Devices
f?AAl I ine TmncIamarc
(369) Services....
1371) lnstallations on Customer Premises........ra72l I aaear{ ph6adr, ^h ar rcl^m.r pEmiqae
f3711 Streat I idhlind end Sidn.l Sr^lemq
1374) Asset Retirement Costs for Distribution Plant... .............
TOTAL Distribution Plant (Enter Total of lines 60 thru 74)......................
5. GENERAL PLANT
'?AQ\ lanri 2n.l l.n.{ Flidhtc
't,35U,595,2t 9
15,457,958
89,805,998
41,036,641
62,224,617
1,800,676
6,200,087
11,751,632
't 't,023,650
38,289,785
5,391,308
'3qnl Stnnhr.ae an.l lm6hvam.hl.
Cr^raa tr^' 'ihma^+'1Or'l T^^lc Sh^6 aar'l .:.E^a Fdr ri^manf
'llQ6l I rhaalaru Fnrrinmanl
'3OAl Powar Omelad For rinmanl
'398) Miscellaneous Equipment.
SUBTOTAL (Enter Total of lines 77 thru 86).....................
1399) Other Tangible Property.......
:399.1) Ass6t Retirement Costs for General P|ant................
TOTAL General Plant (Enter Total of lines 87, 88 and 89).........
TOTAL (Accounts I 01 and 1 06)....................
262,96:l,3C2
zdz,96z,Jaz
4, r1 J,OOO,U6U
.102) tsEctnc Plant Purchased
103) Experimental Plant Unclassified.
TOTAL Electric Plant in Service......$ 4,/lJ,UCt,,UUU
IDAHO SUPPLEMENT
STATE OF IDAHO - ALLOCATED
An Orlglnal December 31,2013ldaho Power Company
ELECTRIC PLANT lN SERVICE (Accounts 10'l,'102,103 and 106) (Continued)
Retirements
(d)
Adjustments
(e)
Transfers
(f)
Daranco at
End of Year
(s)
LITIE
No.
(J4b)
45
46
474
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
81
82
83u
85
85
87
88
89
90
91
92
93
94
95
96
U SJZ,JZU,CI+U
2,1 I O ,421 ,C6 I
34,555,676
67,099,513
372,391,668
155,126,938
1 23,601,400
180,079,653
373,698
(350)
(352)
(353)
(354)
(35s)
(356)
(357)
(358)
(3ss)
(359.1)
96;J,226,C4ti
4,724,O48
31,686,059
190,312,221
217,558,714
1 17,481 ,965
45,617,141
204,356,666
452,677,796
54,008,01s
70,590,833
2,672,425
4,341,934
(360)
(361)
(362)
(s63)
(364)
(365)
(366)
(367)
(368)
(36s)
(370)
(371)
(372)
(37s)
(3741
1.396.U2l,U1 /
15,871.405
98,541,128
39,1 50,924
64,833,977
1,827,216
6,889,490
11,913,052
'12,254,416
42,049,528
5,491,745
(38s)
(3so)
(se1)
(3e2)
(3e3)
(se4)
(3es)
(3s6)
(3s7)
(3s8)
'/96,622,46]
\ovY,
(39s.1)
/,96,6ZZdd'l
4,663,361,t :rU
I ruz,
(102)
(371)
o 4,uo.r,Jo],oJU
IDAHO SUPPLEMENT
STATE OF IDAHO. ALLOCATED
An Original December 31, 2013ldaho Power Company
ELECTRIC OPEMTING REVENUES (Account 400)
1. Report below operating revenues for each prescribed account, and manufactured gas revenues in total.
2. Report number of customers, columns (f) and (g), on the basis of meters, in addition to the number of flat rate
accountsi except that where separate meter readings are added for billing purposes, one customer should be counted
for each group of meters added. The average number of customers means the average of twelve figures at the close
of each month.
3. lf previous year (columns (c), (e) and (g), are not derived from previously reported figures, explain any
inconsistencies in a footnote.
No.
(a)
OPERATING REVENUES
Amount for
Cunent Year
(b)
Amount for
Previous Year
(c)
1
2
3
4
5
6
7
I
I
10
11
12
13
14
15
16
17
18
19
20
2'.|
22
23
24
25
26
Sales of Electricity
44Ol Flecidential Salas 494,516,617
419,209,O17
151,362,762
3,686,439
415,210,872
360,405,504
132,393,331
3,450.987
442) Commercial and lndustrial Sales
Small (or Commercial)(See lnstr. 4) (1 )........................
I ama lan lndr rclrialVQaa lncfr dl /2\
14441 Prrhlin Street and Fliohmv I iahfinn
445) Other Sales to Public Authorities..
t44Al Ralac ln Plilrnar{c and Qailrmve
(2148) I nterdepartm ential Sales
TfiTAI Qnlaa la I lltimata l^nncrrmarc 1,068,774,834
52,068,941
91 1,460,695
58,842,',t711447) Sales for Resale - Opportunity....Non-Firm On|y........
TOTAI Srlec af FlanJricitu 1.120,U3,776
(1 8,719,941 )
970,302,866
(17,787,033)(449) Provision for Rate Refunds..
TOTAL Revenue Net of Provision for Refunds...........
Other Operating Revenues
^ttRfl\ trnifailarl l'licmr rnla
1j02,123,834 952,s15,833
3,490,381
23,276,s87
56,206,697
3,556,088
22.113.462
46,493,618
d51 l Misenllaneorrs Scruim Re.vanr ras
y'.511 Salac nf Watar and lruafor P6mr
454) Rent from Electric Property...........
,6q\ lht6r.la^.rlma^l.l Ela^lc
IEAI f$har Flaafria Parranr
TOTAL Other Operating Revenues.82,973.665 72,163.168
TOTAL Electric Operating Revenues...$ 1,185,097,499 $ 1,024,679,001
('l) Commercial and lndustrial sales - Small - under 1 ,000 KW and includes all irrigation customers.
(2) Commercial and lndustrial sales - Large - 1,000 KW and over.
IDAHO SUPPLEMENT
Page 11
ELECTRIC OPEMTING REVENUES (Account 400) (Continued)
4. Commercial and lndustrial Sales, Account 442, may be classified 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 the Uniform System of Accounts. Explain
5. See page 108, lmporhnt Changes During Year, for important nanv 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 AVEMGE NUMBER OF CUSTOMERS PER MONTH
Line
No.
Amount for
Current Year
(d)
Amount for
Previous Year
(e)
Amount for
Cunent Year
(0
Number for
Previous Year
(s)
5,167,474,041
5,835,266,803
2,937,855,436
30,582,1 03
4,854,235,929
5,684,621,245
2,894,339,717
30,944,414
405,542
78,334
111
2,177
400,291
77,437
112
2,044
1
2
3
4
5
b
7
8
I
10
11
12
13
13,971,178,383 *
1,609,051,066
13,464,141,305
2,087,746,748
486,164
N/A
479,8U
N/A
15,580,229,449 15,551,888,053 486,164 479,884
' lncludes $10,453,848 unbilled revenues.
*'lncludes 36,693,381 K\A/H relating to unbilled revenues.
-ines 1 t hrough 21 arc on an "allocated" basis.
STATE OF IDAHO. ALLOCATED
An Original December 3'1, 2013ldaho Power Company
IDAHO SUPPLEMENT
Page lla
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
I tne amount tor prevrcus year rs not denved trom prevlously reponeo trgures, explarn rn lootnotes.
No.Account
(a)
Current Year
(D)
Previous Year
(c)
1 I. T'UWEK T'K(,UUUIIUN E I'ENsEU
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
28
29
30
31
32
33u
35
36
37
38
39
N
41
42
43
44
45
,{6
47
48
49
50
Operation
/5OO\ f)npralinn Srrncruician and Fnninaarina 1,460,2',17
't53,204,613
8,450,786
1,664,286
9,071,57'l
333,534
1,346,287
128,614,832
7,917,399
't,472,009
7,996,512
273,828
/6O'l \ Fr ral
15ll?l Slaam fmm Olhar Snr
ll
/5O51 FlarJric Fvnanqa<
/6641 Miceallanmrrc Slaam Pnmr F
/(n7\ El6nta
(509) Allo\ 6nces..
TOTAL Operation (Enter Total of lines 4 thru 12)......................
Maintenance
/5'lOl Mainfananca Sr rmruisinn anr{ Fnninmrina
1 /4r1UC,UU/14t,A22,6AI
97,305
610,766
1'.t,912,0'.12
5,160,756
4,348,643
318,0't9
728,455
12,0s4,'.t21
4,914,467
4,795,520(514) Miscellaneous Steam Planl
TOTAL Maintenance (Enter Total of Lines 15 thru 19)........
TOTAL Pouer Production Expenses-Steam Po,\rer (Enter Total of lines 13 and I
B. Nuclear Power Generation
Operation
/5171 Ometion Srrnaruisinn and Fnaincerino
24 tzu,qa t 22,41tJ,W2
'luo,J1r+,r+oo r ru,/tJJ,r+cu
ISlRl Frnl
151 Ol flmlantc and Walcr
Iq?fi\ araam trvrcncae
/q?al trl#iii^ FYnancac
Damr trvmncaa
TOTAL Operation (Enter Total of lines 24 thru 32)....................
Maintenance
/q?n\ M.ihlaarn.a ^f Ela.^l^r pl.nt Fdr ri^mahf
E,l.nl
(532) Maintenance of Miscellaneous Nuclear Plant...
TOTAL Po\iver Prcduction Expenses-Nuclear Pourer (Enter Total of lines 33 and
C. Hydraulic Povner Generation
Operation
f535) Ommtion Srrmruision anri Fnoineerino 5,777,960
5,438,310
12,996,334
't,371,316
4,649,652
135,586
7,136,805
7,4S6,203
12,203,305
1,319,589
2,528,231
315,959
f5?Al Watcr fnr Fmr
/(171 l-lwdarrlin Fvmn<ac
(540) Rents.
TOTAL Operation (Enter Total of lines rt4 thru 49).30,509,156 31,OUO,092
STATE OF IDAHO. ALLOCATED
An Orlglnal December 31, 2013ldaho Power Gompany
IDAHO SUPPLEMENT
Page 12
STATE OF IDAHO. ALLOCATED
An Original December 31,2013ldaho Power Company
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
It the amount tor prevrous year rs not denved trom prevrously reponed trgures, explarn rn tootnotes.
No.Account
(a)
Current Year
(D)
Previous Year
(c)
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
8'l
82
83
84
85
86
87
88
89
90
91
s2
93
94
95
96
97
98
99
100
101
102
103
C. Hydraulic Povver Generation (Continued)
Maintenance
(541) Maintenance Supervision and Engineering..
/6.d.?\ Maintanan^a ^f Sln r.i rree
80,247
1,366,715
1,099,550
2,504,756
2,878,O78
292,792
1,275,663
1,289,334
2,985,623
2,947,769
/EIa\ hiainraaaa^a ^{ Etaaa^r^i"c J'lamc and \Ar.laMVc
(545) Maintenance of Miscellaneous Hydraulic Plant.
TOTAL Maintenance (Enter Total of lines 53 thru 57)........
TOTAL Power Production Expenses-Hydraulic Power (Enter Total of lines 50 and
D. Other Power Generation
Operation
I,929,34lJ o,rv t, to I
36,296,503 39,t91,213
1,303, I 38
51,8't3,183
3,279,2',t5
560,834
0
1,288,599
23,822,329
2,O78,479
387,151
0
l4l'f\ fiol
(550) Rents.
TOTAL Operation (Enter Total of lines 62 thru 66).50,9CO,J/U z/,5/o,55U
Maintenance
15(ll Mainrananaa Qrrmruician and Fnainmrina 95
288,496
125,473
't,181,596
0
199,656
95,543
2,435.555
Qla rntr
Dlanl
554) Maintenanc€ of Miscellaneous Other Porrver Generation Plant...
TOTAL Maintenance (Enter Total of lines 69 thru 72).............
TOTAL Poriver Production Expenses-Other Power (Enter Total of lines 67 and 73.
E. Other Power Supply Expenses
,4q<\9amr
1,5UC,OOU z,t'JtJ,t53
5U,552,U30 30,50/,311
205,462,329
1,343,870
(37,062,415
182,310,250
2,159
(s8,406,670)
(556) System Control and Load Dispatching.
TOTAL Other Power Supply Expenses (Enter Total of lines 76 thru 78)................
TOTAL Porirer Production Expenses (Enter Total of lines 21, 41, 59, 74, and 79).
2. TRANSMISSION EXPENSES
Operation
/(All\
^mmrian
arrmarician and Fnainadna
10Y, r4J, r6J 'rz5,guc,/JY
40z,uru,w5 JO+,.|Jr, ' ' J
3,408,752
2,751,279
2,301,225
701,222
5,388,536
47,470
2,793,402
3,436,111
2,633,4't3
2,284,32s
632,645
6,019,037
168,613
2,881,111
/64?l Slrfinn Fvnaneac
/cAa\ 6rra?haa.l
/5A51 Trancmiccian a{ trlmtrieifv hw f)lharc
F
(567) Rents....
TOTAL Operation (Enter Total of lines 83 thru 90)..l r,JUl,OO'to,uJi,zSJ
Maintenance
/EAA\ lUainrananaa ar raanrician and Fnainorina 309,6s7
721,848
3,456,623
3,435,662
58'l
465,2s8
735,819
3,540,656
5,079,531
1,,t68
\ irlainlananaa af 6rradtaar{ I inac
573) Maintenance of Miscellaneous Transmission Plant.
TOTAL Maintenance (Enter Total of lines 93 thru 98)........
TOTAL Transmission Expenses (Enter Total of lines 91 and 99).............
3. DISTRIBUTION EXPENSES
Operation
(580) Operation Supervision and Engineering
I,924,3tZ J,OZZ\t OJ
z5,JlO,ZCU zr ,oot ,vot
3,980,894 3,942,246
IDAHO SUPPLEMENT
Page 13
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
It the amount tor prevEus year rs not denved lrom prevrously reponeo figures, explaln rn tootnotes.
No.Accounl
(a)
Curent Year
(D'
Previous Year
(c,
104
105
106
107
108
109
110
111
112
113
114
115
't 16
117
118
1't9
't20
121
122
123
124
125
't26
127
128
129
130
131
't32
133
'tu
135
't36
137
138
139
't40
141
142
143
't44
145
146
147
148
149
150
151
152
153
3. DISTRIBUTION EXPENSES (Continued)
3,385,71'l
1,329,950
2,883,020
2,366,316
70,930
4,267,367
620,736
5,505,368
350,339
3,411,958
1,120,001
3,510,192
1,841,055
104,460
3,984,472
590,81 1
s,381,804
472,O27
/4121 St:tian FYncncac
tr
/Fld'l I lndarararnd I ina F
/qnql Str.at I inhtinn and Sianal Srrelam Fvnancae
(588) Miscellaneous Distribution Expenses..........
TOTAL Operation (Enter Total of lines 103 thru 113)...........
Maintenance
z4,IAU,OJ-r zr+,Jcv,uzo
161,580
0
3,69',t,',t23
13,428,428
635,953
275,'.t99
51',t,473
724,350
380,365
214,565
0
3,696,105
14,418,3't7
1,030,138
406,160
541,867
699,899
4€7,673
(592) Maintenance of Station Equipment..
/EOtl tlainrananaa af hrraAaarl I iaaa
lS0ll Mainfanan.-a ^f I ln.{.rdhr rnd I inac
595) Maintenance of Line Transformers............
(OA\ 1tr'ihtan-n^6 ^f Qr66t I iahrina anrl Qianal
(598) Maintenance of Miscellaneous Distribution P|ant.................
TOTAL Maintenance (Enter Total of lines 1'16 thru 1241..................
TOTAL Distribution Expenses (Enter Total of lines 114 and 125)...........
4. CUSTOMER ACCOUNTS EXPENSES
Operation
lort{ \ Qr rnanriciaa
19,UUU,4/U z'1,494,t24
.+rl,loY,tu'l 45,653,750
469,738
1,312,575
1 3,547,108
5,486,585
258
420,669
1,185,721
12,704,355
4,2U,0@
392
fOO2l Meter Rcadino Frnancas
IOO?\ Crrelamar R+arde anrl llallmlinn Fvnaneac
lofill I lnaallaatihla Aaaarrntc
TOTAL Customer Accounts Expenses (Enter Total of lines 129 thru 133).............
5. CUSTOMER SERVICE ANO INFORMATIONAL EXPENSES
Cperation
zu,61l,,zoJ '16,c/+c,1r+J
5',t3,764
4',t,266,485
255,050
555,685
506,730
31,912,362
284,730
524,139
/OORI Cr rctnmcr Aecielannc Fvnan<cc
raliaaal trwnanaac
(91 0) Miscellaneous Customer Service and lnformational Expenses.........
TOTAL Cust. Service and lnformational Expenses (Enter Total of lines 137 thru I
6. SALES EXPENSES
Cperationfo'll\ Srrmruician
42,CgU,Y6r+55,t1t,VO1
i912) Demonstrating and Selling Expenses
i916) Miscellaneous Sales Expenses..
TOTAL Sales Expenses (Enter Total of lines 144 thru 147).
7. ADMINISTRATIVE AND GENERAL EXPENSES
Cperation
foAn\ Arlminictatno qad t?anar.l aalrriac 66,097,448
16,835,064
(25,698,427"
67,20',t,422
18,085,517
(26,962,038)
rO2ll Offiea Srrnnliae and Fxmnscs
iLess) (922) Administrative Expenses Transfened-Credit..
STATE OF IDAHO. ALLOCATED
An Origlnal December 31, 2013ldaho Power Company
IDAHO SUPPLEMENT
Page 14
ldaho Power Company
STATE OF IDAHO. ALLOCATED
An Original December 31,2013
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
It the amount tor prevrous year rs not denved trom prevrously reponed lrgures, explaln ln lootnotes.
No.Account
(a,
Current Year
(D)
Previous Year
(c)
't54
155
'156
'157
158
159
160
't61
162
163
164
't65
166
167
168
169
7. ADMINISTRATIVE AND GENEML EXPENSES (Continued)
$ 5,0s9,591
3,520,294
s,443,509
59,345,081
0
3.60'1.314
475,041
4,059,279
6,257
4,943,764
3,367,186
6,828,251
58,734,s33I
4,955,643
470,811
3,845,202
16,875
(928) Regulatory Commission Expenses..........
/O9O\ FL rnlinara llharaac-(1r
(931) Rents.......
TOTAL Operation (Enter Total of lines 151 thru 164)...........
Maintenance
(935) Maintenance of General P1an1.................
-t36,t24,1C1 l l,+ot, I
5,027,749 4,948,750
TOTAL Admin and General Expenses (EnterTotal of lines 16$167).........
TOTAL Elec Op and Maint Exp (Total of 80, 100, 126, 1U, 141, 148, 168).
14J,tC2,ZO1)1,ro,4JC,9Z4
$ /59,953,012 u o:ro,lrcu,5lro
IDAHO ONLY
NUMBER OF ELECTRIC DEPARTMENT EMPLOYEES
1. I ne oata on number ot emptoyees snould be reported tor the payroll penod endrng nearest to uctober Jl,
or any payroll penod endrng t u days Detore or atter uctoDer 31.
z. tt the respondent's payrol tor the repoftng penoo rnduoes any specral constructon personnel, rndude
such Empbyees on ttne J, and show the number ol such specEl oonstructpn employees rn a iootnote.
u. the numDer ot employees assrgnabl€ to the eEctnc depanment trom lornl tunctrons ol combrnatpn utlftes
may b€ determtned by estmate, on the Dasrs ot employee equrvalents. Show the estmated numDer ot equlv-
alent empbyees atnbuted to the electnc oepanmentrom Jolntrunct|ons.
1 Payroll Period Ended (Date)............... December31,2013l December31,2012
2 Total Regular Full-Time Employees....... 2,010 | 2,011
3 Total Part-Time and Temporary Employees........ 18 I 18
4 Total Employees........ 2,028 | 2,029
IDAHO SUPPLEiIENT
Page 15