2016Annual Report.pdf

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An TDACORP Company
LISA D. NORDSTROM
Lead Gounsel
I [e-mail]
Apnl 27,2017
Ms. Diane Hanian
Secretary
ldaho Public Utilities Commission
PO Box 83720
Boise, lD 83720-0074
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C-Re: ldaho Power Company's 2016 Annual FERC Form 1 Report ::
Dear Ms. Hanian:
Enclosed forfiling are two copies of ldaho PowerCompany's FERC Form 1 report and
ldaho supplement for the year ending December 31,2016. One bound and one unbound
copy are being provided as requested by the ldaho Public Utilities Commission. Also
included is the IDACORP 2016 Annual Report.
lf you have any questions, please contact Regulatory Analyst Kelley Noe at 208-
388-5736 or knoe@ida hooower.com.
Very truly yours,
X,^-L/0**^
Lisa D. Nordstrom
LDN:kkt
Enclosures
THIS FILING IS
Item 1: E An lnitial (Original)
Submission
OR E Resubmission No. _
Form 1 Approved
OMB No.1902-0021
(Expires 1213112019)
ri::iIi'i i:l] Form 1-FApproved
OMB No.1902-0029'r ij j,i:'i,, iB flli s, 5.]1expires 12t31t201s)
,, , i. , Form 3-Q Approved
I . , :' i'-;,' i;;;QMB No.1902-0205
(Expires 1213112019)
FERC FINANCIAL REPORT
FERC FORM No. 1: Annual Report of
Major Electric Utilities, Licensees
and Others and Supplemental
Form 3-Cl: Quarterly Financial Report
These reports are mandatory underthe Federal PowerAct, Sections 3, a(a), 304 and 309, and
18 CFR 141.1 and 141.400. Failure to report may result in criminal fines, civil penalties and
other sanctions as provided by law. The Federal Energy Regulatory Commission does not
consider these reports to be of confidential nature
Exact Legal Name of Respondent (Company)
ldaho Power Company
Year/Period of Report
End of 20161Q4
RC FORM No.1/3-Q (REv. 02-041
THIS FILING IS
Item 1: E An lnitial(Original)
Submission
OR E Resubmission No. _
Form 1 Approved
OMB No.1902-0021
(Expires 1213112019)
Form 1-F Approved
OMB No.1902-0029
(Expires 1213112019)
Form 3-Q Approved
OMB No.1902-0205
(Expires 'l2l31l2019l
FERC FINANCIAL REPORT
FERC FORM No. {: Annual Report of
Major Electric Utilities, Licensees
and Others and Supplemental
Form 3-Q: Quarterly Financial Report
These r€ports are mandatory under the Federal Power Act, Sections 3, (a), 304 and 309, and
18 CFR 141.1 and 14'1.40O. Failure to report may result in criminal fines, civil penalties and
other sanctions as provided by law. The Federal Energy Regulatory Commission does not
consider hese reports to be of confidential nature
Exact Legal Name of Respondent (Company)
ldaho Power Company
Year/Period of Report
End of 20161Q4
FERC FORM No.l/&Q (REv.02-04)
Deloitte.O€loltt lTouchc LLP
80O Wast Main Strrct
SuitG 1400
Boisc. ID A3702-7734
USA
Tel: +l 208 342 9361
www.dcloitte.com
INDEPENDENT AUDITORS' REPORT
Idaho Power Company
Boise, Idaho
We have audited the accompanying financial statements of Idaho Power Company (the
"Company"), which comprise the balance sheet-regulatory basis as of December 31, 2016,
and the related statements of income-regulatory basis, retained earnings-regulatory
basis, and cash flows-regulatory basis forthe yearthen ended, included on pages 110
through t23 of the accompanying Federal Energy Regulatory Commission Form 1, and the
related notes to the financial statements.
Management's Rcsponsibility for thc Financial Statements
Management is responsible for the preparation and fair presentation of these financial
statements in accordance with the accounting requirements of the Federal Energy
Regulatory Commission as set forth in its applicable Uniform System of Accounts and
published accounting releases; this includes the design, implementation, and maintenance
of internal control relevant to the preparation and fair presentation of financial statements
that are free from material misstatement, whether due to fraud or error.
Auditors' Responsibility
Our responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audlt in accordance wlth auditing standards generally accepted in the
United States of America. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free from material
misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and
disclosures in the financial statements. The procedures selected depend on the auditor's
judgment, including the assessment of the risks of material misstatement of the flnancial
statements, whether due to fraud or error. In making those risk assessments, the auditor
considers internal control relevant to the Company's preparation and fair presentation of the
financial statements in order to design audit procedures that are appropriate in the
circumstances, but not for the purpose of expressing an opinion on the effectiveness of the
Company's internal control. Accordingly, we express no such opinion. An audit also includes
evaluating the appropriateness of accounting policies used and the reasonableness of
significant accounting estimates made by management, as well as evaluating the overall
presentation of the financial statements.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide
a basis for our audit opinion.
Opinion
In our opinion, the regulatory-basis financial statements referred to above present fairly, in
all material respects, the assets, liabilities, and proprietary capital of Idaho Power Company
as of December 31, 2016, and the results of its operations and its cash flows for the year
then ended in accordance with the accounting requirements of the Federal Energy
Regulatory Commission as set forth in its applicable Uniform System of Accounts and
published accounting releases.
Basis of Accounting
We draw attention to Note 1 of the financial statements, which describes the basis of
accounting. The financial statements are prepared in accordance with the accounting
requirements of the Federal Energy Regulatory Commission as set forth ln its applicable
Uniform System of Accounts and published accounting releases, which is a basis of
accounting other than accounting principles generally accepted in the United States of
America. Our opinion is not modified with respect to this matter.
Restrlctlon on Use
Our 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 speclfled
pafties.
&"^1.W. td"e$l.lJ-P
April L4,2OL7
-2-
FERC FORM NO. 1/3.Q:
IDENTIFICATION
01 Exact Legal Name of Respondent
ldaho Power Company
02 Y ear I P eriod of Report
End of 20161Q4
03 Previous Name and Date of Change (if name changed during year)tt
04 Address of Principal Office at End of Period (Street, City, State, Zip 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
08 Telephone of Contact Person,lncluding
Area Code
[phone]
09 This Report ls
(1) [ An Original (2) a A Resubmission
10 Date of Report
(Mo, Da, Y)
04t14t2017
ANNUAL CORPORATE OFFICER CERTIFICATION
The undersigned officer certifies that:
I have examined this report and to the best of my knowledge, information, and belief all stiatements of fact contained in this report are correct statements
of the business affairs of the respondent and the financial statements, and other financial information contained in this report, conform in all material
respects to the Uniform System of Accounts.
01 Name
Ken Petersen
02 Title
Vice President, Controller & CAO
03 Signature
Ken Petersen 0411412017
04 Date Signed
(Mo, Da, Yr)
Title 18, U.S.C. 1001 makes it a crime for any person to knowingly and willingly to make to any Agency or Department of the United States any
false, fictitious or fraudulent statements as to any matter within its jurisdiction.
FERC FORM No.1/3-Q (REV. 02-041 Page 1
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5]Rn orisinat(2) nA Resubmission
Date of Report(Mo, Da, Yr)
04t14t2017
Year/Period of Report
End of 20161Q4
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)
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 I 08-1 09
I Comparative Balance Sheet 110-113
I Statement of lncome for the Year 't14-117
10 Statement of Retained Earnings for the Year 118-119
11 Statement of Cash Flows 120-121
12 Notes to Financial Stiatements 122-123
13 Statement of Accum Comp lncome, Comp lncome, and Hedging Activities 122(a)(b\
14 Summary of Utility Plant & Accumulated Provisions for Dep, Amort & Dep 200-201
15 Nuclear Fuel Materials 202-203 N/A
16 Electric Plant in Service 204-207
17 Electric Plant Leased to Others 213 N/A
18 Electric Plant Held for Future Use 214
19 Construction Work in Progress-Electric 216
20 Accumulated Provision for Depreciation of Electric Utility Plant 219
21 lnvestment of Subsidiary Companies 224-225
22 Materials and Supplies 227
23 Allowances 228(ab)-229(ab\N/A
24 Extraordinary Property Losses 230 N/A
25 Unrecovered Plant and Regulatory Study Costs 230 N/A
26 Transmission Service and Generation lnterconnection Study Costs 231
27 Other Regulatory Assets 232
28 Miscellaneous Defened Debits 233
29 Accumulated Deferred lncome Taxes 234
30 Capital Stock 250-251
31 Other Paid-in Capital 253
32 Capital Stock Expense 254
33 Long-Term Debt 256-257
34 Reconciliation of Reported Net lncome with Taxable lnc for Fed lnc Tax 261
35 Taxes Accrued, Prepaid and Charged During the Year 262-263
36 Accumulated Deferred lnvestment Tax Credits 266-267
FERC FORM NO.1 (ED.12-96)Page 2
Name of Respondent
Idaho Power Company
This Reoort ls:(1) 5]An orisinat(2) TIA Resubmission
Date of Report(Mo, Da, Yr)
04t14t2017
Year/Period of Report
End of 2016tQ4
Enter in column (c) the terms "none,' "not applicable," or "NA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
Line
No.
Title of Schedule
(a)
Reference
Page No.
(b)
Remarks
(c)
37 Other Deferred Credits 269
38 Accum ulated Deferred I ncom e Taxes-Accelerated Amortization Property 272-273 N/A
39 Accum ulated Deferred I ncom e Taxes-Other Property 274-275
40 Accumulated Deferred I ncome Taxes-Other 276-277
41 Other Regulatory Liabilities 278
42 Electric 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 3'10-3't1
46 Electric Operation and Maintenance Expenses 320-323
47 Purchased Power 326-327
48 Transmission of Electricity for Others 328-330
49 Transmission of Electricity by ISO/RTOs 331 N/A
50 Transmission of Electricity by Others 332
51 Miscellaneous General Expenses-Electric 335
52 Depreciation and Amortization of Electric Plant 336-337
53 Regulatory Commission Expenses 350-351
54 Research, Development and Demonstration Activities 352-353
55 Distribution of Salaries and Wages 354-355
56 Common Utility Plant and Expenses 356 N/A
57 Amounts included in ISO/RTO Settlement Statements 397 N/A
58 Purchase and Sale of Ancillary Services 398
59 Monthly Transmission System Peak Load 400
60 Monthly ISO/RTO Transmission System Peak Load 400a N/A
61 Electric Energy Account 401
62 Monthly Peaks and Ouput 401
63 Steam Electric Generating Plant Statistics 402-403
64 Hydroelectric Generating Plant Statislcs 406-407
65 Pumped Storage Generating Plant Statistics 408-409 N/A
66 Generating Plant Statistics Pages 410-411
FERC FORM NO.1 (ED. 12-96)Page 3
Name of Respondent
ldaho Power Company
This Reoort ls:(1) []An orisinal(2) l--.1A Resubmission
Date of Report
(Mo, Da, Yr)
04t14t2017
Year/Period of Report
End of 20161Q4
Enter in column (c) the terms "none," 'not applicable," or'NA,n 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:
! Two copies will be submitted
E tto annual report to stockholders is prepared
FERC FORM NO.1 (ED.12-96)Page 4
Name of Respondent
ldaho Power Company
This Report ls:
(1) tr An Original
(2) tr A Resubmission
Date of Report
(Mo, Da, Y)
04t't4t2017
Year/Period of Report
End of 2o16tQ4
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.
I(en Petersen vice Presiden!, Controller and CAO, Idaho Power CoEpany
L227. 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.
Idaho, June 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 Applic.b]-e
4. State the classes or utility and other services furnished by respondent during the year in each State in which
the respondent operated.
Class of Uti].ity service
E].6ctric
Electric
State
Idaho
Oregon
5. Have you engaged as the principal accountant to audit your financial statements an accountant who is not
the principal accountant for your previous year's certified financial statements?
(1) tr Yes...Enter the date when such independent accountant was initially engaged
(2) E No
FERC FORM No.1 (ED. 12-87)PAGE 101
Name of Respondent
ldaho Power Company
This Report ls:
(1) tr An Original
(2) tr A Resubmission
Date of Report
(Mo, Da, Yr)
04114t2017
Year/Period of Report
End of 2o16tQ4
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
wtrich 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 utilig Holding Company incorporated effective 10-1-1998
FERC FORM NO. 1 (ED. 12-96)Page 1O2
Name of Respondent
ldaho Power Company
This Reoort ls:(1) []An original(2) n A Resubmission
Date of Report(Mo, Da, Yr)
04t1412017
Year/Period of Report
End of 20161Q4
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 Resources Company Coal mining and mineral 1O0o/o
3 development
4
5
6
7
8
I
10
11
12
't3
14
15
16
17
18
19
20
21
22
23
24
25
26
27
FERC FORM NO.1 (ED.12-96)Page 103
Name of Respondent
ldaho Power Company
This Report ls:(1) ffiAn Original(2) ;-1A Resubmission
Date of Report
(Mo, Da, Yr)
0411412017
Year/Period of Report
End of 20161Q4
OFFICERS
1. Report below the name, title and salary for each executive officer whose salary is $50,000 or more. An "executive officer" of a
respondent includes its president, secretary, treasurer, and vice president in charge of a principal business unit, division orfunction
(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.
Line
No.(a)
Name ol otttcer
(b)
salarvfor Yedr(c)
,|
2 President & Chief Executive Officer Darrel T. Anderson 750,000
3
4 Executive Vice President Dan Minor (1)245,923
5
b Senior Vice President Rex Blackbum (2)360,000
7
8 Senior Vice Presidenl, CFO & Treasurer Steven Keen 380,000
I
't0 Senior Vice President, Operations Lisa Grow 360,000
11
12 Senior Vice President, Public Affairs Jeffrey Malmen 285,000
13
14 Vice President, Customer Operations Vem Porter 285,000
15
16 Senior Vice President, Human Resources, Admin Services Lonnie Krawl 275,000
17
18 Vice President & Chief Risk fficer Lori Smith (3)70,846
19
20 Vice President, Corporate Controller & CAO Ken Petersen 245,000
2'l
22 Vice President of Regulatory Affairs Gregory Said (4)81,904
23
24 Coryorate Secretary Patrick Harrington 195,000
25
26 Vice President, Power Supply Tessia Park 220,000
27
28 Vice President & General Counsel Brian Buckham 230,000
29
30 Vice President of lnformation Technology & CIO Jeff Glenn 210,000
31
32 Vice President of Regulatory Affairs Tim Tatum 170,000
33
34 ('l)Retirement effective 06/30/16. Salary shows YTD wages
35 (2)Retirement effective 12131116. Salary shows YTD wages
36 (3)Retirement effective 03/31/16. Salary shows YTD wages
37 (4)Retirement effective 04/30/16. Salary shows YTD wages
38
39
40
41
42
43
44
FERC FORM NO. 1 (ED. 12-96)Page 101
Name of Respondent
ldaho Power Company
This(1)
(2)
Report ls:
EAn Original
[lA Resubmission
Date of Report(Mo, Da, Yr)
04t14120't7
Year/Period of
End of
Report
2016/04
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
titles of the directorc 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.
LIIIE
No.Name (and I rtle) ol urrector Pfl ncrpar o,tcl".. Adoress
I
2 Judith A. Johansen 10446 E. Palo Brea Dr., Scottsdale, Arizona85262
3
4 Christine King**.8527 East Old Field Rd
5 Scottsdale, Arizona 85266
6
7 Thomas Carlile 2719 North Woodview place, Boise ldaho 83702
8
o Darrel T. Anderson President & CEO, '. *.ldaho Power Company, 1221 W. ldaho Street,
10 P.O. Box 70, Boise, ldaho 83707-0070
11
12 J. LaMont Keen 481 North Strata Via Way, Boise ldaho 83712
13
14 Robert A. Tinstman ***4433 W. Quail Point Court, Boise, ldaho 83703
15
16 Richard Dahl *..60 Laiki Pl
17 Kailua, Hawaill 96734
18
19 Dennis L. Johnson United Heritage Life lnsurance
20 926 W Oakhampton Dr, Eagle, ldaho 83616
21
22 Ronald W. Jibson Questar Corporation
23 417 Aerie Circle, North Salt Lake City, Utah 84054
24
25 Richard J. Navano '1256 E. Candleridge Ct., Boise, ldaho 83712
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
FERC FORM NO. 1 (ED. 12.95)Page 105
Name of Respondent
ldaho Power Company
This Reoort ls:(1)E An original
(2) [-1 A Resubmission
Date of ReDort(Mo, Da, Yi)
04t1412017
Year/Period of Report
En6 61 2016/Q4
INFORMATION ON FORMULA RATES
FERC Rate Schedule/Tariff Number FERC Proceeding
Does the respondent have formula rates?I 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
I
9
10
't1
12
13
14
15
16
17
18
19
20
2'.!
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
FERC FORM NO.1 (NEW.12-0E)Page 106
Name of Respondent
ldaho Power Company
This Reoort ls:(1)E An Original
(2) [-1 A Resubmission
Date of Report(Mo, Da, Yr)
0411412017
Year/Period of Report
gn6 61 2016/Q4
INFORMATION ON FORMULA RATES
FERC Rate Schedule/Tariff Number FERC Proceeding
Does the respondent file with the Commission annual (or more frequent)
filings containing the inputs to the formula rate(s)?I Yes
ENo
2. If yes, provide a listing of such filings as contained on the Commission's elibrary website
Line
No.Accession No.
Document
Date
\ Filed Date Docket No.Desoiption
Formula Rate FERC Rate
Schedule Number or
Tariff Number
1 201 608295362 08t29t2016 ER-09-1641-000 ldaho Power Compan'FERC Electric Tariff
2 2016 Annua
3 lnformational Fillinl
4 under ER-09-1641-00(
5
6
7
8
9
10
11
't2
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
I I
FERC FORM NO.1 (NEW.12-08)Page 106a
Name of Respondent
ldaho Power Company
This Reoort ls:(1)E An Original
(2) Tl A Resubmission
Date ot Report
(Mo, Da, Yr)
04t14t2017
Year/Period of Report
En6 61 20'16/Q4
INFORMATION ON FORMULA RATES
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 the Form 1.
2. The footnote should provide a narrative description explaining how the "rate" (or billing) was derived if different from the reported amount in the
Form 1.
3. The footnote should explain amounts excluded from the ratebase or where labor or other allocation factors, operating expenses, or other items
impacting formula rate inputs differ from amounts reported in Form 1 schedule amounts.
4. Where the Commission has provided guidance on formula rate inputs, the specific proceeding should be noted in the footnote.
Line
No.Page No(s).Schedule Column Line No
1
2
3
4
5
6
7
8
I
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
FERC FORM NO.1 (NEW.12-08)Page 106b
Name of Respondent
ldaho Power Company
lhrs l{eport ls:
Etr
(1)
(2)
An Original
A Resubmission
uate ot Report
0411412017
Year/Penod of l-(epon
End of 20161Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR
Give particulars (details) concerning the matters indicated below. Make the statements explicit and precise, and number them in
accordance with the inquiries. Each inquiry should be answered. Enter "none," "not applicable," or "NA" where applicable. 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, merger, or consolidation with other companies: Give names of
companies involved, particulars concerning the transactions, name of the Commission authorizing the transaction, and reference to
Commission authorization.
3. Purchase or sale of an operating unit or system: Give a brief description of the property, and of the transactions relating thereto,
and reference to Commission authorization, if any was required. Give date journal entries called for by the Uniform System of Accounts
were submitted to the Commission.
4. lmportantleaseholds(otherthanleaseholdsfornatural gaslands)thathavebeenacquiredorgiven,assignedorsurrendered: 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 territory added or relinquished and date operations
began or ceased and give reference to Commission authorization, if any was required. State also the approximate number of
customers added or lost and approximate annual revenues of each class of service. Each natural gas company must also state major
new continuing sources of gas made available to it from purchases, development, purchase contract or othenivise, giving location and
approximate total gas volumes available, period of contracts, and other parties to any such anangements, etc.
6. Obligations incurred as a result of issuance of securities or assumption of liabilities or guaranlees 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.
I 1. (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 furnish 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 significanl 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. 1 (ED. 12.96)Page 108
Name of Respondent
ldaho Power Company
This Report is:
(1) X An OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
04t14t2017
Year/Period of Report
2016tQ4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
1 None
None
None
None
Effective 72/31/2016 a 2.15? general wage adjustment was impJ-emented.
Disc-losed in Financlal- Statement footnotes, see pages 123.22 to L23.23
3. To enhance the abilities of Idaho Power and Paci-fi-Corp to serve their respective
customers, on October 24,2014, ldaho Power and PacifiCorp executed a Joint Ownership and
Operating Agreement (Joint Operating Agreement) applicab1e to certain transmission-rel-ated
equipment to be exchanged by Idaho Power and PacifiCorp. The exchange was made pursuant to
the terms of a Joint Purchase and Sale Agreement, also dated October 24,2014, between
Idaho Power and PaclfiCorp, under which each party agreed to transfer to the other
specified transmj-ssion-related equipment with a net book value of approximately 945
million as of the closing date. The transaction a.Iso provided for the termlnation and
amendment of a number of legacy lonq-term agreements related to the ownership and
operation of jointly-owned facillties and transmission services between Idaho Power and
PacifiCorp. Idaho Power received FERC approval of the transaction on June 17, 2015 ( See;
Idaho Power Co., PacifiCorp, 151 FERC S 6I,233 (2015). FERC Docket No. EC15-54-000). As
a conditj-on of approval, FERC required Idaho Power and PacifiCorp to submit final
accounting for the transactj-on withln six months of the transact-ion's closing. (See: Idaho
Power Co., PacifiCorp, Order Authorizing Acquisitlon and Dj-sposition of JurisdictionalFaclli-ties, 151 FERC \ 61,233 (2015). The transactj-on closed on October 30, 2015 and final
accounting was submitted to FERC oo April 21, 20L6.
4 None
2
5
1
6. In December 2016, Idaho Power borrowed 52L,800,000 in commerclal paper, which was
repald in January 2071. In April and May 20L6, Idaho Power received orders from the IPUC,
OPUC, and WPSC authorizing Idaho Power to j-ssue and sel1 from time to time up to $500milfion in aggregate principal amount of debt securities and first mortgage bonds, subject
to condit-ions specified in the orders. Authority from the IPUC is effective through May
31, 2019, subject to extension upon request to the IPUC. The OPUC's and WPSC's orders donot impose a time limitation for issuances.
On March 10, 2076, ldaho Power issued $120 million in princi-pa1 amount of 4.05% first
mortgage bonds, secured medium-term notes, Serj-es J, maturing on March 1, 2046. In AprlI
2013, Idaho Power recelved orders from the IPUC, OPUC, and WPSC authorizing Idaho Power to
issue and se1l from time to time up to $500 million in aggregate principal amount of debtsecurlties and first mortgage bonds, subject to conditions specified in the orders.
Authority from the fPUC was through April 9, 2075. On April l, 2015, the IPUC approved a
two-year extension through April 9, 207'7, continuing Idaho Power's authorization to issue
and sefl from time to time debt securities and first mortgage bonds.
9
10. A11 of the befow related person transactions were reviewed and approved by the
Idaho Power Board of Directors and the Corporate Governance and Nominating Committee.
o Steven R. Keen, Idaho Power's Senior Vice President, Chief Financiaf Officer
and Treasurer is the brother of J, LaMont Keen, a member of Idaho Power's
board of directors.
. Rex Blackburn is the Sr. Vi-ce President and General Counsel of Idaho power.
His brother-1n-law, Gary Betts, ls also an employee of Idaho Power.
. Patri-ck A. Harrington ls the Corporate Secretary of Idaho Power. His brother,
FERC FORM NO.1 1 Page 109.1
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
0411412017
Year/Period of Report
2016tQ4
IMPORTANT CHANGES DURING THE QUARTERI/EAR (Continued)
11
t2
13
Jamie Harrington, is also an employee of Idaho Power.o Lori D. Smith was the Vice Presi-dent and Chief Risk Officer of Idaho Power.
Her husband, Matt Smith, was also an employee of ldaho Power.o Jeff Glenn is the the Vice President of Information Technology & CIO of Idaho
Power. His wife, JiII Glenn, is afso an employee of ldaho Power.
o Dan Mlnor was the Executive Vice President of Idaho Power. Hi-s sister, Deb
Mann, is also an employee of Idaho Power.
None
None
Officer Changes in 2016:o Daniel B. Minor retired as Executive Vice Presi-dent and Chief OperatingOfficer effective 6/30/20L6. Gregory W. Said retired as Vice President- Regulatory Affairs effective
4/30/2076o Lorl D. Smith retired as Vice President, Chief Risk Officer effective3/3r/2016o Brian R. Buckham was appointed Vice President and General- Counsel effective4/\/20t6o Tim E. Tatum was appointed Vice President- Regulatory Affairs effective
3/7/2076. Tess R. Park was appointed Vice President of Power Supply effective 1/l/2016o Jeff S. Glenn was appointed Vlce President of Information Technology effective
7/23/20L6o Jeff S. Glenn's title changed to Vice President of fnformation Technology and
Chief Information Officer effective 5/23/2016. Rex Blackburn's title changed from "Sr. Vice President and General- Counsel-" to
"Sr. Vice President" effective 4/l/20I6o Lisa A. Grow's titl-e changed from "Sr. Vice President- Power Supply" to "Sr.Vice Presldent of Operations" effective 7/7/2A76o Lonnie G. Krawl's title changed from "Vi-ce Presldent of Human Resources,
Administrative Services & Chref Information Officer'r to I'Sr. Vice President ofAdministratlve Services and Chief Information Officer" effective 7/L/2076o Lonnie G. Krawl's title changed from "Sr. Vice President of Administrative
Servi-ces and Chief Information Offlcer" to "Sr. Vice President ofAdministrative Servi-ces and Ch-ief Human Resources Officer" effective 5/23/16o Jeffrey L. Mafmen's titfe changed from "Vlce President- Public Affairs" to
"Sr. Vice President- Pubfic Affairs" effective 4/l/2016. N. Vern Porter's title changed from "Sr. Vice President of Customer
Operations" to "Vice President of Customer Operations" effective 7/\/2076
L4. Idaho Power and its unregulated parent, IDACORP have separate cash management
programs (separate bank accounts, liquidity facj-Iities, short-term debt and investment
programs) . No money has been loaned or advanced from Idaho Power to IDACORP through a cash
management program.
FERC FORM NO. 1 (ED. 12-96)Page 109.2
Name of Respondent
ldaho Power Company
This Report ls:
(1) tr AnOriginal
(2) tr A Resubmission
Date of Report
(Mo, Da, Yr)
04114120'.17
Year/Period of Report
End of 20161Q4
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Line
No.Title of Account
(a)
Ref.
Page No.
(b)
Current Year
End of Quarterf/ear
Balance
(c)
Prior Year
End Balance
12t31
(d)
1 UTILITY PLANT
2 Utility Plant (101-106, 114)200-201 5,739,484/4 5,492,554,138
3 Construction Work in Prosress (107)200-201 405,068,524 396,931,372
4 TOTAL Utility Plant (Enter Total of lines 2 and 3)6,144,552,974 5,889,485,510
5 (Less) Accum. Prov. for Depr. Amort. Depl. (108, 1'10, 111, 115)200-201 2,175,085,495 2,097,432,010
6 Net Utility Plant (Enter Total of line 4 less 5)3,969,467,475 3,792,053,500
7 Nuclear Fuel in Process of Ref., Conv.,Enrich., and Fab. (120.1)202-203 0 0
I Nuclear Fuel Materials and Assemblies-Stock Account (120.2)0 0
I Nuclear Fuel Assemblies in Reactor (120.3)0 0
10 Spent Nuclear Fuel ('120.4)0 0
1',l Nuclear Fuel Under Capital Leases (120.6)0 0
12 (Less) Accum. Prov. for Amort. of Nucl. Fuel Assemblies (120.5)202-203 0 0
13 Net Nuclear Fuel (Enter Total of lines 7-1 1 less 12)0 0
14 Net Utility Plant (Enter Total of lines 6 and '13)3,969,,167,475 3,792,053,500
15 Utility Plant Adiustments (1'16)0 0
16 Gas Stored Underground - Noncunent (117)0 0
17 OTHER PROPERTY AND INVESTI,IENTS
18 Nonutility Property (121 )1,071,638 1,555,480
19 (Less) Accum. Prov. for Depr. and Amort. (122)0 0
20 lnvestments in Associated Companies (123)0 0
21 lnvestment in Subsidiary Companies (123.1)224-225 77,130,927 u,'t37,401
22 (For Cost of Account 1 23.1 , See Footnote Page 224, line 42)
23 Noncunent Portion of Allowances 228-229 0 0
24 Other lnvestments (124)0 416
25 Sinking Funds (125)0 0
26 Depreciation Fund (126)0 0
27 Amortization Fund - Federal (127)0 0
28 Other Special Funds (128)24,018,574 24,560,677
29 Special Funds (Non Major Only) (129)0 0
30 Long-Term Portion of Derivative Assets (175)0 126,480
31 Long-Term Portion of Derivative Assets - Hedges (176)0 0
32 TOTAL Other Property and lnvestments (Lines 18-21 and 23-31)102,221,',t35 1 10,380,454
33 CURRENT AND ACCRUED ASSETS
34 Cash and Working Funds (Non-major Only) (130)0 0
35 Cash (13'l)14,159,468 100,745,383
36 Special Deposits (132-134)1,168,084 1,637,072
37 Workinq Fund (135)13,600 10,600
38 Temporary Cash lnvestments ('136)29,967,367 10,000,000
39 Notes Receivable (141)-83,038 0
40 Customer Accounts Receivable (1 42)73.276.818 75,650,719
41 Other Accounts Receivable (143)25,535,458 23,486,155
42 (Less) Accum. Prov. for Uncollectible Acct.-Credit (144)1,t31,759 1,355,042
43 Notes Receivable from Associated Companies (145)0 't,156,202
M Accounts Receivable from Assoc. Companies (146)0 0
45 Fuel Stock (151 )227 53,700,442 61,818,257
46 Fuel Stock Expenses Undistributed (152)227 -2,623 0
47 Residuals (Elec) and Extracted Products (153)227 0 0
48 Plant Materials and Operating Supplies (154)227 54,454,6U 52,445,228
49 Merchandise (155)227 0 0
50 Other Materials and Supplies (156)227 0 0
51 Nuclear Materials Held for Sale (157)202-2031227 0 0
52 Allowances (158.1 and 158.2)228-229 0 0
FERC FORM NO.1 (REV.12-03)Page 110
Name of Respondent
ldaho Power Company
This Report ls:
(1) [J An Original(2) n A Resubmission
Date of Report
(Mo, Da, Yr)
04114120',t7
Year/Period of Report
End of 201610,4
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBlTSlcontinued)
Line
No.Title of Account
(a)
Ref.
Page No.
(b)
Current Year
End of QuarterfYear
Balance
(c)
Prior Year
End Balance
't2t31
(d)
53 (Less) Noncurrent Portion of Allowances 0 0
54 Stores Expense Undistributed (1 63)227 3,403,797 4,478,320
55 Gas Stored Underground - Cunent (164.1)0 0
56 Liquefied Natural Gas Stored and Held for Processing ('164.2-164.3)0 0
57 Prepayments (165)'r8,269,814 17,845,551
58 Advances for Gas (166-167)0 0
59 lnterest and Dividends Receivable (171)24,539 0
60 Rents Receivable ('17 2\0 0
61 Accrued Utility Revenues ('173)80,738,420 65,804,608
62 Miscellaneous Cunent and Accrued Assets (174)0 0
63 Derivative lnstrument Assets (1 75)5,951,233 40s,239
64 (Less) Lonq-Term Portion of Derivative lnstrument Assets (175)0 126,480
65 Derivative lnstrument Assets - Hedges (176)0 0
66 (Less) Long-Term Portion of Derivative lnstrument Assets - Hedges (176 0 0
67 Total Current and Accrued Assets (Lines 34 through 66)359,446,304 414,001,8'12
68 DEFERRED DEBITS
69 Unamortized Debt Expenses (181)16,313,567 '16,539,636
70 Extraordinary Property Losses ('l 82. 1 )23Oa 0 0
71 Unrecovered Plant and Regulatory Study Costs (182.2)230b 0 0
72 Other Regulatory Assets (182.3)232 1,471,940,401 1,355,572,128
73 Prelim. Survey and lnvestigation Charges (Electric) (183)0 1,177
74 Preliminary Natural Gas Survey and lnvestigation Charges 183.'l)0 0
75 Other Preliminary Survey and lnvestigation Charges (183.2)0 0
76 Clearing Accounts (1 84)1,290,608 't,650,910
77 Temporary Facilities (1 85)0 0
78 Miscellaneous Deferred Debits (1 86)233 75,332,6s7 66,701,295
79 Def. Losses from Disposition of Utility Plt. (187)0 0
80 Research, Devel. and Demonstration Expend. (188)352-353 0 0
8'1 Unamortized Loss on Reaquired Debt (189)4't,975,568 29,731,072
82 Accumulated Deferred lncome Taxes (190)234 2ffi,326,529 270,188,39s
83 Unrecovered Purchased Gas Costs (191)(0uTotal Defened Debits (lines 69 through 83)1,893,179,330 't,740,384,613
85 TOTAL ASSETS (lines 14-16,32,67, and 84)6.324.314.244 6,056,820,379
FERC FORM NO.1 (REV.12-03)Page 111
Name of Respondent
ldaho Power Company
This Report is:
(1) tr An Original
(2) n A Resubmission
Date of Report
(mo, da, yr)
04t1412017
Year/Period of Report
end of 2O16lQ4
CoMPARATTVE BALANCE SHEET (LrABrLrTrES AND OTHER CREDITS)
Line
No Title of Account
(a)
Ref.
Page No.
(b)
Current Year
End of QuarterfYear
Balance
(c)
Prior Year
End Balance
'12t31
(d)
1 PROPRIETARY CAPITAL
2 Common Stock lssued (201)250-251 97,877,03C 97,877,030
3 Prefened Stock lssued (204)250-251 c 0
4 Capital Stock Subscribed (202, 205)c 0
5 Stock Liability for Conversion (203, 206)c 0
6 Premium on Capital Stock (207)712,257,43t 712,257,435
7 Other Paid-ln Capital (208-211)253 c 0
I lnstallments Received on Capital Stock (212)252 c 0
I (Less) Discount on Capital Stock (213)254 c 0
10 (Less) Capital Stock Expense (214)254b 2,096,92f 2,096,925
11 Retained Eamings (215, 215.1, 216)118-119 'l ,1 36,879,473 1,045,751,377
12 Unappropriated Undistributed Subsidiary Earnings (216.1)118-119 74,667,833 81,674,308
13 (Less) Reaquired Capital Stock (217)250-251 0 0
14 Noncorporate Proprietorship (Non-major only) (2 1 8)0 0
15 Accumulated Other Comprehensive lncome (219)122(a)(b)-20,881,620 -21,275,735
't6 Total Proprietary Capital (lines 2 through 15)1,998,703,226 1,914,187,490
17 LONG-TERM DEBT
18 Bonds (221 )256-257 1,745,460,000 1,725,460,000
19 (Less) Reaquired Bonds (222)256-257 0 0
20 Advances from Associated Companies (223)256-257 0 0
21 Other Long-Term Debl (224\256-257 20,948,636 22,012,273
22 Unamortized Premium on Long-Term Debt (225)0 0
23 (Less) Unamortized Discount on Long-Term DebtDebit (226)4,417,463 4,458,587
24 Total Long-Term Debt (lines 18 through 23)1,761,991,173 1,743,013,686
25 OTHER NONCURRENT LIABILITI ES
26 Obligations Under Capitial Leases - Noncunent (227)0 0
27 Accumulated Provision for Property lnsurance (228.1)0 0
28 Accumulated Provision for lnjuries and Damages (228.2)1,792,128 1,873,877
29 Accumulated Provision for Pensions and Benefits (228.3)411,633,628 394,131,877
30 Accumulated Miscellaneous Operating Provisions (228.4)0 0
31 Accumulated Provision for Rate Refunds (229)103,219J62 87,689,554
32 Long-Term Portion of Derivative lnstrument Liabilities 0 0
33 Long-Term Portion of Derivative lnstrument Liabilities - Hedges c 0
34 Asset Retirement Obligations (230)26,257,28e 26,152,620
35 Total Other Noncurrent Liabilities (lines 26 through 34)542,902,204 509,847,928
36 CURRENT AND ACCRUED LIABILITIES
37 Notes Payable (231)21,800,00c 0
38 Accounts Pavable (232\126,470,08i 1 19,524,930
39 Notes Payable to Associated Companies (233)244,43t 0
40 Accounts Payable to Associated Companies (234)1,056,374 1,058,872
41 Customer Deposits (235)2,864.762 4,731,724
42 Taxes Accrued (236)262-263 -11,945,251 5,192,418
43 lnterest Accrued (237)22,539,65t 22,387,590
44 Dividends Declared (238)c 0
45 Matured Long-Term Debt (239)c 0
FERC FORM NO. 1 (rev. 12-03)Page 112
Name of Respondent
ldaho Power Company
This Report is:
(1) tr An Original
(2) n A Resubmission
Date of Report
(mo, da, yr)
0411412017
Year/Period of Report
end of 20161Q4
COMPARATIVE BALANCE SHEET (LIABlllTlES AND OTHER CREDIJ&ftinueo)
Line
No.Title of Account
(a)
Ref.
Page No
(b)
Current Year
End of Quarterl/ear
Balance
(c)
Prior Year
End Balance
12131
(d)
46 Matured lnterest (240)c 0
47 Tax Collections Payable (241)2,847,908 1,921,386
48 Miscellaneous Current and Accrued Liabilities (242)49,816,65€53,364,600
49 Obligations Under Capitral Leases-Current (243)c 0
50 Derivative lnstrument Liabilities (244)c 4,972,600
51 (Less) Long-Term Portion of Derivative lnstrument Liabilities c 0
52 Derivative lnstrument Liabilities - Hedges (245)c 0
53 (Less) Long-Term Portion of Derivative lnstrument Liabilities-Hedges c 0
54 Total Cunent and Accrued Liabilities (lines 37 through 53)215,694,623 2'.13.154J20
55 DEFERRED CREDITS
56 Customer Advances for Construction (252)5,252,737 4,678,929
57 Accumulated Deferred lnvestment Tax Credits (255)266-267 79,959,845 79,654,930
58 Deferred Gains from Disposition of Utility Plant (256)c 0
59 Other Deferred Credits (253)269 10,479,342 1'1,757,998
60 Other Regulatory Liabilities (254)278 77,043,013 67,71 1,655
61 Unamortized Gain on Reaquired Debt (257)c 0
62 Accum. Defened I ncome Taxes-Accel. Amort. (28 1 )272-277 c 0
63 Accum. Defened lncome Taxes-Other Property (282)1,449,526,847 't,349,907,020
64 Accum. Defened lncome Taxes-Other (283)182,761,234 162,906,623
65 Total Defened Credits (lines 56 through 64)1 ,805,023,018 1,676,617,'155
66 TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24,35,54 and 65)6,324,314,244 6,056,820,379
FERC FORM NO. 1 (rev. 12-031 Page 113
Name of Respondent
ldaho Power Company
This Report ls:(1) ffiAn Orisinal(2) ;-1A Resubmission
Date of Report(Mo, Da, Yr)
o411412017
Year/Period of Report
End of 2O16lQ4
STATEMENT 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. Repo( 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 U) 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 Quartedy if applicable
5. Do not report fourth quarter data in columns (e) and (f)
6. Report amounts for accounts 412 and 4'13, Revenues and Expenses from Utility Plant Leased to Others, in another utility columnin a similar manner to
a utility department. Spread the amount(s) over lines 2lhru 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)
Total
Cunent Year to
Date Balance for
Quarterffear
(c)
Total
Prior Year to
Date Balance for
QuarterlYear
(d)
Cunent 3 Monhs
Ended
Quartedy 0nly
No 4h Quarter
(e)
Prior 3 Monhs
Ended
Quarterly only
No 4h Quarter
(0
1 UTILITY OPERATING INCOME
2 0perating Revenues (t100)300-301 1,255,298,799 1,266,201,447
3 0perating Expenses
4 0peration Expenses (40'l )320-323 734,428,076 731,125,349
5 Maintenance Expenses (402)320-323 67,074,765 69,399,1 54
6 Depreciation Expense (403)336-337 135,048,584 130,382,128
7 Depreciation Expense for Asset Retirement Cosb (403.1)336-337 720,272 549,017
8 Amort. & Depl. of Utility Plant (404405)336-337 6,649,455 7,095,926
9 Amort. of Utility Plant Acq. Adj. (406)336-337
't0 Amort. Property Losses, Unrecov Plant and Regulatory Study Cosb (407)
11 Amort. of Conversion Expenses (407)
12 Regulatory Debib (407.3)1,242,422 82,611
13 (Less) Regulatory Credib (407.4)
14 Taxes Oher Than lnome Taxes (408.1 )262-263 32,823,311 32,808,301
15 lncome Taxes - Federal (409.'l)262-263 -96,1 37 12,593,365
16 Other (409.1)262-263 3,659,280 5,986,1 '10
17 Provision for Defered lncome Taxes (4'10.1)234,272-277 58,087,034 86,269,807
18 (Less) Provision for Defened lncome Taxes-Cr. (41 1.'l )234,272-277 26,177,294 58,085,989
19 lnvestment Tax Credit Adj. - Net (41 1.4)266 304,915 492,099
20 (Less) Gains hom Disp. of Utility Plant (41 1.6)
21 Losses from Disp. of Utility Plant (411.7)
22 (Less) Gains from Disposition of Allowances (41 I .8)49,266 97,422
23 Losses from Disposit on of Allowances (41 1 .9)
24 Accretion Expense (41 1.'10)231,983 232,049
25 TOTAL Utility Operating Expenses (Enter Tohl of lines 4 hru 24)1 ,013,947,400 1,018,832,505
26 Net Util oper lnc (Enter Tot line 2 less 25) Carry to Pg'l17,line 27 241,351,399 247,368,942
FERC FORM NO. 1r3-O (REV.02.04)Page 114
Name of Respondent
ldaho Power Company
This(1)
(2)
Reoort ls:
5]Rn Originat
1A Resubmission
Date of Report(Mo, Da, Yr)
0411412017
Year/Period of Report
End of 2016/Q4
SIAIEMENI OF INCOME FOR IHE YEAR (Contanued)
9. Use page 'l22lor imgortant notes regarding the statement of income for any account thereof.
'10. Give concise explanations conceming unsettled rate proceedings where a contingency exists such that refunds of a material amount may need to be
made to the utility's customers or which may result in material refund to the utility with respect to power or gas purchases. State for each year effected
the gross revenues or costs to which the contingency relates and the tax effects together with an explanation of the major factors which affect the rights
of the utility to retain such revenues or recover amounts paid with respect to power or gas purchases.
11 Give concise explanations 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 adjustments made to balance sheet, income,
and expense accounts.
12. ll any notes appearing in the report to stokholders arc applicable to the Statement of lncome, such notes may be included al page '122.
13. Enter on page 122 a concise explanation of only those changes in accounting methods made during the year which had an effect on net income,
including the basis of allocations and apportionments from those used in the preceding year. Also, give the appropriate dollar effect of such changes.
14. Explain in a footnote if the previous yea/s/quarte/s figures are different from that reported in prior reports.
15. lf the columns are insufficient for reporting additional utility departments, supply the appropriate account titles report the information in a footnote to
this schedule.
ELECTRIC UTILITY GAS UTILITY OTHER UTILITY
Line
No.Current Year to Date
(in dollars)
(s)
Previous Year to Date
(in dollars)
(h)
Current Year to Date
(in dollars)
(i)
Previous Year to Date
(in dollars)
U)
curent Year t0 Date
(in dollars)
(k)
Prevrous Year t0 Date
(in dollars)
(t)
1
1,255,298,799 1,266,201,447 2
3
734,428,076 731,125,349 4
67,074,765 69,399,154 5
135,Ot8,584 130,382,128 6
720,272 549,017 7
6,649,455 7,095,926 I
I
10
1',!
1,242,422 82,611 12
13
32,823.31',\32,808,301 14
-96,1 37 12,593,36s 15
3,659,280 5,986,110 16
58,087,034 86,269,807 17
26,t77,294 58,085,989 't8
304,915 492.099 19
20
21
49,266 97,422 22
23
231,983 232,049 24
1,013.947,400 1,018,832,505 25
241,35'1,399 247,368,942 26
FERC FORM NO.1 (ED.12.96)Page i,t5
Name of Respondent
ldaho Power Company
This(1)
(2)
Reoort ls:
5jRn Originat
-A Resubmission
Date of Report(Mo, Da, Yr)
0411412017
Year/Period of Report
End of 2016/Q4
Line
No.
Title of Account
(a)
(Ref.)
Page No.
(b)
TOTAL uurrent J Monms
Ended
Quartedy Only
No 4h Quarter
(e)
Pnor 3 Monns
Ended
Quarterly Only
No 4h Quarter
0
Cunent Year
(c)
Previous Year
(d)
27 Net Utility operating lncome (Canied foruard from page 114)241,351,399 247,368,942
28 oher lncome and Deduc{ions
29 0her lncome
30 Nonutilty Operatinq lncome
31 Revenues From Merdrandising, Jobbing and Confact Work (415)4,054,219 1,304,085
32 (Less) Cosb and Exp. of Merchandising, Job. & Contract Work (416)3,886,708 1,485,862
33 Revenues From Nonutility operations (417)31,177 33,733
34 (Less) Exoenses of NonutiliU 0perations (417.1 )97,371 '10,586
35 Nonoperalinq Rental lnome (418)4,136 -791
36 Equity in Eaminqs of Subsidiary Companies (418.1)119 7,993,526 6,659,942
37 lnterest and Dividend lncome (419)4,241,119 3,039,556
38 Allowance for Oher Funds Used During Construction (419.1)22.030.622 21.785,246
39 Miscellaneous Nonooemtinq lnome (421)3,064,489 2,365,842
40 Gain on Disposition of Property (421.1)7,63'r -20
41 TOTAL Other lncome (Enter Tohl of lines 31 hru 40)37,434,568 33,69'1,145
42 oher lncome Deductions
43 Loss on Oispo$tion of Property (421.2)
44 Miscellaneous Amortization (425)
45 Donations (426.1)986,820 750,960
46 Life Insurance (426.2)-2,588,290 1,738,804
47 Penalties (426.3)-3 48,305
48 Exp. for Certain Civic, Political & Related Aclivities (426.4)1,549,848 1,477,633
49 Oher Deduc-tions (426.5)9,203,000 9,937,000
50 ToTAL Other lncome Deduclions fiotal of lines 43 thru 49)9,151,375 10,475,094
5t Taxes Applic. to oher lnmme and Deduclions
52 Taxes Oher Than lncome Taxes (408.2)262-263 28,463 21,055
53 lncome Taxes-Federal (409.2)262-263 560,490 353,061
54 lnome Taxe+Other (409.2)262-263 107.192 69,362
55 Provision for Defened lnc. Taxes (410.2)234,272-277 164,060 5,911 ,613
56 (Les) Provision for Defened lncome Taxes-Cr. (41 1.2)234,272-277 2,307,095 8,478,300
57 lnvestnent Tax Credit Adi.-Net (41 1.5)
58 (Less) lnveshrent Tax Credits (420)
59 T0TAL Taxes on Ofier lncome and Deductions (Iotal of lines 52-58)-1,446,890 -2,123,209
60 Net Oher lncome and Deduclions (Total of lines 41, 50, 59)29,730,083 25,339,260
6'l lnterest Charges
62 lnterest on Long-Term Debt (427)81,956,468 83,055.805
63 Amort. of Debt Disc. and Exoense (428)1,515,'157 1,556,825
64 Amortization of Loss on Reaquired Debt (428.1 )2,033,523 1,521,812
65 (Less) Amort. of Premium on Debt-Credit (429)
66 (Less) Amortization of Gain on Reaquired DebtCredit (429.1)
67 lnterest on Debt to Assoc. Companies (430)27,622 6,859
68 0her lnterest Expense (431 )6,500,414 5,627,193
69 (Less) Allowance for Bonowed Funds Used During Construction-Cr. (432)10,193,622 10,043,775
70 Net lnterest Charges (Tobl of lines 62 hru 69)81,839,562 81,724,719
7',|lnome Before Exfaordinary ltems Clotal of lines 27, 60 and 70)189,241,920 190,983,483
72 Extraordinary ltems
73 Extraordinary lncome (434)
74 (Less) Extraordinary Deductions (435)
75 Net Extraordinary ltems (Total of line 73 less line 74)
76 lncome TaxesFederal and Oher (409.3)262-263
77 Extraordinary ltems After Taxes (line 75 less line 76)
78 Net lncome Ootal of line 71 and 77)189,241,920 190,983,483
FERC FORM NO. 1r3.Q (REV.02-04)Page 117
Name of Respondent
ldaho Power Company
This Reoort ls:(1) fiAn Originat(2) [-1A Resubmission
Date of Report
(Mo, Da, Yr)
0411412017
Year/Period of Report
2016rc4End of
STATEMENT OF RETAINED EARNINGS
1. Do not report Lines 49-53 on the quarterly version.
2. Report all changes in appropriated retained earnings, unappropriated retained earnings, year to date, and unappropriated
undistributed subsidiary earnings for the year.
3. Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436
- 439 inclusive). Show the contra primary account affected in column (b)
4. State the purpose and amount of each reservation or appropriation of retained earnings.
5. List first account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained 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)
Current
QuarterfYear
Year to Date
Balance
(c)
Previous
Quarterffear
Year to Date
Balance
(d)
UNAPPROPRIATED RETAINED EARNINGS (Account 216)
1 Balance-Beginning of Period 1.032.478.271 939,062,769
2 Changes
3 Adiustments to Retained Eamings (Account 439)
4
5
6
7
I
I TOTAL Credits to Retained Eamings (Acct. 439)
10
11
12
13
14
15 TOTAL Debits to Retained Eamings (Acct. 439)
't6 Balance Transferred from lncome (Account 433 less Account 418.1 )181,248,394 184,323,541
17 Appropriations of Retained Eamings (Acct. 436)
18
19
20
21
22 TOTAL Appropriations of Retained Eamings (Acct. 436)
23 Dividends Declared-Preferred Stock (Account 437)
24
25
26
27
28
29 TOTAL Dividends Declared-Preferred Stock (Acct. 437)
30 Dividends Declared-Common Stock (Account 438)
31 -'t05,120,298 ( 96,908,039)
32
33
34
35
36 TOTAL Dividends Declared-Common Stock (Acct. 438)-105,120,298 ( 96,908,039)
37 Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Eamings 1s,000,000 6,000,000
38 Balance - End of Period (Total 1,9,15,16,22,29,36,37)1,123,606,367 1,032,478,271
APPROPRIATED RETAINED EARNINGS (Account 215)
FERC FORM NO. 1r3.Q (REV. 02.04)Page 118
Name of Respondent
ldaho Power Company
This Reoort ls:(1) [An Original(2) 1-1A Resubmission
Date of(Mo, Da
Report
, Yr)
04t14t2017
Year/Period of Report
2016/Q4End of
STATEMENT OF RETAINED EARNINGS
1. Do not report Lines 49-53 on the quarterly version.
2. Report all changes in appropriated retained earnings, unappropriated retained earnings, year to date, and unappropriated
undistributed subsidiary earnings for the year.
3. Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436
- 439 inclusive). Show the contra primary account affected in column (b)
4. State the purpose and amount of each reservation or appropriation of retained earnings.
5. List first account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow
by credit, then debit items in that order.
6. Show dividends for each class and series of capital stock.
7. Show separately the State and Federal income tax effect of items shown in account 439, Adjustments to Retained Earnings.
8. Explain in a footnote the basis for determining the amount reserved or appropriated. 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
Quarter/Year
Year to Date
Balance
(c)
Previous
QuarterfYear
Year to Date
Balance
(d)
39
40
41
42
43
44
45 TOTAL Appropriated Retained Eamings (Account 2'15)
APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Accounl215.'l)
&TOTAL Approp. Retained Eamings-Amort. Reserve, Federal (Acct. 215.1)13,273,106 1 3,273,106
47 TOTAL Approp. Retained Eamings (Acct. 215, 215.1 ) (Total 45,46)13,273,106 I 3,273,1 06
la TOTAL Retained Eamings (Acct. 215, 215.'l , 216) (Total 38, 471 (216.1)1,136,879,473 1,045,751,377
UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account
Report only on an Annual Basis, no Quarterly
49 Balance-Beginning of Year (Debit or Credit)81,674,308 81,014,366
50 Equity in Eamings for Year (Credit) (Account 418.1)7,993,s26 6,659,942
51 (Less) Dividends Received (Debit)15,000,000 6,000,000
52
53 Balance-End of Year (Total lines 49 thru 52)74.667.834 8't,674,308
FERC FORM r{O. t/3-Q (REV.02-04)Page 119
Name of Respondent
ldaho Power Company
This Report ls:(1) [An Original(2) ;_lA Resubmission
Date of(Mo, Da
Report
, Yr)
04t14t2017
Year/Period of Report
End of 20161Q4
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.
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. 'l for Explanation of Codes)
(a)
Current Year to Date
Quarterl/ear
(b)
Previous Year to Date
Quarterl/ear
(c)
1 Net Cash Flow from Operating Activities:
2 Net lncome (Line 78(c) on page 117)189,24',t,920 190,983,483
3 Noncash Charges (Credits) to lncome
4 Depreciation and Depletion 135,048,584 130,382,128
5 Amortization of 11,590,185
6
7
I Defened lncome Taxes (Net)29,875,896 25,793,350
I lnvestment Tax Credit Adjustment (Net)'t95,726 315,879
10 Net (lncrease) Decrease in Receivables 3,368,760 3,988,719
11 Net (lncrease) Decrease in lnventory 7,244,713 -8,079,325
12 Net (lncrease) Decrease in Allowances lnventory
't3 Net lncrease (Decrease) in Payables and Accrued Expenses 17,501,301
14 Net (lncrease) Decrease in Other Regulatory Assets -18,744,516 't,465,215
15 Net lncrease (Decrease) in Other Regulatory Liabilities 13,093,929 12,233,990
16 (Less) Allowance for Other Funds Used During Construction 22,030,622 21,785,246
17 (Less) Undistributed Earnings from Subsidiary Companies -7,006,474 659,942
18 Other (provide details in footnote):-18,199,440
19
20
21
22 Net Cash Provided by (Used in) Operating Activities (Total 2 thru 21)309,866,065 345,530,297
23
24 Cash Flows from lnvestment Activities:
25 Construction and Acquisition of Plant (including land):
26 Gross Additions to Utility Plant (less nuclear fuel)-315,753,782
27 Gross Additions to Nuclear Fuel
28 Gross Additions to Common Utility Plant
29 Gross Additions to Nonutility Plant
30 (Less) Allowance for Other Funds Used During Construction -22.030.622 -21,785,246
31 Other (provide details in footnote):13,456,680
32
33
34 Cash Outflows for Plant (Total of lines 26 thru 33)-288,389,494 -280,51 1,856
35
36 Acquisition of Other Noncunent Assets (d)
37 Proceeds from Disposal of Noncurrent Assets (d)
38
39 lnvestments in and Advances to Assoc. and Subsidiary Companies 83,038 896,996
40 Contributions and Advances from Assoc. and Subsidiary Companies 1,400,637
41 Disposition of lnvestments in (and Advances to)
42 Associated and Subsidiary Companies
43
44 Purchase of lnvestment Securities (a)-24,916,896 -44,105,638
45 Proceeds from Sales of lnvestment Securities (a)15,693,370 34,243,',t80
FERC FORM NO. I (ED.12-96)Page 120
Name ls:
Originalldaho Power Company
(1)
(2)A Resubmission
Date of Report(Mo, Da, Yr)
04t14t2017
Year/Period of Report
End of 2016/Q4
SIAIEMENI OI- 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.
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 leas€s capitalized with the plant cost.
Line
No.
Description (See lnstruction No. 1 for Explanation of Codes)
(a)
Current Year to Date
Quarter/Year
(b)
Previous Year to Date
Quarter/Year
(c)
46 Loans Made or Purchased
47 Collections on Loans
48
49 Net (lncrease) Decrease in Receivables
50 Net (lncrease ) 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):-'t.374.426
54
55
56 Net Cash Provided by (Used in) lnvesting Activities
57 Total of lines 34 thru 55)-2%,185,021 -290,851,744
58
59 Cash Flows from Financing Activities:
60 Proceeds from lssuance of:
61 Long-Term Debt (b)120,000,000 250,000,000
62 Preferred Stock
63 Common Stock
64 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)120,000,000 250,000,000
71
72 Payments for Retirement of:
73 Long-term Debt (b)-101,063,636 -121,063,637
74 Preferred Stock
75 Common Stock
76 Other (provide details in footnote):-22,646,072
77
78 Net Decrease in Short-Term Debt (c)21,800,000
79
80 Dividends on Prefened Stock
81 Dividends on Common Stock -105,120,298 -96,908,039
82 Net Cash Provided by (Used in) Financing Activities
83 (Total of lines 70 thru 81)-80,296,s92 9,382,252
84
85 Net lncrease (Decrease) in Cash and Cash Equivalents
86 (Total of lines 22,57 and 83)-66,615,548 64,060,805
87
88 Cash and Cash Equivalents at Beginning of Period 110,755,983 46,695,178
89
90 Cash and Cash Equivalents at End of period 44,140,435 1 10,755,983
FERC FORM NO. I (ED. 12-96)Page 121
Name of Respondent
ldaho Power Companv
This Report is:
(1) X An Original
Ql A Resubmission
Date of Report
(Mo, Da, Yr)
o411412017
Year/Period of Report
20161Q4
FOOTNOTE DATA
Schedule Page: 120 Line No.: 5 Column: b
AmortizationPlant 6,649,455
Unamortized debt expense 3,576,062
Unamortized discount 295,752
Water rights 1,042,009
Other 81 692
11,644,970
Schedule Page:120 Line No.: 13 Column: b
Cash (received) paid during the period for:
lncome taxes
lnterest (net of amount capitalized)
Schedule Page:120 Line No.:18 Column: b
Cash Flow from Operating Activities (Other)
Pension and postretirement benefit plan expense
Contributions to pension and postretirement benefit plans
Unbilled revenues
Accrued payroll
Prepayments
Company owned life insurance
Deposits from third parties
Other
Schedule Page: 120 Line No.:26 Column: b
Non-cash investing activities:
Additions to PP&E in accounts payable
Schedule Page:120 Line No.:31 Column: b
Other Gash Flows from Plant
Payments received from joint funding partners
Sale of emission allowances and renewable energy certificates
Other
Schedule Page: 120 Line No.:53 Column: b
Other lnvesting Cash Flows
Feasibility study costs
Miscellaneous other investing activities
Schedule Page: 120 Line No;76 Column: b
Other Financing Cash Flows
Make-whole premium on retirement of long-term debt
Debt issuance costs
Discount on debt issuance
22,005,067
78,111,192
29,s96,861
(45,316,746)
(15,670,298)
(4,883,134)
(2,476,233\
1,013,075
(1,504,654)
3,006,925)
(42,248,O53)
34,602,938
7,586,142
971 ,1 65
1,371
8,558,677
(65,296)
9,620
(55,676)
(13,895,000)
(1,708,058)
(309,600)
(15,912,658)
FERC FORM NO.1 1 450.1
ldaho Power Company (1)
(2)
ls:
Original
A Resubmission
Date of Report(Mo, Da, Yr)
o4t't4t2017
Year/Period ol Report
End of 20161Q4
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
1. Report in columns (b),(c),(d) and (e) the amounts of accumulated other comprehensive income items, on a net-of-tax basis, where appropriate.
2. Report in columns (f) and (g) the amounts of other categories of other cash flow hedges.
3. For each category of hedges that have been accounted for as "fair value hedges", report the accounts affected and the related amounts in a footnote.
4. Report data on a year-to-date basis.
Line
No.
Item
(a)
Unrealized Gains and
Losses on Available-
for-Sale Securities
(b)
Minimum Pension
Liability adjustment
(net amount)
(c)
Foreign Cunency
Hedges
(d)
Other
Adjustments
(e)
1 Balance of Account 219 at Beginning of
Preceding Year ( 24,1s7,999)
2 Preceding QtrA/r to Date Reclassifications
from Acct 219 to Net lncome 2,667,521
3 Preceding QuarterfYear to Date Changes in
Fair Value 214,743
4 Total (lines 2 and 3)2.882.264
5 Balance of Account 219 at End of
Preceding Quarterl/ear ( 21,275,735)
6 Balance of Account 219 at Beginning of
Current Year ( 21,275,735)
7 Current QtrfYr to Date Reclassifications
from Acct 2'19 to Net lncome 2.253.040
8 Current QuarterA/ear to Date Changes in
Fair Value ( 1,858,925)
I Total (lines 7 and 8)394,1 1 5
'10 Balance of Account 21 9 at End of Current
QuarterA/ear ( 20,881,620)
FERC FORM NO. r (NEW 0e02)Page 122a
Name of Respondent
ldaho Power Company
This Report ls:(1) EAn Original(2) [lA Resubmission
Date of Report
(Mo, Da, Yr)
04t14t2017
Year/Period of Report
End of 20161Q4
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
Line
No.
Other Cash Flow
Hedges
lnterest Rate Swaps
(0
Other Cash Flow
Hedges
finsert Footnote at Line 1
to specifyl
(s)
Totals for each
category of items
recorded in
Account 219
(h)
Net lncome (Carried
Fonrard from
Page 1'17 , Line 78)
(i)
Total
Comprehensive
lncome
U)
1 ( 24,157,999)
2 2,667,521
3 214,743
4 2,882,264 190,983,483 'r93,865,747
5 ( 21,275,735)
6 ( 21,275,73s)
7 2,253,040
8 ( 1,858,925)
I 394,'115 189,241,920 189,636,035
10 ( 20,881,620)
FERC FORM NO.1 (NEW 0&02)Page 122b
Name of Respondent
ldaho Power Company
lnrs Hepon ls:(1) E] An Original(2) ! A Resubmission
L'ate ot Repoft
0411412017
Year/Penod of t{eport
End of 20161Q4
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. Classify the notes according to each basic statement,
providing a subheading for each statement except where a note is applicable to more than one statement.
2. Furnish particulars (details) as to any signiflcant 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 anears
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 17 of the Uniform System of Accounts.
5. Give a concise explanation of any retained earnings restrictions and state the amount of retained earnings affected by such
restrictions.
6. 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 borrowings or modifications of existing financing agreements; and
changes resulting from business combinations or dispositions. However were material contingencies exist, the disclosure of such
matters shall be provided even though a significant change since year end may not have occurred.
9. Finally, if the notes to the financial statements relating to the respondent appearing in the annual report to the stockholders are
applicable and furnish the data required by the above instructions, such notes may be included herein.
P AGE 122 INTENTIONALLY LEFT BLANK
SEE PAGE 123 FOR REQUIRED INFORMATION.
FERC FORM NO. 1 (ED. 12-96)Page 122
Name of Respondent
ldaho Power Company
This Report is:
(1)X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
0/,t1412017
Year/Period of Report
20't6tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
IDAHO POWERCOMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
I. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Idaho Power Company (ldaho Power) is the principal operating subsidiary of IDACORP, tnc. (IDACORP), a holding company formed
in 1998. Idaho Power is an electric utility engaged in the generation, transmission, distribution, sales, and purchase ofelectric energy
and capacity with a service area covering approximately 24,000 square miles in southem ldaho and eastern Oregon. Idaho Power is
regulated primarily by the state utility regulatory commissions of Idaho and Oregon and the Federal Energy Regulatory Commission
(FERC). Idaho Power is the parent of Idaho Energy Resources Co. (IERCo), a joint venturer in Bridger Coal Company (BCC), which
mines and supplies coal to the Jim Bridger generating plant owned in part by Idaho Power.
Basis of Reporting
The flnancial statements include the assets, liabilities, revenues and expenses ofldaho Power and have been prepared in accordance
with the accounting requirements of the FERC as set forth in the applicable Unifbrm System of Accounts and published accounting
releases, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of
America (U.S. GAAP). As required by the FERC, Idaho Power accounts for its investments in its majority-owned subsidiary on the
equity method rather than consolidating the assets, liabilities, revenues and expenses of the subsidiary as required by U.S GAAP. The
accompanying financial statements include ldaho 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 ditlerences tiom U.S. GAAP in the
presentation of(l) current 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, (7) accrued taxes, and (8) debt issue costs.
Management Estimates
Management makes estimates and assumptions when preparing these financial statements. These estimates and assumptions include
those related to rate regulation, retirement benefits, contingencies, litigation, asset impairment, income taxes, unbilled revenues, and
bad debt. These estimates and assumptions aflect 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, tuture economic factors that are difficult to predict and are
beyond management's control. Accordingly. actual results could differ from those estimates.
System ofAccounts
The accounting records ofldaho Power confbrm to the Unifbrm System ofAccounts prescribed by the FERC and adopted by the
public utility commissions of ldaho, Oregon. and Wyoming.
Regulation of Utility Operations
As a regulated utility, many of ldaho 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.
FERC FORM NO. { (ED. 12.881 Page 123.'t
Idaho Power's financial statements reflect the effects of the different ratemaking principles fbllowed by the jurisdictions regulating
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t14t20't7
Year/Period of Report
2016tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Idaho Power. The application of accounting principles related to regulated operations sometimes results in ldaho 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 or accrued as regulatory assets or regulatory liabilities on the balance sheet and recorded on the
income statement when recovered or retumed in rates. Additionally, regulators can impose regulatory liabilities upon a regulated
company for amounts previously collected fiom customers that are expected to be refunded. The eft'ects of applying these regulatory
accounting principles to ldaho Power's operations are discussed in more detail in Note 3.
Cash and Cash Equivalents
Cash and cash equivalents include cash on-hand and highly liquid temporary investments that mature within 90 days of the date of
acquisition.
Receivables and Allowance for Uncollectible Accounts
Customer receivables are recorded at the invoiced amounts and do not bear interest. A late payment fee ofone 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. Adjustments are charged to income. Customer accounts receivable balances that remain outstanding after
reasonable collection elTorts are written off.
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 3l, 2016 and 2015. Once a receivable is determined to be
impaired, any further interest income recognized is fully reserved.
Derivative Financial Instruments
Financial instruments such as commodity futures, forwards, options, and swaps are used to manage exposure to commodity price risk
in the electricity and natural gas markets. All derivative instruments are recognized as either assets or liabilities at fair value on the
balance sheet unless they are designated as normal purchases and normal sales. With the exception of fbrward contracts for the
purchase ofnatural gas tbr use at ldaho Power's natural gas generation facilities and a nominal number ofpower 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 of energy are recorded when service is rendered or energy is delivered to customers.
Idaho Power accrues estimated unbilled revenues for electric services delivered to customers but not yet billed at year-end. In addition,
regulatory mechanisms in place in ldaho and Oregon affect the reported amount of revenue. See Note 3 for additional discussion of
certain of the tbllowing mechanisms:
FERC FORM NO.1 (ED.I2{8)Page'123.2
Name of Respondent
ldaho Power Company
This Report is:
(1) X An OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
04t14t2017
Year/Period of Report
2016tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
. energy efficiency riders to fund energy efficiency program expenditures. Expenditures funded through the riders are reported
as an operating expense with an equal amount of revenues recorded in other revenues;
o a fixed cost adjustment mechanism that results in recording additional or reduced revenue based on the allowed and actual
fixed costs recovered through current rates;
r a sharing mechanism providing for refunds to customers for earnings above stated retums on equity in ldaho;
o franchise fees and similar taxes related to energy consumption. None of these collections are reported on the income
statement; and
r collection in base rates of a portion of the allowance for funds used during construction (AFUDC) related to its Hells Canyon
Complex (HCC) relicensing project. Cash collected under this ratemaking mechanism is not recorded as revenue but is
instead defbrred 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 ofproperty and replacements and renewals ofitems
determined to be less than units of property. For utility property replaced or renewed, the original cost plus removal cost less salvage is
charged to accumulated provision for depreciation, while the cost of related replacements and renewals is added to property, plant and
equipment.
All utility plant in service is depreciated using the straight-line method at rates approved by regulatory authorities. Annual depreciation
provisions as a percent of average depreciable utility plant in service approximated 2.64 percent in 2016 and 2.68 percent in 2015.
During the period ofconstruction, costs expected to be included in the final value ofthe constructed asset, and depreciated once the
asset is complete and placed in service, are classified as construction work in progress on the consolidated balance sheets. Ifthe project
becomes probable of being abandoned, such costs are expensed in the period such determination is made. Idaho Power may seek
recovery ofsuch costs in customer rates, although there can be no guarantee such recovery would be granted.
Long-lived assets are periodically reviewed tbr impairment when events or changes in circumstances indicate that the carrying amount
ofan asset may not be recoverable. Ifthe sum ofthe undiscounted expected future cash flows from an asset is less than the carrying
value of the asset, impairment is recognized in the financial statements. There were no material impairments of long-lived assets in
2016or2015.
Allowance for Funds Used During Construction
AFUDC represents the cost of tinancing construction projects with borrowed funds and equity funds. With one exception, as discussed
above tbr the HCC relicensing project, cash is not realized currently f'rom such allowance; it is realized under the ratemaking process
over the service lit'e ofthe related property through increased revenues resulting from a higher rate base and higher depreciation
expense. The component of AFUDC attributable to borrowed funds is included as a reduction to total interest expense. Idaho Power's
weighted-average monthly AFUDC rate was 7.6 percent for both 2016 and2015.
Income Taxes
Idaho Power accounts fbr income taxes under the asset and liability method. which requires the recognition of deferred tax assets and
FERC FORM NO.1 (ED.12.88)Page 123.3
Name of Respondent
ldaho Power Company
This Report is:
(1)X An Original(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04t1412017
Year/Period of Report
2016tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
liabilities for the expected future tax consequences ofevents that have been included in the financial statements. Under this method
(commonly referred to as normalized accounting), deferred tax assets and liabilities are determined based on the differences between
the financial statements and tax basis ofassets and liabilities using enacted tax rates in efl'ect for the year in which the differences are
expected to reverse. In.general, deferred income tax expense or benetit tbr a reporting period is recognized as the change in detbrred
tax assets and liabilities from the beginning to the end ofthe period. The effect ofa change in tax rates on detbrred tax assets and
liabilities is recognized in income in the period that includes the enactment date unless ldaho Power's primary regulator, the Idaho
Public Utilities Commission (IPUC), orders direct deferral of the eflect 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 ta,x impact currently (commonly
referred to as flow-through accounting) for rate making and financial reporting. Therefbre, Idaho Power's effective income tax rate is
impacted as these difl-erences arise and reverse. Regulated enterprises are required to recognize such adjustments as regulatory assets
or liabilities if it is probable that such amounts will be recovered from or returned to customers in future rates.
In compliance with the federal income tax requirements for the use of accelerated tax depreciation, Idaho Power provides deferred
income taxes related to its plant assets for the difference between income tax depreciation and book depreciation used for financial
statement purposes. Deferred income taxes are provided for other temporary differences unless accounted tbr using flow-through.
The state of ldaho allows a three percent investment tax credit on qualilying plant additions. Investment tax credits earned on regulated
assets are det-erred and amortized to income over the estimated service lives of the related properties. Credits earned on non-regulated
assets or investments are recognized in the year earned.
Income taxes are discussed in more detail in Note 2
Other Accounting Policies
Debt discount. expense, and premium are deferred and amortized over the terms ofthe respective debt issues. Losses on reacquired
debt and associated costs are amortized over the lif'e of the associated replacement debt, as allowed under regulatory accounting.
Supplemental Cash Flows Information
In 2015, Idaho Power executed an agreement to exchange property with another electric utility. Under the terms of the agreement. each
party transferred to the other transmission-related equipment with a book value of approximately $44 million. Idaho Power received an
immaterial amount of cash, representing the diftbrence in the book value of the assets exchanged. Also in 20 I 5, Idaho Power executed
a long-term service agreement and transferred to the service provider approximately $22 million of spare parts in partial exchange for
future services. No cash was exchanged in the 2015 transfer transaction.
Reclassifications
In these consolidated financial statements, certain immaterial amounts in prior periods'consolidated financial statements and fbotnotes
have been reclassified to conform with the current period presentation.
FERC FORM NO.1 (ED.12.88)Pase'123.4
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
o4t1412017
Year/Period of Report
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
New and Recently Adopted Accounting Pronouncements
Recently Adopted Accounling Pronouncements
In March 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2016-09,
Compensation--Stock Compensation (Topic 7 l8) - lmprovements to Employer Share-Based Payment Accounting, simpliling several
aspects of the accounting for stock compensation paid to employees. As allowed, Idaho Power elected to early adopt the provisions of
the new standard in the first quarter of 2016 under the modifled retrospective method.
In May 2015, the FASB issued ASU 2015-07, Fair Value Measurement (Topic 820) - Disclosuresfor Investments in Certain Entities
That Calculate Net Asset Value per Share (or lts Equivalent),which removes the requirement to categorize within the fair value
hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. As required, Idaho
Power has adopted the provisions ofthis ASU at December 31,2016, and accordingly. has retrospectively adjusted prior periods.
In February 20 I 5, the FASB issued ASU 201 5-02 , Consolidation (Topic 8 l0) - Amendments to the Consolidation Analysis, which
revises the consolidation model that reporting entities use when determining what entities are to be consolidated. The amendments
focus on limited partnerships and similar legal entities. The adoption of ASU 2015-02 in the first quarter of 2016 did not have a
material impact on Idaho Power's financial statements.
Recent Accounting Pronouncemenls Not Yel Adopted
In May 2014, the FASB issued ASU 2014-09 , Revenue from Contracts with Customers (Topic 606). ASU 2014-09 is intended to
enable users of financial statements to better understand and consistently analyze an entity's revenue across industries, transactions, and
geographies. Under the ASU, recognition of revenue occurs when a customer obtains control of promised goods or services. In
addition, the ASU requires disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising f'rom contracts
with customers. The FASB amended certain aspects of ASU 2014-09 to clari$ the implementation guidance, including clarifications
related to principal versus agent considerations, licensing and identifling performance obligations, narrow scope improvements, and
practical expedients. Idaho Power continues to assess the impacts of ASU 2014-09 on their financial statements, including disclosure
requirements, but does not expect the new guidance to significantly affect revenue recognition for tarilT-based sales, which represent a
significant majority ofldaho Power's general business revenue. Accordingly, Idaho Power does not expect the adoption ofASU
2014-09 to have a material effect on its financial statements; however, a number of industry-specitic implementation issues are still
unresolved and the flnal resolution of these issues could aflect the Idaho Power's accounting tbr contributions in aid of construction,
sales of renewable energy credits, alternative revenue programs, and recognition of revenue when collectability is in question. The
guidance in ASU 2014-09 is effective for annual reporting periods beginning after December 15,2017, including interim periods. The
guidance permits two implementation approaches, one requiring retrospective application of the new standard with restatement of prior
years (full retrospective approach) and one requiring prospective application ofthe new standard including a cumulative-ef-fbct
adjustment with disclosure of results under previous standards (modified-retrospective approach). Idaho Power plans to adopt ASU
2014-09 on January I , 201 8, using the modit'ied-retrospective approach.
FERC FORM NO.1 (ED.12.88)Page 123.5
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
04114t20't7
Year/Period of Report
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
In February 2016,the FASB issued ASU 2016-02, Leases (Topic 812), intended to improve financial reporting about leasing
transactions. The ASU significantly changes the accounting model used by lessees to account for leases" requiring that all material
leases be presented on the balance sheet. Under the current model, some leases are classified as capital leases and recorded on the
balance sheet while other leases classifled as operating leases are not recognized on the balance sheet. The new standard is effective
for annual reporting periods beginning after December 15. 20 18, including interim periods, with early adoption permitted. The
standard must be adopted using a modified-retrospective approach. Idaho Power is evaluating the impact of ASU 2016-02 on its
financial statements. At this time, Idaho Power does not know, and cannot reasonably estimate, the dollar impact of the adoption.
Specifically, Idaho Power is considering whether the new guidance will affect its accounting fbr purchase power agreements,
easements and rights-of-way, utility pole attachments, and other utility industry-related areas.
In August 2016, the FASB issued ASU 2016-15. Statement of Cash Flows (Topic 230),which amends ASC 230 to clarifo guidance on
the classification of certain cash receipts and payments in the statement of cash flows. The FASB issued the ASU with the intent of
reducing diversity in practice with respect to eight types of cash flows. Idaho Power expects the ASU to afl-ect the classification of
proceeds from the settlement of corporate-owned life insurance policies and related costs, which will be classified as investing
activities under the new guidance. Idaho Power already presents debt prepayment and extinguishment costs, proceeds from the
settlement of insurance claims (other than corporate-owned life insurance), and distributions received from equity-method investments
in accordance with the new guidance. ASU 2016-15 is effective for annual reporting periods beginning after December 15,2017,
including interim periods, with early adoption permitted one year earlier. Idaho Power does not plan to early adopt the standard. The
standard must be adopted retrospectively to all periods presented, unless impracticable to do so. Idaho Power does not believe the
adoption will have a material impact on their tlnancial statements.
Subsequent Events
Management has evaluated the impact of events occurring after December 31,2016, up to February 23,2017, the date that ldaho
Power Company's U.S. GAAP financial statements were issued and has updated such evaluation for disclosure purposes through April
14,2017. These tinancial statements include all necessary adjustments and disclosures resulting fiom these evaluations.
FERC FORM NO.1 (ED.12.88)Page 123.6
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
Mt14120',t7
Year/Period of Report
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
2.INCOME TAXES
A reconciliation between the statutory f'ederal income tax rate and the effective tax rate is as follows
2016 2015
Federal income tax expense at35o/o statutory rate
Change in taxes resulting from:
Equity eamings of subsidiary companies
AFIJDC
Capitalized interest
Investment tax credits
Bond redemption costs
Removal costs
Capitalized overhead costs
Capitalized repair costs
Tax method change - capitalized repairs
State income taxes, net offbderal benefit
Depreciation
Share-based compensation
Other, net
(thousands ofdollars)78,241 S 82,633$
(2,7e8)
(1r,278)
2,000
(2,922)
(4,997\
(5,559)
( 10,500)
(28,000)
4,880
18,673
( 1,583)
( r.8s5)
(2,331)
( I r,140)
2,693
(2,963)
(6,4s9)
(4,807)
(8,7s0)
(28,700)
7,503
17,149
283
Total income tax expense $ 34,302 $ 45,1 r l
Effective tax rate
The items comprising income tax expense are as follows:
15.30o/o 19.llYo
2016 20t5
(thousands of dollars)
Income taxes currently payable:
Federal
State
464 $ (r2,946)3.767 6,056
$
Total 4.231 19.002
Income taxes deferred:
Federal
State
31,798
(2.032\
28, I 03
(2.486)
Total 29.766 2s.617
Investment tax credits:
Deferred
Restored
3,227
(2,922)
3,455
(2,963)
Total
Total income tax expense
30s 49234,302 45,1I I
FERC FORM NO.1 (ED.12-88)Page 123.7
Name of Respondent
ldaho Power Company
This Report is:
(1)X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t1412017
Year/Period of Report
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
The components of the net deferred tax liability are as follows
2016 2015
(thousands ofdollars)
Deferred tax assets:
Regulatory liabilities
Deferred compensation
Deferred revenue
Tax credits
Retirement benefits
Other
51,326 $
29,424
40,354
33,488
132,362
r 1,069
51,13 I
27,489
34,282
30.223
I 26.885
10,745
$
Total 298,023 280,755
Deferred tax liabilities:
Property, plant and equipment
Regulatory assets
Power cost adjustment
Fixed cost adjustment
Retirement benefits
Other
500,987
948,540
21,077
17,376
140,083
15,922
474,879
875,028
18,489
14,395
126,090
14,499
Total 1,643,985 I,523,380
Net deferred tax liabilities $ 1,345,962 $ 1,242,625
IDACORP's tax allocation agreement provides that each member of its consolidated group compute its income taxes on a separate
company basis. Amounts payable or refundable are settled through IDACORP. See Note I for firrther discussion of accounting policies
related to income taxes.
Uncertain Tax Positions
Idaho Power believes that it has no material income ta,x uncertainties for 2016 and prior tax years. The Company recognizes interest
accrued related to unrecognized tax benefits as interest expense and penalties as other expense.
Idaho Power is subject to examination by its major tax jurisdictions - U.S. t-ederal and the State of ldaho. The open tax years for
examination are 2016 fbr federal and2012-2016 for ldaho. ln May 2009, IDACORP formally entered the U.S. Intemal Revenue
Service (lRS) Compliance Assurance Process (CAP) program for its 2009 tax year and has remained in the CAP program fbr all
subsequent years. The CAP program provides for IRS examination and issue resolution throughout the current year with the objective
of retum filings containing no contested items. In 2016, the IRS completed its examination of IDACORP's 20 I 5 tax year with no
unresolved income tax issues.
3. REGULATORY MATTERS
Idaho Power's financial statements reflect the ef}-ects of the dift'erent ratemaking principles followed by the jurisdictions regulating
Idaho Power. Included below is a summary of ldaho Power's regulatory assets and liabilities, as well as a discussion of notable
regulatory matters.
Regulatory Assets and Liabilities
FERC FORM NO.1 (ED. 12-881 Page 123.8
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t1412017
Year/Period of Report
20161o,4
NOTES TO FINANCIAL STATEMENTS (Continued)
The application of accounting principles related to regulated operations sometimes results in Idaho Power recording some expenses
and revenues in a different period than when an unregulated enterprise would record such expenses and revenues. Regulatory assets
represent incurred costs that have been deferred because it is probable they will be recovered from customers through future rates.
Regulatory liabilities represent obligations to make refunds to customers for previous collections, or represent amounts collected in
advance ofincurring an expense.
The following table presents a summary of Idaho Power's regulatory assets and liabilities (in thousands of dollars):
As of December 31, 20f6
December
31,
Description
Remaining
Amortizatio
n Period
f,arning
a Return(l)
Not f,arning
a Return
Total as of
2016 2015
Regulatory Assets:
Income taxes
Unfunded postretirement benefi ts(2)
Pension expense deferrals
Energy efliciency program costs(3)
Power supply costs(4)
Fixed cost adjustment(4)
Asset retirement obligations(5)
Mark-to-market liabilities(6)
Long-term service agreement(7)
Other
$
83,057
s 55)
53,9il
44,445
t7,879
2,541
$ 948,540
263,779
)) )a<
14,154
$ 948,540
263,779
I 05,352
< <<,
53,911
44,445
14,154
29,081
7,t26
$ 87s,027
251.762
85.790
4.482
47.220
36,820
14,410
4.973
30.225
4,800
2017-2018
2017-2018
2043
2017-2054
fi,202
4,585
Total $ 207,38s $ t,264,555 $ 1.471,940 $ 1.355,509
Regulatory Liabilities:
lncome taxes
Enerry efficiency program costs(3)
Settlement agreement sharing
msghani5m(4)
Mark+o-market assets(6 )
Other
$$ s 1.326 $ sr,326
I 0,730
5l,l3l
6.554
$
I 0.730
5"639
7,831
1,516
7,83 I
7,155
3.1s9
405
6,399
Total $16,369 $ 60,673 $ 77,042 $ 67.648
( I ) Eaming a return includes either interest or a retum on the investment as a component of rate base at the allowed rate of retum.
(2) Represents the unfunded obligation ofldaho Power's pension and postretirement benefit plans, which are discussed rn Note I l.
(3) The energy efficiency asset represents the Oregon jurisdiction balance and the liability represents the ldaho jurisdiction balance.
(4) These items are discussed in more detail in this Note 3.
(5) Asset retirement obligations are discussed in Note I 3.
(6) Mark-to-market assets and liabilities are discussed in Note I 6.
(7)Aportionnotearningaretumasof December3l,20l6,willbeeligibletoeamaretumasolJanuary 1,2018.
Idaho Power's regulatory assets and liabilities are typically amortized over the period in which they are reflected in customer rates. ln
the event that recovery ofldaho Power's costs through rates becomes unlikely or uncertain, regulatory accounting would no longer
apply to some or all of ldaho Power's operations and the items above may represent stranded investments. If not allowed full recovery
of these items, Idaho Power would be required to write otlthe applicable portion, which could have a materially adverse flnancial
impact.
FERC FORM NO.1 (ED.12{8)Page 123.9
Name of Respondent
ldaho Power Company
This Report is:
(1)X An OriginalQ) A Resubmission
Date of Report
(Mo, Da, Yr)
04t'1412017
Year/Period of Report
2016tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Power Cost Adjustment Mechanisms and Deferred Power Supply Costs
In both its Idaho and Oregon jurisdictions, Idaho Power's power cost adjustment mechanisms address the volatility of power supply
costs and provide for annual adjustments to the rates charged to its retail customers. The power cost adjustment mechanisms compare
Idaho Power's actual net power supply costs (primarily fuel and purchased power less off-system sales) against net power supply costs
being recovered in Idaho Power's retail rates. Under the power cost adjustment mechanisms, certain ditferences between actual net
power supply costs incurred by ldaho Power and costs being recovered in retail rates are recorded as a deferred charge or credit on the
balance sheets for future recovery or refund. The power supply costs deferred primarily result from changes in contracted power
purchase prices and volumes, changes in wholesale market prices and transaction volumes, tuel prices, and the levels ofldaho Power's
own generation. The Idaho deferral period or PCA year runs from April I through March 31. Amounts deferred during the PCA year
are primarily recovered or refunded during the subsequent June I through May 3l period.
Idaho Jurisdiction Power Cost Adjustment Mechanisrz.' In the ldaho jurisdiction, the annual PCA adjustment consists of (a) a
forecast component, based on a forecast of net power supply costs in the coming year as compared with net power supply costs
included in base rates; and (b) a true-up component, based on the difference between the previous year's actual net power supply costs
and the previous year's fbrecast. The latter component also includes a balancing mechanism so that, over time, the actual collection or
retund ofauthorized true-up dollars matches the amounts authorized. The 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 ofexpenses associated with PURPA power purchases and demand response
incentive payments, which are allocated 100 percent to customers; and
a sales-based adjustment intended to ensure that power supply expense recovery resulting solely from sales changes does not
distort the results of the mechanism.
The table below summarizes the three most recent PCA rate adjustments, all of which also include non-PCA-related rate adjustments
as ordered by the IPUC:
Effective $ ChangeDate (millions) Notes
June 1,2016 $17 .3 The net increase in PCA rates included the application of (a) a customer rate credit of S3.2
million for sharing of revenues with customers fbr the year 2015 under the terms of the
October 20 l4 settlement stipulation, and (b) $4.0 million reduction due to the transfer of
Idaho energy efficiency rider funds.
a
June 1,2015 $( I I .6) The net decrease in PCA rates included the application of (a) a customer rate credit of $8.0
million for sharing of revenues with customers fbr the year 2014 under the terms of the
December 201 I settlement stipulation. and (b) $4.0 million of surplus Idaho energy etficiency
rider tunds.
ln July 2014, the IPUC opened a docket pursuant to which ldaho Power, the IPUC Stafl, and other interested parties further evaluated
Idaho Power's application of the true-up component of the PCA mechanism and whether a defbrral balance adjustment was
appropriate. While the IPUC's docket was closed in August 2014 with no adjustment to the PCA true-up revenue amount. ldaho Power
subsequently met with the IPUC Staffto explore approaches to increasing the accuracy ofthe actual cost recovery under the PCA
mechanism. In May 2015, the IPUC approved a settlement stipulation that resulted in the replacement of the existing load-based
FERC FORM NO.1 (ED.12.88)Page'123.10
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) _A Resubmission
Date of Report
(Mo, Da, Yr)
Mt14t2017
Year/Period of Report
2016to,4
NOTES TO FINANCIAL STATEMENTS (Continued)
adjustment used for determining the power cost deferrals under the PCA mechanism with a similar sales-based adjustment. The
sales-based adjustment functions in the same manner as the previous load-based adjustment but measures deviations between
Idaho-specific test year sales and actual Idaho sales rather than deviations between test year loads and actual loads. The approved
settlement stipulation implemented the new methodology as of January l. 2015.
Oregon Jurisdiaion Power Cost Adjustment Mechanism: Idaho Power's power cost recovery mechanism in Oregon has two
components: an annual power cost update (APCU) and a power cost adjustment mechanism (PCAM). The APCU allows ldaho Power
to reestablish its Oregon base net power supply costs annually, separate from a general rate case, and to forecast net power supply costs
for the upcoming water year. The PCAM is a true-up filed annually in February. The filing calculates the deviation between actual net
power supply expenses incurred for the preceding calendar year and the net power supply expenses recovered through the APCU for
the same period. Under the PCAM, Idaho Power is subject to a portion of the business risk or benefit associated with this deviation
through application of an asymmetrical deadband (or range of deviations) within which ldaho 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 ldaho Power will occur only to the extent that Idaho Power's
actual Oregon-jurisdictional return on equity (Oregon ROE) fbr the year is no greater than 100 basis points below Idaho Power's last
authorized Oregon ROE. A refund to customers will occur only to the extent that ldaho Power's actual Oregon ROE for that year is no
less than 100 basis points above Idaho Power's last authorized Oregon ROE. Oregon jurisdiction power supply cost changes under the
APCU and PCAM during each of 2016 and 2015 are summarized in the table that follows:
Year and
Mechanism APCU or PCAM Adjustment
20I6 PCAM
2OI6 APCU
20I5 PCAM
20I5 APCU
Actual net power supply costs were within the deadband, resulting in no deferral.
A rate increase of $0.2 million annually took effect June l, 2016.
Actual net power supply costs were within the deadband, resulting in no deferral.
A rate decrease of $0.7 million annually took effect June 1,2015.
Notable ldaho Regulatory Matters
IdahoBaseRateChanges.'Idahobaseratesweremostrecentlyestablishedin2012,andadjustedin2014. EffectiveJanuary 1,2012,
Idaho Power implemented new Idaho base rates resulting from IPUC approval of a settlement stipulation that provided tbr a 7.86
percent authorized overall rate of retum on an Idaho-jurisdiction rate base of approximately $2.36 billion. The settlement stipulation
resulted in a 4.07 percent, or $34.0 million, overall increase in Idaho Power's annual Idaho-jurisdiction base rate revenues. ldaho base
rates were subsequently adjusted again in 2012, in connection with Idaho Power's completion of the Langley Gulch power plant. In
lune2012, the IPUC issued an order approving a $58.1 million inoease in annual ldaho-jurisdiction base rates, effective July 1.2012.
The order also provided tbr a $335.9 million increase in ldaho rate base. Neither the seftlement stipulation nor the IPUC orders
adjusting base rates specil'ied an authorized rate of return on equity or imposed a moratorium on Idaho Power filing a general rate case
at a future date.
As noted above in this Note 3, the IPUC also issued a March 2014 order approving ldaho Power's request fbr an increase in the
normalized or "base level" net power supply expense to be used to update base rates and in the determination ofthe PCA rate that
became efl'ective June I . 20 14.
December 201 I ldaho Settlemcnt Stipulation: In December 20 I I , the IPUC issued an order, separate tiom the then-pending general
rate case proceeding, approving a settlement stipulation that provided as tbllows:
FERC FORM NO.1 (ED.12.88)Page 123.1 1
Name of Respondent
ldaho Power Company
This Report is:
(1)X An Original(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04t14t20'.t7
Year/Period of Report
2016tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
a If ldaho Power's actual ldaho-jurisdiction retum on year-end equity (ldaho ROE) fbr 2012,2013,or2014 was less than 9.5
percent, then Idaho Power could amortize up to a total of $45 million of additional accumulated deferred investment tax
credits (ADITC) to help achieve a minimum 9.5 percent ldaho ROE in the applicable year.
If ldaho Power's actual Idaho ROE fbr 2012,2013, or 2014 exceeded 10.0 percent, the amount of Idaho Power's
Idaho-jurisdiction eamings exceeding a 10.0 percent and up to and including a 10.5 percent Idaho ROE for the applicable
year would be shared equally between Idaho Power and its Idaho customers in the form of a rate reduction to become
efl'ective at the time of the subsequent year's PCA mechanism adjustment.
If Idaho Power's actual Idaho ROE for 2012,2013, or 2014 exceeded 10.5 percent, the amount of Idaho Power's ldaho
jurisdictional earnings exceeding a I 0.5 percent ldaho ROE for the applicable year would be allocated 75 percent to Idaho
Power's Idaho customers as a reduction to the pension regulatory asset and 25 percent to ldaho Power.
a
a
October 2014 ldaho Settlement Stipulation: ln October 2014,the IPUC issued an order approving an extension, with modifications,
ofthetermsoftheDecember20ll ldahosettlementstipulationfortheperiodfrom20l5through2019,or until thetermsareotherwise
modified or terminated by order of the IPUC or the full $45 million of additional ADITC contemplated by the settlement stipulation
has been amortized. The provisions of the new settlement stipulation are as follows:
If Idaho Power's annual Idaho ROE in any year is less than 9.5 percent, then ldaho Power may amoftize up to $25 million of
additional ADITC to help achieve a 9.5 percent Idaho ROE for that year, and may amortize up to a total of $45 million of
additional ADITC over the 201 5 through 20 I 9 period.
If Idaho Power's annual ldaho ROE in any year exceeds 10.0 percent, the amount of eamings exceeding a 10.0 percent Idaho
ROE and up to and including a 10.5 percent Idaho ROE will be allocated 75 percent to Idaho Power's ldaho customers as a
rate reduction to be eft'ective at the time of the subsequent year's PCA and 25 percent to ldaho Power.
If Idaho Power's annual Idaho ROE in any year exceeds 10.5 percent, the amount of eamings exceeding a 10.5 percent ldaho
ROE will be allocated 50 percent to Idaho Power's ldaho customers as a rate reduction to be etlective at the time of the
subsequent year's PCA,25 percent to Idaho Power's Idaho customers in the form of a reduction to the pension expense
deferral regulatory asset (to reduce the amount to be collected in the future from Idaho customers), and 25 percent to Idaho
Power.
lf the full $45 million of additional ADITC contemplated by the settlement stipulation has been amortized the sharing
provisions would terminate.
In the event the IPUC approves a change to Idaho Power's ldaho-jurisdictional allowed return on equity as part ofa general
rate case proceeding seeking a rate change effective prior to January l, 2020, the ldaho ROE thresholds (9.5 percent, 10.0
percent, and 10.5 percent) will be adjusted prospectively.
Neither the settlement stipulation nor the associated IPUC order impose a moratorium on Idaho Power filing a general rate case or
other form ofrate proceeding during the term ofthe settlement stipulation.
In 2015, Idaho Power recorded a $3.2 million provision against current revenue for sharing with customers, as its ldaho ROE for 2015
was above 10.0 percent. In 2016. Idaho Power recorded no additional ADITC amortization and no provision tbr sharing with
customers, as its 2016 ldaho ROE was between 9.5 percent and 10.0 percent. Accordingly, at December 31,2016, the full $45 million
of additional ADITC remains available for future use under the terms of the settlement stipulation.
FERC FORM NO.1 (ED.12.88)Pase 123.12
a
a
a
a
a
Name of Respondent
ldaho Power Company
This Report is:
(1)X An Original(21 A Resubmission
Date of Report
(Mo, Da, Yr)
04t't4t2017
Year/Period of Report
2016tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
ln2016 and 2015, Idaho Power recorded the tbllowing fbr sharing with customers under the October 20 14 Idaho settlement
stipulations (in millions):
Year
Reeorded as Refunds
to Customers
Recorded as a Pre-tax
Charge to Pension Expense
2016
2015
$-
$3.2
$-
$-
Fixed Cost Adjustment: The Idaho jurisdiction fixed cost adjustment (FCA) mechanism is designed to remove Idaho Power's financial
disincentive to invest in energy efficiency programs by separating (or decoupling) the recovery offixed costs from the variable
kilowatt-hour charge and linking it instead to a set amount per customer. The FCA mechanism is adjusted each year to collect. or
refund, the difference between the authorized fixed-cost recovery amount and the actual fixed costs recovered by ldaho Power during
the year. The annual change in the FCA recovery is capped at no more than 3 percent ofbase revenue, with any excess defbrred fbr
collection in a subsequent year.
The following table summarizes FCA amounts approved for collection in the prior three FCA years:
Annual Amount
FCA Year Period Rates in Effect (in millions)
2015
2014
$28. l
$r6.9
June l, 2016-May 31. 2017
June l, 2015-May 31, 2016
In July 20 I 4, the IPUC opened a docket to allow ldaho Power, the IPUC Stat{. and other interested parties to turther evaluate the
IPUC Staffs concems regarding the application of the FCA mechanism (including weather-normalization, customer count
methodology, rate adjustment cap, and cross-subsidization issues) and whether the FCA is eff'ectively removing Idaho Power's
disincentive to aggressively pursue energy efficiency programs. In May 201 5, the IPUC approved a settlement stipulation that
modified the FCA mechanism by replacing weather-norrnalized billed sales with actual billed sales in the calculation of the FCA,
applicable for the entirety of calendar year 2015 and thereafter, and reflected in FCA charges efl-ective June I , 2016.
Depreciation Rate Requests
ln2016, Idaho Power conducted a depreciation study ofall electric plant-in-service that provided updates to net salvage percentages
and service life estimates for all ldaho Power plant assets. Based on the study, in October and November 2016,ldaho Power tiled
applications with the IPUC and OPUC, respectively, requesting approval to institute revised depreciation rates lbr ldaho Power's
electric plant-in-service and adjust base rates by an aggregate of$7.4 million to reflect the revised depreciation rates applied to electric
plant in service balances subject to the most recent general rate cases. The proposed adjustments in these applications are an overall
rate increase of0.6 percent in Idaho and 1.3 percent in Oregon.
At the same time. Idaho Power also liled applications with the IPUC and the OPUC requesting authorization to (a) accelerate
depreciation for the North Valmy coal-fired power plant, to allow the plant to be fully depreciated by December 31,2025, (b) establish
a balancing account to track the inuemental costs and benefits associated with the accelerated depreciation date, and (c) adjust
customer rates to recover the associated incremental annual levelized revenue requirement in the aggregate amount of $29.6 million.
FERC FORM NO.1 (ED.12-88)Page 123.13
Name of Respondent
ldaho Power Company
This Report is:
(1)X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
44i1'4t2017
Year/Period of Report
2016tQ4
NOTES TO FINANCIAL STATEMENTS (Continuecl)
The proposed adjustment in these applications are an overall rate increase of2.5 percent in Idaho and 1.9 percent in Oregon.
Idaho Power expects the IPUC and the OPUC to enter final orders in both matters prior to June 2017 in Idaho and November 2017 in
Oregon.
Western Energy Imbalance Market Costs
Idaho Power plans to participate in a new energy imbalance market implemented in the western United States (Western EIM). In
August 2016, Idaho Power filed an application with the IPUC requesting specified regulatory accounting treatment associated with its
participation in the Western EIM. In January 2017 , the IPUC issued an order authorizing Idaho Power's requested deferral accounting
treatment for costs associated with joining the Western EIM. Idaho Power can defer costs incurred until the earlier of when Idaho
Power requests recovery ofthe costs and the deferral balance or the end of20 I 8. Recovery ofdeferred costs will be addressed in a
future IPUC proceeding. Idaho Power anticipates that its participation in the Westem EIM will commence in the spring of 2018.
Notable Oregon Regulatory Matters
Oregon Base Rate Changes: Oregon base rates were most recently established in a general rate case in 2012. In February 2012, the
OPUC issued an order approving a settlement stipulation that provided for a $1.8 million base rate increase, a retum on equity of 9.9
percento and an overall rate of retum of 7.757 percent in the Oregon jurisdiction. New rates in conformity with the settlement
stipulation were effective March l,2012. Subsequently, in September 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 Culch power
plant in Idaho Power's Oregon rate base.
Federal Regulatory Matters - Open Access Transmission Tariff Rates
Idaho Power uses a fbrmula rate for transmission service provided under its OATT, which allows transmission rates to be updated
annually based primarily on financial and operational data ldaho Power files with the FERC. Idaho Power's OATT rates submitted to
the FERC in ldaho Power's four most recent annual OATT Final Informational Filings were as fbllows:
Applicable Period
OATT Rate
(per kW-year)
October 1.2016 to September 30,2017
October l, 2015 to September 30,2016
October 1,2014 to September 30,2015
$
$
$
25.52
23.43
22.48
Idaho Power's current OATT rate is based on a net annual transmission revenue requirement of $127 .4 million, which represents the
OATT formulaic determination of Idaho Power's net cost of providing OATT-based transmission service.
FERC FORM NO.1 (ED.12-88)Page'123.14
Name of Respondent
ldaho Power ComDanv
This Report is:
(1)X An OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
04t1412017
Year/Period of Report
2016tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
4. LONG-TERM DEBT
The following table summarizes Idaho Power's long-term debt at December 3l (in thousands of dollars):
2016 2015
First mortgage bonds:
6.15% Series due 2019
4.50% Series due2020
3.40% Series due2020
2.95% Series due 2022
2.50% Series due2023
6.00% Series due2032
5.50% Series due 2033
5.50% Series due 2034
5.875o/o Series due 2034
5.30% Series due 2035
6.30% Series due2037
6.25% Series due2037
4.85% Series due 2040
4.30% Series due2042
4.00olo Series due 2043
3.650lo Series due 2045
4.05% Series due 2046
$$100,000
130,000
r00.000
75,000
75,000
t00,000
70,000
50,000
55,000
60,000
140,000
100,000
100,000
75,000
75,000
250,000
130,000
r 00,000
75,000
75,000
100.000
70,000
50,000
55,000
60,000
140,000
r 00,000
100,000
75,000
75,000
250,000
r 20,000
Total first mortgage bonds I,575,000 I,555,000
Pollution control revenue bonds:
5. I 5olo Series due 2024(l)
5.25% Series due 2026(l)
Variable Rate Series 2000 due 2027
49,800
I16,300
4,360
49,800
I16,300
4,360
Total pollution control revenue bonds 170,460 170,460
American Falls bond guarantee
Milner Dam note guarantee
Unamortized discounts
19,885
1,064
(4,417)
I 9,885
2,127
(4,4s9\
Total ldaho Power outstanding deb(2)1,761,992 1,743,013
( I ) Humboldt County and Sweetwater County Pollution Control Revenue Bonds are secured by the first mortgage, bringing the total first mongage bonds outstanding
at December3l,20l6, to $1.741 billion.
(2) At December 3 l, 20 I 6 and 20 I 5, the overall effective cost rate of ldaho Power's outstanding debt was 4.87 percent and 4.96 percent. respectively.
FERC FORM NO. r (ED.12-88)Page 123.15
At December 31,2016, the maturities fbr the aggregate amount of Idaho Power long-term debt outstanding were as follows (in
$r.064 $$$ 230"000 $$ I,535,345
Name of Respondent
ldaho Power Companv
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t14t2017
Year/Period of Report
2016tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
thousands ofdollars):
2017 2018 2019 2020 2021 Thereafter
Long-Term Debt Issuances, Maturities, and Availability
On March 10, 2016, Idaho Power issued $120 million in principal amount of 4.05%o lirst mortgage bonds, secured medium-term notes,
Series J, maturing on March 1,2046. On April ll,2016,ldaho Power redeemed, prior to maturity, $100 million in principal amount of
6.15% tlrst mortgage bonds, medium-term notes, Series H, due April 2019.ln accordance with the redemption provisions of the notes,
the redemption included ldaho Power's payment of a make-whole premium to the holders of the redeemed notes in the aggregate
amount of approximately $14.0 million. Idaho Power used a portion of the net proceeds from the March 2016 sale of first mortgage
bonds, medium-term notes to effect the redemption.
On March 6,2015,ldaho Power issued $250 million in principal amount of 3.650/o first mortgage bonds, secured medium-term notes,
Series J, maturing on March 1,2045. On April 23,2015,Idaho Power redeemed, prior to maturity, $120 million in principal amount of
6.0250/o first mortgage bonds, secured medium-term notes, Series H, due July 2018. In accordance with the redemption provisions of
the notes, the redemption included Idaho Power's payment of a make-whole premium to the holders of the redeemed notes in the
aggregate amount of approximately $17.9 million. Idaho Power used a portion of the net proceeds from the March 2015 sale of first
mortgage bonds, medium-term notes to effect the redemption.
In April and May 2016, ldaho Power received orders from the IPUC, OPUC, and Wyoming Public Service Commission (WPSC)
authorizing ldaho Power to issue and sell from time to time up to $500 million in aggregate principal amount of debt securities and
first mortgage bonds, subject to conditions specified in the orders. The order from the IPUC approved the issuance ofthe securities
through May 31, 2019, subject to extensions upon request to the IPUC. The OPUC's and WPSC's orders do not impose a time
limitation for issuances, but the OPUC order does impose a number of other conditions, including a requirement that the interest rates
fbr the debt securities or first mortgage bonds f'all within either (a) designated spreads over comparable U.S. Treasury rates or (b) a
maximum all-in interest rate limit of 7.0 percent.
On May 20,2016,lDACORP and ldaho Power filed a joint shelf registration statement with the U.S. Securities and Exchange
Commission (SEC), which became effective upon filing, for the offer and sale of, in the case of Idaho Power. an unspecified principal
amount of its first mortgage bonds and debt securities. On September 27 ,2016, ldaho Power entered into a selling agency agreement
with seven banks named in the agreement in connection with the potential issuance and sale from time to time of up to $500 million
aggregate principal amount offirst mortgage bonds, secured medium term notes, Series K (Series K Notes), under ldaho Power's
lndenture of Mortgage and Deed of Trust, dated as of October 1,1937, as amended and supplemented (lndenture). At the same time.
Idaho Power entered into the Forty-eighth Supplemental Indenture, dated as ofSeptember 1,2016, to the Indenture. The Forty-eighth
Supplemental lndenture provides for, among other items, the issuance of up to $500 million in aggregate principal amount of Series K
Notes pursuant to the lndenture. As of December 31, 2016. $500 million in principal amount of Series K Notes remained available for
issuance under the lndenture.
Mortgage: As of December 3l,2016,ldaho Power could issue under its Indenture approximately $l.7 billion of additional tlrst
mortgage bonds based on retired first mortgage bonds and total unfunded property additions. These amounts are further limited by the
maximum amount of first mortgage bonds set fbrth in the Indenture.
FERC FORM NO.1 (ED. t2-88)Page 123.16
Name of Respondent
ldaho Power Company
This Report is:
(1)X An Original(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04t',t412017
Year/Period of Report
2016tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
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 first
mortgage on all the properties of Idaho Power. subject only to certain limited exceptions including liens tbr taxes and assessments that
are not delinquent and minor excepted encumbrances. Certain ofthe properties ofldaho Power are subject to easements, Ieases"
contracts, covenants, workmen's compensation awards, and similar encumbrances and minor defects and clouds common 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 permitted by law during a completed default, securities, or cash, except when pledged, or merchandise or equipment
manufactured or acquired for resale. The mortgage ofthe lndenture creates a lien on the interest ofldaho Power in property
subsequently acquired, other than excepted property, subj ect to limitations in the case of consolidation, merger, or sale of all or
substantially all of the assets of Idaho Power. The Indenture requires Idaho Power to spend or appropriate I 5 percent of its annual
gross operating revenues for maintenance, retirement, or amortization of its properties. Idaho Power may, however, anticipate or make
up these expenditures or appropriations within the five years that immediately follow or precede a particular year.
The Forty-eighth Supplemental Indenture increased the maximum amount of first mortgage bonds issuable by Idaho Power under the
Indenture from $2.0 billion to $2.5 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 that Idaho Power's net eamings be at least twice the annual
interest requirements on all outstanding debt of equal or prior rank, including the bonds that ldaho Power may propose to issue. Under
certain circumstances, the net eamings test does not apply, including the issuance of refunding bonds to retire outstanding bonds that
mature in less than hvo years or that are ofan equal or higher interest rate, or prior lien bonds.
5. NOTES PAYABLE
Credit Facilities
On November 6,2015,ldaho Power entered into a Credit Agreement replacing the existing Second Amended and Restated Credit
Agreement, dated October 26.201l. to provide a credit facility that may be used for general corporate purposes and commercial paper
backup. Idaho Power's credit f-acility consists of a revolving line of credit, through the issuance of loans and standby letters of credit.
not to exceed the aggregate principal amount at any one time outstanding of $300 million, including swingline loans in an aggregate
principal amount at any time outstanding not to exceed S30 million, and letters of credit in an aggregate principal amount at any time
outstanding not to exceed $100 million. Idaho Power has the right to request an increase in the aggregate principal amount ofthe
facilities to $450 million, subject to certain conditions.
The interest rate for any borrowings under the tacility is based on either (l) a floating rate that is equal to the highest ofthe prime rate,
federal funds rate plus 0.5 percent, or LIBOR rate plus L0 percent, or (2) the LIBOR rate. plus. in each case, an applicable margin.
provided that the f'ederal funds rate and LIBOR rate will not be less than 0.0 percent. The margin is based on Idaho Power's senior
unsecured long-term indebtedness credit rating by Moody's Investors Service, [nc., Standard and Poor's Ratings Services. and Fitch
Rating Services, Inc., as set forth on a schedule to the credit agreements. Under the credit tacility, Idaho Power pays a facility fee on
the commitment based on its credit rating for senior unsecured long-term debt securities. While the credit facility provides fbr an
original maturity date of November 6,2020, the credit agreement grants Idaho Power the right to request up to two one-year
extensions, subject to certain conditions. On November 7.2016.ldaho Power executed the first extension agreement with the consent
of all the lenders, extending the maturity date under the credit agreement to November 5,2021 . No other terms of the credit t-acility,
included the amount of permitted borrowing under the credit agreement, were affected by the extension.
FERC FORM NO.1 (ED.12.88)Page 123.'17
Name of Respondent
ldaho Power ComDanv
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
Mt't412017
Year/Period of Report
2016tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
At December 31,2016, no loans were outstanding under Idaho Power's facility. At December 3l,2016,ldaho 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 the interest rates of Idaho Power's short-term borrowings were as fbllows at December 31, 2016, and
December 3 l, 20 I 5:
Idaho Power _
2016 2015
Commercial paper balances:
At the end ofyear
Average during the year
Weighted-average interest rate
At the end ofthe year
$ 2r,800 s
s438S
o/o 1.13o/"-o/o
6. COMMON STOCK
Idaho Power Common Stock
No contributions were made to Idaho Power in 2016 or 2015 and no additional shares of Idaho Power common stock were issued.
Restrictions on Dividends
Idaho Power's ability to pay dividends on its common stock held by IDACORP is limited to the extent payment of such dividends
would violate the covenants in its credit facility or ldaho Power's Revised Code of Conduct. A covenant under ldaho Power's credit
facility requires ldaho Power to maintain a leverage ratio of consolidated indebtedness to consolidated total capitalization, as defined
therein, ofno more than 65 percent at the end ofeach fiscal quarter. At December 31,2016, the leverage ratio for Idaho Power was 47
percent. Based on these restrictions, tdaho Power's dividends were limited to $L0 billion at December 3l,2016. There are additional
f'acility covenants, subject to exceptions, that prohibit or restrict the sale or disposition ofproperty without consent and any agreements
restricting dividend payments to the company from any material subsidiary. At December 3l,2016,ldaho Power was in compliance
with those covenants.
Idaho Power's Revised Policy and Code of Conduct relating to transactions behveen and among ldaho 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 ldaho Power's common equity capital below 35 percent of its total adjusted capital without IPUC approval. At December 3 I ,
2016, Idaho Power's common equity capital was 53 percent of its total adjusted capital. Further, Idaho Power must obtain approval
from the OPUC before it can directly or indirectly loan funds or issue notes or give credit on its books to IDACORP.
Idaho Power's articles of incorporation contain restrictions on the payment of dividends on its common stock if preferred stock
dividends are in arrears. As ofthe date ofthis report, Idaho Power has no preferred stock outstanding.
In addition to contractual restrictions on the amount and payment of dividends, the Federal Power Act (FPA) prohibits the payment of
dividends from "capital accounts." The term "capital account" is undefined in the FPA or its regulations, but Idaho Power does not
believe the restriction would limit Idaho Power's ability to pay dividends out of current year eamings or retained eamings.
FERC FORM NO.1 1 123.18
In accordance with Section l0(d) of the Federal Power Act. Idaho Power has $13.3 million of amortization reserves established for
Name of Respondent
ldaho Power Companv
This Report is:
(1) X An Original(2) A Resubmission
Date of Report
(Mo, Da, Yr)
c/4n4t2017
Year/Period of Report
2016tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
certain of its licensed hydroelectric faci lities.
7. STOCK-BASED COM PENSATION
Through its Parent Company IDACORP, Idaho Power has two share-based compensation plans -- the 2000 Long-Term Incentive and
Compensation Plan (LTICP) and the 1994 Restricted Stock Plan (RSP). The RSP was terminated effective February 9.2017.The
LTICP (for officers, key employees, and directors) permits the grant of stock options. restricted stock, performance shares,
perfbrmance units, and several other types of stock-based awards. At December 31, 2016, the maximum number of shares available
undertheLTICPandRSPwere934,T8l andl5,T96,respectively,excluding(i)issuedbutunvestedperformance-basedrestricted
shares and (ii) issued but unvested time-based restricted shares.
Stock Awards.. Restricted stock awards have three-year vesting periods and entitle the recipients to dividends and voting rights.
Unvested shares are restricted as to disposition and subject to forfeiture under certain circumstances. The fair value ofthese 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 attainment ofspecific perfbrmance
conditions over the three-year vesting period. The performance conditions are h.vo equally-weighted metrics, cumulative earnings per
share (CEPS) and total shareholder return (TSR) relative to a peer group. Depending on the level of attainment of the performance
conditions and the year issued, the final number ofshares awarded can range from zero to 150 percent ofthe target award fbr awards
grantedpriorto20l5andfromzeroto200percentofthetargetawardforawardsgrantedin20l5 and2016. Dividendsareaccrued
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 tbir value of this portion of the awards is charged to compensation expense
over the requisite service period, based on the number of shares expected to vest. The grant-date fair value of the TSR portion is
estimated using the market value at the date of grant and a statistical model that incorporates the probability of meeting performance
targets based on historical returns relative to the peer group. The fair value ofthis portion ofthe awards is charged to compensation
expense over the requisite service period, provided the requisite service period is rendered. regardless ofthe level ofTSR metric
attained.
FERG FORM NO.1 (ED. 12-88)Page 123.19
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t14t2017
Year/Period of Report
20't6tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
A summary of restricted stock and performance share activity is presented below. Share amounts represent the shares of IDACORP
common stock:
Idaho Power
Number of
Weighted-A
verage
Grant Date
Fair Value
Nonvested shares at January 1,2016
Shares granted
Shares forfeited
Shares vested
228,790 $
I 13,708
(24,699\
( r r 8,273)
52.44
64.1 8
65.75
44.32
Nonvested shares at December 31.2016 t99,526 $ 61.51
The total fair value of shares vested was $8.3 million in2016 and $8.3 million in 2015. At December 3l,2016,ldaho Power had $4.9
million oftotal unrecognized compensation cost related to nonvested share-based compensation that was expected to vest. These costs
are expected to be recognized over a weighted-average period of 1.73 years. IDACORP uses original issue and/or treasury shares for
these awards.
ln2016, a total of 12,681 shares of IDACORP common stock were awarded to directors of IDACORP and Idaho Power at a grant date
fair value of$70.96 per share. Directors elected to defer receipt of 4,931 ofthese shares, which are being held as deferred stock units
with dividend equivalents reinvested in additional stock units.
Compensation Expense: The following table shows ldaho Power's share of the compensation cost recognized in income and the tax
benefits resulting from these plans (in thousands ofdollars):
Idaho Power
2016 2015
Compensation cost
Income tax benefit
$ 5,494 $ 5,221
148 2
No equity compensation costs have been capitalized. These costs are primarily reported within other operations and maintenance
expense in the consolidated statements of income.
FERC FORM NO.1 (ED.12.88)Page 123.20
Name of Respondent
ldaho Power Company
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t1412017
Year/Period of Report
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
8. COMMITMENTS
Purchase Obligations
At December 31, 2016,ldaho Power had the following long-term commitments relating to purchases of energy, capacity, transmission
rights, and fuel (in thousands ofdollars):
2017 2018 20t9 2020 2021 Thereafter
Cogeneration and power production
Fuel
$ 228,s4s
56,534
$ 23s,366
22,070
$ 229,4s0
8,948
s 229,473
8,433
s 235,922 S 3,150,212
8,399 100,978
As of December 31,2016, Idaho Power had 945 MW nameplate capacity of PURPA-related projects on-line, with an additional 178
MW nameplate capacity of projects projected to be on-line in2017 and an additional 9 MW expected to be added in 2019. The power
purchase contracts fbr these projects have original contract terms ranging from one to 35 years. Idaho Power's expenses associated with
PURPA-related projects were approximately Sl54 million in2016 and $l3l million in 2015.
Idaho Power also has the following long-term commitments for lease guarantees, equipment" maintenance and services, and industry
related fees (in thousands ofdollars):
20t7 2018 2019 2020 2021 Thereafter
Operating leases s 3.339 $ 4.r7r $ 4.237 $ 4,076 $ 4.038 $ 29.2t8
Equipment, maintenance. and service agreements 26.884 12.435 6,r85 6,871 3.421 5 1,085
FERC and other industry-related fees r 2,508 12,444 8,434 5,744 5,744 28.720
Idaho Power's expense for operating leases was approximately $4.9 million in 2016 and $4.4 million in 2015
Guarantees
Through a self-bonding mechanism, Idaho Power guarantees its portion of reclamation activities and obligations at BCC, of which
IERCo owns a one-third interest. This guarantee, which is renewed annually with the Wyoming Department of Environmental Quality,
was $71 million at December 31,2016, representing IERCo's one-third share of BCC's total reclamation obligation. BCC has a
reclamation trust fund set aside specifically for the purpose of paying these reclamation costs. At December 31,2016. the value of the
reclamation trust fund was $78 million. During 2016, the reclamation trust fund distributed approximately $6 million for reclamation
activity costs associated with the BCC surface mine. BCC periodically assesses the adequacy of the reclamation trust fund and its
estimate of future reclamation costs. To ensure that the reclamation trust fund maintains adequate reserves, BCC has the ability to, and
does, add a per-ton surcharge to coal sales, all ofwhich are made to the Jim Bridger plant. Because ofthe existence ofthe fund and the
ability to apply a per-ton surcharge. the estimated fair value of this guarantee is minimal.
Idaho Power enters into financial agreements and power purchase and sale agreements that include indemnification provisions relating
to various forms of claims or liabilities that may arise f-rom the transactions contemplated by these agreements. Generally, a maximum
obligation is not explicitly stated in the indemnilication provisions and, theretbre, the overall maximum amount of the obligation under
such indemnification provisions cannot be reasonably estimated. ldaho Power periodically evaluates the likelihood of incurring costs
under such indemnities based on their historical experience and the evaluation of the specific indemnities. As of December 3 I , 20 16,
management believes the likelihood is remote that ldaho Power would be required to perform under such indemniflcation provisions or
otherwise incur any significant losses with respect to such indemnification obligations. Idaho Power has not recorded any liability on
FERC FORM NO.1 (ED.12.88)Page 123.21
Name of Respondent
ldaho Power Comoanv
This Report is:
(1)X An Original(21 A Resubmission
Date of Report
(Mo, Da, Yr)
04t14t2017
Year/Period of Report
2016tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
its consolidated balance sheet with respect to these indemnification obligations.
9. CONTINGENCIES
Idaho Power has in the past and expects in the tuture to become involved in various claims, controversies, disputes, and other
contingent matters, including the items described below. Some of these claims, controversies, disputes, and other contingent matters
involve litigation and regulatory or other contested proceedings. The ultimate resolution and outcome of litigation and regulatory
proceedings is inherently difficult to determine, particularly where (a) the remedies or penalties sought are indeterminate, (b) the
proceedings are in the early stages or the substantive issues have not been well developed, or (c) the matters involve complex or novel
legal theories or a large numberofparties. In accordance with applicable accounting guidance Idaho Power, as applicable, establishes
an accrual fbr 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 ofany amounts accrued. Idaho Power
monitors those matters for developments that could aff'ect the likelihood of a loss and the accrued amount, if any, and adjust the
amount as appropriate. Ifthe 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 tbr any developments that would make the loss contingency both probable and
reasonably estimable. As of the date of this report, Idaho Power's accruals fbr loss contingencies are not material to their financial
statements as a whole; however, future accruals could be material in a given period. Idaho Power's determination is based on currently
available information, and estimates presented in financial statements and other financial disclosures involve significant judgment and
may be subject to significant uncertainty.
Western Energy Proceedings
High prices fbr electricity, energy shortages, and blackouts in California and in the western wholesale markets during 2000 and 2001
caused numerous purchasers of electricity in those markets to initiate proceedings to consider requiring refunds and other forms of
disgorgement from energy sellers. Idaho Power and IESCo (as successor to IDACORP Energy L.P.) believe that the current state of
the FERC's orders and the settlement releases they have obtained. including a settlement Idaho Power and IESCo executed in
December 2016 and approved by the FERC relating to the Califomia energy market proceedings, will eliminate or restrict potential
future claims that might result from the remaining proceedings. As Idaho Power believes that its participation in the Califomia and
western wholesale market proceedings has effectively concluded, Idaho Power expects that these matters will not have a material
adverse effect on its respective results ofoperations or flnancial condition in future periods.
Hoku Corporation Bankruptcy Claims
On June 26,2015, the trustee in the Hoku Corporation chapter 7 bankruptcy case (1r? Re: Hoku Corporation, United States Bankruptcy
Court, District of ldaho, Case No. l3-40838 JDP) filed a complaint against ldaho Power, alleging that specified payments made by
Hoku Corporation to Idaho Power in the six years prior to Hoku Corporation's bankruptcy liling in July 20 l3 should be recoverable by
the trustee as constructive fraudulent transfbrs. Hoku Corporation was the parent entity of Hoku Materials, tnc., with which Idaho
Power had an electric service agreement approved by the IPUC in March 2009. Under the electric service agreement. Idaho Power
agreed to provide electric service to a polysilicon production facility under construction by Hoku Materials in the state of ldaho. Idaho
Power also had agreements with Hoku Materials pertaining to the design and construction of apparatus fbr the provision of electric
service to the polysilicon plant. The trustee's complaint against ldaho Power requested recovery from Idaho Power in amounts up to
approximately $36 million. The complaint alleged that the payments made by Hoku Corporation to ldaho Power were subject to
recovery by the trustee on the basis that Hoku Corporation was insolvent at the time ofthe payments and did not have any legal or
equitable title in the polysilicon plant or liability fbr Hoku Materials'debts, and thus did not receive reasonably equivalent value fbr the
FERC FORM NO.1 (ED. {2-88)Page'123.22
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04t14t2017
Year/Period of Report
2016tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
payments it made for or on behalf of Hoku Materials. In September 2016, the bankruptcy judge issued an oral opinion granting Idaho
Power's and other parties' motion for substantive consolidation of Hoku Corporation and Hoku Materials, which consolidated the
bankruptcies of Hoku Corporation and Hoku Materials. On December 20,2016, the bankruptcy judge entered an order of dismissal,
with prejudice, of the complaint against Idaho Power. which effectively ended ldaho Power's participation in the adversary
proceedings.
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, record 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 its consolidated t'inancial 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.
However, Idaho Power does believe that future capital investment for infrastructure and modifications to its electric system facilities
could be significant to comply with these regulations.
IO. BENEFIT PLANS
Idaho Power sponsors defined beneflt and other postretirement benefit plans that cover the majority of its employees. Idaho Power also
sponsors a detlned contribution 401(k) employee savings plan and provides certain post-employment benefits.
Pension Plans
Idaho Power has two pension plans-a noncontributory defined beneflt pension plan (pension plan) and two nonqualified defined
benefit pension plans fbr certain senior management employees called the Security Plan for Senior Management Employees I and
Security Plan for Senior Management Employees II (together, SMSP). Idaho Power also has a nonqualified defined benefit pension
plan fbr directors that was flozen 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 tunding policy for the pension plan is to contribute at least the minimum required under the Employee Retirement
IncomeSecurity Actof 1974(ERISA)butnotmorethanthemaximumamountdeductibleforincometaxpurposes. ln2016and20l5
Idaho Power elected to contribute more than the minimum required amounts in order to bring the pension plan to a more funded
position, to reduce future required contributions, and to reduce Pension Benefit Guaranty Corporation premiums.
FERC FORM NO.1 (ED.12.88}Page 123.23
Name of Respondent
ldaho Power Comoanv
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t14t2017
Year/Period of Report
2016to,4
NOTES TO FINANCIAL STATEMENTS (Continued)
The following table summarizes the changes in beneflt obligations and plan assets of these plans (in thousands of dollars)
Pension Plan SMSP
2016 2015 2016 2015
Change in projected benefit obligation:
Benefit obligation at January I
Service cost
Interest cost
Actuarial loss (gain)
Plan amendment
Benefits paid
$835.523
32,019
37,8 I 3
22,640
8l
(33,016)
95,389
1,228
4,275
2,933
120
(4,37s)
$ 94.4r0
1.689
3.868
(352)
$ 844.812 $
33. r 64
35,1 7 1
(47,952)
(29,672)(4,226)
Projected benefit obligation at December 3 I 895,060 835,523 99,570 95.389
Change in plan assets:
Fair value at January I
Actual retum on plan assets
Employer contributions
Benefits paid
559,616
40,968
40,000
(33,0 l 6)
559.719
(e,431)
39.000
(29,672)
Fair value at December 3 I 607,568 559,6 I 6
Funded status at end ofyear s (287,492) S (27s,907\ $ (99,570) $ (95,389)
Amounts recognized in the statement of financial position
consist of:
Other current liabilities
Noncurrent liabilities
$$s (4,733) $
(94,837)
(4,423)
(90.966)(287,492) (27s,907\
Net amount recopgrized s (28'1,4e2) S (27s,907) $ (ee,570) $ (95,38e)
Amounts recognized in accumulated other
comprehensive income consist of:
Net loss
Prior service cost
$263,634
96
253,212
74
33,660 34,260
673625
Subtotal 263,730 2s3.286 34,28s 34,933
Less amount recorded as regulatory mset (263.730) (2s3,286)
Net amount recogrized in accumulated other
comprehensive income $$$ 34,285 $ 34,933
Accumulated benefit obligation S 766,367 S 7 14,994 $ 9l, 146 $ 86,838
As a non-qualified plan, the SMSP has no plan assets. However, Idaho Power has a Rabbi trust designated to provide funding for
SMSP obligations. The Rabbi trust holds investments in marketable securities and corporate-omed lit'e insurance. The recorded value
of these investments was approximately $78 million and $69 million at December 31"2016 and 2015. respectively, and is retlected in
Investments and in Company-owled 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 f'air value ofthe assets.
Pension Plan SMSP
2016 2015 2016 2015
Service cost
lnterest cost
Expected retum on assets
Amortization of net loss
Amortization of prior service cost
s 32,0r9
37.8 I 3
(42,08 r )
r3.33 r
59
$ 33,164
35,t71
(42.310)
13,92'7
221
$ r.228
4.275
s 1,689
3.868
1 sl?
168
4,1 95
185
Net periodic pension cost 41,l4l 40,173 9,203 9,937
(22. l8 r ) (2t .173)due to the effects of r)
for financial $937Netbenefit cost 960
FERC FORM NO.1 1 123.24
Name of Respondent
ldaho Power ComDany
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
0/,t14t2017
Year/Period of Report
2016tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
( I ) Net periodic beneflt costs for the pension plan are recognized lor financial reporting based upon the authorization of each regulatory jurisdiction in which{ldaho
Power operates. Under IPUC order, income statement recognition of pension plan costs is deferred until costs are recovered through rates.
The following table shows the components of other comprehensive income for the plans (in thousands of dollars):
Pension Plan SMSP
2016 2015 2016 20ts
Actuarial (loss) gain during the year
Reclassi fi cation adj ustments for:
Amortization of net loss
Plan amendment service cost
Amortization of prior service cost
Adjustment for deferred tax effects
Adiustment due to the effects of resulation
s (23,753)s (3,7e0)
13,927
$ (2,933)
? s??
( 120)
168
(253)
s 3s3
4,195r 3,33 I
(81)
59
4,083
6,361
221
(4,0s0)
(6,308)
t85
(1,85t)
Other comprehensive income recognized relatedtopensionbenefitplans $ - $ - $ 394 $ 2,882
ln 2017, Idaho Power expects to recognize as components of net periodic benefit cost $ 16.6 million from amortizing amounts recorded
in accumulated other comprehensive income (or as a regulatory asset for the pension plan) as of December 31.2016, relating to the
pension plan and SMSP. This amount consists of $13.5 million of amortization of net loss for the pension plan and $3.0 million of
amortization of net loss and $0. I 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):
2017 2018 2019 2020 2021 2022-2026
Pension Plan $ 32,592 S 34,957 $ 37,375 $ 39,938 $ 42,477 $ 248,151SMSP 4,829 4,630 4,594 5,199 4,843 26,976
As of December 31,2016, Idaho Power's minimum required contributions to the pension plan are estimated to be zero in 2017 , though
Idaho Power plans to contribute between $20 mitlion and $40 million to the pension plan during 2017 in order to help balance the
regulatory collection of these expenditures with the amount and timing of contributions and to mitigate the cost of being in an
underiunded position.
Postretirement Benefits
Idaho Power maintains a defined benefit postretirement benefit plan (consisting ofhealth 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 qualitying
dependents. Retirees hired on or after January I , I 999, have access to the standard medical option at ful I cost, with no contribution by
Idaho Power. Benefits for employees who retire alter December 31,2002, are limited to a fixed amount, which has limited the growth
of ldaho Power's tuture obligations under this plan.
FERC FORM NO.1 (ED.12.88)Pase 123.25
Name of Respondent
ldaho Power Comoanv
This Report is:
(1)X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
04114t2017
Year/Period of Report
2016tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
The following table summarizes the changes in benefit obligation and plan assets (in thousands of dollars):
2016 2015
Change in accumulated benefit obligation:
Benefit obligation at January I
Service cost
lnterest cost
Actuarial loss (gain)
Benefits paid( I )
$62,393 $
l"l l6
2,766
1,550
(3,949)
6s,999
1,235
2,678
(s,008)
(2,s1l)
Benefit obligation at December 3l 63,876 62,393
Change in plan assets:
Fair value ofplan assets at January I
Actual return on plan assets
Employer contributions( I )
Benefits paid( I )
35,566
) l)<
957
(3,949)
38,375
85
(383)
(2,51 I )
Fair value of plan assets at December 3l 34,999 35,566
Funded status at end ofyear (included in noncurrent liabilities)$ (28,877) $ (26,827)
(l) Contributions and benefits paid are each net of $3.7 million and $3.5 million of plan participant contributions, and $0.3 million and $0.3 million of Medicare Part
D subsidy receipts for 2016 and 201 5, respectively.
Amounts recognized in accumulated other comprehensive income consist of the following (in thousands of dollars):
2016 2015
Net gain
Prior service cost
$(5s) $
t04
( l,654)
130
Subtotal
Less amount recognized in regulatory assets
49
(4e)
(1,s24)
1,524
Net amount recognized in accumulated other comprehensive income $s
The net periodic postretirement benefit cost was as follows (in thousands of dollars):
2016 2015
Service cost
lnterest cost
Expected retum on plan assets
Amortization of prior service cost
s l,l r6 s
2,766
(2,47 4)
26
1,235
2.678
(2,680)
l5
Net periodic postretirement beneflt cost 1,248$ r,434 $
FERC FORnt NO. I (ED. t2-88)Page 123.26
Name of Respondent
ldaho Power Company
This Report is:
(1)X An OriginalQ) A Resubmission
Date of Report
(Mo, Da, Yr)
ul14t20't7
Year/Period of Report
2016tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
The following table shows the components of other comprehensive income fbr the plan (in thousands of dollars)
2016 2015
Actuarial (loss) gain during the year
Reclassification adjustments for amortization of prior service cost
Adjustment for def'erred tax effects
Adjustment due to the effects of regulation
s (r,600) $
26
615
959
2,413
l5
(e4e)
(t,479)
Other comprehensive income related to postretirement benefit plans $$
Medicare Act: The Medicare Prescription Drug, Improvement and Modernization Act of 2003 was signed into law in December 2003
and established a prescription drug benefit under Medicare Part D, as well as a federal subsidy to sponsors ofretiree 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 benetlt payments of the postretirement benefit plan and expected Medicare Part D
subsidy receipts (in thousands ofdollars):
2017 2018 2019 2020 2021 2022-2026
Expected benefit payments
Expected Medicare Part D subsidy receipts
$ 3,980
370
$ 4,040
4t0
$ 4,120
s20
$ 20,620
3,240
$ 4,070 $ 4,r00450 480
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 SMSP
Postretirement
Benelits
2016 2015 2016 2015 2016 2015
Discount rate
Rate of compensation increase( I )
Medical trend rate
Dental trend rate
Measurement date
4.45o/o
4.11o/o
4.600/o
4.1 lo/o
4.45o/o
4.7 5o/o
4.600/o
4.50Vo
4.45o/o 4.600/o
8.3o/o
5.00/o
1213U2016
9.7o/o
5.0o/o
t2/3112015t2l3U20t6 t2l3U20t5 1213112016 t2t3U20ts
( | ) the ZO I O rate of compensation increase assumption for the pension plan includes an inflation component of 2.50% plus a L6 I % composite ment increase
component that is based on employees' years ofservice. Merit salary increases are assumed to be 8.0%o for employees in their first year ofservice and scale down to 07o
lor employees in their fortieth year ofservice and beyond.
FERC FORM NO.1 (ED.12{8)Page 123.27
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
0/.t1412017
Year/Period of Report
2016tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
The following table sets forth the weighted-average assumptions used to determine net periodic beneflt cost fbr all tdaho
Power-sponsored pension and postretirement benefit plans:
Pension Plan SMSP
Postretirement
Benefits
2016 2015 20t6 2015 20t6 2015
Discount rate
Expected long-term rate ofretum on
aSSetS
Rate of compensation increase
Medical trend rate
Dental trend rate
4.600/o 4.25o/o 4.600/o 4.20o/o 4.600/o 4.20o/o
7.50o/o
4.11o/o
750%
4.tt%
7.25o/o 7.25o/o
4.500/o 4.50%
8.3%
5.0o/o
9.7o/o
5.0o/o
The assumed health care cost trend rate used to measure the expected cost of health benefits covered by the postretirement plan was
8.3 percent in 2016 and is assumed to decrease to 6.8 percent in2017,5.3 percent in 2018,5.2 percent in 2019 and to gradually
decrease to 4.5 percent by 2096. The assumed dental cost trend rate used to measure the expected cost ofdental benefits covered by
the plan was 5.0 percent. or equal to the medical trend rate if lower, for all years. A one percentage point change in the assumed health
care cost trend rate would have the following effects at December 31,2016 (in thousands of dollars):
One-Percentage-Point
Increase Decrease
Effect on total of cost components
Effect on accumulated postretirement benefit obligation
s 382 $
3,687
(280)
(2,84 l )
Plan Assets
Pension Asset Allocation Policy: The target allocation and actual allocations at December 31.2016. tbr the pension asset portfolio by
asset class is set forth below:
Target
Actual
Allocation
December 31,
2016Asset Class
Debt securities
Equity securities
Real estate
Other plan assets
24o/o
54o/o
6o/o
l6Yo
22o/o
560/o
7o/o
lsYo
Total lO0o/o 100%
Assets are rebalanced as necessary to keep the porttblio close to target allocations.
FERC FORM NO.1 (ED.12-88}Page 123.28
The plan's principal investment objective is to maximize total retum (defined as the sum of realized interest and dividend income and
Name of Respondent
ldaho Power ComDany
This Report is:
(1)X An Original(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04t',14t2017
Year/Period of Report
2016ta4
NOTES TO FINANCIAL STATEMENTS (Continued)
realized and unrealized gain or loss in market price) consistent with prudent parameters of risk and the liability profile of the portfblio.
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 ldaho Power's asset allocation process are to:
determine if the investments have the potential to eam the rate of retum assumed in the actuarial liability calculations;
match the cash flow needs ofthe plan. Idaho Power sets bond allocations sufficient to cover at least five years ofbenefit
payments and cash allocations sut'ficient to cover the current year benefit payments. Idaho Power then utilizes growth
instruments (equities, real estate, venture capital) to fund the longer-term liabilities ofthe plan; and
maintain a prudent risk profile consistent with ERISA fiduciary standards.
Allowable plan investments include stocks and stock funds, investment-grade bonds and bond funds, core real estate funds, private
equity funds, and cash and cash equivalents. With the exception of real estate holdings and private equity, investments must be readily
marketable so that an entire holding can be disposed of quickly with only a minor effect upon market price.
Rate-of-retum projections for plan assets are based on historical risk/return relationships among asset classes. The primary measure is
the historical risk premium each asset class has delivered versus the yield on the Moody's AA Corporate Bond Index. This historical
risk premium is then added to the current yield on the Moody's AA Corporate Bond Index. Additional analysis is performed to measure
the expected range ofretums, 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 retums generated over the past 20 years when interest rates were generally much
higher.
Idaho Power's asset modeling process also utilizes historical market returns to measure the portfolio's exposure to a'Vorst-case"
market scenario, to determine how much performance could vary from the expected ooaverage" performance over various time periods.
This'Vorst-case" modeling, in addition to cash tlow matching and diversification by asset class and investment style, provides the
basis lbr managing the risk associated with investing portlblio assets.
Fair Value of Plan Assets.' Idaho Power classifies its pension plan and postretirement benefit plan investments using the three-level
fair value hierarchy described in Note 16. The following table presents the fair value of the plans'investments by asset category (in
thousands ofdollars).
FERC FORM NO.1 (ED.12.88)Pase 123.29
a
a
Name of Respondent
ldaho Power Company
This Report is:
(1)X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
Mt't4t2017
Year/Period of Report
2016tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Level I Level2 Level 3 Total
Assets at December 31, 2016
Cash and cash equivalents
Short-term bonds
Intermediate bonds
Long-term bonds
Equity Securities: Large-Cap
Equity Securities: Mid-Cap
Equity Securities: Small-Cap
Equity Securities: Micro-Cap
Equity Securities: Intemational
Equity Securities: Emerging Markets
Plan assets measured at NAV (not subject to
hierarchy disclosure)
Equity Securities: I nternational
Equity Securities: Emerging Markets
Real estate
Private market investments
Commodities fund
$ 28,632
I I,t98
I 1.904 88,734
20.573
$ 28,632
I 1,198
r00,638
20,573
80,582
68,634
53,766
29,67 t
7.782
9,204
64,930
24,443
41,907
33,713
3l,895
80,582
68,634
53,766
29,671
7,782
9,204
Total $ 301.373 $ 109,307 $ 607,568
Postretirement plan assets( I )$ 28 $ 34,971 $ 34,999
Assets at December 31, 2015
Cash and cash equivalents
Short-term bonds
Intermediate bonds
Long-term bonds
Equity Securities: Large-Cap
Equity Securities: Mid-Cap
Equity Securities: Small-Cap
Equity Securities: Micro-Cap
Equity Securities: International
Equity Securities: Emerging Markets
Plan assets measured at NAV (not subject to
hierarchy disclosure)
Equity Securities: Intemational
Equity Securities: Emerging Markets
Real estate
Private market investments
Commodities fund
s 10,5r9
11,023
11,499
$ 10,519
I I,023
104,241
21,747
73,489
64,397
47,777
22,186
7,698
9.679
59,787
23,167
39,035
37,316
27.555
92,742
21,747
73,489
64,397
47,777
22,186
7,698
9.679
Total $ 258,267 $ 114,489 - $ 559,616
Postretirementplan assets(l) S 16 $ 35,550 $ 35,566
( I ) The postretrrement benefits assets are pnmarily life insurance contracts.
For the year ended December 31,2016 and December 31. 2015. there were no material transt'ers into or out of Levels l, 2, or 3 other
than the adoption of ASU 2015-07 , Fair Value Measurement (Topic 820) - Disclosures for Investments in Certain Entilies That
Calculate Net Asset Value per Share (or lts Equivalent), which removed from the fair value hierarchy, investments fbr which the
practical expedient is used to measure lair value at net asset value (NAV). In prior years, certain investments were measured using
NAV as a practical expedient for fair value, and these amounts were included as level 2 and3 items in the f-air value hierarchy. The
FERG FORM NO.1 (ED.12{8)Pase 123.30
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t't412017
Year/Period of Report
20't6tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
requirements of this ASU were adopted retrospectively; therefore, the 2015 amounts have been reclassified to conform to the 2016
presentation. Because these amounts are no longer included in the fair value hierarchy as level 3 items, the level 3 reconciliations are
no longer applicable and have been excluded from this footnote.
Fair Value Measurement of Level 2 Plan assets and Plan assets measured at NAV:
Level 2 Bonds: These investments represent U.S. government, agency bonds, and corporate bonds. The U.S. govemment and agency
bonds. as well as the corporate bonds, are not traded on an exchange and are valued utilizing market prices for similar assets or
liabilities in active markets.
Level 2 Postretirement Asset: This asset represents an investment in a lif'e insurance contract and is recorded at fair value, which is the
cash surrender value, less any unpaid expenses. The cash surrender value ofthis insurance contract is contractually equal to the
insurance contract's proportionate share ofthe market value ofan associated investment account held by the insurer. The investments
held by the insurer's investment account are all instruments traded on exchanges with readily determinable market prices.
Commingled Funds: These funds, made up of the intemational, emerging markets equity securities, and commodites fund measured at
NAV, are not publicly traded, and therefore no publicly quoted market price is readily available. The value of the commingled funds
are presented at estimated fair value, which is determined based on the unit value of the fund. The values of these investments are
calculated by the custodian fbr the fund company on a monthly or more fiequent basis, and are based on market prices of the assets
held by each of the commingled tunds divided by the number of tund shares outstanding for the respective fund. The investments in
commingled funds have redemption limitations that permit monthly redemption following notice requirements of 5 to 7 days.
Real Estate: Real estate holdings represent investrnents in open-ended commingled real estate funds. As the property interests held in
these real estate funds are not fiequently traded, establishing the market value ofthe property interests held by the fund, and the
resulting unit value offund shareholders, is based on unobservable inputs including property appraisals by the fund companies,
property appraisals by independent appraisal firms, analysis ofthe replacement cost ofthe property, discounted cash flows generated
by property rents and changes in property values, and comparisons with sale prices of similar properties in similar markets. These
open-ended real estate funds also fumish annual audited financial statements that are also used to further validate the infbrmation
provided. Redemptions are generally available on a quafterly basis, with l0 to 35 days written notice. depending on the individual
fund. If the fund has sufficient liquidity, the redemption will be processed at the lund NAV or the fund's estimate of fair value at the
end of the quafter. If the fund does not have sufficient liquidity to honor the full redemption, the remainder will be set for redemption
the following quarter on a pro-rata basis with other redemption requests. This same process will repeat until the redemption request has
been completed. To protect other fund holders, real estate fi:nds have no duty to liquidate or encumber funds to meet redemption
requests.
Private Market Investments: Private market investments represent two categories: fund of hedge funds and venture capital funds. These
funds are valued by the fund companies based on the estimated fair values ofthe underlying fund holdings divided by the fund shares
outstanding or multiplied by the ownership percentages of the holder. Some hedge fund strategies utilize securities with readily
available market prices, while others utilize less liquid investment vehicles that are valued based on unobservable inputs including
cost, operating results, recent tunding activity. or comparisons with similar investment vehicles. Redemptions are available on a
quarterly basis with 70 days written notice. Redemptions will be processed at the quarterly NAV or tbir value within 60 days fbllowing
quarter end. In the event of a full redemption, a reserve amount of 5% to l0% of the redemption amount may be held in reserve until
the audited financial statements of the fund are published. This allows the fund to adiust the redemption so that other fund holders are
not adversely impacted. Venture capital fund investments are valued by the fund companies based on estimated fair value of the
FERC FORM NO.1 (ED. {2-88)Page 123.31
Name of Respondent
ldaho Power Company
This Report is:
(1) X An OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
04t14t2017
Year/Period of Report
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
underlying fund holdings divided by the fund shares outstanding. Some venture capital investments have progressed to the point that
they have readily available exchange-based market valuations. Early stage venture investments are valued based on unobservable
inputs including cost, operating results, discounted cash flows, the price olrecent funding events, or pending offers from other viable
entities. These private market investments furnish annual audited financial statements that are also used to further validate the
information provided. These funds are tbrmed for a stated life of l0 to I 5 years. The general partner can extend the fund life tbr 2 or 3
one-year periods. The f'und can be further extended with the approval of the limited partners. There are generally no redemption rights
associated with these funds. The limited partner must hold the fund tbr the life of the fund or find a third-party buyer.
Employee Savings Plan
Idaho Power has a defined contribution plan designed to comply with Section 401(k) ofthe Internal Revenue Code and that covers
substantially all employees. Idaho Power matches specified percentages of employee contributions to the plan. Matching annual
contributions were $8 million and $7 million in2016 and 2015, respectively.
Post-employment Benefits
Idaho Power provides certain benefits to former or inactive employees, their beneficiaries, and covered dependents after employment
but before retirement, in addition to the health care benefits required under the Consolidated Omnibus Budget Reconciliation Act.
These benefits include salary continuation, health care and life insurance for those employees found to be disabled under Idaho
Power's disability plans, and health care for surviving spouses and dependents. Idaho Power accrues a liability for such benefits. The
post employment benefit amounts included in other deferred credits on Idaho Power's consolidated balance sheet at both
December 31,2016 and 2015, were $2 million.
II. PROPERTY, PLANT AND EQUIPMENT AND JOINTLY-OWNED PROJECTS
The following table presents the major classifications of Idaho Power's utility plant in service, annual depreciation provisions as a
percent of average depreciable balance, and accumulated provision for depreciation for the years ended December 31, 2016 and 20 I 5
(in thousands of dollars):
2016 20r5
Balance Avg Rate Balance Avg Rate
Production
Transmission
Distribution
General and Other
s 2,551,823
1,120,903
t,637,131
422.187
2.40% $
2.02o/o
2.72o/o
5.49%
2,422,175
1,077,065
1,578,445
407,779
2.46Yo
2.01o/o
2.72o/o
5.620/o
Total in service
Accumulated provision for depreciation
5,732,044
(2,175.086)
2.640/o 5,485,464
(2,097,432)
2.680/o
ln service - net $ 3,556,958 s 3"388,032
At December 3l,2016,ldaho PoweCs construction work in progress balance of $405 million included relicensing costs of $249
million for the Hells Canyon Complex (HCC). Idaho Power's largest hydroelectric complex. The IPUC authorizes Idaho Power to
include in its Idaho jurisdiction rates approximately 56.5 million annually ($10.7 million when grossed-up for the effect of income
taxes) of AFUDC relating to the HCC relicensing project. Collecting these amounts now will reduce the amount collected in the future
FERC FORM NO.I (ED. 12.881 Page 123.32
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04t14t2017
Year/Period of Report
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
once the HCC relicensing costs are approved for recovery in base rates. At December 31,2016,ldaho Power's accumulated provision
tbr rate refirnds tbr collection of AFUDC relating to the HCC was $103 million.
ldaho 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 ofconstruction, operating, and leasing
costs. Idaho Power's proportionate share of operating expenses for each facility is included in the Consolidated Statements of Income
These jointly-owned facilities, including balance sheet amounts and the extent of Idaho Power's participation, were as follows at
December 31,2016 (in thousands of dollars):
Name of Plant Location
Utility
Plant in
Service
Construction
Work in
Progress
Accumulated
Provisionfor Ownership
Depreciation Mw(l)
Jim Bridger Units l-4
Boardman
Valmy Units I and2
Rock Springs, WY $
Boardman, OR
Winnemucca, NV
7r0,910 $
82,419
4 r 0,390
5,972 $
34
t,373
302,291
67,568
r89,557
33
l0
50
771
64
284
( | ) Idatro 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
$93 million in 2016 and $93 million in 2015.
ldaho Power has contracts to purchase the energy from fbur PURPA qualified facilities that are 50 percent owned by Ida-West. Idaho
Power's power purchases from these facilities were $8 million in 2016 and $8 million in 2015.
12. ASSET RETIREMENT OBLIGATIONS (ARO)
The guidance relating to accounting fbr AROs requires that legal obligations associated with the retirement of property, plant, and
equipment be recognized as a liability at fair value when incurred and when a reasonable estimate of the fair value of the liability can
be made. Under the guidance, when a liability is initially recorded, the entity increases the carrying amount of the related long-lived
asset to reflect the future retirement cost. Over time, the liability is accreted to its estimated settlement value and paid, and the
capitalized cost is depreciated over the useful lif'e ofthe related asset. tf, at the end ofthe asset's life, the recorded liability diflers fiom
the actual obligations paid, a gain or loss would be recognized. 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 earn a return on investment. Beginning June l, 2012,accretion, depreciation, and gains or losses related to the Boardman
generating facility have been exempted from such regulatory treatment as ldaho 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 f'acilities
and the reclamation and removal costs at its jointly-owned coal-fired generation fbcilities. In 2016, changes in estimates at the
coal-fired generation facilities resulted in a net increase of $1.8 million in the recorded AROs.
Idaho Power also has additional AROs associated with its transmission system, hydroelectric facilities, natural gas-fired generation
fbcilities, and jointly owned coal-fired generation facilities; however, due to the indeterminate removal date, the t'air value of the
associated liabilities currently cannot be estimated and no amounts are recognized in the consolidated financial statements.
FERC FORM NO.1 (ED.12{8)Page'123.33
Name of Respondent
ldaho Power Comoanv
This Report is:
(1)X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t14t2017
Year/Period of Report
2016tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
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 sheets as of December 3l.2016 and 2015.
The following table presents the changes in the carrying amount of AROs (in thousands of dollars):
2016 20r5
Balance at beginning ofyear
Accretion expense
Revisions in estimated cash flows
Liability settled
$26,153 $
1,03 1
1,759
(2,686)
2t,930
993
5,043
(1,813)
Balance at end ofyear $26,257 5 26,153
I3.INVESTMENTS
The table below summarizes Idaho Power's investments as of December 3l (in thousands of dollars):
2016 2015
ldaho Power investments:
IERCO
Exchange traded short-term bond funds and cash equivalents
Executive deferred compensation plan investments
s 77,131 $
23,908
ln
84,137
24,4s9
102
Total Idaho Power investments s r0l,r50 $ 108,698
Investments in Equity Securities
Investments in securities classified as available-for-sale securities are reported at fair value. Any unrealized gains or losses on
available-for-sale securities are included in income, as the fair value option has been elected for these instruments. Unrealized gains
and losses on available-for-sale securities were immaterial at December 31.2016 and December 31.2015. The following table
summarizes sales of available-tbr-sale securities (in thousands of dollars):
2016 2015
Proceeds from sales
Gross realized gains from sales
Gross realized losses from sales
$ 34,243
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, 2016 and December 3 I . 2015. there were no
indicators of other-than-temporary impairment related to Idaho Power's investments.
FERC FORM NO.1 (ED.12-88)Page 123.34
$ 15,693
54
Name of Respondent
ldaho Power Companv
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Y0
Mt14t2017
Year/Period of Report
2016tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
14. DERIVATIVE FINANCIAL INSTRUMENTS
Commodity Price Risk
Idaho Power is exposed to market risk relating to electricity, natural gas, and other fuel commodity prices, all of which are heavily
influenced by supply and demand. Market risk may be influenced by market participants' nonperformance of their contractual
obligations and commitments, which atlects 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 ofldaho Power's energy purchase and sale activity are to meet the demand ofretail electric
customers, maintain appropriate physical reseryes to ensure reliability, and make economic use of temporary surpluses that may
develop.
All of ldaho Power's derivative instruments have been entered into tbr the purpose of economically hedging forecasted purchases and
sales, though none ofthese instruments have been desigrated as cash flow hedges. Idaho Power offsets fair value amounts recognized
on its balance sheet and applies collateral related to derivative instruments executed with the same counterparty under the same master
netting agreement. Idaho Power does not offset a counterparty's current derivative contracts with the counterparty's long-term
derivative contracts, although Idaho Power's master netting arrangements would allow current and long-term positions to be offset in
the event of default. Also, in the event of delault, Idaho Power's master netting arrangements would allow for the offsetting of all
transactions executed under the master netting arrangement. These types oftransactions may include non-derivative instruments,
derivatives qualifiing fbr scope exceptions, receivables and payables arising from settled positions, and other forms of non-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 designated as hedging instruments tbr the years ended December 3 l,
2016 and 2015 (in thousands ofdollars):
Location of Realized Gain(Loss) on Gain(Loss) on Derivatives Recognized in lncome(l)
Financial swaps
Financial swaps
Financial swaps
Financial swaps
Forward contracts
Forward contracts
Forward contracts
Off-system sales
Purchased power
Fuel expense
Other operations and maintenance
OIf-system sales
Purchased power
Fuel expense
$1,405
586
(1,947)
(l6r)
2,882
748
(6.045)
(50)
$
3l
139
(6)
54
( I ) Excludes unrealized gains or losses on derivatives, which are recorded on the balance sheet as regulatory assets or regulatory liabilities.
Settlement gains and losses on electricity swap contracts are recorded on the income statement in of]'-system sales or purchased power
depending on the forecasted position being economically hedged by the derivative contract. Settlement gains and losses on contracts
for natural gas are reflected in fuel expense. Settlement gains and losses on diesel derivatives are recorded in other operations and
maintenance expense. See Note l5 fbr additional information concerning the determination of fair value for ldaho Power's assets and
liabilities from price risk management activities.
FERC FORM NO.1 (ED.12-88)Page 123.35
Name of Respondent
ldaho Power Company
This Report is:
(1)X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
ut14t2017
Year/Period of Report
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Derivative Instrument Summary
The table below presents the fair values and locations of derivative instruments not designated as hedging instruments recorded on the
balance sheets and reconciles the gross amounts ofderivatives recognized as assets and as liabilities to the net amounts presented in the
balance sheets at December 31,2016 and 2015 (in thousands ofdollars):
Asset Derivatives Liability Derivatives
Balance Sheet
Gross
Fair
Value
Amounts Net
Gross
Fair
Value
Amounts Net
December 31,2016
Current:
(r
Financialswaps Othercurrentassets $ 8,134 $ (Z,tt:)) $ 5,951 $ 302 $ (302) S
Total $ 8,134 $ (2.183) $ 5,95r S 302 $ (302) $
December 31,2015
Current:
Financial swaps
Financial swaps
Forward contracts
Forward contracts
Long-term:
Financial swaps
Other current assets
Other current liabilities
Other current assets
Other current tiabilities
Other assets
$e99 S
177
64
148
(78s) $
(177)
(785) $
(177)
214 $ 785 S
5,146
64
3
126 22 (22)
4.969
3
(22)
Total $ 1,388 $ (e84) $ 404 $ s,es6 $ (e84) S 4,e72
( I ) Current asset derivative amounts offset include $l,9 million ofcollateral payable for the period ending December 3 l, 20 I 6.
The table below presents the volumes of derivative commodity forward contracts and swaps outstanding at December 31, 2016 and
2015 (in thousands ofunits):
December 31,
Commodity Units 20t6 2015
Electricity purchases
Electricity sales
Natural gas purchases
Natural gas sales
Diesel purchases
MWh
MWh
MMBtu
MMBtu
Gallons
217
135
6,604
70
l,l 88
357
t20
I1,597
78
1,068
FERC FORM NO.1 (ED.12{8)Page 123.36
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
0/,t14t2017
Year/Period of Report
2016tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Credit Risk
At December 3l,2016,ldaho Power did not have material credit risk exposure fiom 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 manages these risks by establishing credit and concentration limits on
transactions with counterparties and requiring contractual guarantees, cash deposits, or letters ofcredit 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 investment grade by at least one rating agency.
Credit-Contingent Features
Certain of ldaho Power's derivative instruments contain provisions that require ldaho Power's unsecured debt to maintain an
investment grade credit rating from Moody's Investors Service and Standard & Poor's Ratings Services. If Idaho Power's unsecured
debt were to fall below investment grade, it would be in violation of these provisions, and the counterparties to the derivative
instruments could request immediate payment or demand immediate and ongoing full ovemight collateralization on derivative
instruments in net liability positions. The aggregate fair value of all derivative instruments with credit-risk-related contingent t'eatures
that were in a liability position at December 31,2016, was $0.3 million. Idaho Power posted no cash collateral related to this amount.
If the credit-risk-related contingent features underlying these agreements were triggered on December 3l,2016,ldaho Power would
have been required to pay or post collateral to its counterparties up to an additional $2.7 million to cover open liability positions as
well as completed transactions that have not yet been paid.
15. FAIR VALUE MEASUREMENTS
Idaho Power has categorized its financial instruments into a three-level fair value hierarchy, based on the priority ofthe 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 l)andthelowestprioritytounobservableinputs(Level 3). lftheinputsusedtomeasurethetinancial instrumentsfall
within diff'erent levels of the hierarchy, the categorization is based on the lowest level input that is significant to the fair value
measurement of the instrument.
Financial assets and liabilities recorded on the consolidated balance sheets are categorized based on the inputs to the valuation
techniques as follows:
. Level l: Financial assets and liabilities whose values are based on unadjusted quoted prices for identical assets or liabilities in
an active market that ldaho Power has the ability to access.
Level 2: Financial assets and liabilities whose values are based on the following:
a) quoted prices tbr similar assets or liabilities in active markets;
b) quoted prices fbr 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 tiom or corroborated by observable market data through
correlation or other means for substantially the full term of the asset or liability.
FERC FORM NO.1 (ED.12.88)Page 123.37
Name of Respondent
ldaho Power Company
This Report is:
(1)X An Originale) A Resubmission
Date of Report
(Mo, Da, Yr)
Ml14t20'17
Year/Period of Report
2016tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Idaho Power Level2 inputs are based on quoted market prices adjusted for location using corroborated, observable market
data.
Level 3: Financial assets and liabilities whose values are based on prices or valuation techniques that require inputs that are
both unobservable and significant to the overall fair value measurement. These inputs reflect management's own assumptions
about the assumptions a market participant would use in pricing the asset or liability.
Idaho Power's assessment of a particular input's significance to the fair value measurement requires judgment and may affect the
valuation of fair value assets and liabilities and their placement within the fair value hierarchy. An item recorded at t'air value is
reclassified among levels when changes in the nature ofvaluation inputs cause the item to no longer meet the criteria for the level in
which it was previously categorized. There were no transf-ers between levels or material changes in valuation techniques or inputs
during the years ended December 31,2016 and 20 I 5.
The following table presents information about Idaho Power's assets and liabilities measured at fair value on a recurring basis as of
December 31,2016 and 2015 (in thousands ofdollars):
December 31, 2016 December 31, 2015
Level I Level 2 Level 3 Total Level I Leve! 2 Level 3 Total
Assets:
Money market funds
Money market funds
Derivatives
Trading securities: Equity securities
Available-for-sale securities: Equity securities
Liabilities:
Derivatives $$$$ 286 S 4,686 $$ 4.972
$29.967
5,951
Ill
23,908
$29,967
5,951
lil
23.908
$10,000
340
102
24,459
$ r 0,000
404
t02
24,459
$-
64
$-$-$-
$
Idaho Power's derivatives are contracts entered into as part ofits management ofloads and resources. Electricity derivatives are valued
on the Intercontinental Exchange (lCE) with quoted prices in an active market. Natural gas and diesel derivative valuations are
performed using New York Mercantile Exchange (NYMEX) and ICE pricing, adjusted for location basis, which are also quoted under
NYMEX and ICE pricing. Trading securities consist of employee-directed investments held in a Rabbi trust and are related to an
executive deferred compensation plan. Available-for-sale securities are related to the SMSP, are held in a Rabbi trust, and are actively
traded money market and exchange-traded funds with quoted prices in active markets.
FERC FORM NO.1 (ED.12.88)Page 123.38
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04t14t2017
Year/Period of Report
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
The table below presents the carrying value and estimated fair value of financial instruments that are not reported at fair value, as of
December 31,2016 and 2015, using available market information and appropriate valuation methodologies (in thousands of dollars):
December 31,2016 December 31,2015
Carrying
Amount
Estimated Fair
Value
Carrying
Amount
Estimated Fair
Value
(thousands of dollars)
Idaho Power
Liabilities:
Long-term deb( I )
( I ) Notes receivable and long-term debt are categorized as Level 3 and Level 2, respectively, ofthe fair value hierarchy, as defined earlier in this Note I 6
Long-term debt is not traded on an exchange and is valued using quoted rates fbr similar debt in active markets. Carrying values for
cash and cash equivalents, deposits, customer and other receivables, notes payable, accounts payable, interest accrued, and taxes
accrued approximate fair value.
16. CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME
Comprehensive income includes net income 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 31,2016 and 2015 (in thousands of
dollars). Items in parentheses indicate reductions to AOCI.
Year Ended December 31,
$ 1,745,678 $ 1,858,666 $ 1,726,474 $ 1,813,243
2016 2015
Defined benefit pension items
Balance at beginning of period $ (21,276) $ (24,158)
Other comprehensive income before reclassitlcations
Amounts reclassified out of AOCI
( r,859)
, r<2
214
2,668
Net current-period other comprehensive income 394 2,882
Balance at end of period s (20,882) $ (21,276)
FERC FORM NO.1 (ED.12.88)Page 123.39
Name of Respondent
ldaho Power Company
This Report is:
(1)X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
Mt14t2017
Year/Period of Report
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
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 31,2016 and 2015 (in thousands ofdollars). Items in parentheses indicate increases to
net income.
Amount Reclassified from AOCI
Year Ended December 31,
2016 2015
Amortization of defined benefit pension items( I )
Prior service cost
Net loss
$168 $
3,532
185
4,195
Total before tax
Tax benefit(2)
3,700
(1,447)
4,380
(1,712)
Net of tax 2,253 2,668
Total reclassitlcation for the period s 2,253 $ 2,668
( | ) Amortization ofthese items is included in Idaho Powe/s consolidated income statements in other expense, net.
(2) The tax benefit is included in income tax expense in the consolidated income statements of ldaho Power.
17. RELATED PARTY TRANSACTIONS
IDACORP: Idaho Power performs corporate firnctions such as financial, legal, and management services for IDACORP and its
subsidiaries. ldaho Power charges IDACORP for the costs of these services based on service agreements and other specifically
identified costs. For these services. Idaho Power billed IDACORP S0.8 million in 2016 and $0.9 million in 2015.
Ida-l{est: Idaho Power purchases all of the power generated by four of Ida-West's hydroelectric projects located in ldaho. Idaho
Power paid lda-West $8 million in both 2016 and 2015.
FERC FORM NO.1 (ED.12.88}Page 123.40
ldaho Power Company (1)
(2)
An Original
A Resubmission
UAIE OI(Mo, Da
KeporI
, Yr)
041'.t4120't7
rearrFenoq or Kepon
End of 20161Q4
SUMMAKY OI- U I ILI I Y PLAN T AND ACCUMULATED PROVISIONS
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Report in Column (c) the amount for electric function, in column (d) the amount for gas function, in column (e), (f), and (g) report other (specify) and in
column (h) common function.
Line
No.
Classification
(a)
Total Company for the
Current Year/Quarter Ended
(b)
Electric
(c)
,|Utility Plant
2 ln Service
3 Plant in Service (Classified)5,731,292,950 5,731,292,950
4 Property Under Capital Leases
5 Plant Purchased or Sold
6 Completed Construction not Classified
7 Experimental Plant Unclassifi ed
8 Total (3 thru 7)5,731,292,950 5,731,292,9s0
9 Leased to Others
10 Held for Future Use 7,440,603 7,440,603
11 Construction Work in Progress 405,068,524 405,068,524
12 Acquisition Adjustments 750,89s 750,893
13 Total Utility Plant (8 thru 12)6,144,552,970 6,144,552,97A
't4 Accum Prov for Depr, Amort, & Depl 2.175,085,495 2,175,085,495
15 Net Utility Plant (13 less '14)3,969,467,475 3,969,467,475
16 Detail of Accum Prov for Depr, Amort & Depl
17 ln Service
18 Depreciation 2,150,749,270 2,150,749,270
19 Amort & Depl of Producing Nat Gas Land/Land Right
20 Amort of Underground Storage Land/Land Rights
2'l Amort of Other Utility Plant 24,336,225 24,s36,225
22 Total ln Service (18 thru 21)2,175,085,495 2,175,085,495
23 Leased to Others
24 Depreciation
25 Amortization and Depletion
26 Total Leased to Others (24 &25)
27 Held for Future Use
28 Depreciation
29 Amortization
30 Total Held for Future Use (28 & 29)
31 Abandonment of Leases (Natural Gas)
32 Amort of Plant Acquisition Adj
33 Total Accum Prov (equals 14) (22,26,30,31,321 2,175,085,495 2,175,085,495
FERC FORM NO. I (EO. 12-89)Page 200
Name of Respondent
ldaho Power Company
(1)
(2)
An Original
A Resubmission
(Mo, Da,
04t1412017
Year/Period of Report
End of 2016/Q4
't. Report below the original cost of electric plant in service according to the prescribed accounts.
2. ln addition to Account 101, Electdc 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, conections 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
relirements, on an estimated basis, with appropriate contra entry to the account for accumulated depreciation provision. lnclude also in column (d)
une
No.
Account
(a)
Additions
(c)
1 .I. INTANGIBLE PLANT
2 (301) Oroanization 5,703
3 (302) Franchises and Consents 29.759.682 272.993
4 (303) Miscellaneous lntanqible Plant 28,493,799 2.169.391
5 TOTAL lntanoible Plant (Enter Total of lines 2. 3. and 4)58.259.184 2.M23U
6 2. PRODUCTION PLANT
7 A. Steam Production Plant
8 (3'10) Land and Land Riqhts 1.730.471 -8,050
I (31 1) Structures and lmDrovements 't53.408,729 -'1.287.206
10 (312) Boiler Plant Eouioment 682.889.150 83,922.600
11 (313) Enoines and Enqine-Driven Generators
12 (31 4) Turbooenerator Units 162.544.079 4,905,944
13 (315) Accessorv Electric Equipment 70,701.789 1.488.262
't4 (316) Misc. Power Plant Equipment 17,503,886 't,707,969
15 (3'17) Asset Retirement Costs for Steam Production 13,930,061 1,381.822
16 TOTAL Steam Production Plant (Enter Total of lines 8 thru '15)1,102,708,165 92,111.34'l
't7 B. Nuclear Production Plant
18 (320) Land and Land Rishts
19 (321) Structures and lmprovements
20 (322) Reactor Plant Equipment
21 (323) Turboqenerator Units
22 (324) Accessory Electric Equipment
23 (325) Misc. Power Plant Equipment
24 (326) Asset Retirement Costs for Nuclear Production
25 TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24)
26 C. Hydraulic Production Plant
27 (330) Land and Land Riqhts 31.223.914 220.924
28 (331) Structures and lmprovements 175.996.371 3.223.850
29 (332) Reservoirs, Dams, and Waterways 269.959.842 1.896.784
30 (333) Water Wheels, Turbines, and Generators 211,679.356 31.349.747
3'l (334) Accessory Electric Equipment 58.474.3',t8 2.456.072
32 (335) Misc. Power Plant Equipment 22.796.263 1.824.',t7s
33 (336) Roads, Railroads, and Bridges 10.880,502 -1.514
34 (337) Asset Retirement Costs for Hydraulic Production
35 TOTAL Hydraulic Production Plant (Enter Total of lines 27 lhru 34)781,010.566 40.970.038
36 D. Other Production Plant
37 (340) Land and Land Riqhts 2,690,006
38 (341) Structures and lmprovements 142,711,065 498,927
39 (342) Fuel Holders, Products, and Accessories 10.452.547
40 (343) Prime Movers 218,960,892 't0,912,86C
4',!(344) Generators 66,531,876
42 (345) Accessory Electric Equipment 91,098,988 59,863
43 (346) Misc. Power Plant Equipment 6,010,475 229,891
44 (347) Asset Retirement Costs for Other Production
45 TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44)538.455.849 11.701.541
46 TOTAL Prod. Plant (Enter Total of lines '16, 25, 35, and 45)2.422.',t74.580 144.782.924
FERC FORri NO. I (REV. 12-05)Page 201
Name of Respondent
ldaho Power Company
This ReDort ls:(1) E]An Originat(2) ;1A Resubmission
Date of Report(Mo, Da, Yr)
o411412017
Year/Period ol Report
End of 20'l6lQ4
ELECTRIC PLANT lN SERVICE (Account '1O1.102. 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 adjustments, etc., and show in column (f) only the offset to the debits or credits distributed in column (f) to primary
account classifications.
8. For Account 399, state the nature and use of plant included in this account and if substantial in amount submit a supplementary statement showing
subaccount classification of such plant conforming to the requirement of these pages.
9. For each amount comprising the reported balance and changes in Account 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 the Commission as required by the Uniform System of Accounts, give also date
Retirements
(d)
Adjustments
(e)
Transfers
(fl
Balance at
End flfear
Line
No.
1
5.703 2
30.032.675 3
7,960,965 22.702.225 4
7.960.965 52.740.603 5
o
7
't.722.421 8
560,561 151.560.962 o
8.667.325 758.144.425 10
11
1.728.354 16s,721.669 12
56,504 72.133.547 13
1.708.323 17.503.532 14
15,311,883 't5
12.72',1,067 1,182,098,439 16
17
18
't9
20
21
22
23
24
25
26
31,444,838 27
197,235 179,022,gffi 28
94,468 271,762,158 29
1,37',\,762 241,657,341 30
553,305 60,377,085 31
105,965 24,514,473 32
s6,404 10.842.584 33
34
2,359,1 39 819.62't.465 35
36
2.690.006 37
42.002 143,167,990 38
10.452.547 39
229.873.752 40
66,531,876 4',|
12,000 91,146,85'r 42
6,240,366 43
44
54,002 550,103,388 45
15,134,208 2,551,823,292 ,t6
FERC FORM NO. 1 (REV.12-05)Page 205
Name of Respondent
ldaho Power Company
This(1)
(2)
ReDort ls:
5]Rn Originat
[lA Resubmission
Date of Report(Mo, Da, Yr)
04114t2017
Year/Period of Report
End of 20161Q4
Ltne
No.
ACCOUnI
(a)
E,arance
Beginning of Year
(b)
AOOtItOnS
(c)
47 3. TRANSMISSION PLANT
48 (350) Land and Land Riqhts 36.379.079 814.',t43
49 (352) Structures and lmprovements 77.780.246 1 .851.59S
50 (353) Station Equipment 407.602.629 7.067.324
51 (354) Towers and Fixtures 184.628,055 13.550.729
52 (355) Poles and Fixtures 1 58,380,1 94 17.657.509
53 (356) Overhead Conductors and Devices 211.904.657 8.556.373
54 (357) Underqround Conduit
55 (358) Underground Conductors and Devices
56 (359) Roads and Trails 390,266
57 (359.1 ) Asset Retirement Costs for Transmission Plant
58 TOTAL Transmission Plant (Enter Total of lines 48 thru 57)1.077.06,5.126 49.497.677
59 4. DISTRIBUTION PLANT
60 (360) Land and Land Rights s,300.524 647,447
6'l (361) Structures and lmorovements 34,175.353 2.842.549
62 (362) Station Equipment 216.853.729 6.762.998
63 (363) Storaoe Batterv Eouioment
64 (364) Poles. Towers. and Fixtures 246.98s,666 11,4',t5,269
65 (365) Overhead Conductors and Devices 129.331,468 3.739.895
66 (366) Underoround Conduit 48.322,609 1,861 ,831
67 (367) Underoround Conductors and Devices 230,'143,'168 15,383,360
68 (368) Line Transformers 5',15,652,279 27.403.469
69 (369) Services 58.770.764 1,191,980
70 (370) Meters 85.247.458 6,296,981
71 (371 ) lnstallations on Customer Premises 2,954,458 127,799
72 (372) Leased ProDertv on Customer Premises
73 (373) Street Liqhtinq and Siqnal Systems 4,s43,249 74,540
74 (374) Asset Retirement Costs for Distribution Plant 164,191
75 TOTAL Distribution Plant (Enter Total of lines 60 thru 74)1,578,444,916 77,748,1'18
76 5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT
77 (380) Land and Land Riqhts
78 (381) Structures and lmprovements
79 (382) Computer Hardware
80 (383) Computer Software
81 (384) Communication Equipment
82 (385) Miscellaneous Regional Transmission and Market Operation Plant
83 (386) Asset Retirement Costs for Regional Transmission and Market Oper
84 TOTAL Transmission and Market Operation Plant (Total lines 77 thru 83)
85 6. GENERAL PLANT
86 (389) Land and Land Riqhts 16.578.582 643.905
87 (390) Structures and lmprovements 110,924,656 7,736,358
88 (391) Office Furniture and Equipment 46.692,083 5.534.502
89 (392) Transportation Equipment 75.878.863 9,368,330
90 (393) Stores Equipment 2.255.403 407,050
91 (394) Tools, Shop and Garage Equipment 8.021,556 925,406
92 (395) Laboratorv EouiDment 12.703,819 841,679
93 (396) Power Ooerated EouiDment 15,082,035 612,102
94 (397) Communication Eouipment 55,415,200 3,452,061
95 (398) Miscellaneous EouiDment 5,967,704 617,357
96 SUBTOTAL (Enter Total of lines 86 thru 95)349,519,901 30,138,750
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)349.s19.901 30.138.750
100 TOTAL (Accounts 101 and 106)5.485.463.707 304.609.849
101 (102) Electric Plant Purchased (See lnstr. 8)
102 (Less) (102) Electric Plant Sold (See lnstr. 8)
't03 (1 03) Experimental Plant Unclassified
104 TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103)5.485.463.707 304.609.849
FERC FORM NO.1 (REV.12-05)Page 206
Respondent Anldaho Power Company )(Mo, Da
(2)A Resubmission 041't412017
Year/Period of Report
End of 20161Q4
IN 101
Retirements
(d)
Adjustments
(e)
Transfers
(fl
Balance at
End flfear
Line
No.
47
37193222 48
91,962 79.539.883 49
3,380,833 411.289.120 50
76,185 198,102,599 51
865,060 175.172.643 52
1.26.222 219.2',t4.808 53
54
55
390,266 56
57
5.660.262 't,120.902.541 58
59
5.947.971 60
33,536 36.984.366 61
1.259.863 222.356.ffi4 62
63
2.242.023 256,'t58,912 64
1.796.023 131.275,340 65
389,672 49,794,768 66
1.876.265 243,650,263 67
6.505,273 536,s50,475 68
491,357 59,471,387 69
4.2U.884 87,259,555 70
65,280 3,016,977 71
72
1 17,336 4,500,453 73
164,191 74
19,061,512 1,637 ,131 ,522 75
76
77
78
79
80
8'l
82
83
84
85
46,532 17.175.955 86
211,661 1 18.449.353 87
3.1M.715 49.081.870 88
3,817,493 81.429.700 89
42.456 2.619.997 90
280.796 8.666.166 9'l
s23,133 13,022,365 92
609,100 15,085,037 93
2.274.049 s6,593,212 94
13,724 6,571,337 95
10,963,659 368,694,992 96
97
98
10,963,659 368.694.992 99
58,780,606 5.731.292.950 100
't01
't02
103
58.780.606 5.731.292.950 104
FERC FORM NO. 1 (REV.12-05)Page 207
Name of Respondent
ldaho Power Company
This(1)
(2)
Report ls:
fiAn Original
1A Resubmission
Date of Report(Mo, Da, Yr)
o411412017
Year/Period of Report
End of 20161Q4
ELECTRIC PLANT HELD FOR FUTURE USE (Account 105)
1 . Report separately each property held for future use at end of the year having an original cost of $250,000 or more. Group other items of property held
for future use.
2. For property having an original cost of $250,000 or more previously used in utility operations, now held for future use, give in column (a), in addition to
other required information, the date that utility use of such property was discontinued, and the date the original cost was transfened to Account 105.
Line
No.
uescnpuon ano Locauon
Of Pro;ertV
uate unornailv tnctuoeo
in Tf,is A6count(b)
uale trxpecteo Io oe useo
in Utility Service
Balance at
End of Year(d)
,|Land and Rights:
2 Boise Operations Center 12t31t82 2017 655,550
3 Production 109,961
4 Transmission Stations 423,089
5 Transmission Lines 195,489
6 Distribution Stations 973,839
7 Beacon Light Substation 12t30t02 2020 465,662
8 Homedale Substation 2129t08 2025 109,453
I North River Operations Center 1/31/08 20't9 2,630,412
10 Line 11854 500 Kv 3/31/09 2024 308,066
1',l
12
13
't4 Column B and C if no date listed it is various
15
16
17
'18
19
20
21 Other Property:
22 Boise Operations Center 12131182 20't7 82,790
23 Transmission Stations 199,069
24 Distribution Stations 69,941
25 Homedale Substation 2t29t08 2025 217,797
26 Beacon Light Substation 't2t30l02 2020 555,940
27 Underground Vault, Blaine County 8/30/16 2020 443,545
28
29
30
31 Column B and C if no date listed it is various
32
33
34
35
36
37
38
39
40
41
42
43
44
45
lm
47 Total 7,,140,603
FERC FORM NO. I (ED.12-96)Page 2irt
Name of Respondent
ldaho Power Company
This Report ls:(1) [An Original(2) f-1A Resubmission
Date of Report(Mo, Da, Yr)
04t1412017
Year/Period of Report
End of 20161Q4
'1. Report below descriptions and balances at end of year of projects in process of construction (107)
2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see
Account 1 07 of the Uniform System of Accounts)
3. Minor projects (5% of the Balance End of the Year for Account 107 or $1 ,000,000, whichever is less) may be grouped.
Line
No.
Description of Project
(a)
Construction work in
Electric (Account
(b)
progress
107)
1 ROLLUP RELIC COST BROWNLEE 94,1 1 5,655
2 ROLLUP RELIC COST HELLS CANYON 64,130,776
3 GATEWAY WEST sOOKV LINE 32,34'1,951
4 ROLLUP RELIC COST OXBOW 29,790,797
5 HELLS CANYON RELICENSING OUTSI 25,648,76s
6 B2H PERMITTING 11/1/2011& FOR 13,253,239
7 BOARDMAN - HEMINGWAY 5OO KV LI 12,594,948
8 BROWNLEE UNIT 3 TURBINE REFURB 8,062,489
9 HCC WATERSHED ENHANCEMENT PROG 4,915,672
'10 LEGAL DEPT, LABOR FOR RELICENS 3,960,343
11 BROWNLEE UNIT 2 TURBINE REFURB 3,807,724
12 BROWNLEE UNIT 4 TURBINE REFURB 3,645,624
13 BAYHA ISLAND RESEARCH PROJECT 3,537,551
14 RAPID RIVER HATCHERY INTAKE SC 3,221,312
15 REL.HCC OREGON REAUTHORIZATION 3,000,969
16 WQ HCC4O1 CERTIFICATION OPS AN 2,942,538
't7 B2H TLINE CONSTRUCTION COSTS 2,687,809
't8 OUTAGE MANAGEMENT SYSTEM (OMS)2,143,924
19 TOOMHZ SPECTRUM PURCHASE 2,113,759
20 WDRI-KCHM NEW,138KV 1,959,756
21 WQ HCC4O1 APPLICATION, REVISIO 1,860,230
22 HCC MOONSHINE MINE DEEP WATER 1,851 ,957
23 FALL CHINOOK PROGRAM. REDD SU 1,705,552
24 BULL TROUT PROGRAM - ADMINISTR 1,679,070
25 BRIDGER UNDISTRIBUTED WORK ORD 1,627,000
26 BOBN14OOO3 - REPL 138KV BUS PR 1,622,364
27 METEOROLOGY MODEL FOR OPERATIO 1,621,407
28 HBND-041:ALT LINE ROUTE TO GAR 1,599,669
29 RELICENSING: BAKER COUNTY SETT 1,579,612
30 BLISS UNIT 3 TURBINE REBURBISH 1,529,927
31 BRIDGER 2016C052 U2 REPLACE FI 1,472,497
32 T4331001-2017 K|NG TO WOOD RIV 1,438,150
33 REC. BAKER COUNTY SETTLEMENT 1,402,585
34 CR&B ENHANCEMENT & SUPPORT PAC 1,363,584
35 HC EVALUATION OF MAINSTEM SEDI 1,281,365
36 BLISS UNIT 3 GENERATOR REWIND 1,262,344
37 HCC RELICENSING WATER QUALITY 1,199,403
38 GRAND VIEW IRRIGATION UPGRADE 1,10'1,079
39 Other Minor Projects Under 1,000,000 59,995,130
40
41
42
43 TOTAL 405,068,s24
FERC FORM NO. 1 (ED. 12-87)Page 2'16
Name of Respondent
ldaho Power Company
This(1)
(2)
Report ls:
EAn Original
;-TA Resubmission
Date of Reoort(Mo, Da, Yi)
04t14t2017
Year/Peilod of Report
End of 2016/Q4
ACCUMULAT ErJ PR()VTSTON r-OR TJEPREC|AT|ON OF ELECTRIC UTTL|TY PLANT (Account 106)
1. Explain in a footnote any important adjustments during year.
2. Explain in a footnote any difference between the amount for book cost of plant retired, Line 11, column (c), and that reported for
electric plant in service, pages 204-207, column 9d), excluding retirements of non-depreciable property.
3. The provisions of Account 108 in the Uniform System of accounts require that retirements of depreciable plant be recorded when
such plant is removed from service. lf 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 Ghanges During Year
Ltne
No.
trem
(a)
_ lotat.(c+d+e)
(b)
Ereqlnc rranlservrce tn
(c)
Etec(nc rtant netofor Future Use(d)
Etecrnc rtanrLeased to Others
(e)
,|Balance Beginning of Year 2,071,7U,276 2,07',t,7U,276
2 Depreciation Provisions for Year, Charged to
I (403) Depreciation Expense 135,048,584 135,Ol8,584
4 (403.1 ) Depreciation Expense for Asset
Retirement Costs
720,272 720,272
E (413) Exp. of Elec. Plt. Leas. to Others
6 Transportation Expenses-Clearing 3,983,3s9 3,983,33S
7 Other Clearing Accounts
8 Other Accounts (Specify, details in footnote):
s Fuel Stock 102,213 102,213
10 TOTAL Deprec. Prov for Year (Enter Total of
lines 3 thru 9)
139,854,408 139,854,408
11 Net Charges for Plant Retired
12 Book Cost of Plant Retired 50.773.',t13 50,773,1',13
13 Cost of Removal 15,807,186 15,807,186
't4 Salvage (Credit)2,333,822 2,333,822
't5 TOTAL Net Chrgs. for Plant Ret. (Enter Total
of lines 12 thru '14)
64,246,477 64,246,477
16 Other Debit or Cr. ltems (Describe, details in
footnote):
3,357,063
17
18 Book Cost or Asset Retirement Costs Retired
19 Balance End of Year (Enter Totals of lines 1,
10, 15, 16, and 18)
2.150.749.270 2,150,749,270
Section B, Balances at End of Year According to Functiona! Glassification
2C Steam Production 554,543,068 554,543,06f
21 Nuclear Production
22 Hydraulic Production-Conventional 413,700,238 413,700,23t
23 Hydraulic Production-Pumped Storage
24 Other Production 105,528,829 105,s28,82€
2a Transmission 350,571,3',t2 350,571,3',12
2C Distribution 610,936,319 6 t0,936,31S
21 Regional Transmission and Market Operation
28 General 115,469,504 115,469,504
29 TOTAL (Enter Total of lines 20 thru 28)2,150,749,270 2,',t50,749,27C
FERC FORil NO. I (REV. 12-05)Page 2tg
Name of Respondent
ldaho Power Company
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t14t2017
Year/Period of Report
2016tQ4
FOOTNOTE DATA
Echedule Page: 219 Line No.: 16 Column: c
CIAC, Reserve Adjustments and Asset Retirement Obligation activity.
FERC FORM NO. I (ED. 12-871 Page 450.1
Name of Respondent
ldaho Power Company
This ReDort Is:(1) 5]Rn originat(2) [-1A Resubmission
Date of Report
(Mo, Da, Yr)
04t1412017
Year/Period of Report
End of 20161Q4
INVESTMENTS IN SUBSIDIARY COMPANIES Account 123.1
1. Report below investments in Accounts 123.'1, investments in Subsidiary Companies.
2. Provide a subheading for each company and List there under the information called for below. Sub - TOTAL by company and give a TOTAL in
columns (e),(f),(g) and (h)
(a) 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 settlement. With respect to each advance show whether the advance is a note or open account. List each note giving date of issuance, maturity
date, and specifying whether note is a renewal.
3. Report separately the equity in undistributed subsidiary eamings since acquisition. The TOTAL in column (e) should equal the amount entered for
Account 418.1.
Lrne
No.
uescflptron ot lnvestment
(a)
Date Acquired
(b)
Date ol
wtafiyitv
Amount or lnvestmenl at
Beoinnino of Year- (d)-
1 ldaho Energy Resources Company
2 Common Stock 02101174 500
3 Capital contributions 2,462,594
4 Equity in eamings 81,674,307
5
6 Subtotal ldaho Energy Resources Company 84,137,401
7
8
I
10
1',!
12
13
14
15
't6
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
u
35
36
37
38
39
40
41
42 otal of Account '123.1 TOTAL 84.137,401
FERC FORM NO. I (ED. 12-89)Page 224
Name of Respondent
ldaho Power Company
This
(1)
(2)
Report
EAn
ls:
Original
[lA Resubmission
Date of Report(Mo, Da, Yr)
04t14t2017
Year/Period of Report
End of 20161Q4
1
4. Fot any securities, notes, or accounts that were pledged designate such securities, notes, or accounts in a footnote, and state the name of pledgee
and purpose of the pledge.
5. 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 investments, including such revenues form securities disposed of during the year.
7. ln column (h) report for each investment disposed of during the year, the gain or loss represented by the difference between cost of the investment (or
the other amount at which carried in the books of account if difference from cost) and the selling price thereof, not including interest adjustment includible
in column (f).
8. Report on Line 42, column (a) the TOTAL cost of Account 1 23.1
tsqurty rn l;ubsrdrary
Earninls ff Year
K.evenues ror Year
(0
Amount or tnveslmenl aI
End of Year(s)
uatn or Loss Trom tnvesrmenl
Disolrsfd of Line
No.
1
500 2
2,462,594 3
7,993,526 15,000,000 74,667,833 4
5
7,993,526 15,000,000 77330,927 6
7
I
9
10
11
12
13
't4
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
7,993,526 15,000,000 77,130,927 42
FERC FORM NO. 1 (ED. 12-89)Page 225
Name of Respondent
ldaho Power Company
This Reoort ls:(1) Slnn Orisinat
(21 f]A Resubmission
Date ot Report(Mo, Da, Yr)
o4l't4t2017
Year/Period ol Report
End of 20161Q4
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 adjustments during the year (in a footnote) showing general classes of material and supplies and the
various accounts (operating expenses, clearing accounts, plant, etc.) affected debited or credited. Show separately debit or credits to stores expense
clearing, if applicable.
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 151)6',t,818,257 53,700,442 Electric
2 Fuel Stock Expenses Undistributed (Account 152)-2,623 Electric
3 Residuals and Extracted Products (Account 153)
4 Plant Materials and Operating Supplies (Account 154)
5 Assigned to - Construction (Estimated)
6 Assigned to - Operations and Maintenance
7 Production Plant (Estimated)17,384,869 17,442,34',1
I Transmission Plant (Estimated)1 1 ,"t9't ,094 13,353,307
I Distribution Plant (Estimated)z',t,957,543 21,236,284
10 Regional Transmission and Market Operation Plant
(Estimated)
11 Assigned to - Other (provide details in footnote)1,911,722 2,422,752
12 TOTAL Account 154 (Enter Total of lines 5 thru 1 1 )52.445.228 54,454,684 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)4,478,320 3,403,797 Electric
17
18
19
20 TOTAL Materials and Supplies (Per Balance Sheet)'t 18,741,805 111,556,300
FERC FORM NO. 1 (REv. 12.05)Page 227
Name of Respondent
ldaho Power Company
This Reoort ls:(1)E An Original
(2) l-l A Resubmission
Date of Report(Mo, Da, Yr)
o4114t2017
Year/Period of Report
gn6 6 2016/Q4
I ransmission Service and Generation lnterconnection Study Costs
1. Report the particulars (details) called for concerning the costs incuned and the reimbursements received for performing transmission service and
geneEtor interconnection studies.
2. List each study separately.
3. ln column (a) provide the name of the study.
4. ln column (b) report the cost incuned 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 study costs at end of period.
7. ln column (e) report the account credited with the reimbursement received for performing the study.
Line
No.Description
(a)
Costs lncurred During
Period
(b)
Account Charged
(c)
t{eimbursementsReceived During
the Period
(d)
Account Credited
With Reimbursement
(e)
1 Transmission Studies
2 BPAP Network SIS 83177020 5,995 186623 186623
3
4
5
6
7
8
I
10
11
't2
'13
14
15
'16
17
't8
19
20
21 Generatlon Studies
22 MAHLHUER RIVER SOLAR #477 186623 186623
23 LITTLE VALLEY SOLAR 491 'r8662s 7,859 186623
24 BAKER SOLAR 1 #507 207 186623 ( 2s3)186623
25 BAKER SOLAR 2 #508 44 186623 ( el)186623
26 BOISE CITY SOLAR #432 ( 5,354)186623 72,705 186623
27 DAVIS SOLAR # 506 44 186623 ( 146)186623
28 EVERGREEN SOLAR #475 186623 35,943 1m623
29 FAIRWAY SOLAR #493 1 86623 7,332 186623
30 HUNTINGTON SOLAR 1 #505 801 186623 ( 755)I 86623
31 JACKPOT SOLAR NORTH #502 25,4',t8 186623 ( 33,392)186623
32 JACKPOT SOLAR SOUTH #503 21.O32 186623 ( 33,577)186623
33 JOHN DAY SOLAR #480 1,189 186623 38,314 1 86623
34 MAHLHUER RIVER SOLAR #477 186623 26,913 1 86623
35 MERIDIAN/NORTH RD PV1-A 1,890 186623 7,670 186623
36 MOORES HOLLOW #476 186623 36,371 186623
37 MORTH GOODING MAIN HYDRO #494 2,369 186623 19,212 186623
38 MOUTAIN HOME SOLAR.2OMW #435 2,346 186623 16,286 186623
39 OLD FERRY ROAD SOLAR #473 408 186623 35,130 186623
40 ONTARIO SOLAR #504 1,843 186623 ( 1,8s6)186623
FERC FORM NO. 1/1-Fr3-O (NEW. 03-07)Page 231
Name of Respondent
ldaho Power Company
This Report ls:(1)E An Original
(2) [l A Resubmission
Date ot Report(Mo, Da, Yr)
o4l't4120't7
Year/Period of Report
966 e1 2016/Q4
Transmassion Service and Generation lnterconnection Study Costs (continued)
Line
No.Description
(a)
Costs lncurred During
Period
(b)
Account Charged
(c)
HeimbursementsReceived Duringthe Period
(d)
Account Credited
With Reimbursement
(e)
1 Transmission Studies
2
3
4
5
b
7
8
9
'10
11
't2
13
14
'ts
16
'17
18
19
20
21 Generation Studies
22 ORCHARD RANCH 2 #488 186623 10,000 186623
23 ORCHARD RANCH SOLAR-2OMW #441 327 186623 16,447 186623
24 POCATELLO SOLAR-2OMW #436 186623 18,811 'tffi623
25 SIMCOESOLAR2#487 186623 42,808 186623
26 SIMCOE SOLAR CENTER #428 840 186623 12,281 186623
27 SOUTHERN IDAHO SOLID WASTE #501 6,809 186623 ( 26,02',t)186623
28 SUTTON CREEK SOLAR #495 2,488 186623 6,384 186623
29 WEGNER SOLAR #499 186623 671 1 86623
30 BAKER CITY 1 SOLAR 1 86623 ( 10,000)186623
31 BRUSH SOLAR #512 7,374 186623 ( 34,115)'t86623
32 CARTER SOLAR #517 't1,268 186623 ( 10,000)186623
33 IPCO COMMUNITY SOLAR #509 186623 186623
34 JACKPOT SOLAR EAST #514 17,',t14 186623 ( 45,000)186623
35 JACKPOT SOLAR WEST #5.I3 17,OO7 186623 ( 45,000)186623
36 MORGAN SOLAR #510 8,575 186623 ( 38,575)186623
37 SHOSHONE FALLS HYDRO PROJECT IPCO 2,149 1 86623 186623
38 VALE 1 SOLAR #511 5,549 186623 ( 31,944)186623
39
40
FERC FORM NO. 1/'t.Fr3-O (NEW. 03-07)Page 231.1
Name of Respondent
ldaho Power Companv
This Report is:
(1) X An Original(21 A Resubmission
Date of Report
(Mo, Da, Yr)
o4t14t2017
Year/Period of Report
2016tQ4
FOOTNOTE DATA
Schedule 231 Line No.: 2 Column: d
Amounts n column D represent both re mbursements rece l-ved (cre t amounts)and refundsinitiafback to the counterparties (debit amounts) . Refunds are initiated when thedeposit exceeds the final expenses.
FERC FORM NO. 1 (ED. 12-871 Page 450.1
Name of Respondent
ldaho Power Company
This
(1)
(2)
Reoort ls:
fiAn originat
l-lA Resubmission
Date of Report
(Mo, Da, Yr)
0411412017
Year/Period ot Report
End of 2016tQ4
OTHER REGULATORY ASSETS (Account'1 82.3)
1. Report below the particulars (details) called for conceming other regulatory assets, including rate order docket number, if applicable.
2. Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $100,000 which ever is less), may be grouped
by classes.
3. For Regulatory Assets being amortized, show period of amortization.
Line
No
Description and Purpose of
Other Regulatory Assets
(a)
Balance at Beginnin!
of Cunent
Quarter/Year
(b)
Debits
(c)
CREDITS Balance at end of
Cunent Ouarterffear
(0
Written off During the
Quarter ffear Account
Charsed (d)
Written off During
the Period Amount
(e)
1 Fixed Cost Adiustment (FCA) (182302\27,938,848 34,892,466 400, 1823 27,963,827 34,867,487
2 Order#33527 (Amort period 06/17 thru 05/18)
3
4 AOCl lmpact of Unfunded Post Retirement Liability ( 1,s24,416)1,599,868 2283 26,083 49,369
5 Order#30256 (182306)
6
7 FCA Calender Mo Adiustment 1,056,775 5,786,559 400 't0,236,716 -3,393,382
I Order#33295 (182308)
o
10 Prior Year FCA - Order#33527 (182309)7,824,769 28,054,542 400 22,908,285 12,971,026
11 (Amort period 06/16 thru 05/17)
12
13 PCA Unbilled Amortization ( 1 8231 6)( 1,210,063)3,950,415 400/401 4,727,806 1,987,454
14 (Amort period 06/'16 thru 05/17)
15
16 AOCI lmpact of Unfunded Pension Liability 253,286,229 23,833,252 2283 13,389,s29 263/29,952
17 0rder#30256 (182320)
18
19 Defened Pension Expense Net of Contributions 21,204,s91 40 088,330 Various 38,997,492 22,295,429
20 Order#30333 (182321)
21
22 FAS 109 Unfunded (1823221 875,027,482 73,512,340 948,539,822
23 Accum Defened lncome Noncunent
24
25 PCA Defenal ldaho - Order #33526 49,340,227 64,6s0,399 Various 61,001,484 52p89,142
26 (Amort period 06/17 thru 05/18) (182323)
27
28 PCA Prior Year Defenal ldaho - Order #33526 2,749 43,860,736 Various 33,709,156 '10,154,329
29 (Amort period 06/16 thru 05117) (182324\
30
31 PCA Unbilled Forecast - Order#32821 (1823251 ( 2,117,1s3\6,257j62 401 7,167,419 -3,027,410
32
33 PCA SBA Unbilled Adi-Order#33307 (182326)( 1,4s9,348)8,427,488 40'l 't'1,653,921 4,685,78'l
34
35 ldaho Pension Cash - Order #32248 (182327\61,318,926 38,891,706 401 17,153,713 83,056,919
36 (Amort period beginning 06/'11 thru indefinite)
37
38 PCAM lnterest Reserve 2008 (1 82329)( 330,493)254,983 -75,510
39 (Amort period 01/14 - 06/17)
40
41 ASC 815 Mark to Market (182330 & 182333)4,972,600 8,557,502 244 1 3,530,1 02
42 Order #2866'l
43
FERC FORM NO. 1/3-Q (REV. 02-04)Page 232
Name Respondent Date(Mo,ldaho Power Company
(1)
(2)
Original
A Resubmission 04114t2017
Year/Period of Report
End of 2016tQ4
OTHER REGULATORY ASSETS (Account 182.3)
1. Report below the particulars (details) called for concerning other regulatory assets, including rate order docket number, if applicable.
2. Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $100,000 which ever is less), may be grouped
by classes.
3. For Regulatory Assets being amortized, show period of amortization.
Line
No.
Description and Purpose of
Other Regulatory Assets
(a)
Balance at Beginninq
of Cunent
Quarterffear
(b)
Debits
(c)
CREDITS Balance at end of
Cunent QuarterlYear
(0
Written off During the
Quarter /Year Account
charged 1d)
Wriften off During
the Period Amount
(e)
1 Oregon Pension Exoense Capitalized (182339)3,266,661 597,030 401. 4073 'r06,917 3,756,774
2 Order #'10-064
3
4 Asset Retirement Obliqations (82341\14J80,771 1,285,929 230 '1,495,854 13,970,846
5 IPUC Order #29414-OPUC Order #04-585
6
7 PCAM Oregon 2008 ('182346)3,231,443 57,012 401 2,548,989 739,466
8 Order#08-238 & #13-439 (Amort 0'l/14 - 06/17)
o
10 OATT Defenal - Order #33313 (182350)1,083,701 3,332,340 40014210 4,416,041
'11
12 2008 PCAM Unbilled Amort (182356)( 165,4721 410,612 401 440,333 -195,193
13 (Amort period 01/14 thru 06/17)
14
15 Lidar Surveys - Order #32426 (1 82361 )261,628 402 43,605 218,023
16 (Amort period 0'l/12firu 12121)
17
18 PS&l Shoshone - Order #29904 (182368)666,978 401 266,791 400,'187
19 (Amort period 07/15 thru 06/'18)
20
21 Oregon CUB Fund Amortization-Order 15-399 ('182386)272,714 401 '192,504 80,210
22 (Amort period 01/16 thru 05/17)
23
24 ldaho Boardman ARO - Order#29414 (182393)217,783 4031, 4'110 43,557 174,226
25 (Amort period thru 2020)
26
27 Lanqley Revenue Accrual - Order #12-226 (182398)1,017,428 8'1,518 1,098,946
28
29 Siemens Lonq Term Defened Rate Base ('182410)11,632,907 4073 431,488 11,201,419
30 Order #33420 (Amort period 011'16lhru 12142]'
31
32 Siemens Lonq Term Defened Rate Base (182411ll 17,358,636 4073 643,866 16,714,770
33 Order #33420 (Amort period 01l16lhru 12142\
34
35 Siemens Long Term Defened Rate Base ('182412)446,876 34,485 Various 39,s87 441,774
36 Order#'15-387 (Amort period 01116thru 12142)
37
38 Siemens Lonq Tenn Defened Rate Base (182413)786,31 s 4073 29,166 757,149
39 Order#15-387 (Amort period 0'1116lhru 12142\
40
41 ldaho Boardman Decomissioning (1 82493)1,413,643 5,501,1 't5 Various 5,443,473 1,471,285
42 Order#32549 &#32457
43
FERC FORM NO. 1/3-Q (REV. 02-04)Page 232.'l
Name ent
ldaho Power Company
(1)
(2)
An Original
A Resubmission
(Mo, Da,
04t14t2017
Year/Period of Report
End of 20161Q4
OTHER REGULATORY ASSETS (Account 1 82.3)
1. Report below the particulars (details) called for conceming other regulatory assets, including rate order docket number, if applicable.
2. Minor items (5% of the Balance in Account 182.3 atend of period, or amounts less than $100,000 which ever is less), may be grouped
by classes.
3. For Regulatory Assets being amortized, show period of amortization.
Line
No.
Description and Purpose of
Other Regulatory Assets
(a)
Balance at BEinning
of Curent
Quarterffear
(b)
Debits
(c)
CREDITS Balance at end of
Cunent Quarterffear
(f)
Written off During the
Quarler ffear Account
6harged 1d)
Written off During
the Period Amount
(e)
1 Oreqon DSM Rider (182405)4,482,485 2,748,208 Various 1,678,552 5,552,141
2 Advise #05-03
3
4 Minor ltems (21)85,908 334,223 Various 345,691 74,440
5
6
7
8
o
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
u TOTAL 1,355,572,128 397,000,220 280,631,947 1,471,940,401
FERC FORM NO. 1/3-Q (REV. 02-04)Page 232.2
Name of Respondent
ldaho Power Company
This ReDort ls:(1) [1Rn Orisinat(2) l--1A Resubmission
Date of Report(Mo, Da, Yr)
04114t2017
Year/Period of Report
End of 2016/Q4
1
1. Report below the particulars (details) called for concerning miscellaneous deferred debits.
2. For any deferred debit being amortized, show period of amortization in column (a)
3. Minoritem(1%oftheBalanceatEndofYearforAccountl36oramountslessthan$l00,000,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
Amount
(e)
1 Prepaid Credit Facilitv('l 86025)1,044,482 1,'170,936 Various 1.192.172 1,023.246
2 (Amort period 11116 thru 1'1120\
3
4 Prepaid Service Contract 753,844 2.078.ffil 165, 401 644,515 2,188,'t96
5 Lonq Term Portion (186052)
o
7 Lonq Term (186121)1,069,659 401,222 27.782 1,041.877
I Workers Compensation
9
10 Prepaid ROW (186160)382,974 401 43,087 339,887
11 Rents/Easements Lonq Term
12
13 Long-Term Portfolio (1 86255)1,093,626 165, 402 628,157 465,rt69
14
15 OATT Reserve (186350)-1.083.701 4,416,041 400,4210 3,332,340
16
17 Advance Prepaid (186709)1.170.132 15'l 81,692 1,088,440
'18 Coal Royalties
19
20 Stable Value Life (186719)30,004.992 11,452,70C 't86 35,089 41,422,609
21
22 Security Plan (186720)14.769,993 250.078 143,4262 2,643,498 12,376,573
23 Net lnsurance Asset
24
25 American Falls Bond Ret(186722\133,395 401 14,552 118,U3
26 (Amort Period 04/00 thru 02/25)
27
28 Retiree Medical-COLI ( 1 86726)3,79',t.248 731.351 't43.4262 768.623 3.753.976
29
30 American Falls Water Riqhts 9.464.913 401 1,042.009 8.422.904
31 (Amort 01/06 - 02125\ fi867271
32
33 Shelf Reoistration (186733)147.328 186 147.328
34
35 Milner Bond Guarantee (186734)2.',t27.273 253 1,063.637 1,063.636
36 Amon02107 -21171
37
38 American Falls - Bond Refinance 439,992 401 47,999 391,993
39 (Amort throuqh 021251 (ffi7701
40
4',!Power Plant - Bridger (186780)127.397 401 127,397
42 (Amort thru 06/14 thru 12116)
43
44 Bridser Coal Study ('186781)1.405,787 66.827 107 355 1,472,259
45
46 Minor ltems (3)s,289 1.683.166 Various 1.673.034 15.42',1
47 Misc. Work in Progress
48 uereneo KeguEtory uomm.
Expenses (See pages 350 - 351)
49 TOTAL 66,701,295 75,332,657
FERC FORIll NO. 1 (ED. 12-9.1)Page 233
Name of Respondent
ldaho Power Company
This(1)
(2)
ReDort ls:
5]An original
TIA Resubmission
Date of Report(Mo, Da, Yr)
04114t2017
Year/Period of Report
End of 20161Q4
1. Report the information called for below concerning the respondent's accounting for deferred income taxes
2. At Other (Specify), include defenals relating to other income and deductions.
Lrne
No.
uescnplron ano Localron
(a)
E atance or Eeotntnoof Year -
(b)
Balance at Endof Year
(c)
1 Electric
2
a
4
q Other Electric (See footnote)83,1 81,338
6
7 Other (See footnote)163,213,808
8 TOTAL Electric (Enter Total of lines 2 thru 7)246,39s,146 260,803,740
s Gas
10
11
12
13
14
15 Other
16 TOTAL Gas (Enter Total of lines '10 thru 15
17 Other Non Electric See footnote 23,793,249
18 TOTAL (Acct 190) (Total of lines 8, 't 6 and I 7)270,'t 88,395 286,326,529
Notes
FERC FORM NO.1 (ED. 12{8)Page 231
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(21 A Resubmission
Date of Report
(Mo, Da, Yr)
04t14t2017
Year/Period of Report
2016tQ4
FOOTNOTE DATA
Schedule Page:234 Line No.: 5 Column: c
Prov for Rate Refund-HC Relicensing (AFUDC)
Deferred ldaho ITC
VE BA-Post Retirement Benefits
lncentive Deferral-Profit Sharing-Not in Rates
Stock Based Compensation
Revenue Sharing
Pension Expense-Oregon
Rate Case Disallowance
Construction Advances
Asset Retirement Obligation (ARO)
Postretirement Benefits
Bridger Revenue Deferral
Executive Deferred Compensation
Retention Pay Accrual
Deferred GBC Federal
USBR-American Falls O&M Costs Settlement
Non-VEBA Pension and Benefits
Total Other Electric
Schedule Page:234 Line No;7 Column: c
Pension-FAS 158
Regulatory Liability-FAS 1 09
Minimum Pension Liability
Postretirement Plan-FAS 1 58
TotalOther
Schedule Page:234 Line No.: 17 Column: c
Senior Management Security Plan
Micron CIAC-Depr Timing Diff
Meridian Gold CIAC-Depr Timing Diff
TotalNon Electric
Beginning Balance
34,282,231
19,624,338
11,343,166
3,814,372
3,813,934
1 ,235,198
3,008,600
2,273,741
1,637,625
1,171,049
486,873
316,603
39,761
0
31,500
138,920
(36,572)
Ending Balance
40,3s3,531
21,721,941
11,747,529
4,939,496
3,861,627
0
3,523,081
2,157,902
1,838,458
1,543,332
566,1 12
442,426
39,761
22,212
69,872
125,256
(179,497)
83,181,338 92,773,039
Beginning Balance
99,022,251
51 ,130,605
13,656,923
(595,971)
Ending Balance
103,332,880
51,326,330
13,403,940
(32,449)
163,213,808 168,030,701
Beginning Balance
23,635,408
153,366
4,475
Ending Balance
25,522,789
0
0
23,793,249 25,522,789
FERC FORM NO. 1 (ED. 12.871 Page 450.1
Name of Respondent
ldaho Power Company
This Report ls:(1) fiAn Original(2\ l--;A Resubmission
Date of Report
(Mo, Da, Yr)
04t't4t2017
Year/Period of Report
End of 2016/Q4
1. Report below the particulars (details) called for conceming common and preferred stock at end of year, distinguishing separate
series of any general class. Show separate totals for common and preferred 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 repo(ed in column (a) provided the fiscal years for both the 10-K report and this report are compatible.
2. Entries in column (b) should represent the number of shares authorized by the articles of incorporation as amended to end of year.
Line
No.
Class and Series of Stock and
Name of Stock Series
(a)
Number of shares
Authorized by Charter
(b)
Par or Stated
Value per share
(c)
Call Price at
End of Year
(d)
1 Account 20'l
2 Common Stock all of which is held by 50,000,000 2.50
3 ldaCorp, lnc. and not traded
4 Total Common Stock 50,000,000 2.50
5
6 Account 204 - None
7
8
I
10
11
12
'13
14
15
16
17
18
't9
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
FERC FORM NO. 1 (ED. 12-91)Page 250
Name of Respondent
ldaho Power Company
ls:(1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
04t14t20',t7
Year/Period of Report
End of 2016/Q4
uAPl I AL S I OCKS (Account 2O1 and 204) (Continued)
3. Give particulars (details) concerning shares of any class and series of stock authorized to be issued by a regulatory commission
which have not yet been issued.
4. The identification of each class of preferred stock should show the dividend rate and whether the dividends are cumulative or
non-cumulative
5. State in a footnote if any capital stock which has been nominally issued is nominally outstanding at end of year.
Give particulars (details) in column (a) of any nominally issued capital stock, reacquired stock, or stock in sinking and other funds which
is pledged, stating name of pledgee and purposes of pledge.
OUTSTANDING PER BALANCE SHEET(Total amount outstanding without reduction
for amounts held by respondent)
HELD BY RESPONDENT Line
No.AS REACQUIRED STOCK (Account 217)IN SINKING AND OTHER FUNDS
snares(e)Amount(f)s;hares(s)UOSt(h)Shares(i)Amount
U)
,|
39,150,812 97,877,030 2
3
39,150,812 97,877,030 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
38
39
40
41
42
FERC FORM NO. 1 (ED. 12-88)Page 251
Name of Respondent
ldaho Power Company
This Report(1) EAn
ls:
Original(2) ;-1A Resubmission
Date of(Mo, Da
Report
, Yr)
04t14t2017
Year/Period of Report
End of 2016/Q4
OTHER PAID-IN CAPITAL (Accounts 208-211, inc.)
Report below the balance at the end of the year and the information specified below for the respective other paid-in capital accounts. Provide a
subheading for each account and show a total for the account, as well as total of all accounts for reconciliation with balance sheet, Page 1 1 2. Add more
columns for any account if deemed necessary. Explain changes made in any account during the year and give the accounting entries effecting such
change.
(a) Donations Received from Stockholders (Account 208!State amount and give brief explanation of the origin and purpose of each donation.
(b) Reduction in Par or Stated value of Capital Stock (Account 209): State amount and give brief explanation of the capital change which gave rise to
amounts reported under this caption including identification with the class and series of stock to which related.
(c) Gain on Resale or Cancellation of Reacquired Capital Stock (Account 210): Report balance at beginning of year, credits, debits, and balance at end
of year with a designation of the nature of each credit and debit identified by the class and series of stock to which related.
(d) Miscellaneous Paid-in Capital (Account 21 1)-Classify amounts included in this account according to captions which, together with brief explanations,
disclose the general nature of the transactions which gave rise to the reported amounts.
LtneNo.tlem(a)Amount(b)
1 Account 208 - Donations received from stockholders - None
2
3 Account 209 - Reduction in par or stated value of Capital Stock - None
4
5 Account 210 - Gain on reacquired Capital Stock - None
6
7
8 Account 211 - Miscellaneous paid-in Capital - None
I
10
't1
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 TOTAL
FERC FORi' NO. 1 (ED. 12-87)Page 253
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5jRn Originat(2) nA Resubmission
Date of Report(Mo, Da, Yr)
04h4t2017
Year/Period of Report
End of 20161Q4
CAPITAL STOCK EXPENSE (Account 214)
1. Report the balance at end of the year of discount on capital stock for each class and series of capital stock.
2. lf any change occuned during the year in the balance in respect to any class or series of stock, attach a statement giving particulars
(details) of the change. State the reason for any charge-off of capital stock expense and specify the account charged.
Line
No
ulass and Senes ol Stocl(
(a)
Balance at Eno ol Year
(b)
1 Common Stock 2,096,925
2
3
4
5
6
7
8
9
10 Explanation of Changes during the year:
11
12
13
14
15
't6
17
18
19
20
21
22 TOTAL 2,096,925
FERC FORM NO. 1 (ED. 12-87)Page 2!4b
Name of Respondent
ldaho Power Company
ls:(1)
(2)
An Original
Resubmission
Date of Report(Mo, Da, Yr)
o411412017
Year/Period of Report
End of 2O16lQ4
1. Report by balance sheet account the particulars (details) concerning long{erm debt included in Accounts 221, Bonds,222,
Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other 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 dis@unt should not be netted.
9. Furnish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with
issues redeemed during the year. Also, give in a footnote the date of the Commission's authorization of treatment other than as
specified by the Uniform System of Accounts.
Line
No.
Class and Series of Obligation, Coupon Rate
(For new issue, give commission Authorization numbers and dates)
(a)
Principal Amount
Of Debt issued
(b)
Total expense,
Premium or Discount
(c)
1 Accounl22l
2 First Mortgage Bonds:
3 4.50% Series due 2020 130,000,000 1,190,698
4 234,601 D
5
6 5.50% Series due 2033 70,000,000 728,70',!
7 36,400 D
8
I 6.15% Series Due 2019 100,000,000 1,034,909
't0 184,949 D
1',i
12 3.40olo Series due 202O 100,000,000 1,159,871
13 498,864 D
14
15 5.30% Series Due 2035 60,000,000 408,411 D
16 3,802,019
17
't8 4.00% Series due 2043 75,000,000 742,017
19 193,836 D
20
21 6.00% Series due 2032 100,000,000 1,191,216
22 543,244 D
23
24 5.875% Series due 2034 5s,000,000 -585,759
25 746,961 D
26
27 5.50% Series due 2034 50,000,000 524,419
28 383,322 D
29
30 4.85% Series Due 2040 100,000,000 1,284,871
31 169,984 D
32
33 TOTAL 1,877,045,000 31,172,757
FERC FORM NO. I (ED. 12-96)Page 256
Name of Respondent
ldaho Power Company
This ReDort ls:(1) [An Original(2) [lA Resubmission
Date of Report
(Mo, Da, Yr)
04t1412017
Year/Periocl o, Report
End of 20'l6lQ4
LONG-TERM DEBT r
10. ldentify separate undisposed amounts applicable to issues which were redeemed in prior years.
11. Explain any debits and credits other than debited to Account 428, Amorlization and Expense, or credited to Account 429, Premium
on Debt - Credit.
12. ln a footnote, give explanatory (details) for Accounts 223 and 224 ol nel 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{erm 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.
1 5. lf interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest
expense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427, interest on
Long-Term Debt and Account 430, 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 LJursranotnq(Total amount outstanAing without
reduction for amounts held byresnl6fent)
lnterest for Year
Amount
(i)
Line
No.Date From
(0
Date To
(s)
1
2
11t20t09 3l'U20 11t20109 3t1t20 130,000,00c 5,850,000 3
4
5
0s/01/03 o4to1l33 0s/01/03 03/31/33 70,000,00c 3,850,000 6
7
I
4t1t09 4t1t19 4t1tog 411l't9 1,708,333 I
10
11
1'll1t10 5t112020 11t1110 st1t20 100,000,00c 3,400,000 12
13
14
08/26/05 o8126135 08t26105 08t26t35 60,000,00c 3,180,000 15
16
17
4t8t20't3 4t112043 418t2013 4t1t2043 75,000,00c 3,000,000 18
19
20
't'U15t02 11t15132 11t15tO2 11115132 100,000,00c 6,000,000 21
22
23
08/16/04 081't6134 08/16/04 oal16l34 55,000,00c 3,23'.t,250 24
25
26
03126104 o3t1st34 03126104 03t15t34 50,000,000 2,750,000 27
28
29
2t15t10 8t15t40 2t1st10 8t15140 100,000,00c 4,850,000 30
31
32
1,766,408,636 81,956,468 33
FERC FORi' NO. 1 (ED. 12-96)Page 257
Name of Respondent
ldaho Power Company
This(1)
(2)
Report ls:
[]An Original
nA Resubmission
Date of Report(Mo, Da, Yr)
o411412017
Year/Period of Report
End of 2O16lQ4
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, Olher 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.
Line
No.
Class and Series of Obligation, Coupon Rate
(For new issue, give commission Authorization numbers and dates)
(a)
Principal Amount
Of Debt issued
(b)
Total expense,
Premium or Discount
(c)
1 6.30% Series due 2037 140,000,000 1,495,799
2 278,367 D
3
4 6.25% Series due 2037 100,000,000 1,141,489
5 267,677 D
b
7 Port of Monow Vanable due 2027 4,360,000 188,545
I
9 Humboldt Variable due 2024 49,800,000 1,697,8s6
10
't1 Sweetwater Variable due 2026 1 16,300,000 3,026,122
12
13 2.50% Series due 2023 75,000,000 648,267
14 371,854 D
15
't6 4.30% Series Due 2042 75,000,000 802,240
17 49,417 D
'18
19 2.95% Series Due 2022 75,000,000 708,490
20 't27,607 D
21
22 3.65% Series Due 2045 250,000,000 2,559,510
23 1,715,000 D
24
25 4.05% Series Due 2046 120,000,000 1,31 '1 ,383
26 309,600 D
27
28 Subtotal Account 221 1,845,460,000 31,172,757
29
30 Accounl222 - Reaquired Bonds
31
32 Account 223: Advances for Associated Companies
33 TOTAL 1,877,045,000 31.',t72.757
FERC FORM NO. I (EO. 12-96)Page 256.1
Name of Respondent
ldaho Power Company
ls:(1)
(2)
An Original
A Resubmission
Date of Reoort
(Mo, Da, Yi)
04t14t20't7
Year/Period of Report
End of 2O16lQ4
10. ldentifo separate undisposed amounts applicable to issues which were redeemed in prior years.
'l 1. Explain any debits and credits other than debited to Account 428, Amorlization and Expense, or credited to Account 429, Premium
on Debt - Credit.
12. ln a footnote, give explanatory (details) for Accounts 223 and 224 oI nel 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 incurred during the year on any obligations retired or reacquired before end of year, include such interest
expense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427, interest on
Long-Term Debt and Account 430, 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 UUISIANOINO(Total amount outstanAing without
reduction for amounts held byres0l5fent)
lnterest for Year
Amount
(i)
Line
No.Date From
(f)
Date To
(s)
6122107 611512037 6t22107 6115t37 140,000,00c 8,820,000 1
2
3
10118t07 10115t2037 10118107 10115t37 100,000,00c 6,250,000 4
5
o
05117100 o2lo1l27 o5117100 02101127 4,360,00c 30,435 7
I
10t22t03 12101t24 't1t01los 12tO',U24 49,800,00c 2,564,700 I
10
10/3/06 7115126 10/3/06 7t15t26 1 16,300,00c 6,105,750 11
12
418120',t3 41112023 4t812013 4t1t2023 75,000,00c 1,875,000 13
14
'15
4t13112 4t1t42 4t131',t2 4t1142 75,000,000 3,225,000 16
't7
18
4113112 411122 4113112 4t1t22 75,000,000 2,212,500 19
20
21
316t15 311145 316115 3t1t45 250,000,000 9,125,000 22
23
24
3t10t16 3t1t46 3t10t't6 3t1146 120,000,000 3,928,500 25
26
27
1,745,460,000 81,956,,168 2A
29
30
31
32
1,766,408,636 81,956,468 33
FERC FORM NO. 1 (ED. 12-96)Page 257.1
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5]Rn Orisinat(2) nA Resubmission
Date of Report(Mo, Da, Yr)
04t14t2017
Year/Period of Report
End of 20161Q4
LONG-TERM DEBT (Account 221 ,222, 223 and ?.24)
1 . Report by balance sheet account the particulars (details) concerning long{erm debt included in Accounts 221, Bonds,222,
Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other 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 certifi€tes 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.
L 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.
Line
No.
Class and Series of Obligation, Coupon Rate
(For new issue, give commission Authorization numbers and dates)
(a)
Principal Amount
Of Debt issued
(b)
Total expense,
Premium or Discount
(c)
1
2 Account 224:
3 Bond Guarantee - American Falls 19,885,000
4 Note Guarantee - Milner Dam 11,700,000
5 Subtotal A*ounl224 31,585,000
b
7
8
I
10
11
't2
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33 TOTAL 1,877,045,00C 31,172,757
FERC FORM NO. 1 (EO. 12-96)Page 256.2
Name of Respondent
ldaho Power Company
This(1)
(2)
Reoort ls:
5]Rn Originat
[lA Resubmission
Date of Report(Mo, Da, Yr)
04114t2017
Year/Period of Report
End of 2016lQ4
LONG-TERM DEBT (Account 221,222,223 and 224) (Continued)
10. ldentiff separate undisposed amounts applicable to issues which were redeemed in prior years.
11. Explain any debits and credits other than debited to Account 428, Amorlization and Expense, or credited to Accounl 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.
1 5. 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 Account 427, 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 uulslanotno(Total amount outstantling without
reduction for amounts held by
resnl55dent)
lnterest for Year
Amount
(i)
Line
No.Date From
(f)
Date To
(s)
1
2
04t26t00 211125 19,885,000 3
o2t10t92 1,063,636 4
20,948,636 5
6
7
I
9
't0
't'l
12
13
14
15
16
't7
18
't9
20
2',!
22
23
24
25
26
27
28
29
30
31
32
't,766,408,636 81,956,468 33
FERC FORM liIO. I (ED. 12-96)Page 257.2
This Reoort ls:(1) 5]An originat(2) [lA Resubmission
Date of Report(Mo, Da, Yr)
04t14t2017
Year/Period ot Report
End of 20161Q4
Name of Respondent
ldaho Power Company
RECONCILIATION OF REPORTED NET INCOME WITH TAXABLE INCOME FOR FEDERAL INCOME TAXES
1. Report the reconciliation of reported net income for the year with taxable income used in computing Federal income tax accruals and show
computation of such tax accruals. lnclude in the reconciliation, as far as practicable, the same detail as fumished on Schedule M-1 of the trax retum for
the year. Submit a reconciliation even though there is no taxable 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 return, reconcile reported net income with taxable net income as if a
separate retum 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 the requirements of
the above instructions. For electronic reporting purposes complete Line 27 and provide the substitute Page in the context of a footnote.
Ltne
No,
Amount
(b)(a)
Panrculars (uelarls)
't89,241,920,|Net lncome for the Year (Page 'l 17)
2
3
4 Taxable lncome Not Reported on Books
5
6
7
I
I Deductions Recorded on Books Not Deducted for Retum
10
11
't2
13
't4 lncome Recorded on Books Not lncluded in Retum
't5
't6
17
18
19 Deductions on Return Not Charged Against Book lncome
20
21
22
23
24
25
26
27 Federal Tax Net lncome -1,642,387
28 Show Computation of Tax:
29 fenative Federal Tax @ 35%-574,835
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(21 A Resubmission
Date of Report
(Mo, Da, Yr)
04t1412017
Year/Period of Report
2016tQ4
FOOTNOTE DATA
Schedule Page:261 Line No.:5 Column: b
4OOs-AVOIDED COST 5,713,081
4OO3.CONSTRUCTION ADVANCES 573,808
4O13.CIAC - TAXABLE - ACCT 107 1,343,114
4021-ENGINEERING FEES - TAXABLE - ACCT 107 175,222
4024-REN EWABLE ENERGY CE RTI FICATES (REC) SALES 1,718,789
4506-MERIDIAN GOLD CIAC - DEPR TIMING DIFF. NON-OP (11,446)
4507-MICRON CIAC - DEPR TITUING DIFF. NON-OP (3e2,2e0)
fota!9.120.278
Schedule 261 Line No.: 10 Column: b
s{neaule 261 Line No.: 15 Column: b
lotal Federal and State taxes deducted on books 34,302,445
5OO1-BAD DEBT EXPENSE (223,283)
5022-263A CAP ITAL IZED OVE RH EADS (30,000,000)
5024-NON-DEDUCTIBLE MEALS 500,000
5O7O-INCENTIVE DEFERRAL-CRI & RELIABILITY-INCLUDED IN RATES 3,406,871
501 O-POSTEMPLOYMENT BENEFITS 202,685
5023-PENSION EXPENSE (22,846,287)
5O35.PCA EXPENSE DEFERRAL (8,886,414)
5047-EXECUTIVE DEFERRED COMP 0
5053-STOCK BASED COMPENSATION 121,992
5058-FIXED COST ADJUSTMENT (7,624,739)
5060-0REGON - PCAIV 2,266,716
5061-PENSION EXPENSE - OREGON 1,315,976
JO65-VALMY UNION PACIFIC CONTRACT 0
5067-455ET RETTREMENT OBLTGATTON (ARO)952,255
5069-M & E RESERVE 0
5071 -INCENTIVE DEFERRAL-PROFIT SHARING-NOT IN RATES 2,877,922
5501-SMSP - INSURANCE COSTS (1,539,906)
5503-EDC - UNREALIZED GAIN/LOSS FROM RABBITRUST 0
5504-NON-DEDUCTIBLE POLITICAL EXPENSES 1,081,872
5505-SMSP - NET 4,827,677
Total Line 10 (19,264,2181
7501-REVERSE EQUITY EARNINGS OF SUBSIDIARIES 7,993,526
923,6667509-SMSP - INSURANCE PROCEEDS
75o2-ALLOWANCE FOR OFUDC 22,030,622
7503-ALLOWANCE FOR BFUDC 10,193,622
701O-PROV FOR RATE REFUND - HC RELICENSING
(AFUDC)
(15,529,608)
701 1-OATT REVENUE DEFICIENCY 0
7012-REVENUE SHARING 3,159,478
701 3-LANGLEY REVENUE ACCRUAL 0
Iotal Line 15 28,771,306
Schedule eagg: ZU tini No.:20 Cotumn: b
FERC FORM NO.1 ED.1 450.1
Name of Respondent
ldaho Power Companv
This Report is:
(1) X An OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
04t14t2017
Year/Period of Report
2016tQ4
FOOTNOTE DATA
5538-STOCK BASED COMP. STOCK 3,905,006
3702-STOCK BASED COMP. DIVIDENDS 618,377
302S-MANUFACTURI NG DEDUCTION 0
3034-REIVIOVAL COSTS 15,883,233
3O42.GAIN/LOSS ON REACQUIRED DEBT 12,244,496
3073-REPAI RS DEDUCTION 80,000,000
3077-PREPAID INSURANCE & OTHER EXPENSES (202,826)
3OO1.VEBA - POST RETIREMENT BENEFITS (1,047,703)
3020.CONSE RVATION EXPENSES 1,053,843
30sg-SOFTWARE - LABOR COSTS DEDUCTED - ACCT 107 1,900,000
3o72-RELICENSING - LABOR COSTS DEDUCTED - ACCT 107 2,200,000
3OOg-DEPR TIMING DIFF. OPERATING - FEDERAL 30,91 1 ,318
STATE INCOME TAX DEDUCTED ON FEDERAL RETURN 4,503,319
Iotal 151,969,063
FERC FORM NO. 1 (ED. 12-871 Page 450.2
Name of Respondent
ldaho Power Company
This Report ls:(1) []An Original(2) [lA Resubmission
Date of Report(Mo, Da, Yr)
04t14t2017
Year/Period of Report
End of 20'l6lQ4
TAXES ACGRUED, PREPAID AND CHARGED DURING YEAR
1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during
the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. 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 accrued taxes.)
Enter the amounts in both columns (d) and (e). The balancing of this page is not affected by the inclusion of these taxes.
3. 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.
Lrne
No.
Kind of Tax
(See instruction 5)
(a)
BALANCE AT BEGINNING OF YEAR I axesCharoed
R/#?s
(d)
I axesPaid
QgringYear
(e)
Adjust-
ments
(f)
r axes Accrueo(Account 236)(b)
rleDato taxes(lnclude in Account 165)
,|Federal:
2 lncome -5,185,372 464,352 15,218,447
3 Social Security - (FOAB)-534 15,391,446 14,949,530
4 Unemployment 132,993 95,131
5 Subtotal Federal -5,185,906 15,988,791 30,263,108 -s33
b
7 State of ldaho:
8 Property 9,435,081 22,108,882 21,948,161
I Non-Operating 10,3rt6 26,542 27,291
10 lncome -258,247 3,717,2',t1 6,573,864
11 KWH 92,925 1,405,449 't,420,374
12 Unemployment 566,5'15 542.928
13 Regulatory Commission 2,212,657 2.212.657
14 Business License - Sho Ban 't50 150
15 Subtotal ldaho 9,280,105 30,037,406 32,725,425
16
17 State of Oregon
18 Property 1,596,798 3,189,676 3,184,038
19 Non-Operating Property 948 1,921 1,946
20 lncome -106,776 67,740 209,442
21 Regulatory Commission 224,995 224,995
22 Unemployment -857 54,996 51,227
23 Franchise 197,487 820,300 823,375
24 Subtotal Oregon 89,854 1,597 ,746 4,359,628 4,495,O23
25
26 State of Montana:
27 Property 169,627 322,249 330,789
28 Subtotal Montana 169,627 322,249 330,789
29
30 State of Nevada
31 Property 536,309 1,035,811 987,O24
32 Subtotal Nevada 5s6,309 't,035,811 987,024
33
34 State of Wyoming
35 Corporate License 4,680 4,680
36 Property 815,142 1,593,455 1,61 1,869
37 Subtotal Wyoming 815,',t42 1,598,135 1,616,549
38
39
40
41 TOTAL 5,',t92,418 2,134,055 37,183,591 70,41 't,537
FERC FORM NO. 1 (ED. 12-96)Page 262
Name of Respondent
ldaho Power Company
ls:(1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
0411412017
Year/Period of Report
End of 2O16lQ4
5. lf any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year,
identifying the year in column (a).
6. Enter all adjustments of the accrued and prepaid tax accounts in column (f) and explain each adjustment in a foot- note. Designate debit adjustments
by parentheses.
7. Do not include on this page entries with respect to defened income taxes or taxes collected through payroll deductions or otheruise 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 rND c)F YEAR Line
No.(Taxes accrued
Account 236)(s)
Prepaid Taxes
(lncl. in lc;;unt 165)
Electric(Account 408.1 , 409.1 )
Extraordinary ltems
(Accou6t a0e.3)
AOIUSImenIS IO KeI.Eamings (Account 439)
(k)
Other
(t)
1
-19,939,467 -96,1 37 2
44',t.915 15,391,446 3
37,862 132,993 4
-19,459,690 15,428,302 560,489 5
6
7
9,595,802 22,107,982 8
9,597 I
-3,114,901 3.6'17.124 't0
78,001 1,405,449 11
23,588 566,515 12
2,212,657 13
150 14
6,592,087 29,909,877 127,529 15
16
17
1,591,160 3,089,583 18
't9
-248,478 62,813 20
973 224,995 21
2,9't2 54,996 22
194,412 820,300 23
-51,154 't,592,133 4.252.687 106,941 24
25
26
161,088 322,249 27
161,088 322,249 28
29
30
487,522 1,035,81 1 31
487,522 1,035,81 1 32
33
34
4,680 35
7%,727 1,593,45s 36
796,727 '1,598,135 37
38
39
40
-11,945,257 2,079,655 36,386,4s4 797,',t37 41
FERC FORM NO.1 (ED. 12-96)Page 263
Name of Respondent
ldaho Power Company
This Report ls:(1) [An Original(2) ;-1A Resubmission
Date of Report
(Mo, Da, Yr)
04t1412017
YeariPeriod of Report
End of 201O|A4
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during
the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. 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 accrued taxes.)
Enter the amounts in both columns (d) and (e). The balancing of this page is not affected by the inclusion of these taxes.
3. 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. Listtheaggregateofeachkindoftaxinsuchmannerthatthetotal taxforeachStateandsubdivisioncanreadilybeascertained.
Lrne
No.
Kind of Tax
(See instruction 5)
(a)
tsALANUE AI tsE,GINNING OI- YEAK I axesPaid
QUringYear(e)
Adjust-
ments
(f)
PreDato laxes(lnclude in Account 165)
1 State of Washington
2 Property 6,000
{Subtotal Washington 6,000
4
5 Other States lncome 31,5't6 -18,479 3,3'r4
6 Payroll Tax Credit -16,'145,950
7 Canada GST tax -7,920 -5,812
8
o
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 TOTAL 5,192,418 2,',t34,055 37,183,591 70,4'15,'t,537
FERC FORM NO. 1 (ED. 12-96)Page 262.1
Name of Respondent
ldaho Power Company
This Report ls:(1) [An Original(2) [lA Resubmission
Date of Report
(Mo, Da, Yr)
04t14120',t7
Year/Period ol Report
End of 20161Q4
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR I
5. lf any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year,
identifying the year in column (a).
6. Enter all adjustments of the accrued and prepaid tax accounts in column (f) and explain each adjustment in a foot- note. Designate debit adjustments
by parentheses.
7. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or othemise 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.'l 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.
BALANCF AT :ND OF YEAR Dll Line
No.(Taxes accrued
AccolnJ 236)
Prepaid laxes
(lncl. in
lchTunt
165)
Electric(Account 408.1, 409.1 )
Extraordinary ltems
(Account 409.3)
AO.lUSImenIS rO KeI.Eamings (Account 439)
(k)
Other
(t)
I
6,000 6,000 2
6,000 6,000 3
4
9,723 -20,657 5
6
-38 7
8
I
10
11
12
13
14
15
16
17
't8
19
20
2',!
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
-11.945,257 2,079,655 36,386,4s4 797,137 4'l
FERC FORM NO. 1 (ED. 12-96)Page 263.1
Name of Respondent
ldaho Power Comoany
This Report is:
(1) X An Originalel A Resubmission
Date of Report
(Mo, Da, Yr)
04t14t2017
Year/Period of Report
2016tQ4
FOOTNOTE DATA
Scneaute Pase:262 Line No.:2 Column: IAccount 409.2 $ 56.0, 489
s_glp{tttp!ege!?9?Line No.:3 Column: f
FICA Refund is an adjustment because the offset account is not a 600 expen se account.
Schedule Page:262 Line No.: I Column: I
Account 107 $ e00
lSchedule Page:262 Line No.:9 Column: I
Account 408.2
lScneaute eage:262
$26 EA1
Line No.: 10 Column: I
Account 409.2 $ 100 087
)Schedule Page:262 Line No.:18 Column: I IAccount 107 $ 100 093262 Line No.: 19 Column: I
Account 408.2 1 921262 Line No.:20 Column: I
Account 4 o,t A Oa1
262.1 Line No.: 5 Column: I
Account 4 2,17 8
262.1 Line No.:6 Column: iThis amount is an offset to lines 3, 4, 12 and 22. Each month employer paid taxes flowinto various 408.1 accounts. fn that same month these amounts are offset with a different408.1 account. These payroll taxes are then al-located back to the balance sheet and OeM
accounts based on current month labor charges.
lSchedule Page:262.1 Line No.:7 Column: f ]Canada GST accrual is an adjustment because the offset account
account.
r5 not a 600 expense
FERC FORM NO. 1 (ED. 12.871 Page 450.1
Name of Respondent
ldaho Power Company
This(1)
(2)
Report ls:
ffiAn Original
l-lA Resubmission
Date of Report(Mo, Da, Y0
04114t2017
Year/Period of Report
End of 20161Q4
Report below information applicable to Account 255. Where appropriate, segregate the balances and transactions by utility and
nonutility operations. Explain by footnote any correction adjustments to the account balance shown in column (g).lnclude in column (i)
the average period over which the tax credits are amortized.
Lrne
No.sub{vfions
Balance at tseornntno
of Year-
(b)
Defened for Year Adjustments
(s)AGCOUNI NO.(c)AmounI(d)ACCOUNI NO(e)Amr(IUNI
,|Electric Utility
3o/o
4o/o 377,771 53,844
4 7o/o
E 10o/o 18,316,035 't,374,923
6 11o/o 1,135,795 26,029
7 Other- State 59,825,329 411.4 3.227.080 41',t.4 1,467,36S
8 TOTAL 79,654,930 3,227,080 2,922,16!
o Other (List separately
and show 3o/o, 4o/o,7o/o,
'10% and TOTAL)
10 Line6Col A11olo
1',!
12 State of ldaho 59,825,329 411.4 3,227,080 411.4 1,467,36€
13
14
15
'16
17
18
19
20
2',l
22
23
24
25
26
27
28
30
31
32
33
34
35
36
37
3t
2C
4C
41
42
42
44
4a
4C
41
4e
FERC FORM NO.1 (ED.12-89)Page 266
Name
ldaho Power Company (1)
(2t A Resubmission 0411412017
Year/Period of Report
End of 2016/Q4
Balance at Endof Year
(h)to
ADJUSTMENT EXPLANATION Line
No.
1
2
323,927 7.02 3
4
'16,941,',t12 't3.32 5
1,109,766 43.64 6
6'r,585,040 40.77 7
79,959,845 I
I
10
11
61,585,040 12
13
't4
15
16
17
't8
't9
20
2'.1
22
23
24
25
26
27
28
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
6
47
48
FERC FORM NO. I (ED. r2{9)Page 26i1
Name of Respondent
ldaho Power Company
This(1)
(2)
Reoort ls:
fiRn Originat
[lA Resubmission
Date of Report
(Mo, Da, Yr)
0411412017
Year/Period of Report
End of 20161Q4
1. Report below the particulars (details) called for concerning other deferred credits.
2. For any deferred credit being amortized, show the period of amortization.
3. Minor items (5% of the Balance End of Year for Account 253 or amounts less than $100,000, whichever is greater) may be grouped by classes
Line
No.
Description and Other
Deferred Credits
(a)
Balance at
Beginning of Year
(b)
DEBITS
Credits
(e)
Balance at
End of Year
(0
Contra
Account(c)
Amount
(d)
1 Point to Point Trans Study(253201)2,058,725 235 2't 1,500 1,U7,225
2
3 Frv (2s3202)2,466,666 400 400,000 2,066,666
4 (Amort Period Mar 1998-Feb 2023)
5
b Sho Ban Trans ROW (253480)187,500 242 15,000 172,500
7 (Amort Period Jan 2005-Dec 2027)
8
I Operations Accrual (253550)1,293,253 Various 1,035,594 266,797 524,456
10
11 Milner Falling Water (253953)713,831 186 1,063,636 1,205,477 855,672
't2 Amort Period (Feb '1992 - Feb 2017)
13
14 Postretirement Benefi ts (253960)1,245,358 253 1,245,358 1,448,043 't/4q043
15
't6 Directors Defened Compensation 3,789,347 131 525,032 296,354 3,560,669
't7 (253980-253999)
18
19 Minor ltems (1) 253042 3,318 401 74,236 75,029 4,111
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47 TOTAL 11,757,998 4,570,356 3,291,700 10,479,342
FERC FORM NO. I (ED. 12-94)Page 269
Name of Respondent
ldaho Power Company
This(1)
(2\
Reoort ls:
5l1An Orlsinat
-A Resubmission
Date of Report(Mo, Da, Yr)
04t14t20't7
Year/Period of Report
End of 2016/Q4
ACCUMULATED DEFFERED INCOME TAXES. OTHER PROPERTY (ACCOUNI zEZ
1. Report the information called for below concerning the respondent's accounting for defened income taxes rating to property not
subject to accelerated amortization
2. For other (Specify),include deferrals relating to other income and deductions.
Line
No.
Account
(a)
Balance at
Beginning of Year
(b)
CHANGES DURING YEAR
Amounts Debited
to Account 410.1
(c)
Amounts Credited
to Account 41 1 .1
(d)
,|Account 282
2 Electric 39,050,389 12,942,903
3 Gas
4 Other
5 TOTAL (Enter Total of lines 2 thru 4)469,103,751 39,050,389 12,942,903
6 Non-Operating Property
7 Other - Regulatory Asset 875,027,483
8 Like Kind Exchange- Reclass No 5,775,786
o TOTAL Account 282 (Enter Total of lines 5 thru 1,349,907,020 39,050,389 12,942,903
10 Classification of TOTAL
11 Federal lncome Tax 1,156,602,661 38,712,647 12,834,476
't2 State lncome Tax 193,304,359 337,742 108,427
13 Local lncome Tax
NOTES
FERC FORM NO. 1 (ED. 12-96)Page 271
Respondent
ldaho Power Company (1)
(2)
An Original (Mo, Da,
Resubmission 04t14t2017
Year/Period of Report
End of 2016/Q4
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 4'11.2
(0
Debits Credits
Accrunt
Credited(s)
Amount
(h)
Account
Debited
(i)
Amount
(i)
1
-144,665 495,355,90'2
3
4
-144,665 495,355,90'5
6
182 73,512,341 948,539,82r 7
282100 'l/14,665 5,631,',121 8
73,512,341 1,449,526,84i I
10
60,909,10S 1,243,389,94r 't'l
12,603,232 206,1 36,90(12
13
NOTES (Continued)
FERC FORM ilO. I (ED.12.96)Page 275
Name of Respondent
ldaho Power Companv
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t14120'17
Year/Period of Report
2016tQ4
FOOTNOTE DATA
2016 Chanoes durino Year Adiustments Debits Adiustrnents Credits 2016
Account
Beginning
Balance
DR to
410.1
CR to
411.1
Acct.
credited Amount
Acct.
debited Amount
Ending
Balance
)epreciation Timing
)iff-Operating
-ike Kind Exchange -
leclass Non-Rate Base
ntangible-Labor Costs
)educted-Acct 107
llAC-Taxable-Acct 107
r'almy Capitalized ltems
Software-Labor Costs
)educted-Acct 107
ingineering:ees-Taxable-Acct 107
453,391,724
18,348,619
(3,287,799\
63,560
1,051,482
(463,83s)
38,856,279
(648,922)
366,430
476,602
12,310,946
470,090
63,560
98,307
282111 (144,665)
Trf
Trf
5,775,786
(s,775,786)
485,712,843
(5,631 ,121)
17,699,697
(3,391,459)
1,528,0U
(562,142)
IOTAL Line 2 469,103,751 39,050,389 12,942,W3 (144,665)495,355,902
Schedule 274 Line No.:2 Column: b
FERC FORM NO. 1 (ED. 12-871 Page 450.1
Name of Respondent
ldaho Power Company
This Reoort ls:(1) fiAn Originat(2) ;1A Resubmission
Date of Report
(Mo, Da, Yr)
04t1412017
Year/Period ot Report
End of 201'O|A4
1. Report the information called for below concerning the respondent's accounting for deferred income taxes relating to amounts
recorded in Account 283.
2. For other (Specify),include defenals relating to other income and deductions.
Line
No.
Account
(a)
Balance at
Beginning of Year
(b)
CHANGES DURING YEAR
to AcctBlt 410.1 to Acco,urlt 41 1 .1
1 Account 283
2 Electric
3 Other Electric -- See Note 17,030,507 1,636,552
4
5
6
7
8 Other - See Note
I TOTAL Electric (Total of lines 3 thru 8)162,588,387 17,030,50i 1,636,552
't0 Gas
1'l
12
13
14
15
16
17 TOTAL Gas (Total of lines 11 thru 16)
18 Other - See Note
19 TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18)162,906,623 17,030,507 1,636,5s2
20 Classification of TOTAL
21 Federal lncome Tax 136,654,884 14,286j14 1.372.828
22 State lncome Tax 26.251.739 2,744,397 263,724
23 Local lncome Tax
NOTES
FERC FORM NO. I (ED. 12-96)Page 276
Name of Respondent
ldaho Power Company
This ReDort ls:(1) 5]Rn original(2) 1A Resubmission
Date of Report
(Mo, Da, Yr)
04t't4t2017
Year/Period of Report
End of 2016/Q4
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.
EHANGFS DI IRING YFAR ADJUSTMENTS
Balance at
End of Year
(k)
Line
No.
Amounts uebited
to Account 410.2
(e)
Amounts Gredited
to Account 41't .2
(f)
Debits Credits
ACCOUntc1$feo Amount
(h)
,lmounl
(i)
1
2
79,556,060 3
4
5
6
7
4,874,150 103,300,432 I
4,874,150 182.856,492 I
10
't1
12
13
14
15
16
17
6,221 419,7',\!-95,258 18
6,221 419,7',\!4,874,150 182,761,234 19
20
5,219 352,08C 4,088,701 153,310,006 21
1,002 67,635 785,449 29,451,228 22
23
NOTES (Continued)
FERC FORM ilO. 1 (ED. 12-96)Page 277
Name of Respondent
ldaho Power Companv
This Report is:
(1) X An Original(21 A Resubmission
Date of Report
(Mo, Da, Yr)
o4t14t2017
Year/Period of Report
20161Q4
FOOTNOTE DATA
276 Line No.:3 Column: b
TOTAL Line 3
Schedule T16 tine No.i Column: b
Schedule Line No.: 18 Column: b276
2016 Chanqes durino Year 2016
Acc,ount
Beginning
Balance
DR to
410.1
CR to
4',t1.',|
Ending
Balance
Pension Expense
PCA Expense
Conservation Expenses
Fixed Cost Adjustment
Cregon PCAM
Boardman Decpmmission
Cregon Excess Power Costs
PS & I Costs
Renewable Energy Certifi cates (REC)
Sales
[angley Revenue Accrual
Royalty lncome
2011 LIDAR Surveys Deferral
Sennett Mtn Maint Defenal
ntervenor Funding Orders
CPUC Grid West Loans
imission Allowances
Siemens LTP Contractrrepaid Credit Facility
27,66/.,003
17,419,329
1,733,392
14,394,933
't.131.323
4U.201
(61,8e8)
745,859
370,974
119,331
29,277
121,344
925
9j02
(0)
9,1 18,756
3,474,144
412,000
2,980,892
2,803
70,496
260,755
361,616
37,092
272.859
39,094
886,1 73
2,803
693,226
17,047
29,277
925
7,101
36,782,759
20,893,473
2,14s,392
17,375,825
247,953
554,697
(64,691)
260,755
52,633
370,974
361 ,616
102,284
't60,438
2,001
37,092
272,859
64,162,105 17,030,507 1,636,552 79,556,060
20't6 Adiustments Credits 2016
Beginning
Balance
Acct.
debited Amount
Ending
BalanceAerount
)ension-FAS 158)ostretirement Plan-FAS 1 58
99,O22,252
(595,970)
190
190
4,310,629
563,521
103,332,881
G2,449\
IOTAL Line E 98,426,282 4,874,',t50 103,300,432
2016 2016
Account
Beginning
Balance
DR to
410.2
CR to
411.2
Ending
Balance
IDC-Unrealized Gain/Loss From Rabbit Trust
SMSP-Unrealized Gain/Loss From Rabbi Trust
loyalty lncome
)regon Non-Op Prop Tax Adi
4,420
(41,951)
355,408
359
6,208
13
58,099
361 .616
4,420
(100,050)
0
372
IOTAL Line 18 318,236 6,221 4',t9,715 (95,258)
FERC FORM NO.1 12-8 450.1
Name of Respondent
ldaho Power Company
Th.S
(1)
(2')
Reoort ls:
fiAn originat
llA Resubmission
Date of Report(Mo, Da, Yr)
04t14t2017
Year/Period ot Report
End of 20161Q4
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
QuarterlYear
(b)
DEBITS
Credits
(e)
Balance at End
of Current
Quarterl/ear
(0
Ac@unt
Credited
(c)
Amount
(d)
1 Market to Market Short Term - (254001 )278,759 175 5,863,292 '13,415,95(7,831,417
2 IPUC Order#2866'l
3
4 Oreqon Solar Pilot (254005)3,040,517 Various 507,417 1,228,981 3,762,081
5 Order #10-1 98
6
7 Revenue Sharing (254101)3,159,478 400, 1823 3,17'1,340 11,86'
8 IPUC Oder#33149
I
10 ldaho DSM Rider (254201)6,554,074 Various 43,278,699 47,454,77(10,730.15't
11 IPUC Order#29026
12
't3 FAS 133 Market to Market - (254203)'126,480 175 |,749,267 1,622,781
14 IPUC Order#2866'1
15
16 BPA Credit Residential ldaho (254401)2,025,068 Various 8,593,632 8,4'17,55t 1.848,994
17 Advice # 15-13
18
19 Bridger Depreciation (254800)1,1 31,669 400 319,76;1.451.436
20 OPUC Order#12-296
21
22 Unfunded Accum Def lncome Tax (254966)51,1 30,605 Various 525,024 720,74t 51,326,330
23
24 Minor ltems (6)265,005 Various 2,100,436 1,928,03r 92,604
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41 TOTAL 67,71 1,655 65,789,107 75,120,465 77,043,013
FERC FORM NO. 1/3-Q (REV 02-04)Page 27E
Name of Respondent
ldaho Power Company
Thas Report ls:(1) [An Orisinal(2) 1A Resubmission
Date of Report(Mo, Da, Yr)
04t14t2017
Year/Period ot Report
End of 20161Q4
ELECTRIC OPERATING REVENUES
1 . The following instructions generally apply to the annual version of these pages. Do not report quarterly data in columns (c), (e), (0, and (g). Unbilled revenues and MWH
related to unbilled revenues n€ed not be reported separately as required in the annual version ofthese pages.
2. Report below operating revenues fur each prescribed account, and manufactured gas ,evenues in total.
3. Report number of cuslomeG, columns (f) and (g), on the basis of meters, in addition to the number of flat rate accounts; except that where separate meter readings are added
for billing purposes, one customer should be counted for each group of meters added. The -average number of customers means the average of twelve figures at the close of
each month.
4. lf increases or decreases from previous period (columns (c),(e), and (g)), are not derived from previously report€d figures, explain any inconsistencies in a footnote.
5. Disclose amounts of $250,000 or greater in a footnote for accounts 451, 456, and 457.2.
Line
No
Title of Account
(a)
Operating Revenues Year
to Date Quarterly/Annual
(b)
0perating Revenues
Previous year (no Quarterly)
(c)
1 Sales of Electricity
2 (440) Residential Sales 514,953,833 512,068,335
3 (442) Commercial and lndustrial Sales
4 Small (or Comm.) (See lnstr. 4)455,158,518 466,541,569
5 Large (or lnd.) (See lnstr. 4)182,590,036 182,254,287
6 (444) Public Street and Highway Lighting 3,996,825 4,039,381
7 (445) Other Sales to Public Authorities
8 (446) Sales to Railroads and Railways
I (448) lnterdepartmental Sales
10 TOTAL Sales to Ultimate Consumers 1,156,699,212 1,164,903,572
't1 (447) Sales for Resale 25,204,985 30,887,261
12 TOTAL Sales of Electricity 1,18't,904,197 1,195,790,833
't3 (Less) (449.1 ) Provision for Rate Refunds 10,706,040 13,865,518
14 TOTAL Revenues Net of Prov. for Refunds 1 ,171,198,157 1,18'1,925,315
15 Other Operating Revenues
't6 (450) Forfeited Discounts
17 (451 ) Miscellaneous Service Revenues 4,119,479
18 (453) Sales of Water and Water Power
19 (454) Rent from Electric Property 14,260,349 24,852,979
20 (455) lnterdepartmental Rents
21 (456) Other Electric Revenues 31,174,302
22 (456.1 ) Revenues from Transmission of Electricity of Others 31,490,797 24,129.372
23 (457.1) Regional Control Service Revenues
24 (457.2) Miscellaneous Revenues
25
26 TOTAL Other Operating Revenues 84,100,642 84,276,132
27 TOTAL Electric Operating Revenues 1.255.298.799 1,266,20',1,447
FERC FORM NO. 1r3-O (REV. 12-05)Page 300
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5jRn Orlsinat(2) [lA Resubmission
Date of Report(Mo, Da, Yr)
o4114t2017
Year/Period of Report
End of 20161Q4
ELECTRIC OPERATING REVENUES I
6. Commercial and industrial Sales, Account 1142, may be classified according to the basis of classifcation (Small or Commerial, and Latge or lndustrial) regularly used by the
respondentifsuchbasisofclassificationisnotgenerallygreaterthanl000Kwofdemand. (SeeAccount442oftheUniformSystemofAccounts. Explainbasisofclassification
in a fuotnote.)
7. See pages 108-109, lmportant Changes During Period, for important new teritory added and important rate incGase 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 Quartedy/Annual
(d)
Amount Previous year (no Quarterly)
(e)
Cunent Year (no Quarterly)
(f)
Previous Year (no Quartedy)
(s)
1
5,004,352 4,977,',t76 440,362 432,275 2
3
5,916,649 6,059,428 86,621 85.560 4
3,243,344 3,195,786 't2'l 119 5
31,,105 32,103 2,797 2,592 6
7
I
I
14,195,750 14,264,493 529,901 520,546 10
1,185,879 1,254,136 11
15,381,629 15,518,623 529,901 520,546 12
13
15,381,629 15,518,629 529,901 520,546 14
Line 12, column (b) includes $
Line 12, column (d) includes
14,098,656
14't,068
of unbilled revenues.
MWH relating to unbilled revenues
FERC FORM NO.1l3-Q (REV. 12-05)Page 301
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(21 A Resubmission
Date of Report
(Mo, Da, Yr)
04t14t2017
Year/Period of Report
20161Q4
FOOTNOTE DATA
ischedule Pige:300 Line No.: 17 Column: b l,
This amount consists of:
Service Establishment/Connection Charges $ 3,971,647(Incl-udes late and after hour charges)Misc. Under $250,000 1,1,1 ,970
Totaf Account 451 $ 4 ,089,677
Scneaub qq{,e:399 Line No.:21 Column: bThis amount consists of:Al-ternate Distribution Service
DSM ActivityMisc. Under $250,000
32L,995
33, 754, 060
L83,824
Tota-I Account 456 $ 34, 259 ,8'7 9
FERC FORM NO. 1 (ED. 12.871 Page 450.1
Name of Respondent
ldaho Power Company
This Report ls:(1) [An Original
(21 [-1A Resubmission
Date of Report(Mo, Da, Yr)
0411412017
Year/Period of Report
End of 20161Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 3'10-311.
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), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. Theaveragenumberofcustomersshouldbethenumberofbillsrenderedduringtheyeardividedbythenumberof billingperiodsduringtheyear(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. Reportamountofunbilledrevenueasofendofyearforeachapplicablerevenueaccountsubheading.
Ltne
No.
NumDer and lrile oI KaIe scneoule
(a)
MWn 50to
(b)
Kevenue
(c)
Kvvn OPer Ct(e
Kevenue PerKWh Sold(f)
1 440 - Residential Sales:
2 01 - Residential 4,880,040 490,'t74,874 4s9,033 11,114 0.1 004
a 03 - Residential Master Meter 3,842 368,532 22 174,63e 0.0959
4 05-Residential -TOD 21,216 2,06't,824 1,307 16,233 0.0972
E 15 - Dusk to dawn lighting 2,631 647,151 0.2460
6 Unbilled Revenues 96,623 10,801,968 0.'t 1 18
7 Other Revenues 10,899,484
8 Total 440 5,004,352 514,953,833 440,362 11,364 0.1029
o
10 442-Commercial & lndustrial Sales
11 07 - General service 148,314 18,286,983 30,677 4,835 0.1233
't2 09P - General service 483,647 31,260,864 217 2,228,788,0.0646
13 09S - General service 3,282,659 241,833,988 34,289 95,735 0.0737
14 09T - General service 6,052 431.147 4 1 ,513,00C o.0712
15 15 - Dusk to Dawn Light 4,216 747,696 0.1773
16 19P - Uniform rate contracts 2.224.994 't28.490.778 't14 19,517,491 o.0577
17 19S - Uniform rate contracts 6,363 404,552 1 6,363,000 0.0636
18 19T - Uniform rate contracts 130,478 7,484.544 a 43,492,667 0.0574
.to 24S - lrrigation Pumping 1,948,079 155,460,562 20,535 94,866 0.0798
20 40 - General service 10,593 915,795 89S 11,783 0.0865
21 Special Contracts 870,207 44,140,269 2 290,069,000 0.0507
22 Commercial & lndustrial Unbill 44,391 3,287,794 o.o74'l
23 Other Revenues 5,003,586
24 fo|e.l 442 9,1s9,993 637,748,554 ffi.742 105,600 0.0696
25
26 444 - Public Street Lighting:
27 40 - General service 857 74,365 45S 1,867 0.0868
28 41 - Street lighting 27,737 3,712,785 '1.768 15,688 0.1 339
29 42 - f raffic control lighting 2,757 't73,916 57(4,837 0.0631
30 Unbilled 54 8,894 o.1647
3'l Other Revenues 26,865
32 fo|al 444 31,405 3,996,825 2,797 11,228 0.1273
33
34
35
36
37
38
39
40
41 TOTAL Billed 14,054,682 1,142,600,556 529,901 26,523 0.0813
42 Total Unbilled Rev.(See lnstr. 6)141,06t 14,098,6s6 (c 0.0999
43 TOTAL 14,195,75(1,156,699,212 529,901 26,789,0.0815
FERC FORM NO. I (ED. 12-95)Page 30,1
Name of Respondent
ldaho Power Company
(1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
0411412017
Year/Period of Report
End of 2016/Q4
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 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 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.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule orTariff Number
(c)
Averaoe
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
(e)
Averaoe
Monthly CP-Demand
(0
,|OS nla nla nla
2 Arizona Public Service Co.SF WSPP nla nla nla
3 Avangrid Renewables, LLC SF WSPP nla nla nla
4 OS WSPP nla nla nla
5 OS WSPP nla nla nla
b Avista Corp.SF WSPP nla nla nla
7 Basin Electric Power Cooperative SF WSPP nla nla nla
8 Black Hills Power lnc.SF WSPP nla nla nla
I OS WSPP nla nla nla
't0 Bonneville Power Administration SF WSPP nla nla nla
11 Calpine Energy Services, L.P SF WSPP nla nla nla
12 Carglll Power Markets LLC SF WSPP nla nla nla
'13 Citigroup Energy lnc.SF WSPP nla nla nla
14 Clatskanie PUD SF WSPP nla nla nla
Subtotal RQ c 0 0
Subtotal non-RQ c 0 0
Total 0 0 0
FERC FORM NO.1 (ED. 12-90)Page 310
Respondent (1)
(2)
An Originalldaho Power Company A Resubmission
Date of Report
(Mo, Da, Yr)
04t14t2017
Year/Period of Report
End of 20161Q4
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 repo( 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), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 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.'t0. 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
($)
(i)
other uharges
($)
(i)
1,405,42e 1.405.42t I
179 7,295 7,294 2
4,728 113,488 't13,48t 3
5,30C 5,30C 4
5,94.S 5,94€5
96,781 1,501,183 1,501,183 6
2,160 11,465 't1,461 7
3,679 28,930 28,93C I
1 e I
74,713 1,391 ,848 1 ,391,848 10
337 7,327 7,327 11
410 9,350 9,35C 12
9,857 227,554 227,554 13
399 5,160 5,1 6C 14
0 0 0 0 0
'r,'r85,879 0 22,766,467 2,438,518 25.204.985
1,185,879 0 22,766,167 2,4it8,518 25,20'0,985
FERC FORM NO. 1 (ED. 12-90)Page 311
Name of
ldaho Power Company
(1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
o411412017
Year/Period of Report
End of 2O16lQ4
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{erm 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 setter can unilaterally get out of the contracl.
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 flrm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line
No.
Name of Company or Public Authority
(Footnote Affi liations)
(a)
Statistical
Classifi-cation
(b)
FERC Rate
Schedule orTariff Number
(c)
Averaoe
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
AVeraoe
Monthly NCF Demanr
(e)
Averaoe
Monthly CPDemanc
(f)
,|EDF Trading North America, LLC SF WSPP nla nla nla
2 Energy Keepers SF WSPP nla nla nla
3 Eugene Electric Board SF WSPP nla nla nla
4 Exelon Generation Company. LLC SF WSPP nla nla nla
5 OS WSPP nla nla nla
6 Los Angeles Department of Water & Power SF WSPP nla nla nla
7 Macquarie Energy LLC SF WSPP nla nla nla
8 OS WSPP nla nla nla
I Morgan Stanley Capital Group lnc.SF ISDA nla nla nla
10 os ISDA nla nla nla
11 OS WSPP nla nla nla
12 Municipal Energy Agency of Nebraska SF WSPP nla nla nla
13 NV Energy SF WSPP nla nla nla
14 OS WSPP nla nla nla
Subtotal RQ c 0 0
Subtotal non-RO 0 0 0
Total 0 0 0
FERC FORM NO. 1 (ED. 12-90)Page 310.'l
Name of Respondent
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
04t14t20't7
Year/Period of Report
End of 20161Q4
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 cplumn (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. ln Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the 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.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401 , line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
Megawatt Hours
Sold
(s)
REVENUE Total ($)
(h+i+j)
(k)
Line
No.Demand Charges($)
(h)
Energy Charges
($)
(i)
Other Charges
($)
(i)
37,544 553,422 553,422 ,|
382 9,189 9,18€2
2,513 39,535 39,539 3
11',t,210 2,625,370 2,625,37C 4
89,305 89,305 5
220,850 5,839,425 5,839,425 6
4 24 24 7
317,348 317,348 8
56,485 756,679 756,679 o
238 5,474 5,474 10
499,468 499,468 't'l
70 150 15C 12
7,551 89,744 89,744 '13
2,117 2,117 14
0 0 0 0 0
1,185,879 0 22,766,467 2,438,518 25,204,985
1,185,879 0 22,766,167 2,,f38,518 2s,204,98s
FERC FORM NO. 1 (ED. 12-90)Page 3'11.1
me
ldaho Power Company
(1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
o4t14t2017
Year/Period of Report
End of 20161Q4
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{erm" 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{erm 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{erm firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short{erm 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{erm 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{erm service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule orTariff Number
(c)
Averaoe
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
AVeraoe
Monthly NCP Demanr
(e)
Averaoe
Monthly CP-Demand
(0
1 NorthWestern Energy SF WSPP nla nle nla
2 NorthWestem Energy OS WSPP nla nle nla
3 OS WSPP nla nla nla
4 PacifiCorp lnc.SF WSPP nla nle nla
5 PacifiCop lnc.OS T-7 nla nla nla
6 Portland General Electric Company SF WSPP nla nla nla
7 Poilland Generd Electdc Cofipany OS r-7 nla nla nla
I Podard General Ebctdc Cotnpany OS WSPP nla nle nla
I Powerex Corp.SF WSPP nla nle nla
10 Powercx Corp.OS WSPP nla nla nla
11 Porwrcx Corp.OS WSPP nla nle nla
12 Public Service of Colorado SF WSPP nla nla nla
13 Puget Sound Energy, lnc.SF WSPP nla nla nla
14 Puget Sound Energy, lnc.OS T-7 nla nla nla
Subtotal RO 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORM NO. 1 (ED. 12-90)Page 310.2
ldaho Power Company (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)
o4t14t2017
Year/Period of Report
End of 20161Q4
RESALE
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), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (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 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 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
4O1,iine 24.
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
($)
(i)
Other Charges
($)
(i)
5,'102 74,220 74,224 1
64 192 192 2
6,013 6,013 3
11,282 160,279 160,279 4
36 836 836 5
124,937 2.675,748 2,675,748 6
12 244 244 7
3,099 3,099 8
20,713 220,241 220,241 I
2$246 246 10
7A 7A 't1
3,600 67,920 67,924 12
14,4%210,788 2',t0,788 13
4 81 81 't4
0 0 0 0 0
1.185,879 0 22,766,467 2,438,5't8 25,204,985
1,185,879 0 22,766,167 2,438,518 25,201,985
FERC FORM NO. 1 (ED. 12-90)Page 311.2
ldaho Power Company
(1)
(2)
An Original
A Resubmission
Date of Report
(Mo, Da, Yr)
04t14t2017
Year/Period of Report
End of 20161Q4
SALES FOR
1. Reportall salesforresale(i.e.,salestopurchasersotherthanultimateconsumers) transactedonasettlementbasisotherthan
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{erm service. "Long{erm" 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{erm 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{erm firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short{erm 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{erm 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{erm service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule orTariff Number
(c)
AveraoeMonthly Billing
Demand (MW)
(d)
Actual Demand (MW)
AVeraae
Monthly NCF Demanr
(e)
AveraoeMonthly CP-Demand
(0
1 Rainbow Energy Marketing Corporation SF WSPP nla nla nla
2 Salt River Pro.ject SF WSPP nla nla nla
3 Seattle City Light SF WSPP nla nla nla
4 Seattle City Light OS WSPP nla nla n/a
5 Shell Energy North America (US), L.P SF WSPP nla nla nla
6 (US),OS WSPP nla nla nla
7 Siena Pacific Pouer Co., dba NV Eneqy OS T-7 nla nla nla
8 Snohomish County PUD SF WSPP nla nla nla
I Talen Energy Marketing, LLC.SF WSPP nla nla nla
10 OS WSPP nla nla nla
11 Talen Energy Marketirg, LLC.OS WSPP nla nla nla
12 Tenaska Power Services Co.SF WSPP nla nla nla
13 Power Co.OS WSPP nla nla nla
14 The Energy Authority, lnc SF WSPP nla nla nla
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORM NO. 1 (ED. 12-90)Page 310.3
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report
(Mo, Da, Yr)
0411412017
Year/Period of Report
End of 2016/Q4
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), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Repo( 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 RCt/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
Megawatt Hours
Sold
(s)
REVENUE Total ($)
(h+i+j)
(k)
Line
NoDemand Charges
($)
(h)
Energy Charges
($)
(i)
other charges
($)
(i)
6,800 71,088 71,088 1
332 8,865 8,865 2
5,468 104,626 104,626 3
45 45 45 4
182,065 2,707,230 2,707,230 5
73,23a 73,235 b
98 1,93t 't.938 7
605 12,180 12,'t 80 I
7,391 84,1 30 84,1 30 o
1,54S 1,54S 10
1.080 4,435 4,43!'t1
4,330 32,390 32,39C 't2
37e 37e 13
't60,594 2,978,97',!2,978,971 14
0 0 0 0 0
1,185,879 0 22,766,467 2,438,518 25,204,985
1,185,879 0 22,7ffi,167 2,138,518 25,204,985
FERC FORM NO. I (ED. 12-90)Page 311.3
ldaho Power Company (1)
(2)
Original
A Resubmission
Date ot Report(Mo, Da, Yr)
04t't412017
Year/Period ot Report
End of 20161Q4
'l . 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 Classiflcation 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 "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 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 flve years.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule orTariff Number
(c)
Averaoe
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
I\VeraoeMonthly NCP Demanr
(e)
AveraoeMonthly CP-Demanc
(f)
1 OS WSPP nla nla nla
2 TransAlta Energy Marketing (U.S.), lnc.SF WSPP nla nla nla
3 OS WSPP nla nla nla
4 Tri-State Generation and Transmission SF WSPP nla nla nla
5 Prior Year Write Off Recovered AD nla nla nla
6 Transmission Penalty Distribution OS nla nla nla
7
8
I
10
1',!
12
13
14
Subtotal RQ c 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORM NO. 1 (ED. 12-90)Page 310.t1
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Reoort(Mo, Da, Yi)
0411412017
Year/Period of Report
End of 201O|A4
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
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401,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)
9ther uharges
($)
(i)
'l,774 1,774 1
6,414 140,478 140,478 2
4,401 4,401 3
75 175 '175 4
3,255 3,255 5
6,337 6,337 t)
7
8
I
10
't'l
12
13
't4
0 0 0 0 0
1,185,879 0 22,766,467 2,438,5'18 25,204,985
1,185,879 0 22,766,167 2,'|38,518 25,204,985
FERC FORM NO. 1 (EO. 12-90)Page 311.4
Name of Respondent
ldaho Power Companv
This Report is:
(1) X An Original
Ql A Resubmission
Date of Report
(Mo, Da, Yr)
0411412017
Year/Period of Report
2016tQ4
FOOTNOTE DATA
Schedule Page:310 Line No.: 1 Column: a
ADM Investor SU! v ruUo,Inc Eutures Account Document, dated May 5
dated January 16,
, 20L5
2at5
Schedule Page: 310 Line No.:4 Column: a
Avangrid Renewables, LLC, Capacity Agreement,
Schedule Page: 310 Line No.: 5 Column: a
Financial Transmission Losses
Schedule Page: 310 Line No; 9 Column: a
Einancial Transmissi-on Losses
Schedule Page:310.1 Line No.: 5 Column: a
Financial Transmission Losses
Schedule Page:310.1 Line No.: I Column: aFinancial Transmission Losses
Schedule Page:310.1 Line No.: 10 Column: a
Non-firm Sales
Schedule Page:310.1 Line No.: 11 Column: aFinancial Transmission Losses
Schedule Page: 310.1 Line No.: 14 Column: a
Financial Transmisslon Losses
Schedule Page:310.2 Line No.: 2 Column: a
Non-firm sales
Schedute Page:310.2 Line No.: 3 Column: aFinancial Transmissi-on Losses
Schedule Page:310.2 Line No.: 5 Column: a
Sprnn:-ng or operating reserves
Schedule Page: 310.2 Line No.:7 Column: a
Spinning or operatlng reserves
Schedule Page: 310.2 Line No.: I Column: aFinancial Transmission Losses
Schedule Page:310.2 Line No.: 10 Column: a
Non-firm sales
Schedute Page:310-2 Line No.: 11 Column: a
Financial Transmisslon Losses
Schedule Page:310.2 Line No.: 14 Column: a
Spinning or operating reserves
Schedule Page:310.3 Line No.:4 Column: a
Non-firm saLes
Schedu/e Page: 310.3 Line No.: 6 Column: aEinancial Transmission Losses
Schedule Page: 310.3 Line No.:7 Column: a
Spinning or operating reserves
Schedule Page:310.3 Line No.: 10 Column: a
Financial Transmisslon Losses
Schedule Page:310.3 Line No.: 11 Column: a
Non-firm sal,es
Schedule Page:310.3 Line No.: 13 Column: a
Financial Transmission Losses
Schedule Page:310.4 Line No.: 1 Column: a
Fi-nanicaL Transmission Losses
Schedule Page: 310.4 Line No.: 3 Column: a
Financial Transmission Losses
FERC FORM NO. 1 (ED. 12-871 Page 450.1
ldaho Power Company
(1)
(2)
An Original
A Resubmission
(Mo, Da
04114120't7
Year/Period of Repofi
End of 2016/Q4
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
lf the amount for previous year is not derived from previously reported figures, explain in footnote.
Line
No.
Account
(a)
Amount forCurrent Year
(b)
Amount forPrevious Year(c)
1 1. POWER PROOUCTION EXPENSES
2 A. Steam Power Generation
3 Operation
4 (500) Ooeration Suoervision and Engineering 't.158.861 1.287.887
5 (501) Fuel 137.688.753 131.286.3s6
6 (502)Steam Exoenses 8.971.',192 9.791.612
7 (503) Steam from Other Sources
8 (Less) (504) Steam Transferred-Cr
I (505) Electric Expenses 1.46,6,072 1.262.175
10 (506) Miscellaneous Steam Power Expenses 9,097,246 6,676,269
11 (507) Rents 206.742 432,038
12 (509) Allowances
13 TOTAL Operation (Enter Total of Lines 4 thru 12)158.588.866 150,736,337
14 Maintenance
15 (5'10) Maintenance Supervision and Engineering 100,102 126,993
16 (51 'l ) Maintenance of Structures 528,121 878,O71
17 (512) Maintenance of Boiler Plant 14,263.344 13,861,559
18 (513) Maintenanc,e of Electric Plant 5.150.575 5.412.553
19 (514) Maintenance of Miscellaneous Steam Plant 6,435,348 6,923.251
20 TOTAL Maintenance (EnterTotal of Lines 15 thru 19)26.477.490 27,202.427
2',!TOTAL Power Production Expenses-Steam Power (EntrTot lines 13 & 20)'t85,066,356 177,938,764
22 B. Nuclear Power Generation
23 Operation
24 (517) Ooeration Suoervision and Enqineerinq
25 (5'18) Fuel
26 (5'19) Coolants and Water
27 (520) Steam ExDenses
28 (521) Steam ftom Other Sources
29 (Less) (522) Steam Transfened-Cr
30 (523) Electric ExDenses
31 (524) Miscellaneous Nuclear Power Expenses
32 (525) Rents
33 TOTAL Operation (Enter Total of lines 24 thru 32)
34 Maintenance
35 (528) Maintenance Supervision and Engineering
36 (529) Maintenance of Structures
37 (530) Maintenance of Reactor Plant Equipment
38 (531) Maintenance of Electric Plant
39 (532) Maintenance of Miscellaneous Nuclear Plant
40 TOTAL Maintenance (Enter Total of lines 35 thru 39)
41 TOTAL Power Production Expenses-Nuc. Power (Entr tot lines 33 & 40)
42 C. Hydraulic Power Generation
43 Operation
44 (535) Operation Supervision and Engineering 5,676,404 5.798.402
45 (536) Water for Power 6.O25.791 9,070,347
46 (537) Hvdraulic Exoenses 't4.667,285 14,907,949
47 (538) Electric Exoenses 1,696,943 1,623.508
48 (539) Miscellaneous Hvdraulic Power Generation Expenses 5,699,628 5,675,338
49 (540) Rents 235,365 235.266
50 TOTAL Operation (Enter Total of Lines 44 thru 49)34,001,4't 6 37.310.810
51 C. Hydraulic Power Generation (Continued)
52 Maintenance
53 (541) Mainentance Supervision and Engineering 116.729 120,335
54 (542) Maintenance of Structures 1,218.450 1.120.484
55 (543) Maintenance of Reservoirs, Dams, and Watenrays 658,337 575.444
56 (544) Maintenance of Electric Plant 2.197.930 2,655.929
57 (545) Maintenance of Miscellaneous Hydraulic Plant 2.345.337 2,860,095
58 TOTAL Maintenance (Enter Total of lines 53 thru 57)6.536.783 7.332.287
59 TOTAL Power Prcduction Expenses-Hydraulic Power (tot of lines 50 & 58)40,538.199 44.643.097
FERC FORM NO.1 (ED. 12-93)Page 320
Name of Respondent
ldaho Power Company
This Reoort ls:(1) fiRn Originat(2) nA Resubmission
Date ol Report(Mo, Da, Yr)
04t14t2017
Year/Peflod ot Report
End of 2016/Q4
lf the amount for previous year is not derived from previously reported figures, explain in footnote.
Line
No.
Account
(a)
Amount forCurrent Year(b)
Amount forPrevious Year(c)
60 D. Other Power Generation
61 ODeration
62 (546) Ooeration Suoervision and Enqineerinq 738.484 646,633
63 (547) Fuel 41.802.251 54.944.643
64 (548) Generation Exoenses 4.155.51't 4,603,907
65 (549) Miscellaneous Other Power Generation Expenses 807,061 934,376
66 (550) Rents
67 TOTAL Ooeration (Enter Total of lines 62 thru 66)47 61,129.559
68 Maintenance
69 (551) Maintenance SuDervision and Enqineerinq
70 (552) Maintenance of Structures 400,817 363,695
71 (553) Maintenance of Generatinq and Electric Plant 126,988 71,909
72 (554) Maintenance of Miscellaneous Other Power Generation Plant 2.764.692 1.270.216
73 TOTAL Maintenance (Enter Total of lines 69 thru 72)1.705.820
74 TOTAL Power Production Expenses-Other Power (Enter Tot of 67 & 73)50,795,804 62,835,37S
75 E. Other PowerSuoolv Expenses
76 (555) Purchased Power 240,208,728 217,596,604
77 (556) Svstem Control and Load Dispatchinq 2,678 2,436
78 (557) Other Exoenses -1,206,336 20,61s,245
79 TOTAL Other Power Supply Exp (Enter Total of lines 76 thru 78)239,005,070 238,214,285
80 TOTAL Power Production Expenses (Total of lines 21,41,59,74 &791 515,405,429 523,631,525
81 2. TRANSMISSION EXPENSES
82 Operation
83 (560) Operation Supervision and Enqineering 2,953,141 4,136,382
84
85 (56'1.1) Load Dispatch-Reliability 43,356
86 (561.2) Load Dispatch-Monitor and Operate Transmission System 1,602,644 1,757 ,323
87 (561.3) Load Dispatch-Transmission Service and Scheduling 1.390.552 't.159.643
88 (561.4) Scheduling, System Control and Dispatch Services
89 (561.5) Reliability, Planning and Standards Development
90 (561.6) Transmission Service Studies
91 (561.7) Generation lnterconnection Studies 25.459 21.585
92 (561.8) Reliability, Planning and Standards Development Services 1,634,564
93 (562) Station Exoenses 2.637.946 2.633.328
94 (563) Overhead Lines Exoenses 953,376 967,338
95 (564) Underground Lines Expenses
96 (565) Transmission of Electricitv bv Others 5,555.'121 6,279.133
97 (566) Miscellaneous Transmission Expenses 7.471 2,365
98 (567) Rents 4139.757 3.084.84S
99 TOTAL ODeration (Enter Total of lines 83 thru 98)20.943.387 20,041,946
100 Maintenance
101 (568) Maintenance SuDervision and Enoineerinq 169,832 157,051
102 (569) Maintenance of Structures 2,882 12,69C
103 (569.1) Maintenance of Computer Hardware 27,827 23,40e
'l04 (569.2) Maintenance of Computer Software 896,206 867,398
105 (569.3) Maintenance of Communication Equipment 1s,105 29,123
106 (569.4) Maintenance of Miscellaneous Regional Transmission Plant
107 (570) Maintenance of Station Equipment 2.220.242 3.286.32S
108 (571 ) Maintenance of Overhead Lines 1.132.781 2.935.312
'109 (572) Maintenance of Underground Lines
110 (573) Maintenance of Miscellaneous Transmission Plant
1'11 TOTAL Maintenance (Total of lines 101 thru 1 10)4.46,4.875 7 .311.311
112 TOTAL Transmission ExDenses (Total of lines 99 and 111)25.408.262 27,353.257
FERC FORM NO. 1 (ED. 12-93)Page32'l
Name of Respondent
ldaho Power Company
This(1)
(2)
Reoort ls:
5]Rn Originat
1A Resubmission
Date of Report(Mo, Da, Yr)
041't412017
Year/Period of Report
End of 20161Q4
lf the amount for previous year is not derived from previously reported figures, explain in footnote
Line
No.
Account
(a)
Amount forCurrent Year
(b)
Amount forPrevious Year
(c)
113 3. REGIONAL MARKET EXPENSES
114 Operation
115 (575. 1) Ooeration Supervision
116 (575.2) Dav-Ahead and Real-Time Market Facilitation
'117 (575.3) Transmission Riqhts Market Facilitation
118 (575.4) Caoacitv Market Facilitation
't 19 (575.5) Ancillarv Services Market Facilitation
120 (575.6) Market Monitoring and Compliance
121 (575.7) Market Facilitation, Monitoring and Compliance Services
122 (575.8) Rents
123 Total Operation (Lines 1 15 lhru '122)
124 Maintenance
125 (576.1 ) Maintenance of Structures and lmprovements
't26 (576.2) Maintenance of Computer Hardware
127 (576.3) Maintenance of Computer Soft\,vare
't28 (576.4) Maintenance of Communication Equipment
129 (576.5) Maintenance of Miscellaneous Market Operation Plant
130 Total Maintenance (Lines 125 thru '129)
131 TOTAL Regional Transmission and Market Op Expns (Total 123 and 130)
132 4. DISTRIBUTION EXPENSES
133 Operation
134 (580) Operation Supervision and Engineering 4.226.094 4.289.300
135 (581 ) Load Dispatching 4.026.028 3.897.253
136 (582) Station Exoenses 1.544.740 1.339.544
't37 (583) Overhead Line Exoenses 3.606.076 3,968,00S
138 (584) Underoround Line Exoenses 3.076.757 2.889.346
139 (585) Street Liohtino and Siqnal Svstem Expenses 82,633 87,956
140 (586) Meter Exoenses 4.717.443 4.769.220
14'l (587) Customer lnstallations Expenses 897,759 784,',t57
142 (588) Miscellaneous Exoenses 7.518.466 6.041.032
143 (589) Rents 305,059 262,07',!
144 TOTAL Operation (Enter Total of lines 134 thru 143)30,001,055 28.327.888
145 Maintenance
'146 (590) Maintenance Suoervision and Enqineerinq -1,554,525 10,627
'147 (591) Maintenance of Structures
148 (592) Maintenance of Station Equipment 3,870,89S 3,630,6't8
't49 (593) Maintenance of Overhead Lines 14,975,930 14,203,471
150 (594) Maintenance of Underqround Lines m,8,712 604,456
151 (595) Maintenance of Line Transformers 28,581 36,603
152 (596) Maintenance of Street Lighting and Signal Systems 588,626 486,847
1s3 (597) Maintenance of Meters 873,691 767,987
154 (598) Maintenance of Miscellaneous Distribution Plant 380,105 289,620
155 TOTAL Maintenance (Total of lines 146 thru 154)20,032,019 20,030,229
156 TOTAL Distribution Expenses (Total of lines 144 and '155)50,033,074 48,3s8,1 17
157 5. CUSTOMER ACCOUNTS EXPENSES
'158 Operation
159 (901) Suoervision 617.373 484.451
160 (902) Meter Readino Exoenses ,|1,843,348
't61 (903) Customer Records and Collection Expenses 14.631,724 15,508.388
162 (904) Uncollectible Accounts 3,946,809 3,319,967
163 (905) Miscellaneous Customer Accounts Expenses -551 395
164 TOTAL Customer Accounts Expenses (Total of lines 159 thru 163)20,u4,622 21,156,549
FERC FORM NO. I (ED. 12-93)Page322
Name of Respondent
ldaho Power Company
This Report ls:(1) [An Original(2) ;-1A Resubmission
Date of Report
(Mo, Da, Yr)
041't4120't7
Year/Period of Report
End of 20'l6lQ4
lf the amount for previous year is not derived from previously reported figures, explain in footnote.
Line
No.
Account
(a)
Amount forCunent Year(b)
Amount forPrevious Year(c)
165 6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
166 Operation
167 (907) Suoervision 796.990 807.713
168 (908) Customer Assistance Expenses 41.249.994 37.606,989
'169 (909) lnformational and lnstructional Expenses 427.793 424.680
't70 (910) Miscellaneous Customer Service and lnformational Expenses 449.522 735.552
171 TOTAL Customer Service and lnformation Expenses (Total 167 thru 170)42.924.299 39.574.934
172 7. SALES EXPENSES
't73 Operation
174 (91 1) Suoervision
175 (9'12) Demonstratinq and Sellinq Expenses 24 79,720
176 (91 3) Advertisino Exoenses
177 (9'1 6) Miscellaneous Sales Expenses
178 TOTAL Sales Expenses (Enter Total of lines 174 thru 177)24 79.720
179 8. ADMINISTRATIVE AND GENERAL EXPENSES
180 Operation
181 (920) Administrative and General Salaries 81.422.856 73.062,858
182 (921) ffice Supplies and Expenses 14.719.911
18s (Less) (922) Administrative Expenses Transferred-Credit 33.792.414 26.120.468
184 (923) Outside Services Employed 8,226.785 8,177,858
't8s (924) Propertv lnsurance 3,362,',t54 3,382,607
't86 (925) lniuries and Damaqes 5,991,970 6,644,800
't87 (926) Employee Pensions and Benefits 52,679,051 45,004,540
188 (927) Franchise Requirements
189 (928) Regulatory Commission Expenses 3,818,396 3,616,257
190 (929) (Less) Duplicate Charges-Cr
191 (930.1 ) General Advertising Expenses 582,063 618,107
192 (930.2) Miscellaneous General Expenses 3,552,222 5,444,853
193 (931) Rents 2,000
194 TOTAL Operation (EnterTotal of lines 18'l thru 193)140,616,030 134,553,323
195 Maintenance
196 (935) Maintenance of General Plant 6,271,101 5,817,078
't97 TOTAL Administrative & General Exoenses (Total of lines 194 and 196)146.887.131 140.370.401
'198 TOTAL Elec Oo and Maint ExDns (Total 80,'112.'131.156.164.171.178.197\801.502.841 800.524.s03
FERC FORM NO.1 (ED. 12.93)Page 323
ldaho Power Company (1)
(2)
)ort ls:
lAn Original
lA Resubmission
Date of Report(Mo, Da, Yr)
041',t412017
Year/Period of Report
End of 2016/Q4
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 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.
Line
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 Demanr
(e)
Average
Monthly CP Demanc
(0
1 AgPower Jerome / Double A Digester LU N/A N/A N/A
2 Allan RavenscrofUMalad River LU .488Mw
3 Baker City Hydro LU N/A N/A N/A
4 Bannock County, ldaho LU N/A N/A N/A
5 Bennett Creek Wind Farm LU N/A N/A N/A
6 Bettencourt DryCreek Biofactory LU N/A N/A N/A
7 Big Sky West Dairy Digester LU N/A N/A N/A
8 Big Wood Canal Company
I Black Canyon #3 LU N/A N/A N/A
10 Jim Knight LU N/A N/A N/A
11 Sagebrush LU N/A N/A N/A
12 Black Canyon Bliss LU N/A N/A N/A
't3 Blind Canyon Hydro LU N/A N/A N/A
14 Branchflowerffrout Company LU NiA N/A N/A
Total
FERC FORM NO. I (ED. 12-90)Page 326
Respondent (1)
(2)
An Originalldaho Power Company A Resubmission
Date of Report(Mo, Da, Yr)
04t'14t20't7
Year/Period of Report
End of 20161Q4
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-mincident 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 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)
MegaWatt Hours
Delivered
(i)
Demand Charges
($)
0)
Energy Charges
($)
(k)
Other Charges
($)
(t)
Total (j+k+l)
of Settlement ($)
(m)
25,654 2,263,62e 2,263,626 I
1,74a '155,672 72,103 227,775 2
88i 44,777 44,777 3
10,971 612,752 612,752 4
44,697 2.844.',!8C 2,8/,4j8A 5
10,779 943,333 943,333 6
8,693 563,96C 563,960 7
8
267 19,06€19,069 I
902 67,00€67,009 't0
804 59,031 59,031 11
151 3,34€3,346 't2
3,347 1 39,10i 1 39,1 07 13
701 50,151 50,151 14
4,330,800 234,7',17 18't.766 2,B',t5,124 228,585,769 8,807,835 240,208,72t
FERC FORM NO. 1 (ED. 12-90)Page 327
Name Respondent
ldaho Power Company (1)
(2)
)on ls
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
0411412017
Year/Period of Report
End of 20161Q4
1. Reportall powerpurchasesmadeduringtheyear. Alsoreportexchangesofelectricity(i.e.,transactionsinvolvingabalancingof
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{erm" 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.
Line
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
Monthly Monthly
(e)(0
1 Burley Butte Wind Park LU N/A N/A N/A
2 Bypass Limited LU N/A N/A N/A
3 Camp Reed Wind Park LU N/A N/A N/A
4 Cargill I nc./86 Anaerobic Digester LU N/A N/A N/A
5 Cassia Wind Farm LU N/A N/A N/A
6 CCP OR Tenant 1, LLC - Grove LU N/A N/A N/A
7 CCP OR Tenant 1, LLC - Hyline LU N/A N/A N/A
8 CCP OR Tenant 1, LLC - Open Range LU N/A N/A N/A
9 CCP OR Tenant 1, LLC - Railroad LU N/A N/A N/A
10 CCP OR Tenant '1, LLC - Vale Air LU N/A N/A N/A
11 CCP OR Tenant 1, LLC - Thunderegg LU N/A N/A N/A
12 City of Cove, Oregon / Mill Creek LU N/A N/A N/A
13 LU N/A N/A N/A
14 City of Pocatello LU N/A N/A N/A
Total
FERC FORM NO. I (ED. 12-90)Page 326.1
Name
ldaho Power Company
(1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
04t14t2017
Year/Period of Report
End of 20161Q4
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 supplieds 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 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'l ,
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)
Megawatt Hours
Delivered(i)
Demand Charges
($)
(i)
Energy Charges
($)
(k)
Other Charges
($)
(t)
Total U+k+l)of Settlement ($)
(m)
56,37!3,224,07e 3,224,07e 1
26,06(1,421,76t 't,421 ,76e 2
69,00:5,811,842 5,811,842 3
10,37t 896,224 896,22a 4
24,50e 1,470,871 1,470,877 5
941 53,06(53,06S 6
63(36,93(36,93C 7
2,26i 131,50€131 ,506 8
224 1 1,95!11,954 I
1,15t 66,45:66,453 10
74i 37,654 37,654 11
2,87(204,18!204,185 12
6(-47.794 47.793 13
1,35!99,384 99,384 14
4,330,800 234,7',t7 181,766 2,815,124 228,585,769 8,807,835 240,208,72t
FERC FORM NO. I (ED. 12-90)Page 327.1
Name of
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
04t1412017
Year/Period of Report
End of 2016/Q4
P
1. Reportall powerpurchasesmadeduringtheyear. Alsoreportexchangesofelectricity(i.e.,transactionsinvolvingabalancingof
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 suppliefs service to its own ultimate consumers.
LF - for long{erm firm service. "Long{erm" 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{erm 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{erm service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
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 Demand
(0
1 Clear Springs Food lnc.LU N/A N/A N/A
2 Clifton E. Jenson/Birch Creek LU 05Mw
3 Cold Springs Windfarm, LLC LU N/A N/A N/A
4 Consolidated Hydro lnc. / Enel
5 Barber Dam LU N/A N/A N/A
b Dietrich Drop LU N/A N/A N/A
7 GeoBon #2 LU N/A N/A NiA
8 Lowline #2 LU N/A N/A N/A
I Rock Creek #2 LU N/A N/A N/A
10 Contractors Power Group lnc./Mile 28 LU N/A N/A N/A
11 Crystal Springs Hydro LU N/A N/A N/A
12 Curry Cattle Company LU .084Mw
't3 David McCollum/Canyon Springs LU N/A N/A N/A
't4 David R Snedigar LU N/A N/A N/A
Total
FERC FORM NO. 1 (ED. 12.90)Page 326.2
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
o411412017
Year/Period of Report
End of 2016lQ4
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 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 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)
Megawatt Hours
Delivered
(i)
Demand Charges
($)
U)
Energy Charges
($)
(k)
Other Charges
($)
(t)
Total U+k+l)
of Settlement ($)
(m)
s,50(340,64i 340,642 I
34(17,50C 14,03:3'l,s33 2
53,6'ti 3,832,99(3,832,99€3
4
12,07t 608,95(608,95e 5
13,78t 774,85e 774,85C 6
3,00i 232,422 232,422 7
8,11(434,101 434,107 I
7,211 357,601 357,60'l I
4,62a 327,934 327,934 10
11,021 750,782 750,782 't'l
67S 26,79e,28,067 54,863 't2
56(7,913 7,913 13
1,371 94,51t 94,516 14
4,330,800 234,717 't81,766 2,815,124 228,585,769 8,807,835 240,208,72t
FERC FORM NO. I (ED. 12-90)Page 327.2
Name of Respondent
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
04t14t2017
Year/Period of Report
End of 2016lA4
PURCHASED POWER (Account 555)(lncluding power exchanges)
1. Reportall powerpurchasesmadeduringtheyear. Alsoreportexchangesofelectricity(i.e.,transactionsinvolvingabalancingof
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 suppliefs 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{erm firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short{erm 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{erm 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{erm service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
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 Demanr
(e)
Average
Monthly CP Demanc
(f)
1 Desert Meadow Wind Farm LU N/A N/A N/A
2 Eightmile Hydro Corp LU N/A N/A N/A
3 Faulkner Brothers Hydro lnc.LU N/A N/A N/A
4 Fisheries Development N/A N/A N/A
5 Fossil Gulch Wind LU N/A N/A N/A
b G2 Energy Hidden Hollow LU N/A N/A N/A
7 Golden Valley Wind Park LU N/A N/A N/A
8 Grand View PV Solar Two, LLC LU N/A N/A N/A
I Hammett Hill Windfarm, LLC LU N/A N/A N/A
't0 Haebn B PorcrComnmy LU N/A N/A N/A
1',|Head of U Canal LU N/A N/A N/A
12 High Mesa Energy LU N/A N/A N/A
13 H.K. Hydro Mud Creek S & S LU N/A N/A N/A
14 Horseshoe Bend Hydro LU N/A N/A N/A
Total
FERC FORM NO. 1 (ED. 12-90)Page 326.3
Name of
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
0411412017
Year/Period of Report
End of 2O'l6lQ4
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
yearc. Provide an explanation in a footnote for each ad.iustment.
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 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 houdy (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 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)
Megawatt Hours
Delivered(i)
Demand Charges
',fl
Energy Charges
($)
(k)
Other Charges
($)
(t)
Total U+k+l)of Settlement ($)
(m)
61,81€4,419,722 4,419,722 1
1,501 82,321 82,325 2
3,263 254,932 254,932 3
1,07e 15,30'1 5,302 4
25,76C 1,487,921 1,487,927 5
22,044 1,419,33{1,4't 9,338 6
31,281 1,782,161 1,782,',t66 7
3,58'168,00(168,000 8
60,62,.4,323,031 4,323,037 9
21,931 1,577,841 1,577 ,844 10
4,38(355,54t 355,548 11
99,24(4,874,85i 4,874,853 12
1,621 't38,871 138,874 13
46,50(3.222.72!3,222,72s 14
4,330,80C 234,7',t7 181,766 2,815,124 228.585.769,8,807,83s 240,208,72e
FERC FORM NO. 1 (ED. 12-90)Page 327.3
Name of Respondent
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
04t1412017
Year/Period of Report
End of 2016/Q4
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 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 servipe 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{erm service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
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 Demanr
(e)
Average
Monthly CP Demand
(0
1 Horseshoe Bend Wind/United Materials LU N/A N/A N/A
2 Hot Springs Wind Farm LU N/A N/A N/A
3 lD Solar 1, LLC LU N/A N/A N/A
4 ldaho Winds / Sawtooth Wind Project LU N/A N/A N/A
5 J R Simplot Co.LU N/A N/A N/A
6 J.M. Miller/Sahko Hydro LU N/A N/A N/A
7 James B. Howell / CHI Elk Creek LU N/A N/A N/A
8 John R LeMoyne LU N/A N/A N/A
9 Kasel & Witherspoon LU N/A N/A N/A
10 Kootenai Electric Cooperative / Fighti LU N/A N/A N/A
11 Koyle Hydro lnc.LU N/A N/A N/A
't2 Lateral 10 Ventures LU N/A N/A N/A
13 Lemhi Hydro Power Co./Schaffner LU N/A N/A N/A
14 Lime Wind LU N/A N/A N/A
Total
FERC FORM NO. 1 (ED. 12-90)Page 326.4
Name of
ldaho Power Company (1)
(2)
An Odginal
A Resubmission
Date of Report
(Mo, Da, Yr)
o411412017
Year/Period of Report
End of 2016lA4
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
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 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 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)
Megawatt Hours
Delivered(i)
IJemand Charges
($)
0)
Energy Charges
($)
(k)
other charges
($)
(t)
Iotal u+K+l)of Settlement ($)
(m)
18,17'1,059,56(1,059,56C I
40,87t 2,548,88(2,548,88C 2
26,22(618,341 618,344 3
60,87i 4,969,39t 4,969,395 4
65,04t 2,888,78i 2,888,782 5
1,38:108,371 108,374 6
2,'t41 154,777 154,777 7
62e 35,34(35,34C I
3,76(336,98(336,98S I
10,82:836,70:836,703 '10
3,33(31s,06t 315,06€11
6,66i 421,45t 421,45t 12
1,341 98,611 98,611 13
5,867 423,272 423,272 14
4,330,80C 234,717 181,766 2,8',t5,124 228,585,769 8,807,835 240,208,72t
FERC FORM NO. t (ED. 12-90)Page 327.1
Name of Respondent
ldaho Power Company (1)
(2)
Original
Resubmission
Date of Report
(Mo, Da, Yr)
0411412017
Year/Period of Report
End of 20161Q4
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 suppliefs 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{erm 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 yearc.
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, capaci$, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
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
Monthly NCP Demanr
(e)
Avelilge
Monthly CP Demand
(0
1 Little Mac Power Co./Cedar Draw LU N/A N/A N/A
2 Little Wood River lrrigation District LU N/A N/A N/A
3 Magic Reservoir Hydro LU N/A N/A N/A
4 Mainline Windfarm LU N/A N/A N/A
5 Marco Rancher's lnigation lnc.LU N/A N/A N/A
6 LU N/A N/A N/A
7 Milner Dam Wind Park LU N/A N/A N/A
8 Mud Creek White Hydro, lnc LU N/A N/A N/A
I New Energy One / Rock Creek Dairy LU N/A N/A N/A
10 North Gooding Main, Hydro LU N/A N/A N/A
't1 Oregon Trail Wind Park LU N/A N/A N/A
't2 Owyhee lnigation District
13 Mitchell Butte LU N/A N/A N/A
14 Owyhee Dam LU N/A N/A N/A
Total
FERC FORM NO. I (EO. 12-90)Page 326.5
Name of
ldaho Power Company
(1)
(2\
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
o4t't4t2017
Year/Period of Report
End of 2O16lQ4
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 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 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). Repo( 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 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.Megawatt Hours
Received
(h)
Megawatt Hours
Delivered(i)
Demand Charges
($)
(i)
Energy Charges
($)
(k)
Other Charges
($)
(t)
Total U+k+l)of Settlement ($)
(m)
5.761 377.41i 377,413 ,|
4,77(345,42a 345,423 2
16,89i 931,94t 931,945 3
58,64(4,192,744 4.192.744 4
2,93(200,64i 200,647 5
37,751 2,429,63e 2,429,636 b
52,55t 2,990,322 2,990,322 7
50€34,18(34, 1 8C 8
13,43€1,060,717 1,060,7',t7 I
€277 277 10
38,581 2,233,10t 2,233,104 11
12
3,78€1 15.38€1 15,386 13
13,36€332,15C 332,1 50 14
4,330,800 234,717 18't,766 2,815,124 228,585,769 8,807,835 240,208,72t
FERC FORM NO. 1 (ED. 12-90)Page 327.5
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Y0
04t14t2017
Year/Period of Report
End of 2016/Q4
1. Repo(all powerpurchasesmadeduringtheyear. Alsoreportexchangesofelectricity(i.e.,transactionsinvolvingabalancingof
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 Classiflcation 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
supplierincludesprojectsloadforthisserviceinitssystemresourceplanning). lnaddition,thereliabilityofrequirementservicemust
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long{erm" 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{erm 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 flve years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
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 Demanr
(e)
Average
Monthly CP Demand
(0
,|Tunnel #1 LU N/A N/A N/A
2 Paynes Ferry Wind Park LU N/A N/A N/A
3 Pigeon Cove Power LU 1.389
4 Pilgrim Stage Station Wind Park LU N/A N/A N/A
5 Pristine Springs lnc #1 LU N/A N/A N/A
6 Pristine Springs lnc. #3 LU N/A N/A N/A
7 Reynolds lrrigation District LU N/A N/A N/A
8 Richard Kaster
I Box Canyon LU N/A N/A N/A
't0 Briggs Creek LU N/A N/A N/A
11 Riverside Hydro/Mora Drop LU N/A N/A N/A
12 Riverside lnvestments
13 Arena Drop LU N/A N/A N/A
14 Fargo Drop LU N/A N/A N/A
Total
FERC FORM NO. I (ED. 12-90)Page 326.6
Name of Respondent
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
o4t14t2017
Year/Period of Report
End of 20161Q4
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 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
Purchased
(s)
POWER EXCHANGES COST/SETTLEMENT OF POWER Line
No.Megawatt Hours
Received(h)
Megawatt Hours
Delivered(i)
Demand Charges
($)
(,)
Energy Charges
($)
(k)
Other Charges
($)
(t)
Total 0+k+l)
of Settlement ($)
(m)
10,561 1,175,18e 1,175,lffi 1
66,76€5,640,875 5,640,875 2
8,80S 486,1 50 316,68i 802,837 3
31,054 1,813,19(1,813,196 4
74(41,10t 41,108 5
1,30t 76,80(76,806 b
1,20i 91,02t 91,025 7
E
1,85('t21,81i 121,817 o
3,521 240,24(240,240 10
4,Ut 287,02(287,026 11
12
1,69(136,00'136,002 13
3,74(213,771 213,774 't4
4,330,80C 234,7',t7 't81,766 2,815,124 228,585,76€8,807,835 240,208,72e
FERC FORM NO. 1 (ED. 12-90)Page 327.6
An OriginalName of Respondent
ldaho Power Company (1)
(2)A Resubmission
Date ot Report(Mo, Da, Y0
04t14t20't7
Year/Period ol Report
End of 20161Q4
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 supplief s service to its own ultimate consumers.
LF - for longterm firm service. "Long{erm" 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{erm 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{erm firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short{erm 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{erm service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
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 Demanr
(e)
Average
Monthly CP Demano
(0
,|Rock Creek #1 Joint Venture LU 1.732Mw
2 Rockland Wind Project LU N/A N/A N/A
3 Rupert Cogeneration Partners/Magic Val LU N/A N/A N/A
4 Ryegrass Windfarm LU N/A N/A N/A
5 Salmon Falls Wind Park LU N/A N/A N/A
6 SE Hazelton A LP LU N/A N/A N/A
7 Shorock Hydro lnc.
8 Shoshone CSPP LU N/A N/A N/A
I Shoshone #2 LU N/A N/A N/A
'10 Snake River Pottery LU N/A N/A N/A
11 8ar*l Fo*t Joint \ffinerLltildine C&LU N/A N/A N/A
12 Tamarack €rlctgy Pdfierdtip ''LU 4.942Mw
13 Tasco - Nampa q6 N/A N/A N/A
14 Tasco - Twin Falls 6 ::,': -N/A N/A N/A
Total
FERC FORM NO. 1 (EO. 12-90)Page 326.7
ldaho Power Company (1)
(2',)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
04t',t4t2017
Year/Period of Report
End of 20161Q4
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 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 U), 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 EXUHANGES COST/SEIILEMENT OF POWER Line
NoMegaWatt Hours
Received
(h)
MegaWatt Hours
Delivered
(i)
Demand Charges
',?l
Energy Charges
($)
(k)
other Gharges
($)
(t)
I otal u+l(+l)of Settlement ($)
(m)
10,88'1 552,50r 449,72!1,002,233 ,|
252,23!16,273,68(16,273,68€2
65,827 4,390,141 4,390,141 3
56,94[4,069,57:4,069,575 4
62,402 3,579,89(3,579,89C 5
22,445 1,695,73r '1,695,734 6
7
1,51t 139,96:139,963 8
2,16i 154,55t 154,558 I
361 24,52t 24,528,10
26,60!1,940,79r 1,940,798 11
26,307 1,576,498 't,239,453 2,815,951 't2
45t 7,56t 7,565 13
't4
4,330,800 234,717 181.766 2,815,124 228,s8s,769 8,807,835 240,208,72t
FERC FORM NO. 1 (ED. 12-90)Page 327.7
Name
ldaho Power Company
(1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
04t14t2017
Year/Period of Report
End of 20161Q4
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 afflliation 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 crnsumers.
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{erm service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
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 Demanr
(e)
AVerarge
Monthly CP Demand
(0
,|Ted S. Sorenson/Tiber Dam LU N/A N/A N/A
2 Thousand Springs Wind Park LU N/A N/A N/A
3 Tuana Gulch Wind Park LU N/A N/A N/A
4 Tuana Springs Expansion LU N/A N/A N/A
5 Twin Falls Energy/Lowline Midway Hydro LU N/A N/A N/A
6 Two Ponds Windfarm LU N/A N/A N/A
7 White Water Ranch LU N/A N/A N/A
8 William Arkoosh/Littlewood LU N/A N/A N/A
I Littlewood River Ranch ll LU N/A N/A N/A
10 Willis and Betty Deveny/Shingle Creek LU N/A N/A N/A
11 LU N/A N/A N/A
't2 Yahoo Creek Wind Park LU N/A N/A N/A
13 Scheduling Deviation N/A N/A N/A
14 Other Purchased Power
Total
FERC FORM NO. 1 (ED. 12.90)Page 326.8
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
0411412017
Year/Period of Report
End of 2O16lQ4
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
yeaE. 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 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.
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
Purchased
(s)
POWER EXCHANGES COST/SETTLEMENT OF POWER Line
No.Megawatt Hours
Received(h)
MegaWatt Hours
Delivered(i)
Demand Charges
($)
(,)
E.nergy Charges
($)
(k)
other charges
($)
(t)
Iotal U+k+lof Settlement
(m)
)($)
29,85S 'l,71',t,99C 1,71 1 ,99C 1
34,025 1,972,ffi2 1,972,862 2
30,264 1.747 ,502 1,747 ,502 3
77,819 5,194,03€5,194,036 4
8,281 515,642 515,642 5
62,',t72 4,437,57C 4,437,574 6
638 43,44(43,44 7
3,09(236,66:236,663 I
3,48'216,29!2'16,295 I
95(73,06(73,069 10
25,58(1,840,711 1,840,717 11
66,80:5,653,65(5,653,659 12
10i 13
14
4,330,80C 234,717 '181,766 2,815,124 228,585,769,8,807,835 240,208,72t
FERC FORM NO. 1 (ED. 12-90)Page 327.8
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report
(Mo, Da, Yr)
04t14t2017
Year/Period of Report
End of 20161Q4
PURCHASED POWER (Account 555)(lncluding power exchanges)
1. Repo( 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 supplieds 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{erm 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.
Line
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 Oemand
Monthly
(e)(0
1 ADM lnvestor Services, lnc.N/A N/A N/A
2 Arizona Public Service Co.SF WSPP N/A N/A N/A
3 Arizona Public Service Co.WSPP N/A N/A N/A
4 Avangrid Renewables, LLC SF WSPP N/A N/A N/A
5 Avista Corp.T-',t2 N/A N/A N/A
6 Avista Corp.SF WSPP N/A N/A N/A
7 Avista Corp.WSPP N/A N/A N/A
8 Bonneville Power Administration WSPP N/A N/A N/A
I Bonneville Power Administration WSPP N/A N/A N/A
10 Bonneville Power Administration SF WSPP N/A N/A N/A
11 BP Energy Company SF WSPP N/A N/A N/A
12 Calpine Energy Services, L.P WSPP N/A N/A N/A
13 Calpine Energy Services, L.P SF WSPP N/A N/A N/A
14 Cargill Power Markets LLC SF WSPP N/A N/A N/A
Total
FERC FORM NO. I (ED. 12-90)Page 326.9
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
04t14t2017
Year/Period of Report
End of 20161Q4
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 houdy (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 401 ,
line 12. The total amount in column (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.MegaWatt Hours
Received
(h)
Megawatt Hours
Delivered(i)
Demand Charges
($)
0)
Energy Charges
($)
(k)
Other Charges
($)
(l)
Total (j+k+l)
of Settlement ($)
(m)
-356,33C -356.330 1
40,90(1,290,60(1,290,600 2
282 282 3
32,771 838,58;838,587 4
6t 't,574 1,574 5
28,31(626,75i 626,752 6
1 20,089 120,089 7
312,sO1 312,501 8
43(9,871 9,871 9
89,49t 2,161,12(2,161,126 't0
3,80(82,51(82,510 11
I 57 57 12
18,00(456,93t 456,938 13
4,6(104,58(104,586 14
4,330,80C 234,7',t7 181,766 2,8',t5,124 228,585,76S 8,807,835 240,208,72e,
FERC FORM NO. 1 (ED. 12-90)Page 327.9
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
04t14t2017
Year/Period of Report
End of 2016/Q4
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 suppliels service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and 'tirm" 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.
Line
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 Demanr
(e)
Average
Monthly CP Demand
(0
,|Cargill Power Markets LLC W ISDA N/A N/A N/A
2 Chelan Co PUD SF WSPP N/A N/A N/A
3 Chelan Co PUD re WSPP N/A N/A N/A
4 Citigroup Energy lnc.SF WSPP N/A N/A N/A
5 Citigroup Energy lnc.ISDA N/A N/A N/A
6 Clatskanie PUD SF WSPP N/A N/A N/A
7 Douglas County PUD WSPP N/A N/A N/A
8 EDF Trading North America, LLC SF WSPP N/A N/A N/A
I Energy Keepers SF WSPP N/A N/A N/A
't0 Eugene Water & Electric Board SF WSPP N/A N/A N/A
11 Exelon Generation Company, LLC SF WSPP N/A N/A N/A
't2 Grant CO Public Utility District #2 -WSPP N/A N/A N/A
13 Gridforce Energy Management, LLC.NWPP N/A N/A N/A
14 Los Angeles Department of Water & Powe SF WSPP N/A N/A N/A
Total
FERC FORM NO. 1 (ED. 12-90)Page 326.10
Name of
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of
(Mo, Da
Report
,YO
0411412017
Year/Period of Report
End of 2016/Q4
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 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 otherthan 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 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.Megawatt Hours
Received(h)
Megawatt Hours
Delivered(i)
Demand charges
($)
0)
Energy Uharges
($)
(k)
other charges
($)
(t)
I otal u+K+l)of Settlement ($)
(m)
-27,076 -27,07e ,|
28,00(546,63i 546,632 2
1t 438 438 3
45,20('t,262,888 1,262,88e 4
-17,429 -'t7,429 5
4i 38f 385 6
1(241 24',l 7
185,02t 4,134,111 4,134,1',11 8
5,00(119,774 119,774 I
2,22C 40.00(40,00c 't0
8.00(197,79(197,79C 11
31 849 84€12
't1 300 30c 13
332 8,941 8,941 14
4,330,800 234,7',17 181,766 2,815,124 228,585,769 8,807,835 240,208,72t
FERC FORM NO. I (ED. 12.90)Page 327.'10
Name Respondent
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
o411412017
Year/Period of Report
End of 2016/Q4
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 'Tirm" 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.
Line
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)
Aveiage
Monthly CP Demand
(0
1 Macquarie Energy LLC SF WSPP N/A N/A N/A
2 Macquarie Energy LLC ISDA N/A N/A N/A
3 Morgan Stanley Capital Group lnc.SF ISDA N/A N/A N/A
4 Morgan Stanley Capital Group lnc.SF ISDA N/A N/A N/A
5 Nevada Power Company, DBA NV Energy SF WSPP N/A N/A N/A
6 Nevada Power Company, DBA NV Energy WSPP N/A N/A N/A
7 NorthWestem Energy T-7 N/A N/A N/A
8 NorthWestem Energy WSPP N/A N/A N/A
I NorthWestem Energy SF WSPP N/A N/A N/A
10 PacifiCorp lnc.T-13 N/A N/A N/A
11 PacifiCorp lnc.SF WSPP N/A N/A N/A
12 PacifiCorp lnc.WSPP N/A N/A N/A
13 Portland General Electric Company IT-14 N/A N/A N/A
14 Portland General Electric Company SF WSPP N/A N/A N/A
Total
FERC FORM NO. I (ED. 12-90)Page 326.11
ldaho Power Company (1)
(2)
Original
A Resubmission
Date of Report(Mo, Da, Yr)
04114t2017
Year/Period of Report
End of 2016iQ4
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. 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 EXUHANGE,S COST/SETTLEMENT OF POWER Line
No.MegaWatt Hours
Received
(h)
MegaWatt Hours
Delivered(i)
Demand Charges
($)
U)
Energy Charges
($)
(k)
other charges
($)
(t)
lotal U+K+lof Settlement
(m)
)($)
15,80C 371,258 371,258 1
-141,724 -141,724 2
'13,35€369,663 369,663 3
-43,049 43,04S 4
15,75C 605,224 605,225 5
82 82 6
58 1,43e 1,436 7
c o 8
3,747 77,84e 77.846 I
357 8,084 8,084 10
57,341 1,517 ,881 't,517,8U 1',l
-21,381 -z',t,381 12
't07 2,541 2,541 13
28,112 747,54i 747,542 14
4,330,800 234,717 181.766 2,815,124 228,585,769 8,807,835 240,208,72t
FERC FORM NO. 1 (ED. 12-90)Page 327.11
ldaho Power Company
(1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
0411412017
Year/Period of Report
End of 20161Q4
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 deliveiles 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.
Line
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 Demanr
(e)
Average
Monthly CP Demanc
(0
1 Powerex Corp SF WSPP N/A N/A N/A
2 Public Service Company of Colorado SF WSPP N/A N/A N/A
3 Puget Sound Energy, lnc.T-9 N/A N/A N/A
4 Puget Sound Energy, lnc.SF WSPP N/A N/A N/A
5 Rainbow Energy Marketing Corporation WSPP N/A N/A N/A
6 Salt River Project SF WSPP N/A N/A N/A
7 Seattle City Light WSPP N/A N/A N/A
8 Seattle City Light SF WSPP N/A N/A N/A
9 Shell Energy North America (US), L.P SF WSPP N/A N/A N/A
10 Siena Pacific Power Co., dba NV Energ T-55 N/A N/A N/A
11 Siena Pacific Power Co., dba NV Energ WSPP N/A N/A N/A
12 Snohomish County PUD SF WSPP N/A N/A N/A
13 Tacoma Power WSPP N/A N/A N/A
14 Tacoma Power SF WSPP N/A N/A N/A
Total
FERC FORM NO. 1 (ED. 12-90)Page 326.12
Name of Respondent
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date ol Report
(Mo, Da, Yr)
041't412017
Year/Period of Report
End of 2O16lQ4
)(uonilnueo)
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 (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 40't , 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
NoMegawatt Hours
Received(h)
Megawatt Hours
Delivered
(i)
uemand Gharges
($)
0)
Energy L;harges
($)
(k)
other Gharges
($)
(t)
Total 6+1+1;of Settlement ($)
(m)
86,48r 2,688,152 2,688,154 ,|
17,20t 370,88t 370,888 2
't21 2,806 2,806 3
50,211 1,037,992 1,037,994 4
't.19t 20,862 20,862 5
331,60(8,424,10!8,424,',tO!6
4(1 ,105 I,105 7
43,21i 857,36i 857,362 8
36,08(696,58r 696,584 I
17t 4,132 4,132 10
1t 346 34e 11
5,45('t07,921 107,921 12
za 547 547 't3
5,77(127,774 127,775 14
4,330,80C 234,717 181,766 2,815,124 228,585,76€8,807,835 240,208,72t
FERC FORM NO. 1 (ED. 12.90)Page 327.'12
Name
ldaho Power Company
(1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
0411412017
Year/Period of Report
End of 20161Q4
power
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 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 flve 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 reliabili$ of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
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 Demanr
(e)
Average
Monthly CP Demanc
(0
1 Talen Energy SF WSPP N/A N/A N/A
2 Talen Energy WSPP N/A N/A N/A
3 Tenaska Power Services Co.SF WSPP N/A N/A N/A
4 The Energy Authority, lnc.SF WSPP N/A N/A N/A
5 TransAlta Energy Marketing (U.S.) Inc.SF WSPP N/A N/A N/A
o Tucson Electric Power Company SF WSPP N/A N/A N/A
7 Turlock lrrigation District SF WSPP N/A N/A N/A
8 Westem Area Power Administration (UGP WSPP N/A N/A N/A
9 Raft River Energy I LLC LU N/A N/A N/A
10 Telocaset Wind Power Partners LLC LU APP-A N/A N/A N/A
11 Neal Hot Springs Unit #1 LU N/A N/A N/A
12 Oregon Solar Customers grutw N/A N/A N/A
13 Power Exchanges
14 Avista Corp
Total
FERC FORM NO. 1 (ED. 12-90)Page 326.13
Name
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
o4l't4t2017
Year/Period of Report
End of 20'l6lQ4
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 supplieds 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 (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
(s)
POWER EXCHANGES COST/SETTLEMENT OF POWER Line
No.Megawatt Hours
Received(h)
Megawatt Hours
Delivered(i)
Demand Charges
($)
0)
Energy Charges
(s)
(k)
Other Charges
($)
(t)
Total U+k+l)of Settlement ($)
(m)
't34,565 3,404,16i 3,404,167 1
4,81('125,593 125,593 2
6(2,61(2,616 3
't2,571 213,67i 213,677 4
75,90r 1,862,69(1,862,696 5
10(2,50(2,500 t)
10(1,851 1,852 7
3C 30 8
71,99(4,775,68(4,775,6ffi 9
331,66(19,682,01r 19,682,018 10
179,56(19,552,58'19,552,58i 11
88(15,383 15,383 12
13
5,574 't4
4,330,80C 234,717 181,766 2,815,124 228,585,769 8,807,835 240,208,72t
FERC FORM NO. 1 (ED. 12-90)Page 327.13
(1)
(2)
An Original
A Resubmissionldaho Power Company
Date of(Mo, Da
Report
, Yr)
04t14120't7
Year/Period of Report
End of 20'l6lQ4
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 supplieis service to its own ultimate consumers.
LF - for long-term firm service. "Long{erm" 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 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{erm 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 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.
No.
Line Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classili-
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 Demand
(0
1 Bonneville Power Administration
2 NorthWestem Energy
3 PacifiCorp lnc.
4 Siena Pacific Power Co., dba NV Energ
5 Clatskanie PUD 't53
6 Other Transactions
7 Acctg Valuation of Clatskanie PUD N/A N/A N/A
8 Demand Response Avoided Energy N/A N/A N/A
I
't0
11
12
't3
14
Total
FERC FORM ilO. I (ED. 12-90)Page 326.14
ldaho Power Company (1)
(2',)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
041't4t2017
Year/Period of Report
End of 20161Q4
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 eplumn (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (Q. 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 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.
MegaWatt Hours
Purchased
(s)
POWER EXCHANGES COST/SETTLEMENT OF POWER Line
No.Megawatt Hours
Received
(h)
MegaWatt Hours
Delivered
(i)
Demand Charges
($)
0)
Energy Charges
($)
(k)
other charges
($)
(t)
Iotal u+K+l)of Settlement ($)
(m)
65,916 1
192 2
96,367 120,059 3
71 't.'t 1s 4
66,789 60,400 5
6
92,'t 0c 92,100 7
7,O59,42C 7,059,420 8
9
'10
11
12
13
14
4,330,80C 234,717 181,766 2,815,124 228,585,769 8,807,835 240.208.728,
FERC FORM NO. 1 (ED.12.90)Page 327.11
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t14t2017
Year/Period of Report
20161Q4
FOOTNOTE DATA
Schedule Page:326 Line No.:2 Column: e
UnavailabLe
Schedule Page:326 Line No.:2 Column: f
Unava i Iable
Schedule Page:326.1 Line No.: 13 Column: a
fncludes recovery of prior period overpayments
Schedule Page:326.2 Line No.: 2 Column: e
Unavai labIe
Schedule Page:326.2 Line No.: 2 Column: f
Unavai Iable
Schedule Page:326.2 Line No.: 12 Column: e
Unavai lable
Schedule Page:326.2 Line No.: 12 Column: f
Unavailable
Schedule Page:326.3 Line No.:4 Column: b
Non-firm Purchases
Schedule Page:326.3 Line No.: 10 Column: a
Ida West, a subsidary of Idaho Power Company, has partial ownership of these projects
Schedule Page:326.5 Line No-: 6 Column: a
Ida West, a subsidary of Idaho Power Company, has partial ownership of these projects
Schedule Page:326.6 Line No.:3 Column: e
Unavai 1ab1 e
Schedule Page:326.6 Line No;3 Column: f
Unavai-f able
Schedu/e Page:326.7 Line No.: 1 Column: e
Unavailabl-e
Schedule Page:326.7 Line No.: 1 Column: f
Unavailabl-e
Schedule Page:326.7 Line No.: 11 Column: a
fda West, a subsidary of Idaho Power Company, has partial ownershlp of these projects
Schedu/e Page:326.7 Line No.: 12 Column: a
The Tamarack Energy Partnership demand readings are taken from an electronic demand
recorder provided by Idaho Power Company. The actual demnad is not used in determining
cost of energy.
Schedule Page:326.7 Line No.: 12 Column: e
Unava i fabl e
Schedule Page:326.7 Line No.: 12 Column: f
Unava i fable
Schedule Page:326.7 Line No.: 13 Column: bNon-firm Purchases
Schedule Page:326.7 Line No.: 14 Column: b
Non-firm Purchases
Schedule Page:326.8 Line No.: 11 Column: a
Ida West, a subsi-dary of Idaho Power Company, has partial ownership of these projects
Schedule Page:326.8 Line No.: 13 Column: b
Difference between booked and scheduled energy
Schedule Page:326.9 Line No.: 1 Column: b
ADM Investor Services, Inc. Futures Account Document dated 5/5/2015
Schedule Page:326.9 Line No.: 3 Column: b
Financlal Transmission Losses
Schedule Page:326.9 Line No.: 5 Column: b
Sprnning or Operating Reserves
Schedule Page:326.9 Line No.:7 Column: b
the
FERC FORM NO. 1 (ED. 12-871 Page 450.1
Name of Respondent
ldaho Power Companv
This Report is:
(1)X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t14t2017
Year/Period of Report
2016tQ4
FOOTNOTE DATA
Flnanciaf Transmission Losses
Schedule Page:326.9 Line No.: I Column: b
Financiaf Transmission Losses
Schedule Page:326.9 Line No.: I Column: b
Spinning or Operating Reserves
Schedule Page:326.9 Line No.: 12 Column: b
Spinn-ing or Operating Reserves
Schedule Page:326.10 Line No.: 1 Column: b
ISDA Master Agreement with Cargill Power Markets, LLC, dated 6/L3/2oll
Schedule Page:326.10 Line No.: 3 Column: b
Spinning or Operatj-ng Reserves
Schedule Page:326.10 Line No.: 5 Column: b
ISDA Master Agreement with Citigroup Energy, Inc, dated 3/1 /2ALl
Schedule Page:326.10 Line No.:7 Column: b
Spinning or Operatj-ng Reserves
Schedule Page:326.10 Line No.: 12 Column: b
Spinning or Operating Reserves
Schedule Page:326.10 Line No.: 13 Column: b
Spinning or Operating Reserves
Schedule Page:326.11 Line No.: 2 Column: b
ISDA Master Agreement with Macquarie Energy, LLC, dated 4/12/2011
Schedule Page:326.11 Line No.: 6 Column: b
Financial- Transmission Losses
Schedule Page:326.11 Line No.:7 Column: b
Spinning or Operating Reserves
Schedule Page:326.11 Line No.: I Column: b
Spinning or Operating Reserves
Schedule Page:326.11 Line No.: 10 Column: b
Spinning or Operating Reserves
Schedule Page:326.11 Line No.: 12 Column: b
Einanciaf Transmission Losses
Schedule Page:326.11 Line No.: 13 Column: b
Spinning or Operating Reserves
Schedule Page:326-12 Line No.:3 Column: b
Spi-nnrng or Operating Reserves
Schedule Page:326.12 Line No.: 5 Column: b
Non-firm Purchases
Schedule Page:326.12 Line No.:7 Column: b
Spinning or Operating Reserves
Schedule Page:326.12 Line No.: 10 Column: b
Spinning or Operating Reserves
Schedule Page:326.12 Line No.: 11 Column: b
Spinning or Operating Reserves
Schedule Page:326.12 Line No.: 13 Column: b
Spinning or Operating Reserves
Schedule Page:326.13 Line No.:2 Column: b
Unit Contingent Purchases
Schedule Page:326.13 Line No.: I Column: b
Spinninq or Operating Reserves
Schedule Page:326.13 Line No.: 12 Column: b
Schedul-e BB Oregon Solar
Schedule Page:326.13 Line No.: 14 Column: b
Finanical Transmission Losses
Schedule Page:326.14 Line No.: 1 Column: b
FERC FORM NO. 1 1 450.2
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t14t2017
Year/Period of Report
20161Q4
FOOTNOTE DATA
Finanical Transmission Losses
Schedute Page1g2614 Line No.: 2 Cotumn: bFinanical Transmi-ssion Losses
Schedute Page:326.14 Line No.:3 Cotumn: bFinanical Transmlssion Losses
Schedute Page:326.14 Line No.:4 Citumi: O
Finani-cal Transmission Losses
Schedule Pagq 326:14 Line No.: 5 Citumi: b
Energy exchinge between Clatskanie and Idaho Eower Company at Airowrock Dam
Schedule Page1326J4 Line No.: 7 Columry; bEnergy exchange between Clatskanie and Idaho Powel Company at Arrowrock Dam
Schedule Page:32614 Line No.:8 Column: bIncentj-ve program for customers to reduce demand during peak hours
FERC FORM NO. 1 (ED. 12.871 Page 450.3
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date ot Report(Mo, Da, Yr)
04t1412017
Year/Period ot Report
End of 20161Q4
I KANi transactions as ccount 4Jb. I ,
1. Report all transmission of electilcity, 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 cplumns (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.
Line
No.
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
,|Bonneville Power Administration Oregon Trails Electric Co-op FNO
2 Bonneville Power Administration United States Bureau of Reclamati FNO
3 Bonneville Power Administration Priority Firm Customers FNO
4 PacifiCorp West PacifiCorp West FNO
5 United States Bureau of Reclamati Milner lnigation District OLF
6 Bonneville Power Administration United States Bureau of lndian Af OS
7 Seattle City Light Bonneville Power Administration OS
I PacifiCorp East ldaho Power Company OS
I United Materials of Great Falls PacifiCorp East ldaho Power Company OS
't0 United Materials of Great Falls PacifiCorp East ldaho Power Company OS
't1
12 Bonneville Power Administration PaciliCorp West PacifiCorp East LFP
'13 Bonneville Power Administration PacifiCorp West PacifiCorp East LFP
14 PacifiCorp lnc.PacifiCorp East Bonneville Power Administration LFP
15 PacifiCorp lnc.PacifiCorp East PacifiCorp West LFP
16 PacifiCorp lnc.PacifiCorp East PacifiCorp West LFP
17 Morgan Stanley Capital Group lnc.ldaho Power Company Bonneville Power Administration LFP
18
19 Black Hills Power PacifiCorp East PacifiCorp East NF
20 Bonneville Power Administration Northwestern/PacifiCorp East Sierra Pacific Power NF
21 Bonneville Power Administration Bonneville Power Administration PacifiCorp East NF
22 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration NF
23 Bonneville Power Administration Bonneville Power Administration Sierra Pacific Power NF
24 Bonneville Power Administration Bonneville Power Administration Sierra Pacific Power SFP
25 Bonneville Power Administration Avista PacifiCorp East NF
26 Bonneville Power Administration Avista Bonneville Power Administration NF
27 Bonneville Power Administration Avista Sierra Pacific Power NF
28 Bonneville Power Administration Avista Bonneville Power Administration NF
29 lberdrola Renewables LLC PacifiCorp East Bonneville Power Administration NF
30 lberdrola Renewables LLC Northwestem/Pacifi Corp East PacifiCorp East NF
31 lberdrola Renewables LLC NorthWestern/Pacifi Corp East Sierra Pacific Power NF
32 lberdrola Renewables LLC Bonneville Power Administration Pacificorp East NF
33 lberdrola Renewables LLC Bonneville Power Administration Siena Pacific Power NF
34 lberdrola Renewables LLC Sierra Pacific Power NorthWestern/Pacifi Corp East NF
TOTAL
FERC FORM NO. 1 (ED. 12-90)Page 328
Name of Respondent
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
o4t14120't7
Year/Period of Report
End of 20161Q4
to as rt 45ttXuontinued)
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 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.Megawan Hours
Received(i)
Megawatt Hours
Delivered
0)
338,33€338,33t I
I 281,20!281,20t 2
I 1,257,463 1,257,463 3
I 2,133 2.13i 4
Minidoka, ldaho Various in ldaho 9,407 9,40i 5
Legacy LaGrande, Oregon Various in ldaho 14,87C 14,87C 6
340,288,340,28€7
2,935 2,935 8
5/6 4,647 4,647 I
5/6 10,347 10,347 10
11
M500 KPRT 31,600 31,60C 12
7t8 SMLK KPRT 75,285 75,281 13
7t8 BORA LAGRANDE 447.747 447.747 14
718 BORA HURR 't,250,676 'l,250,67G '15
7t8 KPRT HURR 492,190 492,19C 16
7t8 LYPK LAGRANDE 45,224 45,224 17
't8
7t8 BORA BRDY 15 1t 19
7t8 BPAT.NWMT M345 't6,290 16,29(20
7t8 LAGRANDE KPRT 22 Zt 21
7t8 LAGRANDE LAGRANDE 2,701 2,701 22
718 LAGRANDE M345 24,4't8 24,4',tt 23
7t8 LAGRANDE M345 1.073 1,07i 24
7t8 LOLO BORA 2 25
718 LOLO LAGRANDE 675 67t 26
7t8 LOLO M345 4,325 4,32t 27
7t8 LOLO OTEC 31 3'1 28
7t8 BORA LAGRANDE 78 7t 29
718 BPAT.NWMT BRDY 83 8:30
718 BPAT.NWMT M345 50 5(31
7la LAGRANDE BORA 3,869 3,86!32
7t8 LAGRANDE M345 4,022 4,02i 33
7t8 M345 BPAT.NWMT 39C 39(34
0 6,319,072 6,319,07i
FERC FORM NO. r GD. 12-90)Page 329
Name of
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Reoort
(Mo, Da, Yi)
0411412017
Year/Period of Report
End of 2O16lQ4
il-(ANt transactions to as ccount 456.1 )
1. Repo( 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.
Line
No.
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
Eneryy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
,|lberdrola Renewables LLC Sierra Pacific Power Bonneville Power Administration NF
2 lberdrola Renewables LLC PacifiCorp West PacifiCorp East NF
3 lberdrola Renewables LLC PacifiCorp West Sierra Pacilic Power NF
4 lD Solar I NF
5 Morgan Stanley Capital Group lnc.NorthWestem/Pacifi Corp East PacifiCorp East NF
6 Morgan Stanley Capital Group lnc.NorthWestern/Pacifi Corp East PacifiCorp East SFP
7 Morgan Stanley Capital Group lnc.NorthWestem/Pacifi Corp East PacifiCorp East NF
8 Morgan Stanley Capital Group lnc.NorthWestern/Pacifi Corp East Bonneville Power Administration NF
I Morgan Stanley Capital Group lnc.NorthWestern/Pacifi Corp East Bonneville Power Administration SFP
10 Morgan Stanley Capital Group lnc.NorthWesterrVPacifi Corp East Avista NF
11 Morgan Stanley Capital Group lnc.NorthWestern/PacifiCorp East Sierra Pacific Power NF
12 Morgan Stanley Capital Group lnc.NorthWestern/Pacifi Corp East Siena Pacific Power SFP
13 Morgan Stanley Capital Group lnc.PacifiCorp East Bonneville Power Administration NF
14 Morgan Stanley Capital Group lnc.PacifiCorp East Siena Pacific Power NF
15 Morgan Stanley Capital Group lnc.Northwestem/Pacifi Corp East PacifiCorp East NF
,,16 Morgan Stanley Capital Group lnc.NorthWestem/Pacifi Corp East PacifiCorp East NF
17 Morgan Stanley Capital Group lnc.NorthWestern/Pacifi Corp East PacifiCorp West NF
18 Morgan Stanley Capital Group lnc.NorthWestern/Pacifi Corp East Bonneville Power Administration NF
19 Morgan Stanley Capital Group lnc.Northwestern/Pacifi Corp East Sierra Pacific Power NF
20 Morgan Stanley Capital Group lnc.PacifiCorp East PacifiCorp East NF
21 Morgan Stanley Capital Group lnc.PacifiCorp East PacifiCorp East SFP
22 Morgan Stanley Capital Group lnc.PacifiCorp East Bonneville Power Administration NF
23 Morgan Stanley Capital Group lnc.PacifiCorp East Siena Pacific Power NF
24 Morgan Stanley Capital Group lnc.PacifiCorp East Siena Pacific Power SFP
25 Morgan Stanley Capital Group lnc.PacifiCorp East PacifiCorp East NF
26 Morgan Stanley Capital Group lnc.PacifiCorp East Bonneville Power Administration NF
27 Morgan Stanley Capital Group lnc.PacifiCorp East Siena Pacific Power NF
28 Morgan Stanley Capital Group lnc.PacifiCorp East PacifiCorp East NF
29 Morgan Stanley Capital Group lnc.PacifiCorp East PacifiCorp East NF
30 Morgan Stanley Capital Group lnc.PacifiCorp East Bonneville Power Administration NF
3'l Morgan Stanley Capital Group lnc PacifiCorp East Sierra Pacific Power NF
32 Morgan Stanley Capital Group lnc.PacifiCorp East Sierra Pacific Power SFP
33 Morgan Stanley Capital Group lnc.Bonneville Power Administration PacifiCorp East NF
34 Morgan Stanley Capital Group lnc.Bonneville Power Administration PacifiCorp East NF
TOTAL
FERC FORM NO. I (ED. 12-90)Page 328.1
Name of
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
o4114120't7
Year/Period oI Report
End of 20161Q4
to as rr 4cb)(uonunueo,
5. ln column (e), identifi 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 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 O 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
NoMegawatt Hours
Received(i)
Megawaft Hours
Delivered
0)
7t8 M345 LAGRANDE 't,073 1,074 I
7t8 SMLK BORA 3,',t41 3,141 2
7t8 SMLK M345 791 791 3
7t8 4
7t8 AVAT.NWMT BORA 4,109 4,10S 5
7la AVAT.NWMT BORA 10,908 10,90t 6
7t8 AVAT.NWMT BRDY 34 34 7
718 AVAT.NWMT LAGRANDE 31,034 31.03,4 8
718 AVAT.NWMT LAGRANDE 17,629 17,62(I
718 AVAT.NWMT LOLO 't8i 187 10
718 AVAT.NWMT M345 27,914 27,914 11
7t8 AVAT.NWMT M345 14,289,14,289 't2
7t8 BORA LAGRANDE s9c 59C 13
718 BORA M345 75 7!14
718 BPAT.NWMT BORA 30s 30s 15
7t8 BPAT.NWMT BRDY 51 51 't6
7t8 BPAT.NWMT HURR 25 't7
7t8 BPAT.NWMT LAGRANDE 3,445 3,445 't8
7t8 BPAT.NWMT M345 8,695 8,695 19
7t8 BRDY BORA 1,435 1,43t 20
718 BRDY BORA 35 3t 21
718 BRDY LAGRANDE 7.694 7,69 22
718 BRDY M345 37,86S 37,86(23
7t8 BRDY M345 44,641 44.641 24
7t8 JBSN BORA 95S 95(25
7t8 JBSN LAGRANDE 213 2',ti 26
7t8 JBSN M345 1,224 1,221 27
7t8 JEFF BORA 12,976 12,97t 28
7t8 JEFF BRDY 80 8(29
718 JEFF LAGRANDE 4,025 4,O2!30
7t8 JEFF M345 66,210 66,21(31
7t8 JEFF M345 66 6(32
718 LAGRANDE BORA 9,214 9,214 33
718 LAGRANDE BRDY 572 572 34
0 6,319,072 6,319,072
FERC FORM NO. 1 (ED. 12-90)Page 329.1
Name of Respondent
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
0411412017
Year/Period of Report
End of 2016/Q4
I KANI
to as
ccounl 45o.1 )
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non{raditional 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.
Line
No.
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
1 Morgan Stanley Capital Group lnc.Bonneville Power Administration Siera Pacific Power NF
2 Morgan Stanley Capital Group lnc.Avista PacifiCorp East NF
3 Morgan Stanley Capital Group lnc.Avista PacifiCorp East SFP
4 Morgan Stanley Capital Group lnc.Avista PacifiCorp East NF
5 Morgan Stanley Capital Group lnc.Avista Sierra Pacific Power NF
6 Morgan Stanley Capital Group lnc.Avista Sierra Pacific Power SFP
7 Morgan Stanley Capital Group lnc.ldaho Power Company PacifiCorp East NF
8 Morgan Stanley Capital Group lnc.ldaho Power Company PacifiCorp East SFP
I Morgan Stanley Capital Group lnc.ldaho Power Company NorthWestem/Pacifi Corp East NF
't0 Morgan Stanley Capital Group lnc.ldaho Power Company PacifiCorp East NF
11 Morgan Stanley Capital Group lnc.ldaho Power Company Avista NF
12 Morgan Stanley Capital Group lnc.ldaho Power Company Siena Pacific Power NF
13 Morgan Stanley Capital Group lnc.ldaho Power Company Siena Pacific Power SFP
14 Morgan Stanley Capital Group lnc.Sierra Pacific Power PacifiCorp East NF
15 Morgan Stanley Capital Group lnc.Siena Pacific Power NorthWestern/Pacifi Corp East NF
16 Morgan Stanley Capital Group lnc.Sierra Pacific Power PacifiCorp East NF
17 Morgan Stanley Capital Group lnc.Sierra Pacific Power Bonneville Power Administration NF
18 Morgan Stanley Capital Group lnc.Siena Pacific Power Avista NF
19 Morgan Stanley Capital Group lnc.Siena Pacific Power Avista SFP
20 Morgan Stanley Capital Group lnc.PacifiCorp West PacifiCorp East NF
21 Morgan Stanley Capital Group lnc.PacifiCorp West PacifiCorp East NF
22 Morgan Stanley Capital Group lnc.PacifiCorp West PacifiCorp East NF
23 Morgan Stanley Capital Group lnc.PacifiCorp West PacifiCorp East NF
24 Morgan Stanley Capital Group lnc.Pacificorp West Sierra Pacific Power NF
25 Nevada Power Company PacifiCorp East Siena Pacific Power NF
26 Nevada Power Company Bonneville Power Administration Sierra Pacific Power NF
27 Nevada Power Company Avista Sierra Pacific Power NF
28 Nevada Power Company Avista Sierra Pacific Power SFP
29 PacifiCorp lnc.PacifiCorp East Avista NF
30 PacifiCorp lnc.PacifiCorp East PacifiCorp East NF
31 PacifiCorp lnc.PacifiCorp East PacifiCorp East NF
32 PacifiCorp lnc.PacifiCorp East PacifiCorp East SFP
33 PacifiCorp lnc.PacifiCorp East PacifiCorp West NF
34 PacifiCorp lnc.PacifiCorp East Bonneville Power Administration NF
TOTAL
FERC FORM NO. 1 (EO. 12-90)Page 328.2
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of ReDort
(Mo, Da, Yi)
0411412017
Year/Period of Report
End of 20161Q4
t 4coxuon0nueo)
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 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 O 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
NoMegawall Hours
Received(i)
Megawa[ Hours
Delivered(i)
7t8 LAGRANDE M345 22,900 22,90t 1
718 LOLO BORA 23,234 23,23t 2
7t8 LOLO BORA 3,0't 0 3,01(3
7t8 LOLO BRDY 230 23C 4
7t8 LOLO M345 184,155 1 84,1 5a 5
7t8 LOLO M345 34,36€34,36(6
7t8 LYPK BORA 22,835 22.831 7
718 LYPK BORA 22,324 22.324 8
718 LYPK BPAT.NWMT 51 51 I
7t8 LYPK BRDY 41e 41e 10
7t8 LYPK LOLO 11C 't 1(11
7t8 LYPK M345 23,71C 23.71C 't2
7t8 LYPK M345 223,399 223,395 13
718 M345 BORA 2,055 2,05€14
7t8 M345 BPAT,NWMT '172 172 15
7t8 M345 BRDY 7a 7!16
718 M345 LAGRANDE 1,445 1,44a 17
7t8 M345 LOLO 52e,52e 18
718 M345 LOLO 306 30€19
718 SMLK BORA 33S 33S 20
7t8 SMLK BRDY 65 65 21
7t8 WALLAWALLA BORA 1,285 1,28a 22
7t8 WALLAWALLA BRDY 175 175 23
7t8 WALLAWALLA M345 739 73!24
7t8 BRDY M345 208 20e 25
7t8 LAGRANDE M345 50 5C 26
7t8 LOLO M345 14,435 14,435 27
7t8 LOLO M345 10,900 10,90c 28
7t8 BORA LOLO 1.185 1.185 29
7t8 BRDY BORA 808 80t 30
7t8 BRDY BRDY 't,279 1,271 31
7t8 BRDY BRDY 2,531 2,53',32
7t8 BRDY HURR 2,585 2,58{33
7t8 BRDY LAGRANDE 3,716 3,7',t(34
0 6,319,072 6,319,07'
FERC FORi' NO. l (ED. 12-90)Page 329.2
ldaho Power Company (1)
(2t
An Original
A Resubmission
Date of Report
(Mo, Da, Yr)
04114t2017
Year/Period of Report
End of 2016/Q4
I KANi
as
ccount 4co.1)
1. Report all transmission of electricity, i.e., Mteeling, 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.
Line
No.
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
( Footnote Affiliation )(c)
Statistical
Classifi-
cation
(d)
1 PacifiCorp lnc.PacifiCorp East NorthWestern/PacifiCorp East NF
2 PacifiCorp lnc.PacifiCorp West PacifiCorp East NF
3 PacifiCorp lnc.PacifiCorp West PacifiCorp East SFP
4 PacifiCorp lnc.PacifiCorp West Bonneville Power Administration NF
5 PacifiCorp lnc.PacifiCorp East PacifiCorp East NF
6 PacifiCorp lnc.PacifiCorp East PacifiCorp West SFP
7 PacifiCorp lnc.Bonneville Power Administration PacifiCorp East NF
8 PacifiCorp lnc.Bonneville Power Administration PacifiCorp East NF
I PacifiCorp lnc.Avista PacifiCorp East NF
10 PacifiCorp lnc.Avista PacifiCorp East NF
11 PacifiCorp lnc.PacifiCorp West PacifiCorp East NF
12 PacifiCorp lnc.PacifiCorp West PacifiCorp East SFP
13 PacifiCorp lnc.PacifiCorp West PacifiCorp East NF
14 PacifiCorp lnc.PacifiCorp West PacifiCorp East NF
15 PacifiCorp lnc.Pacificorp West PacifiCorp East SFP
16 PacifiCorp lnc.PacifiCorp West PacifiCorp East NF
17 Portland General Electric Company PacifiCorp East Bonneville Power Administration NF
18 Portland General Electric Company Bonneville Power Administration PacifiCorp East NF
19 Portland General Electric Company Bonneville Power Administration Sierra Pacific Power NF
20 Portland General Electric Company Sierra Pacific Power Bonneville Power Administration NF
21 Powerex Corporation PacifiCorp East Sierra Pacific Power NF
22 Powerex Corporation NorthWestern/PacifiCorp East PacifiCorp East NF
23 Powerex Corporation NorthWestem/Pacifi Corp East PacifiCorp East NF
24 Powerex Corporation NorthWestem/Pacifi Corp East Sierra Pacific Power NF
25 Powerex Corporation NorthWestem/Pacifi Corp East Sierra Pacific Power SFP
26 Powerex Corporation PacifiCorp East PacifiCorp East NF
27 Powerex Corporation PacifiCorp East Bonneville Power Administration NF
28 Powerex Corporation PacifiCorp East Sierra Pacific Power NF
29 Powerex Corporation PacifiCorp East Sierra Pacific Power SFP
30 Powerex Corporation PacifiCorp West PacifiCorp East NF
31 Powerex Corporation PacifiCorp East Sierra Pacific Power NF
32 Powerex Corporation PacifiCorp East PacifiCorp East NF
33 Powerex Corporation PacifiCorp East PacifiCorp East SFP
34 Powerex Corporation PacifiCorp East PacifiCorp East NF
TOTAL
FERC FORM NO. 1 (ED.12-90)Page 328.3
ldaho Power Company (1)
(2\
An Oilginal
A Resubmission
Date of Report(Mo, Da, Yr)
0411412017
Year/Period of Report
End of 20161Q4
I 4CbXUOnIrnUeO'
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 appropilate 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)
(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(i)
7t8 BRDY MLCK 10c 10(1
718 HURR BORA 9,64C 9,64(2
7t8 HURR BORA 66,578 66,57t 3
718 HURR LAGRANDE 341 341 4
7t8 JEFF BGSY 5C 5C 5
7t8 JEFF BGSY 7C 7C 6
7t8 LAGRANDE BORA 2,532 2,532 7
7t8 LAGRANDE BRDY 8,702 8,702 8
7t8 LOLO BORA 33C 33C 9
7t8 LOLO BRDY 4,317 4,317 10
718 SMLK BORA 66,107 66,10i 1',!
718 SMLK BORA 48,505 48,505 12
7t8 SMLK BRDY s,07c 5,07C 13
7t8 WALLAWALLA BORA 81,394 8't,394 14
7t8 WALLAWALLA BORA 126,597 126,597 15
7t8 WALLAWALLA BRDY 347 347 16
7t8 BRDY LAGRANDE 3,148 3,1,|t 17
7la LAGRANDE BORA 90 9(18
7t8 LAGRANDE M345 100 10(19
7t8 M345 LAGRANDE 100 10(20
7t8 BORA M345 100 10(21
7t8 BPAT.NWMT BORA 306 30(22
7t8 BPAT.NWMT BRDY 436 43(23
718 BPAT.NWMT M345 2,695 2,69{24
7t8 BPAT.NWMT M345 15,008 15,00(25
7t8 BRDY BORA 251 251 26
718 BRDY LAGRANDE 152 't5i 27
718 BRDY M345 '1.974 1,971 28
7t8 BRDY M345 1.370 1,37(29
7t8 HURR BORA 64 6t 30
718 JBSN M345 77 7i 31
718 JEFF BORA 1,994 1,99 32
7t8 JEFF BORA 320 32(33
7t8 JEFF BRDY 330 33(34
0 6,319,072 6,319,07'
FERC FORM NO. 1 (ED.12-90)Page 329.3
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date ot Repod(Mo, Da, Yr)
04t't4t2017
Year/Period of Report
End of 201.6lA4
I t<ANl
as
ccounr 45o.r)
1, Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non{raditional 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 lerms and conditions of the service as follows:
FNO - Firm Network Service for Otherc, 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.
Line
No.
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
,|Powerex Corporation PacifiCorp East Sierra Pacific Power NF
2 Powerex Corporation PacifiCorp East Sierra Pacific Power SFP
3 Powerex Corporation Bonneville Power Administration PacifiCorp East NF
4 Powerex Corporation Bonneville Power Administration PacifiCorp East NF
5 Powerex Corporation Bonneville Power Administration Siena Pacific Power NF
6 Powerex Corporation Avista PacifiCorp East NF
7 Powerex Corporation Avista PacifiCorp East NF
8 Powerex Corporation Avista Sierra Pacific Power NF
9 Powerex Corporation Siena Pacific Power PacifiCorp East NF
10 Powerex Corporation Siena Pacific Power PacifiCorp East NF
11 Powerex Corporation Siena Pacific Power Bonneville Power Administration NF
12 Powerex Corporation PacifiCorp West PacifiCorp East NF
13 Powerex Corporation PacifiCorp West PacifiCortp East NF
't4 Powerex Corporation PacifiCorp West Sierra Pacific Power NF
't5 Powerex Corporation PacifiCorp West PacifiCorp East NF
16 Powerex Corporation PacifiCorp West PacifiCorp East NF
17 Powerex Corporation Pacificorp West Sierra Pacific Power NF
18 Shell Energy North America (US), L.P PacifiCorp East Sierra Pacific Power NF
19 Shell Energy North America (US), L.P Northwestern/Pacifi Corp East PacifiCorp East NF
20 Shell Energy North America (US), L.P Northwestern/Pacifi Corp East Siena Pacific Power NF
2',!Shell Energy North America (US), L.P PacifiCorp East NorthWestem/Pacifi Corp East NF
22 Shell Energy North America (US), L.P PacifiCorp East Bonneville Power Administration NF
23 Shell Energy North America (US), L.P PacifiCorp East Sierra Pacific Power NF
24 Shell Energy North America (US), L.P PacifiCorp East Siena Pacific Power SFP
25 Shell Energy North America (US), L.P ldaho Power Company Bonneville Power Administration NF
26 Shell Energy North America (US), L.P Bonneville Power Administration PacifiCorp East NF
27 Shell Energy North America (US), L.P Bonneville Power Administration Sierra Pacific Power NF
28 Shell Energy North America (US), L.P Avista PacifiCorp East NF
29 Shell Energy North America (US), L.P Avista PacifiCorp East SFP
30 Shell Energy North America (US), L.P Avista Siena Pacific Power NF
31 Shell Energy North America (US), L.P Avista Sierra Pacific Power SFP
32 Shell Energy North America (US), L.P ldaho Power Company PacifiCorp East NF
33 Shell Energy North America (US), L.P Siena Pacific Power PacifiCorp East NF
34 Shell Energy North America (US), L.P Siena Pacific Power Bonneville Power Administration NF
TOTAL
FERC FORM NO. 1 (ED.12-90)Page 328.1
Name of Respondent
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of(Mo, Da
Report
, Yr)
04t14t2017
Year/Period of Report
End of 2016/Q4
as I 4COXUonUnueO)
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 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)
(f)
Point of Delivery
(Substation or Other
Designation)
(g)
Billing
Demand
(Mw)
(h)
TRANSFER OF ENERGY Line
No.Megawalt Hours
Received(i)
Megawan Hours
Delivered
0)
7t8 JEFF M345 6,597 6,sgi 1
7t8 JEFF M345 1,80C 1,80(2
7t8 LAGRANDE BORA 10,xe 10,2',tc 3
7t8 LAGRANDE BRDY 2,985 2,985 4
7t8 LAGRANDE M345 33,95i 33,957 5
7t8 LOLO BORA 682 68i t)
7t8 LOLO BRDY 2,31C 2,31(7
7t8 LOLO M345 795 795 8
7t8 M345 BORA $e 43C o
718 M345 BRDY 13 13 10
7t8 M345 LAGRANDE 2C 2C 't1
7t8 SMLK BORA 17.185 17.18!12
7t8 SMLK BRDY 1,729 '1,729 13
7t8 SMLK M345 2,35€2,359,14
7t8 WALLAWALLA BORA 1,883 1,883 15
7t8 WALLAWALLA BRDY 't,641 1,641 16
718 WALLAWALLA M345 390 39C 17
7t8 BORA M345 630 63C '18
7t8 BPAT.NWMT BRDY 139 13S 19
7t8 BPAT.NWMT M345 4,221 4,22',1 20
7t8 BRDY BPAT.NWMT 96'l 961 21
7t8 BRDY LAGRANDE 1,077 1,071 22
7t8 BRDY M345 19,939 19,939 23
7t8 BRDY M345 6,208 6,20{24
718 IPCOGEN LAGRANDE 734 734 25
7t8 LAGRANDE BRDY 2,80S 2,80€26
718 LAGRANDE M345 65,438 65,43€27
7t8 LOLO BRDY 2,224 2,22e 28
7t8 LOLO BRDY 224 22t 29
7t8 LOLO M345 28,695 28,69{30
7t8 LOLO M345 6,397 6,39;31
718 LYPK BRDY 288 28t 32
718 M345 BRDY 151 15'33
7t8 M345 LAGRANDE 1,825 't,821 34
0 6,319,072 6,319,07i
FERC FORM NO. I (ED.12-90)Page 329.4
Name of Respondent
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report
(Mo, Da, Yr)
04t't4t2017
Year/Period of Report
End of 20161Q4
I KAN:
as ccount 4co. r )
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.
Line
No.
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
1 Shell Energy North America (US), L.P PacifiCorp West PacifiCorp East NF
2 Shell Energy North America (US), L.P PacifiCorp West PacifiCorp East NF
3 Shell Energy North America (US), L.P PacifiCorp West PaciliCorp East SFP
4 Shell Energy North America (US), L.P PacifiCorp West Sierra Pacific Power NF
5 Shell Energy North America (US), L.P PacifiCorp West Sierra Pacific Power SFP
6 Shell Energy North America (US), L.P PacifiCorp West PacifiCorp East NF
7 Shell Energy North America (US), L.P PacifiCorp West Sierra Pacific Power NF
8 Talen Energy Marketing, LLC PacifiCorp East ldaho Power Company NF
I Talen Energy Mafteting, LLC PacifiCorp East Bonneville Power Administration NF
10 Talen Energy Marketing, LLC Sierra Pacific Power ldaho Power Company NF
11 Tenaska Power Services Co PacifiCorp East Bonneville Power Administration NF
't2 Tenaska Power Services Co.PacifiCorp East PacifiCorp East NF
13 Tenaska Power Services Co Bonneville Power Administration PacifiCorp East NF
14 The Energy Authority, lnc.PacifiCorp East Bonneville Power Administration NF
15 The Energy Authority, lnc.NorthWestern/Pacifi Corp East PacifiCorp East NF
16 The Energy Authority, lnc.Northwestern/Pacifi Corp East Sierra Pacific Power NF
17 The Energy Authority, lnc.Bonneville Power Administration PacifiCorp East NF
18 The Energy Authority, lnc.Bonneville Power Administration Siena Pacific Power NF
19 The Energy Authority, lnc.Sierra Pacific Power Bonneville Power Administration NF
20 The Energy Authority, lnc.PacifiCorp West PacifiCorp East NF
21 The Energy Authority, lnc.PacifiCorp West PacifiCorp East NF
22 Transalta Energy Marketing (U.S.) lnc.PacifiCorp East Bonneville Power Administration NF
23 Transalta Energy Marketing (U.S.) lnc.Bonneville Power Administration PacifiCorp East NF
24 Transalta Energy Marketing (U.S.) lnc.Bonneville Power Administration Sierra Pacific Power NF
25 Transalta Energy Marketing (U.S.) lnc.Avista PacifiCorp East NF
26 Transalta Energy Marketing (U.S.) lnc.Avista Siena Pacific Power NF
27 Transalta Energy Marketing (U.S.) lnc.Sierra Pacific Power Northwestern/Pacifi Corp East NF
28 Transalta Energy Marketing (U.S.) lnc.Sierra Pacific Power Bonneville Power Administration NF
29 Transalta Energy Marketing (U.S.) lnc.PacifiCorp West PacifiCorp East NF
30 Transalta Energy Marketing (U.S.) lnc.PacifiCorp West Sierra Pacific Power NF
31 Utah Associated Municipal Power PacifiCorp East Sierra Pacific Power NF
32
33
34
TOTAL
FERC FORM NO. 1 (ED. 12-90)Page 328.5
Name
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report
(Mo, Da, Yr)
04114t2017
Year/Period of Report
End of 20161Q4
to as I 4CbXUOnIrnUeO'
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 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)
(g)
Billing
Demand
(MW)
(h)
TRANSFER OF ENERGY Line
No.Megawarr Hours
Received(i)
Megawafi Hours
Delivered
U)
7t8 SMLK BORA 704 704 1
7t8 SMLK BRDY 15,037 15,037 2
718 SMLK BRDY 1,192 1,',tgi 3
7t8 SMLK M345 19,483 19,48:4
7t8 SMLK M345 3,274 3,271 5
7t8 WALLAWALLA BRDY 2,92',1 2,921 6
7t8 WALLAWALLA M345 3,265 3,26r 7
7t8 BRDY rPco 't1 't1 8
7t8 BRDY LAGRANDE 1,664 1,66r I
7t8 M345 rPco 64 6t 10
718 BRDY LAGRANDE 127 12i 1'.1
718 JEFF BRDY 65 6t 't2
7t8 LAGRANDE BRDY 385 38r 13
7t8 BORA LAGRANDE C a 14
7t8 BPAT.NWMT BRDY 144 141 15
718 BPAT.NWMT M345 111 1',t1 16
718 LAGRANDE BRDY 1,223 1,22i 17
7t8 LAGRANDE M345 531 531 18
7t8 M345 LAGRANDE 79€79t 19
7t8 SMLK BORA 449 445 20
718 SMLK BRDY 5C 5(21
7t8 BORA LAGRANDE 753 751 22
718 LAGRANDE BORA 4,316 4,31e 23
7t8 LAGRANDE M345 185 't 8r 24
7t8 LOLO BORA 4',t3 413 25
7t8 LOLO M345 50 5C 26
7t8 M345 BPAT.NWMT 150 15C 27
718 M345 LAGRANDE 498 49€28
7t8 SMLK BORA 4,267 4,267 29
7t8 SMLK M345 50 5C 30
718 BORA M34s 1,198 't,'19€31
32
33
34
0 6,319,072 6,3't9,07i
FERC FORM NO. 1 (ED. 12-90)Page 329.5
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date ot Report(Mo, Da, Yr)
04t14t2017
Year/Period ot Report
End of 20161Q4
AS
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). In 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 (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 ($)
(k+l+m)
(n)
Ltne
No.
1,676,396 200,287 1,876,683 1
1,603,473 56,273 1,659,746 2
6,247,662 463,643 6,71 1,305 3
1 1 ,016 953 't 1,969 4
15,240 15,240 5
54,752 54,752 6
140,325 140,325 7
2,598 2,598 8
4,',t't3 4,113 I
9,158 9,158 10
11
1,223,760 1,223,760 12
1,223,760 't,223,760 13
1,652,729 1,652,729 14
5,772,577 5,772,577 15
4,790,520 4,790,520 16
2,419,213 2,419,213 't7
18
40 40 't9
67,832 67,432 20
92 92 21
'11,247 't1,247 22
101,677 't01,677 23
4,468 4,68 24
I I 25
2,811 2,811 26
18,00s 18,009 27
129 129 28
353 3s3 29
376 376 30
227 227 3'l
't7,527 17,527 32
18,220 18,220 33
1,767 1.767 34
9,s93,299 21,897,198 0 31,'190,797
FERC FORM NO.1 (ED.12-90)Page 330
Name
ldaho Power Company
(1)
(2)
An Original
A Resubmission
Date of(Mo, Da
Report
,YO
o411412017
Year/Period of Report
End of 20161Q4
to as
9. ln column (k) through (n), report the revenue amounts as shown on bills or vouchers. ln column (k), provide revenues from demand
charges related to the billing demand reported in column (h). ln column (l), provide revenues from energy charges related to the
amount of energy transfened. ln column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). lf no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401 , Lines 16 and 17 , respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(t)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Ltne
No.
4,861 4,861 1
14,229 't4,229 2
3,s83 3,583 3
75 75 4
5,145 5,145 5
13,657 13,657 6
43 43 7
38,856 38,856 I
22,072 22.072 9
234 234 10
34,949 34,949 't1
17,890 17,890 12
739 739 13
94 94 14
387 387 15
64 64 16
31 31 17
4,313 4,313 18
10,886 10,886 't9
1.797 1.797 20
44 44 21
9,633 9,633 22
47,414 47,414 23
55,892 55,892 24
1,201 1,20',1 25
267 267 26
1,532 1,532 27
16,246 16,246 28
100 100 29
5,039 5,039 30
82,898 82,898 31
83 83 32
11,536 11,536 33
716 716 34
9,593,299 21,897,498 0 31,190,797
FERC FORM NO. r (ED. 12-q))Page 330.1
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
04t14t20'17
Year/Period of Report
End of 2016/Q4
as
9. ln column (k) through (n), report the revenue amounts as shown on bills or vouchers. ln column (k), provide revenues from demand
charges related to the billing demand reported in column (h). ln column (l), provide revenues from energy charges related to the
amount of energy transferred. ln column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). lf no monetary settlement was made, enter zero (1 1011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401 , Lines 16 and 17 , respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(t)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Ltne
No.
28,672 28,672 1
29.090 29,090 2
3,769 3,769 3
288 288 4
230,570 230,570 5
43,028 43,028 6
28,595 28,595 7
27,951 27,951 I
64 64 I
521 521 10
138 138 1'.!
29,686 29,686 12
279,705 279,705 't3
2,573 2,573 14
215 215 15
94 94 16
1,809 1,809 17
659 659 18
383 383 19
424 424 20
81 81 21
1,609 1,609 22
219 219 23
925 92s 24
778 778 25
187 187 26
53,985 53,985 27
40,765 40,765 28
3,268 3,268 29
2,229 2,229 30
3,528 3,s28 31
6,981 6,981 32
7.130 7,',t30 33
10.249 10,249 34
9,s93,299 21,897,498 0 31,490,797
FERC FORM NO. 1 (ED.12-90)Page 330.2
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
04t1412017
Year/Period of Report
End of 20161Q4
as
9. ln column (k) through (n), report the revenue amounts as shown on bills or vouchers. ln column (k), provide revenues from demand
charges related to the billing demand reported in column (h). ln column (l), provide revenues from energy charges related to the
amount of energy transferred. ln column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). lf no monetary settlement was made, enter zero (1101 1) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 40'1 , Lines 16 and 17, respectively.
't 1. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(t)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Ltne
No.
276 276 1
26,588 26,588 2
183,630 183,630 3
941 941 4
138 138 5
193 193 b
6,984 6,984 7
24,001 24,001 8
910 910 I
11,907 't 1,907 '10
182,331 182,331 11
't33,782 't33,782 12
13,984 13,984 13
224,494 224,494 14
349,169 349,169 't5
957 957 16
14,915 14,915 't7
426 426 't8
474 474 19
474 474 20
440 440 21
1,347 1,347 22
1,919 '1,919 23
11,862 11,862 24
66,055 66,055 25
1,'t05 1,105 26
669 669 27
8,688 8,688 28
6,030 6,030 29
282 282 30
339 339 31
8,776 8,776 32
1,408 1,408 33
1,452 1,452 34
9,593,299 21,897,498 0 31,490,797
FERC FORM NO. 1 (ED. 12-90)Page 330.3
Name of
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
o4t14t2017
Year/Period of Report
End of 20'l6lQ4
to as
9. ln column (k) through (n), report the revenue amounts as shown on bills or vouchers. ln column (k), provide revenues from demand
charges related to the billing demand reported in column (h). ln column (l), provide revenues from energy charges related to the
amount of energy transferred. ln column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). lf no monetary settlement was made, enter zero (1 101 1) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401 , Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(t)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Ltne
No.
29.036 29,036 1
7,922 7,922 2
44,964 44,964 3
'13,138 13,138 4
149,457 149,457 5
3.002 3,002 6
10,167 10,167 7
3,499 3,499 8
1,919 1,919 I
57 57 10
88 88 't1
75,637 75,637 't2
7,6't0 7,610 13
10,383 10,383 't4
8,288 8,288 15
7,223 7,223 16
't,717 '1,7'17 17
2,338 2,338 18
516 516 19
'r 5,667 15,667 20
3,567 3,567 21
3,997 3,997 22
74,008 74,008 23
23,042 23,042 24
2,724 2,724 25
10,426 10,426 26
242,886 242.886 27
8,270 8,270 28
831 831 29
106,507 106,507 30
23,744 23,744 31
1,069 1,069 32
560 560 33
6,774 6,774 34
9,s93,299 21,897,498 0 31,490,797
FERC FORM NO. 1 (ED.12-90)Page 330.4
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
04t1412017
Year/Period of Report
End of 20161Q4
to as
9. ln column (k) through (n), report the revenue amounts as shown on bills or vouchers. ln column (k), provide revenues from demand
charges related to the billing demand reported in column (h). ln column (l), provide revenues from energy charges related to the
amount of energy transfened. ln column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). lf no monetary settlement was made, enter zero (1 1011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and (1) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401 , Lines 16 and 17 , respectively.
1 1. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICIry FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(t)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Ltne
No.
2,6',t3 2,613 ,|
55,813 55,813 2
4,424 4,424 3
72,3',!5 72,315 4
12,151 12,',t51 5
10,842 10,u2 6
12,118 't2,'t18 7
44 44 8
6,710 6,710 o
258 258 10
531 531 1',l
272 272 12
1 ,611 1,61 1 't3
21 21 't4
608 608 15
469 469 16
5,168 5.168 't7
2,244 2,244 18
3,364 3,364 19
1,897 1,897 20
21',l 211 21
3,056 3,056 22
17,513 17,513 23
751 751 24
1,676 1,676 25
203 203 26
609 609 27
2,021 2,021 28
17,314 17,314 29
203 203 30
5,883 5,883 3'r
32
33
34
9,593,299 21,897,498 0 31,'f90,797
FERC FORM NO. 1 (ED.12-90)Page 330.5
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
0411412017
Year/Period of Report
2016tQ4
FOOTNOTE DATA
Schedule Page:328 Line No.: 1 Column: a
The network service agreement between Idaho Power and the Bonneville Power Administration
for the Oregon Trail Electric Cooperati-ve expires September 3O , 2A2B -
Schedule Page:328 Line No.: 1 Column: eg, Open Access Transmission Tariff, Schedufe 9 Network Integration Transmission Service
Schedule Page:328 Line No.: 1 Column: h
The billing demand for network service j-s the customer's demand at the tlme of Idaho Power
Company transmission system peak and varies by month.
Schedule Page:328 Line No.:2 Column: a
The network service agreement between Idaho Power and the Bonnevilfe Power Admrnistration
for the United States Bureau of Recl-amatj-on expires December 31, 2023.
Schedule Page: 328 Line No.: 2 Column: h
The billing demand for network service is the customer's demand at the time of Idaho Power
Company transmisslon system peak and varies by month.
Schedule Page:328 Line No.:3 Column: a
The network service agreement between Idaho Power and the Bonnevifle Power Administrationfor the Priority Firm Customers expires September 30, 2028.
Schedule Page:328 Line No.: 3 Column: h
The bilfing demand for network service is the customer's demand at the time of Idaho Power
Company transmission system peak and varies by month.
Schedule Page:328 Line No.:4 Column: a
The contract between Idaho Power and PacifiCorp - Imnaha expires on March 31, 2021.
Schedute Page:328 Line No.:4 Column: h
The billing demand for network service is the customer's demand at the time of Idaho Power
Company transmission system peak and varies by month.
Schedule Page:328 Line No.: 5 Column: a
The contract between fdaho Power and the Milner Irrigation District expires December 31,
20t1 -
Schedule Page:328 Line No.: 5 Column: eLegacy, contract prior to the Open Access Transmission Tariff
Schedule Page:328 Line No;6 Column: a
The agreement between Idaho Power and the United States Department of the Interior, Bureauof Indian Affairs is subject to termination upon 90 days written notice by the Bureau.
Schedule Page:328 Line No.:7 Column: a
The agreement between Idaho Power and the City of Seattle expires December 31, 20L1. Crtyof Seattle has re-so-Id this transmission service request to Morgan Stanley Capital Groupand Morgan Stanley is now responsible for payment.
Schedule Page:328 Line No.:7 Column: e4, Open Access Transmission Tariff, Schedule 4 Energy Imbalance Service
Schedule Page:328 Line No.:8 Column: a
The agreement between Idaho Power and Unlted Materials of Great Fal1s, Inc. has noexpiration date and can be terminated by either party at any time.
Schedule Page:328 Line No.: I Column: e
5/6, Open Access Transmission Tariff, Schedule 5/6 Operating Reserves
Schedule Page:328 Line No.: 12 Column: e1/8, Open Access Transmisslon Tariff, Schedule 7/B Point-to-Point Transmission Service
FERC FORM NO. 1 (ED. 12-871 Page 450.1
Name of Respondent
ldaho Power Company
This
(1)
(2)
Report ls:
IAn Original
[l A Resubmission
Date of Report(Mo, Da, Yr)
0411412017
Year/Period of Report
End of 20161Q4
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
(lncluding transactions referred to as "wheeling")
1. Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public
authorities, qualifying facilities, and others for the quarter.
2. 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 transferred. On column (g) report the total of all
other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all
components of the amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. 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.
Line
No.Name of Company or Public
Authority ( Footnote Affiliations)
(a)
Statistical
Classification
(b)
TRANSFER OF ENERGY EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERI
Magawalt-hoursReceived
(c)
ruagawatt-
hOUTSDelivered
(d)
Enerov
Charo-ds($I
(f)
UINET
Charoes($r
(o)
Total Cost of
Transmission($)(h)
1 Anzona Public Service NF 3,690 3,690
2 AdzcrB,Rlric Servie I OS 29 29
3 Arizo*tA6[c Seilico OS -18 -18
4 Avarylid Renardles OS -23,008 -23,008
6 Avista Corp-VlArVP Div NF 4,337 4,337 27.592 27592
6 Avista Corp-VVWP Div SFP 125,471 125,471 478.047 478,047
7 Avisb&a-ltvl fP oiv ::OS -121 -ttl
8 Benbn Cointy PUD NF 250 250
o Bonneville Power Admin LFP 352,51 4 352.51 4 3,163,292 3,163,292
10 Bonneville Power Admin SFP 2,516 2,516 14,336 14,336
11 Bonneville Power Admin NF 6,634 6,634 32,995 32,995
12 Bonnafle PowerAdmin OS 632,309 632,309
13 Bdmewe Pof,erAdmin UJ 25,725 25,725
14 BonnadgPoverAdmli ,na 190,297 190,297
't5 Bormadb PowerArln*r OS 200 200
16 Bonnevile PorerAdmh U5 26,055 26,055
TOTAL 740,642 740,642 5,231 ,419 317.702 5,555,1 21
FERC FORM NO. 1l3-Q (REV. 02-04)Page 332
Name of Respondent
ldaho Power Company
This Report ls:(1) EAn Original(2) l-lA Resubmission
Date of Report(Mo, Da, Yr)
o411412017
Year/Period of Report
End of 20161Q4
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
(lncluding transactions referred to as "wheeling")
l.Reportall transmission,i.e.wheelingorelectricityprovidedbyotherelectricutilities, cooperatives,municipalities,otherpublic
authorities, qualifying 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 - OtherTransmission Service. See General lnstructionsfordefinitions 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 amountof energytransferred. On column (g) reportthe 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.
Line
No.Name of Company or Public
Authority ( Footnote Affiliations)
(a)
Statistical
Classification(b)
TRANSFER OF ENERGY EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERI
Maoawatt-h-oursReceived
(c)
Maoawatt-
h-ours
Delivered
(d)
uemanoCharoes($r
(e)
tnerov
Charoi'r-is($I
(f)
utnerCharoes($I
(q)
Total Cost of
Tranig\ission
(h)
1 OS 3,144 3,144
2 Adnin OS 1s92 '1 ,592
3 Boonev*le P0erAdmin OS 4,582 4582
4 Exdon Gecerdion Co OS -25,464 -25,464
5 NV Energy SFP 271 271 5,000 5,000
6 NVEmrSy U5 717 717
7 NV U5 -49,426 -49,426
8 Northwestem Energy SFP 1,783 1,783 11,429 11.429
I Northweslem Energy NF 2,343 2,343 10,500 10,500
10 Nofftwbaerr energy os 1,095 1,095
11 PacifiCorp lnc.2,896 2,896 969,534 969,534
12 PacifiCorp lnc NF 16,007 16,007 s8,751 98,751
13 PacifiCsp lnc.OS 47,205 47,205
14 PacifCorp lnc.OS -1,400 -1,400
15 ?ffiWW.OS -2,236 -2,236
to OS -11 -11
TOTAL 740,642 740,642 5,237,419 317,702 5,555,'121
FERC FORM NO. 1/3-Q (REV. 02-04)Page 332.1
Name of Respondent
ldaho Power Company
Thi
(1)
(2)
s Report
EAn
ls:
Original
[lA Resubmission
Date of Report
(Mo, Da, Yr)
0411412017
Year/Period of Report
End of 2016/Q4
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
(lncluding transactions referred to as "wheeling")
1. Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public
authorities, qualifying facilities, and others for the quarter.
2. 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 conditrons 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{o- 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 transferred. On column (g) report the total of all
other charges on bills or vouchers rendered to the respondent, including any out of period adjustments" Explain in a footnote all
components of the amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. 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.
Line
No.Name of Company or Public
Authority (Footnote Affiliations)
(a)
Statistical
Classification
(b)
TRANSFER OF ENERG\EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERI
Magawatt-hoursReceived
(c)
vrdgawatt-
hoursDelivered
(d)
Eilergyunaroes($I
(f)
Total Cost of
rranlglission
(h)
1 OS -489 -489
2 Powe*eorp.OS -1 90,557 -1 90,557
3 PWelSerd Enorgy, lnc SFP 378,491 378.491
4 Seaffie Cly Light SFP 4,625 4.625
5 She{ Erreey N. Amerha SFP 4,893 4,893
6 She[ En€rgy X. Arierba OS -861 -861
7 $rdrmislr OounV PUD SFP 31,582 31,582
8 SFP 2,412 2,412
I os -95,787 -95.787
10
11
12
'13
14
15
'16
TOTAL 740,64i 7 40.642 5,237,419 317 702 5,555,121
FERC FORM NO. 1/3-Q (REV. 02-04)Page 332.2
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t14t2017
Year/Period of Report
20161Q4
FOOTNOTE DATA
Schedule Page: 332 Line No.: 2 Column: a
AnciJ-lary Services
Schedule Page:332 Line No;3 Column: a
Unreserved use penalty credit
Schedule Page:332 Line No.:4 Column: a
Transmission Resale
Schedule Page:332 Line No.:7 Column: a
Unreserved Use Penalty Credrt
Schedule Page:332 Line No.: I Column: a
BPAT is provider for capacity reassignment
Schedule Page:332 Line No.:9 Column: b
Contract Exprration Date 12/3I/2A27
Schedule Page:332 Line No.: 12 Column: a
Ancillary Services
Schedule Page:332 Line No.: 13 Column: a
Sprnnrng/Supplemental Reserves
Schedule Page:332 Line No.: 14 Column: a
BPAT rs provider for capacity reassignment
Schedule Page:332 Line No.: 15 Column: a
BPAT is provider for capacity reassignment
Schedule Page:332 Line No.: 16 Column: a
BPAT rs provider for capacity reassignment
settled with Benton County PUD
settled with Puget Sound Energy
settled with Benton County
settled with Snohomish Countv PUD
Schedule Page: 332.1 Line No.: 1 Column: a
BPAT is provider for capacity reassignment settled with Seattle Ci-ty Light
Schedule Page:332.1 Line No.: 2 Column: a
BPAT is provider for capacity reassignment settled with Tacoma Power.
Schedule Page:332.1 Line No.: 3 Column: a
BPAT is provider for capacity reassignment settled with Shell Energy.
Schedule Page:332-1 Line No.:4 Column: a
ResaIe Transmission
Schedule Page:332.1 Line No.:6 Column: a
AnclIlary Services
Schedule Page:332.1 Line No.:7 Column: a
Refunded PTP transmission for 1/9/I5 - 4/9/16 due to 155 FERC P61,249 (2076)
Schedule Page:332.1 Line No.: 10 Column: a
Ancillary Services
Schedule Page:332.1 Line No.: 11 Column: b
Contract Expiratron Date 05/31/2019
Schedule Page:332.1 Line No.: 13 Column: a
AnciLlary Servlces
Schedule Page:332.1 Line No.: 14 Column: a
ResaLe Transmission
Schedule Page:332.1 Line No.: 15 Column: a
PTP 2015 true-up
Schedule Page:332.1 Line No.: 16 Column: a
Unreserved use penalty credit
Schedule Page:332.2 Line No.: 1 Column: a
PTP 2014 true-up
Schedule Page:332.2 Line No.: 2 Column: a
ResaIe Transm i ss Lon
Schedule Page:332.2 Line No.: 3 Column: a
BPAT is provider for capacity reassignment settfed with Puget Sound Energy
FERC FORM NO. 1 (ED. 12.871 Page 450.1
Name of Respondent
ldaho Power Companv
This Report is:
(1) X An OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
0411412017
Year/Period of Report
2016tQ4
FOOTNOTE DATA
Schedule Page:332.2 Line No.:4
BEAT is provider for capacity
Schedule Page:332.2 Line No.: 5
BPAT i! provider fol capacity
Schedule Page: 332.2 Line No.: 6
Resal-e Transmission
Schedute Page:332.2 Ljne No.:7
EB4r iq provi-der for capacity
Schedule Page:332.2 Line No.:8
BPAT is provider for capacity
Schedule Page:332.2 Une No;9Resale Transmisslon
Column: a
reaEsignment
Column: a
reqsslgnment
Column: a
Column: a
reaisignment
Column: a
reassignment
Column: a
settfed
setEled
with
wiltr
Seattle City Light
SheII Energy
settled with Snohomish County PUD
settled with Tacoma Power
FERC FORM NO.1 1 450.2
Name of Respondent
ldaho Power Company
rhrs FsgElon rs:
(1) lx_l An Original
(2) n A Resubmission
uate oI KeDon(Mo, Da, Yi)
o411412017
YeailPenoo or Kepon
End of 20,t61Q4
MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Line
No.
Amount
(b)
1 lndustry Association Dues 516,427
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
6
7 Director Fees and Expenses:
I Christine King 91,305
I Dennis Johnson 69,959
't0 J Lamont Keen 64,025
1'l Judith Johansen 77,647
12 Richard Dahl 91,',t12
't3 Richard Navarro 76,166
14 Robert Tintsman 177,685
15 Ronald Jibson 7',t,144
16 Thomas Carlile 75,845
17 Director travel and lodging 22,O99
't8
19 Corporate Memberships and Subscriptions:
20 Associated Taxpayers of ldaho 26,000
21 Business Plus 5,000
22 ldaho Association of Commerce & lndustry 15,000
23 ldaho Technology Council '12,350
24 National Association of Directors 7,125
25 National Hydropower Association 35,860
26 North American Energy Standard 7,000
27 Northwest Power Pool 158,932
28 Pacific NW Utilities 42,747
29 SNL Financial Unlimited Subscription 25,931
30 Westem Energy Coordinating Council -21,979
31 Western Energy lnstitute 30,988
32 Misc Memberships Under $2,000 8,286
33
34 Chambers of Commerce & Other Civic Organizations 85,875
35
36
37
38
39
40
41
42
43
44
45
46 TOTAL 3,552,222
FERC FORM NO. 1 (ED. r2-9,f)Page 335
Name of Respondent
ldaho Power Companv
This Report is:
(1) X An OriginalQ) A Resubmission
Date of Report
(Mo, Da, Yr)
04t1412017
Year/Period of Report
20161Q4
FOOTNOTE DATA
Schedule Pase:335 Line No.:4 Column: b
Recipient
American Stock Transfer & Trust
Bloomberg Finance LP
Broadridge Einancial Sol-utions
Deutsche BankE Source
Moodyrs Analyti-cs
NASDAQ Corp Solutions
New York Stock ExchangePayroII Related Expenses
PR Newswi-reRivef Research GroupStock Based CompensationWells Eargo Shareowner Services
$9!9dule Page:335 Line No.: 5
Recipient
Bank of New YorkInspirus, LLC.fnvestis, Inc.Payroll Rel-ated Expense
Miscellaneous under $5, 000
Purpose
Mgmt ServicesMlsc Expense
Misc Expense
Broker Eees
Mgmt Services
Mgmt Services
Mgmt Servj-cesListing ServicesMisc Expense
Misc Expense
Mgmt ServicesMisc Expense
Mgmt Services
Purpose
Revenue Bonds
Employee Engagement
Website Design
Misc Expense
Misc Expense
Column: b
$
$ 1, 652, 922
Amount
t2,925
54,848
L2, 63'7
L1 ,660
28 ,1 0L
Amount
69,353
1L,299
47 ,5!230,000
41, 499
33,708
91, 676
51, 9r1
249,217
75,662
15,840
890,845
704, 400
$
5 126,117
FERC FORM NO. 1 (ED. 12-871 Page 450.1
Name of Respondent
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
04t't4t2017
Year/Period of Report
End of 20'l6lQ4
DEPRECTA I ION ANL' AMOR I tZA I tON Ot- E LEC I RtC 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, repoftng 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. ldentify 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 (0 the type mo(ality 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
Line
No.Functional Classification
(a)
De;creciation
Expense(Account 403)(b)
uepreciation
Expense for Asset
Retirement Costs(Account 403.1)(c)
Amortization ot
Limited Term
Electric Plant(Account 404)(d)
Amortization ofOther Electric
Plant (Acc 405)
(e)
Total
(0
1 lntangible Plant 6,649,4s5 6,649,455
I Steam Production Plant 26,985,885 720,272 27,706,157
?Nuclear Production Plant
4 Hydraulic Production Plant-Conventional "t4,955,319 14,955,319
q Hydraulic Production Plant-Pumped Storage
6 Other Production Plant 16,492,282 't6,492,282
7 Transmission Plant 22,117,697 22,',t17,697
8 Distribution Plant 43,603,291 43,603,291
o Regional Transmission and Market Operation
10 General Plant 1 0,894,1 10 10,894,'1't0
11
12
Common Plant-Electric
TOTAL 135,048,584 720,272 6,649,455 't42,418,31'l
B. Basis for Amortization Charges
Acct 404
(1)
(2)
(3)
(4)
(5)
(6)
(7)
Balance 11112016
24,000
9,794,550
5,062,565
13,191,811
3,460,098
193,795
878,552
2016 Amortization
12,000
537,',t'14
189,129
5,592,337
287,899
8,026
22.950
Balance 1213112016
12,000
9,257,436
4,873,436
9,768,866
3,'t72,',t99
185,769
1,128,967
Remaining Months
12
309
132
48
Total 32,605,372 6,649,455 28,398,674
(1) Shoshone-Bannock Tribe License & Use Agreement(Termination dale 12131123).
(2) Middle Snake Relicensing Costs (Amortized over a 30 year license period; licenses expire 07131134 and 02128135).
(3) Swan Falls Relicensing Costs (Amortized over a 30 year license period).
(4) Computer Software packages (Amortized over a 60 month period from date of purchase).
(5) Shoshone-Bannock Right of Way (Termination date 121311271.
(6) Boardman Retrofit Tech Analysis (Scheduled decommission dale 12131120).
(7) FERC License Compliance Costs (Termination date will be expiration date of the applicable FERC Licenses) .
FERC FORM ilO. I (REV. 12-03)Page 336
Name of Respondent
ldaho Power Company
This Reoort ls:(1) fiRn Origlnat(2) l--1A Resubmission
Date ol Report(Mo, Da, Yr)
0411412017
Year/Period of Report
End of 20161Q4
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line
No.Account No.
(a)
ueprecraore
Plant Base(ln Thousands)(b)
trsumaleo
Avg.Service
Life(c)
NEI
Salvaoe(Perceht)
(d)
AppIeo
Depr. rates(Percent)
(e)
MO[aflry
Curve,Ifi"
AVerage
Remaining
(o)
't2 310.20 649 75.0C 3.70 R4.0 20.20
13 311.00 151,56'l 't 00.0c -10.0c 't.82 s1.0 21.30
14 312.10 193,075 60.0c -5.0c 1.41 R3.0 21.80
15 312.20 560,728 60.00 -5.00 2.78 R1.5 20.90
16 312.30 4,341 25.00 20.00 2.26 R3.0 7.9C
17 314.00 165,722 45.00 -5.00 3.27 s't.0 't 9.4C
18 315.00 72.133 60.00 1.44 s1.5 19.8C
1g 316.00 '13.558 45.00 -5.00 3.78 R0.5 't 9.0c
20 316.10 152 12.00 15.00 8.19 L2.0 6.3C
21 316.40 2s0 12.0A 15.00 0.68 12.0 7.9C
22 316.50 366 12.04 15.00 3.19 L2.0 5.10
23 316.60 106 20.00 15.00 4.39 L2.0 18.00
24 3't 6.70 8C 20.00 15.00 2.09 L2.0 M.4A
25 316.80 2,97t 20.00 30.00 3.50 o1.0 16.60
26 316.90 14 35.00 15.00 2.45 s1.0 34.74
27 317.00 15,312
28 1,181,021
29 331.00 179,023 105.00 -25.00 2.39 R2.5 33.00
30 332.10 19,461 95.00 -20.00 1.31 s4.0 39.80
31 332.20 246,829 95.00 -20.00 1.65 s4.0 35.60
32 332.30 5,472 1.44 Square 49.10
33 333.00 24',t,657 80.00 -5.00 1.74 R3.0 32.60
34 334.00 60,377 50.00 -5.00 2.77 R1.5 26.10
35 335.00 23,707 95.00 2.26 R2.0 28.10
36 335.10 88 1s.00 7.94 Square 6.50
37 335.20 407 20.00 5.6'l Square 5.30
38 335.30 313 5.00 14.22 Square 3.30
39 336.00 10,843 75.00 2.48 R3.0 21.40
40 788,177
4',!341.00 143,'t68 2.92 Square 27.20
42 342.00 't0,452 50.0c 2.90 s2.5 28.50
43 343.00 229,874 40.0c 3.32 s1.5 25.90
44 344.00 66,532 45.0C 2.64 s2.0 26.80
45 345.00 91,',t47 50.0c 3.39 s't.5 22.60
46 346.00 6,240 35.0C 3.35 R2.5 24.50
47 547,413
48 350.20 32,571 70.00 1.39 R3.0 58.50
49 350.22 187 30.00 3.33
50 352.00 79,540 65.00 -35.00 't.84 R3.0 53.70
FERC FORM NO. 1 (REV. 12-03)Page 337
Name of Respondent
ldaho Power Company
This ReDort ls:(1) fiAn Origlnal(2) [lA Resubmission
Date of Report(Mo, Da, Yr)
041't4t2017
Year/Period ot Report
End of 2016/04
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Lrne
No Account No.
(a)
ueprectaote
Plant Base(ln Thousands)' (b)
trsItmaIeo
Avg. Service
Life(c)
NEI
Salvage
(Percent)(d)
Appfleo
Depr. rates(Percent)(e)
MOnailry
Curve
'ffi"
AVerage
Remaining
Life(o)
't2 353.00 411,289 50.00 -5.0c 1.90 R1.5 40.70
13 354.00 1 98,1 03 65.00 -15.0C 1.70 s3.0 50.80
14 355.00 174,174 60.00 -70.0c 2.77 R2.0 43.60
'15 355.10 1,003 10.00 't0.00
16 356.00 219,215 6s.00 -40.0c 2.25 R2.0 48.50
17 359.00 390 65.00 0.79 R2.5 24.00
't8 Subtotal Transmission 't ,1 16,468
19 360.22 730 30.0c 3.33 30.00
20 361.00 36,984 65.00 -40.0c 2.14 R2.5 53.30
21 362.00 222,357 50.00 -5.0c 2.00 R't.0 40.20
22 364.00 252,409 44.0C -45.0C 3.08 R1.5 31.30
23 364.'t0 3,750 12.0C 8.34
24 365.00 131,275 45.0C -35.0C 2.98 R0.5 33.60
25 s66.00 49,795 60.0c -20.0c 1.95 R2.0 48.40
26 367.00 243,650 46.0C -15.0C 2.26 R2.0 35.30
27 368.00 536,551 35.0C -3.0c 2.58 Rl.0 27.00
28 369.00 59,471 40.0c -40.0c 2.55 R2.0 29.50
29 370.00 16,367 22.0C 1.0c 3.46 o1.0 17.50
30 370.1 0 70,892 15.0C 6.96 s2.5 13.10
31 371.10 12.OC -2.0c s4.0 9.00
32 371.20 3,017 't7.oc -2.0c 1.51 Rl.5 14.70
33 373.20 4,501 30.0c -25.0C 2.4',l R1.0 20.60
34 374.OO 164
35 Subtotal Distribution 1 ,631 ,913
36 390.1 1 30,295 100.00 -s.00 2.58 s0.5 28.80
37 3go.'t2 88,155 55.00 -5.00 1.90 s0.5 44.30
38 390.20 35.00 2.15 s3.0 25.7C
39 391.10 't4,885 20.00 2.88 Square 12.9C
40 391.20 26,027 5.00 1',t.12 Square 3.2C
41 391.2',l,8.172 8.00 1',t.22 L2.0 5.7C
42 392.10 917 12.O4 15.00 7.50 L2.O 8.90
43 392.30 4,56:10.00 50.00 1.73 s2.5 3.40
44 392.40 23,744 12.00 15.00 7.36 L2.0 6.80
45 392.50 1,11€12.00 15.00 3.53 L2.0 9.00
46 392.60 39,162 20.00 15.00 4.14 L2.0 13.40
47 392.70 6,845 20.00 15.00 3.2',1 L2.O 12.54
48 392.90 5,077 35.00 15.00 2.10 s1.0 24.34
49 393.00 2,62C 25.00 3.30 Square '19.40
50 394.00 8,666 20.00 4.13 Square 13.30
FERC FORM NO. I (REV. 12-03)Page 337.1
Name of Respondent
ldaho Power Company
This ReDort ls:(1) 5]en orisinat(2) l--1A Resubmission
Date of Report
(Mo, Da, Yr)
04t't4t2017
Year/Period of Report
End of 20161Q4
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line
No.Account No.
(a)
ueprecraDre
Plant Base(ln Thousands)(b)
ESUMAIEO
Avg.Service
Life(c)
NEI
Salvage(Percent)' (d)
Appfleo
Depr. rates(Percent)
(e)
MOnar[y
Curve
'[f"
AVerage
Remaining
Life(o)
't2 39s.00 13,O22 20.00 4.29 Square 1214
13 396.00 15,085 20.00 30.00 1.66 o1.0 17.60
14 397.10 4,145 15.00 4.25 Square 8.30
15 397.20 29,94e 15.00 s.38 Square 9.80
16 397.30 3,473 15.00 5.31 Square 8.00
't7 397.40 19,02€10.00 7.90 Square 6.50
't8 398.00 6,571 15.00 5.20 Square 10.60
't9 Subtotal General 351,519
20 Total Plant 5,616,515
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
45
46
47
48
49
50
FERC FORM NO. I (REV. 12.03)Page 337.2
Name of Respondent
ldaho Power ComDanv
This Report is:
(1) X An OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
04t14t2017
Year/Period of Report
2016tQ4
FOOTNOTE DATA
Schedule Page:336 Line No.:28 Column: a
Steam, hydro, and other productj-on depreclation and amortization of certain electric plant i-s
maintained by plant l-ocation. Effective April 1, 1993 the forecast Ij-fe span method of life
analysis using an interim retirement rate was utilized to develop all production plant rates.
Rates, servj-ce fives, net salvage and remaj-ning lives indicated are on a composite basis. An
average pfant balance was used in computing these rates by FERC account. Effective April 1, 1,993,aII depreciable pJ-ant is bej-ng depreciated using the straight-1ine remainj-ng l-ife method.
Schedylg Page.'336 Line No.:40 Column: a
Steam, hydro, and other production depreciation and amortization of certain electric plant is
maintained by plant locatj-on. Effective April 1, 1993 the forecast life span method of life
analysis usi-ng an interim reti-rement rate was utilized to develop atl production plant rates.
Rates, servj-ce lives, net salvage and remaining lives indicated are on a composite basis. An
average plant balance was used in computlng these rates by FERC account. Effective April 1, 7993,
aJ-1 depreciable plant is being depreciated using the straight-l-ine remaining life method.
Schedule Page:336 Line No.:47 Column: a
Steam, hydro, and other production depreci-ation and amortization of certain el-ectric plant is
maintaj-ned by plant l-ocation. Effective April 1, 1993 the forecast life span method of life
analysis using an interlm retirement rate was utili-zed to develop all production plant rates.
Rates, service 1ives, net salvage and remaining lives indicated are on a composite basis. An
averaqe plant balance was used in computing these rates by EERC account. Effective April 1, \993,a1I depreciable plant is being depreciated using the stralght-1ine remainj-ng Iife method.
FERC FORM NO. 1 12-87 450.1
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5]en Orisinat(2) nA Resubmission
Date of(Mo, Da
Report
, Yr)
04t14t2017
Year/Period of Report
End of 20161Q4
REGULA I ORY COMMISSION EXPENSES
1. Report particulars (details) of regulatory commission expenses incurred during the current year (or incurred in previous years, if
being amortized) relating to format cases before a regulatory body, or cases in which such a body was a party.
2. Report in columns (b) and (c), only the current year's expenses that are not deferred and the current yea/s amortization of amounts
deferred in previous years.
Line
No.
Description
(Fumish name of reoulatory commission or bodv the
dbcket or case numb-er anda description of the iase)
(a)
Assessed by
Regulatory
Commission
(b)
Expenses
of
Utility
(c)
Total
Exoense forCuirent Year(b) + (c)
(d)
L'elened
in Account
182.3 atBeginning of Year
(e)
,|Federal Energy Regulatory Commission:
2 Annual admin charges assessed by FERC 3,289,462 3.289.462
3
4 General Regulatory Expenses and
5 Various other Dockets 23.538 23.538
6
7 Oregon Hydro - Fees Amortization 163,353 163,353
8
I Regulatory Commission Expenses - ldaho
10 Rate Case - Misc expenses 193,188 193,188
11
12 Regulatory Commission Expenses - Oregon
'13 Rate Case - Misc expenses 425 425
14 General Regulatory 136,981 136,98'l
'15 Other OPUC expenses 11,049 1 1,049
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 TOTAL 3,452,8',t5 365,581 3,818,s96
FERC FORM NO. 1 (EO. 12-96)Page 350
Name of Respondent
ldaho Power Company
This Report ls:(1) ElAn Orisinal(2) ;1A Resubmission
Date of Report(Mo, Da, Yr)
04t14t2017
Year/Period ot Report
End of 20161Q4
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, (g), and (h) expenses incurred during year which were charged currently to income, plant, or other accounts.
5. Minor items (less than $25,000) may be grouped.
EXPENSES INCURRED DURING YEAR AMORTIZED DURING YEAR
CURRENTLY CHARGED TO Deferred to
Account 182.3
(i)
Contra
Account
(i)
Amount
(k)
Defened inAccount 182.3
End of Year(t)
Line
Nouepartment
(f)
AGCOUIItNo.(s)
Amounl
(h)
1
Electric 928 3,289,462 2
3
4
Electric 928 23,538 5
b
Electric 924 163,353 7
I
I
Electric 928 684 928203 192,504 80,210 '10
11
12
Electric 928 82r 13
Electric 928 136,981 't4
Electric 928 1 1,04€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
4'l
42
43
44
45
3,625,892 192,504 80,210 46
FERC FORM NO. 1 (ED. 12-96)Page 351
Name of Respondent
ldaho Power Company
This
(1)
(2\
Reoort ls:
5]An Original
TIA Resubmission
Date of Report(Mo, Da, Yr)
0411412017
Year/Period of Report
End of 2O'l6lQ4
RESEARCH, I]E,VELOPMENT, AND DEMONSTRATION AGTIVITIES
1. Describe and show below costs incuned and accounts charged during the year for technological research, development, and demonstration (R, D &
D) projectinitiated,continuedorconcludedduringtheyear. Reportalsosupportgiventoothersduringtheyearforjointly-sponsoredprojects.(ldentify
recipient rcgardless of affiliation.) For any R, D & D work canied 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. Electric R, D & D Performed lntemally:
(1)Generation
a. hydroelectric
i. Recreation fish and wildlife
ii Other hydroelectric
b. Fossil-fuel steam
c. lntemal combustion or gas turbine
d. Nuclear
e. Unconventional generation
f. Siting and heat rejection
(2) Transmission
a. Overhead
b. Underground
(3) Distribution
(4) Regional Transmission and Market Operation
(5) Environment (other than equipment)
(6) Other (Classifu and include items in excess of $50,000.)
(7) Total Cost lncuned
B. Electric, R, D & D Performed Externally:
('l ) Research Support to the electrical Research Council or the Electric
Power Research lnstitute
Line
No.
Classification
(a)
Description
(b)
,|ldaho Power did not incur any Research and
2 Development expenditures in 2016.
3
4
5
6
7
8
9
10
11
12
13
14
,,15
16
17
't8
't9
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
FERC FORI NO. 1 (ED. 12-87)Page 352
Name of Respondent
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date(Mo,
o411412017
Year/Period of Report
End of 2016/Q4
(2) Research Support to Edison Electric lnstitute
(3) Research Support to Nuclear Power Groups
(4) Research Support to Others (Classify)
(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 Account 107, Construction Work in Progress, first. Show in column (0 the amounts related to the account charged in column (e)
5. Show in column (g) the total unamortized accumulating of costs of projects. This total must equal the balance in Account 188, Research,
Development, and Demonstration Expenditures, Outstanding at the end of the year.
6. 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
Curre6!Year Costs lncuned Externally
Current Year
(d)
AMOUNTS CHARGED IN CURRENT YEAR Unamortized
Accumulation
(s)
Line
NoAccount
(e)
Amount(fl
I
2
3
4
5
6
7
I
o
10
11
12
,,1 3
't4
15
16
17
18
19
20
2'l
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
FERC FORM NO. 1 (ED. 12.87)Page 353
Name of Respondent
ldaho Power Company
This Report ls:(1) EAn Original(2) TIA Resubmission
Date of Report(Mo, Da, Yr)
0411412017
Year/Period of Report
End of 2016/Q4
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 PavrollDistribution
(b)
Total
(d)
1 Electric
2 Operation
3 Production 21,637,003
4 Transmission 6,570,443
5 Regional Market
6 Distribution 18.245.062
7 Customer Accounts 9,445,563
8 Customer Service and lnformational 5,338,448
9 Sales
't0 Administrative and General 71,207 ,473
11 TOTAL Operation (Enter Total of lines 3 thru 10)132,443,992
12 Maintenance
13 Production 4,501,996
14 Transmission 3,042.252
15 Regional Market
16 Distribution 8,567,356
17 Administrative and General 1,093,877
18 TOTAL Maintenance (Total of lines 13 thru '17)17,205,481
't9 Total Operation and Maintenance
20 Production (Enter Total of lines 3 and 13)26,138,999
21 Transmission (Enter Total of lines 4 and 14)9,612,695
22 Regional Market (EnterTotal of Lines 5 and 15)
23 Distribution (Enter Total of lines 6 and 16)26,812,418
24 Customer Accounts (Transcribe from line 7)9,445,563
25 Customer Service and lnformational (Transcribe from line 8)5,338,448
26 Sales (Transcribe from line 9)
27 Administrative and General (Enter Total of lines 10 and '17)72,301,350
28 TOTAL Oper. and Maint. (Total of lines 20 lhru 27)149,649,473 149,649,473
29 Gas
30 Operation
3'l Production-Manufactured Gas
32 Production-Nat. Gas (lncluding Expl. and Dev.)
33 Other Gas Supply
34 Storaqe, LNG Terminaling and Processing
35 Transmission
36 Distribution
37 Customer Accounts
38 Customer Service and lnformational
39 Sales
40 Administrative and General
41 TOTAL Operation (Enter Total of lines 31 thru 40)
42 Maintenance
43 Production-Manufactured Gas
44 Production-Natural Gas (lncluding Exptoration and Development)
45 Other Gas Supply
46 Storaqe, LNG Terminaling and Processing
47 Transmission
FERC FORM NO. r (ED. 12-88)Page 354
Name of Respondent
ldaho Power Company
This
(1)
(2\A Resubmission 04114120',t7
Year/Period of Report
End of 20161Q4
DISTRIBUTION OF SALARIES AND WAGES (Continued)
Line
No.
Classification
(a)
Direct Pavroll
Oistribution
(b)
Total
(d)
4A Distribution
49 Administrative and General
50 TOTAL Maint. (Enter Total of lines 43 thru 49)
51 Total Operation and Maintenance
52 Production-Manufactured Gas (Enter Total of lines 31 and 43)
53 Production-Natural Gas (lncluding Expl. and Dev.) (Total lines 32,
54 Other Gas Supply (Enter Total of lines 33 and 45)
55 Storage, LNG Terminaling and Proe,essing (Total of lines 31 thru
56 Transmission (Lines 35 and 47)
57 Distribution (Lines 36 and 48)
58 Customer Accounts (Line 37)
59 Customer Service and lnformational (Line 38)
60 Sales (Line 39)
61 Administrative and General (Lines 40 and 49)
62 TOTAL Operation and Maint. (Total of lines 52 thru 61)
63 Other Utility Departments
64 Operation and Maintenance
65 TOTAL All Utility Dept. (Total of lines 28,62, and 64)149,649,473 149,649,473
66 Utility Plant
67 Construction (By Utility Departments)
68 Electric Plant
69 Gas Plant
70 Other (provide details in footnote):
71 TOTAL Construction (Total of lines 68 thru 70)
72 Plant Removal (By Utility Departments)
73 Electric Plant
74 Gas Plant
75 Other (provide details in footnote):
76 TOTAL Plant Removal (Total of lines 73 thru 75)
77 Other Accounts (Specify, provide details in footnote):
78 Stores Expense 4,767,872 4.767.872
79 Other Clearing Accounts 3,$2,128 3,462,128
80 Construction Work in Progress 57,ffi2,2',t3 57,ffi2,213
81 Other Work in Proqress 3,330,273 3,330,273
82 Preliminary Survey and lnvest -930 -930
83 Other Accounts 4,721,481,4,721,481,
M lndirect Loading 6,73',t,443 46.731.443
85
86
87
88
89
90
91
92
93
94
95 TOTAL Other Accounts 74,143,037 6,731,443 74,',t43,037
96 TOTAL SALARIES AND WAGES 223,792,s',t0 $.731.443 223.792.510
FERC FORM NO. r (ED.12-88)Page 355
This Page lntentionally Left Blank
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
04114t2017
Year/Period of Report
20161Q4
FOOTNOTE DATA
Schedule Page:354 Line No.: 81 Column: a
Amount reported is total amount of indirect loading. The loading j-s allocated to
departments based on l-abor charges.
FERC FORM NO. 1 (ED. 12-871 Page 450.1
Name of Respondent
ldaho Power Company
This(1)
(2)
Reoort ls:
5]An orisinat
[lA Resubmission
Date of(Mo, Da
Report
, Yr)
0411412017
Year/Period of Report
End of 20161Q4
PURCHASES AND SALES OF ANCILLARY SERVI(;ES
Report the amounts for each type of ancillary service shown in column (a) for the year as specified in Order No. 888 and defined in the
respondents Open Access Transmission Tariff.
ln columns for usage, report usage-related billing determinant and the unit of measure.
(1) On line 1 columns (b), (c), (d), (e), (f) and (g) report the amount of ancillary services purchased and sold during the year.
(2) On line 2 columns (b) (c), (O), (e), (f), and (g) report the amount of reactive supply and voltage control services purchased and sold
during the year.
(3) On line 3 columns (b) (c), (O), (e), (f), and (g) report the amount of regulation and frequency response services purchased and sold
during the year.
(4) On line 4 columns (b), (c), (d), (e), (f), and (g) report the amount of energy imbalance services purchased and sold during the year.
(5) On lines 5 and 6, columns (b), (c), (d), (e), (f), and (g) report the amount of operating reserve spinning and supplement services
purchased and sold during the period.
(6) On line 7 columns (b), (c), (d), (e), (0, and (g) report the total amount of all other types ancillary services purchased or sold during
the year. lnclude in a footnote and speci! the amount for each type of other ancillary service provided.
Amount Purchased for the Year Amount Sold for the Year
Usage - Related Billing Determinant Usage - Related Billing Determinant
Line
No.
Type of Ancillary Service
(a)
Number of Units
(b)
Unit of
Measure
(c)
Dollars
(d)
Number of ljnits
(e)
Unit of
Measure
(f)
Dollars
(s)
Scheduling, System Contol and Dispatch 660,996
I Reaclive Supply and Voltage 20,360
Regulation and Frequency Response 3,056,677 KW 299,401
4 Energy lmbalance 1,251 KWH 82,801
operating Reserve - Spinning 13,422 4,110,746 KW 402,648
€operating Reserve - Supplement 12,303 4,110,746 KW 402,648
7 0her
€Total (Lines t hru 7)707,081 11,279,420 1 ,187,498
FERC FORM NO. 1 (New 2-04)Page 398
Name of Respondent
ldaho Power Companv
This Report is:
(1) X An Original(21 A Resubmission
Date of Report
(Mo, Da, Yr)
04t14t2017
Year/Period of Report
2016tQ4
FOOTNOTE DATA
Schedule Pase:398 Line No.: I Column: bIdaho Power does notservices purchased.systematically record the number of units related to anciJ-Iary
FERC FORM NO. I (ED. 12-871 Page 450.1
Name of Respondent
ldaho Power Company
(1)
(2)
An Original
A Resubmission
Date of Report
(Mo, Da, Yr)
0411412017
Year/Period of Report
End of 20161Q4
MONTHLY TRANSMISSION 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 O by month the system'monthly maximum megawatt load by statistical classifications. See General lnstruction for
the definition of each statistical classification.
NAME OF SYSTEM:
Line
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
Point-to-point
Reservations
(s)
Other Long-
Term Firm
Service
(h)
Short-Term Firm
Pointto-point
Reservation
(i)
Other
Service
(i)
1 January 3,051 1i 800 1,853 222 77i 207
2 February 3,09r 800 2,016 221 774 84
?March 2,65:,1t 2100 1,328 175 774 376
4 Total for ouarter 1 5,1 97 618 2,311 667
q April 2l01 2a 1 100 1,305 204 77i 425
6 May 3,19t 1:2200 1,762 253 771 405
7 June 4,35(21 1S00 2,9't6 365 77i 305
I Total for Quarter 2 I 5,983 822 2,314 1,135
o July 4,32i 2t 2100 2s52 344 o7'.58
10 August 4,311 1t 1800 2,982 331 972 28
11 September 3,68{1 2100 2,256 294 97:165
12 Total for Ouarter 3 8,190 969 2,91!251
13 0ctober 2,86r 1S 800 1,585 171 973 136
14 November 3,06i 3(190C 1,66'l 18S 97i 239
15 December 3,55t 1t 200c 2,0u 233 97i 3'15
16 Total for Querter'4 5,280 593 2,914 690
17 Total Year to
Date,Year 24,650 3,002 10,47t 2,743
FERC FORM NO. 1/3-Q (NEW. 07-04)Page 400
Name of Respondent
ldaho Power Company
This(1)
(2\
Reoort ls:
5]nn originat
;1A Resubmission
Date of Report(Mo, Da, Yr)
04t14t2017
Year/Period of Report
End of 2016/Q4
ELEC I RIC ENERGY ACCOUNT
Report below the information called for conceming the disposition of electric energy generated, purchased, exchanged and wheeled during the year
Line
No.
Item
(a)
MegaWatt Hours
(b)
Line
No.
Item
(a)
MegaWatt Hours
(b)
1 SOURCES OF ENERGY 21 DISPOSITION OF ENERGY
2 Generation (Excluding Station Use):22 Sales to Ultimate Consumers (lncluding
lnterdepartmental Sales)
14,195,750
3 Steam 4.045.17i
4 Nuclear 23 Requirements Sales for Resale (See
instruction 4, page 31 1.)5 Hydro-Conventional 6,407,99(
6 Hydro-Pumped Storage 24 Non-Requirements Sales for Resale (See
instruction 4, page 31 1.)
1,185,87S
7 Other 1,721,54(
8 Less Energy for Pumping 25 Energy Furnished Without Charge
I Net Generation (Enter Total of lines 3
through 8)
12,174,71i 26 Energy Used by the Company (Electric
Dept Only, Excluding Station Use)
10 Purchases 4,330,80(27 Total Energy Losses 1,181,741
11 Power Exchanges:28 TOTAL (Enter Total of Lines 22 Through
27) (MUST EOUAL L|NE 20)
16,s63,370
12 Received 234,71i
13 Delivered 181,76(
't4 Net Exchanges (Line 12 minus line 13)52,95'1
15 Transmission For Other (Wheeling)
16 Received 6,319,07'
't7 Delivered
18 Net Transmission for Other (Line 16 minus
line 17)
4,907
1g Transmission By Others Losses
20 TOTAL (Enter Total of lines 9, 10, 14, 18
and 19)
16,s63,37(
FERC FORM NO. r (ED. 12-90)Page 401a
Name of Respondent
ldaho Power Company
This Report is:
(1) X An OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
04114t2017
Year/Period of Report
20161Q4
FOOTNOTE DATA
Schedule Pase:4O1 Line No.:17 Column: b
Page 329 column f differs from page 401 by 4,907 MWH, reported for Lucky Peak variationand BPA energy imbalance schedules on page 401. The numbers that are shown on paqes
328-330 are for account 456 wheeling on1y, the numbers on page 401 have to be adjusted foraccount 447 transmission.
FERC FORM NO. 1 (ED. 12-871 Page 450.1
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
0411412017
Year/Period of Report
End of 2016/Q4
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 (f) the specified information for each monthly peak load reported in column (d).
NAME OF SYSTEM: IDAHO POWER COMPANY. SYSTEM LOAD
Line
No.Month
(a)
Total Monthly Energy
(b)
Monthly Non-Requirments
Sales for Resale &
Associated Losses
(c)
MONTHLY PEAK
Megawatts (See lnstr. 4)
(d)
Day of Month
(e)
Hour
(0
29 January 1,457,546 183,',t92 2,183 2 1O AM
30 February 't,241,728 142,613 2,110 2 8AM
31 March 1,262,333 180,716 1,856 18 8AM
32 April 1,128,524 52,857 1,983 21 6PM
21 May 1,284,936 47,292 2,251 31 7PM
34 June 1,626,701 6,491 3,299 28 7PM
35 July 't,758,',172 s9,1 35 3,172 30 6PM
36 August 1,69 t ,699 57,739 3,032 2 7PM
37 September 1,248,843 107,061 2,533 1 6PM
38 October 1,148,79t 108,560 1,759 17 8PM
39 November 1 ,171 ,78a 115,460 1,902 30 7PM
40 December 1,542,3',t3 124,762 2,409 19 9AM
41 TOTAL 16,563,370 1,'t 85,878
FERC FORM NO. 1 (ED. 12-q))Page 40lb
Name of Respondent
ldaho Power Company
This(1)
(2)
Reoort ls:
fiAn original
3A Resubmission
Date of Report(Mo, Da, Yr)
04t14t2017
Year/Period of Report
End of 20161Q4
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in
this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. 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 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 bumed (Line 38) and average cost
per unit of fuel bumed (Line 4'l ) must be consistent with charges to expense accounts 50'l and 547 (Line 42) as show on Line 20. 8. lf more than one
fuel is bumed in a plant fumish only the composite heat rate for all fuels bumed.
Line
No.
Item
(a)
Plant
Name: Jim Bridger
(b)
Plant
Name: Boardman
(c)
1 Kind of Plant (lntemal Comb, Gas Turb, Nuclear Steam Steam
2 Type of Constr (Conventional, Outdoor, Boiler, etc)Semi-Outdoor Boiler Conventional
3 Year Originally Constructed
4 Year Last Unit was lnstalled 't979 1980
5 Total lnstalled Cap (Max Gen Name Plate Ratings-Mw)
6 Net Peak Demand on Plant - MW (60 minutes)726 60
7 Plant Hours Connected to Load 878/.3952
8 Net Continuous Plant Capability (Megawatts)0 0
I When Not Limited by Condenser Water
10 When Limited by Condenser Water 0 0
11 Average Number of Employees 0 0
't2 Nel Generation, Exclusive of Plant Use - KWh 3671656000 134253000
13 Cost of Plant: Land and Land Rights 509671 1 0661 0
14 Structures and lmprovements 69929509 12627358
't5 Equipment Costs 616689787 63694825
16 Asset Retirement Costs 9832782 5380764
17 Total Cost 69696't749 81809557
18 Cost per KW of lnstalled Capacity (line 't7l5) lncluding 904.5578 1274.2922
19 Production Expenses: Oper, Supv, & Engr 194683 446094
20 Fuel 122819957 341255',!
21 Coolants and Water (Nuclear Plants Only)0 0
22 Steam Expenses 5396104 687008
23 Steam From Other Sources 0 0
24 Steam Transfened (Cr)0 0
25 Electric Expenses 0 0
26 Misc Steam (or Nuclear) Power Expenses 6168487 790829
27 Rents 206742 0
28 Allowances 0 0
29 Maintenance Supervision and Engineering 26858 73194
30 Maintenance of Structures 0 45008
31 Maintenance of Boiler (or reacto{ Plant 883694S 165264
32 Maintenance of Electric Plant 2332824 1373692
33 Maintenance of Misc Steam (or Nuclear) Plant 6295983 50491
34 Total Production Expenses 152278587 7044131
35 Expenses per Net KWh 0.0415 0.0525
36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)Coal oil Coal oil
37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)Tons Barrels Tons Barrels
38 Quantity (Units) of Fuel Burned 2080695 7181,0 80208 87',l 0
39 Avq Heat Cont - Fuel Burned (btu/indicate if nuclear)9098 't40000 0 8576 "t38800 0
40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 54.148 74.919 0.000 31.383 72.61'l 0.000
41 Average Cost of Fuel per Unit Bumed 58.653 82.O24 0.000 41.595 73.1 16 0.000
42 Average Cost of Fuel Bumed per Million BTU 3.200 13.950 0.000 2.425 12.542 0.000
43 Average Cost of Fuel Bumed per KWh Net Gen 0.033 0.000 0.000 0.02s 0.000 0.000
44 Averaqe BTU per KWh Net Generation 10400.000 0.000 0.000 10285.000 0.000 0.000
FERC FORM NO.1 (REV.12-03)Page 402
Name of Respondent
ldaho Power Company
This Report ls:(1) [An Original
(2)[lA Resubmission
Date ot Report(Mo, Da, Yr)
04t1412017
Year/Period of Report
End of 2016/Q4
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)(Contin ued)
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. 11. Fot a plant equipped with combinations of fossil fuel steam, nuclear
steam, hydro, intemal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined
cycle operation with a conventional steam unit, include the gas-turbine with the steam plant. '12. lf a nuclear power generating plant, briefly explain by
footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units
used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the
report period and other physical and operating characteristics of plant.
Plant
Name: Valmy
(d)
Plant
Name: Dansktn
(e)
Plant
Name: Bennefl Mountain
(0
Line
No.
Steam Gas Turbine Gas Turbine 1
Outdoor Conventional Conventional 2
2001 2005 3
1985 2008 200s 4
270.90 172.80 5
262 292 190 6
4878 1208 662 7
0 261 164 I
0 0 I
0 0 0 't0
0 7 5 11
239264000 I 981 02000 103240000 12
1't06140 402745 0 13
69004095 6049223 1688442 14
3331 18561 I 00471 959 520501 51 15
98338 0 0 16
403327134 106923927 53738593 17
1422.6707 394.6989 3',10.9872 18
518084 165577 4108 19
't1456244 8436529 36't0656 20
0 0 0 2',1
2888080 0 0 22
0 0 0 23
0 0 0 24
1466072 358307 371728 25
2',t37930 275907 1 16703 26
0 0 0 27
0 0 0 28
50 0 0 29
4831 1 3 201461 102460 30
5261',t32 9520 15798 31
1444059 2776',t6 211424 32
88874 0 0 33
2s743638 9724917 4432877 34
0.1 076 0.0491 0.0429 35
Coal oir Gas Gas 36
Tons Barrels MCF MCF 37
120330 7480 0 2050748 0 0 1072868 0 0 38
9945 138778 0 1027 0 0 1027 0 0 39
0.000 64.976 0.000 4.114 0.000 0.000 3.365 0.000 0.000 40
90.993 65.204 0.000 4.1'.t4 0.000 0.000 3.365 0.000 0.000 41
4.575 11.187 0.000 3.7't0 0.000 0.000 2.990 0.000 0.000 42
0.048 0.000 0.000 0.043 0.000 0.000 0.035 0.000 0.000 43
10185.000 0.000 0.000 't0631.000 0.000 0.000 't0673.000 0.000 0.000 44
FERC FORM NO. I (REV. 12-03)Page 403
Name of Respondent
ldaho Power Company
This(1)
(2)
Report ls:
IAn Original
|_lA Resubmission
Date of Report(Mo, Da, Yr)
0411412017
Year/Period of Report
End of 201610.4
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
1. Report data for plant in Service only. 2. Latge plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in
this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. lndicate by a footnote any plant leased or operated
as a joint facility. 4. lt 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 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 bumed (Line 38) and average cost
per unit offuel bumed (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 bumed.
Line
No
Item
(a)
Plant
Name: Langley Gulch
(b)
Plant
Name
(c)
1 Kind of Plant (lnternal Comb, Gas Turb, Nuclear Gas Turbine
2 Type of Constr (Conventional, Outdoor, Boiler, etc)Conventional
3 Year Originally Constructed 20't2
4 Year Last Unit was lnstalled 2012
5 Total lnstalled Cap (Max Gen Name Plate Ratings-Mw)318.45 0.00
6 Net Peak Demand on Plant - MW (60 minutes)304 0
7 Plant Hours Connected to Load s443 0
8 Net Continuous Plant Capability (Megawatts)300 0
I When Not Limited by Condenser Water 0 0
10 When Limited by Condenser Water 0 0
11 Average Number of Employees 23 0
12 Net Generation, Exclusive of Plant Use - KWh 1420178000 0
13 Cost of Plant: Land and Land Rights 2287261 0
14 Structures and I mprovements 1 3541 8367 0
15 Equipment Costs 250825980 0
'16 Asset Retirement Costs 0 0
17 Total Cost 388531608 0
18 Cost per KW of lnstalled Capacity (line 17l5) lncluding 1220.07',to 0
19 Production Expenses: Oper, Supv, & Engr 432090 0
20 Fuel 29750594 0
21 Coolants and Water (Nuclear Plants Only)0 0
22 Steam Expenses 0 0
23 Steam From Other Sources 0 0
24 Steam Transfened (Cr)0 0
25 Electric Expenses 3424534 0
26 Misc Steam (or Nuclear) Power Expenses 306858 0
27 Rents 0 0
28 Allowances 0 0
29 Maintenance Supervision and Engineering 0 0
30 Maintenance of Structures 96896 0
31 Maintenance of Boiler (or reactor) Plant 56641 0
32 Maintenance of Electric Plant 2275652 0
33 Maintenance of Misc Steam (or Nuclear) Plant 0 0
34 Total Production Expenses 36343265 0
35 Expenses per Net KWh 0.0256 0.0000
36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)Gas
37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)MCF
38 Quantity (Units) of Fuel Bumed 9708637 0 0 0 0 0
39 Avq Heat Cont - Fuel Burned (btu/indicate if nuclear)1027 0 0 0 0 0
40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 3.064 0.000 0.000 0.000 0.000 0.000
4'l Average Cost of Fuel per Unit Bumed 3.064 0.000 0.000 0.000 0.000 0.000
42 Average Cost of Fuel Bumed per Million BTU 2.810 0.000 0.000 0.000 0.000 0.000
43 Average Cost of Fuel Bumed per KWh Net Gen o.021 0.000 0.000 0.000 0.000 0.000
44 Averaqe BTU per KWh Net Generation 7021.000 0.000 0.000 0.000 0.000 0.000
FERC FORM NO. 1 (REV.12-03)Page 1102.1
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t14t2017
Year/Period of Report
20161Q4
FOOTNOTE DATA
Schedule Page:402 Line No.:3 Column: bThls footnote applies to lines 3 and 4. The Jim Bridger PowerPfant consists of four equal units constructed lorntly 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, 1914, Unit #2 December 1, 7915,Unit #3 September 1, 19'76, and Uni-t #4 November 29, L9]9.
Schedule Page:402 Line No.:3 Column: cThis ftotnote appfles to l-ines 3 and 4. The Boardman p1anCconsists of one unlt constructed jointly by Portland General-Electric Company, ldaho Power Company, and Pacific Northwest
Generatj-ng Company, with Idaho Power Company owning 1O%. The
uni-t was pJ-aced in commercial operqtlon August 3, 1980.
Schedule Page:403 Line Alo.; ! Column: dThls footnote applies to lines 3 and 4. The Valmy plant consistsof two units constructed jointly by Sj-erra Pacific Power Company
and ldaho Power Company, with Sierra owning l/2 and Idaho ownlngL/2. Unit #1 was ptaced in commercj-al operation December 11, 1981
and Un:-t #2 May 27 , 198 5 .
Schedule Page:402 Line No.: 5 Column: bThis footntte appfles to llne 5 and fines 12 through 43.
Information reflects Idaho Power Company's share as explainedin note for line 3 page 402 column B.
Schedule Page:402 Line No.: 5 Column: cThis footnote applies to line 5 and lines 12 through 43.Information reflects Idaho Power Company's share as explainedin note on .Iine 3 page 402 cofumn C
Schedute Page:403 Line No.: 5 eotumn: dThis footnote appJ-1es to line 5 and lines 12 through 43.
Information ref-l-ects Idaho Power Company's share as explainedin note for l-ine 3 page 403 column D.
Scheduie Page:402 line No.:9 Column: bThis footnote applies to l-ines 9, 10, and 11. PacifiCorp
as operator of the plant will report thj-sinformation.
Schedule Page: lO2 Line No.:9 Column: cThis footnote applies to 1j-nes 9, 10, and 11. Portl-and GeneralElectri-c Company, as operator will report this information.
Schedule Pige:403 t ine No.:9 Column: dThis footnote ippfies to 1ines 9, 10, and 11. Sierra PacificPower, as operator of the p1ant, wilI report this information.
FERC FORM NO. 1 (ED. 12-871 Page 450.1
Name of Respondent
ldaho Power Company
This Report ls:(1) [An Original
(2)f-|A Resubmission
Date of Report
(Mo, Da, Yr)
o411412017
Year/Period of Report
End of 2O16lQ4
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. ll any plant is leased, opemted 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 aftends more than one generating plant, report on line 'l'l the approximate average number of employees assignable to each
plant.
Line
No.
Item
(a)
FERC Licensed Project No. 2736
Plant Name: American Falls
(b)
FERC Licensed Project No. 1975
Plant Name: Bliss
(c)
1 Kind of Plant (Run-of-River or Storage)Run-of-River
2 Plant Construction type (Conventional or Outdoor)Outdool Outdoor
3 Year Originally Constructed 1978 1949
4 Year Last Unit was lnstalled 1978 1950
5 Total installed cap (Gen name plate Rating in MW)92.30 75.00
o Net Peak Demand on Plant-Megawatts (60 minutes)101 50
7 Plant Hours Connect to Load 4,991 8,760
I Net Plant Capability (in megawatts)
I (a) Under Most Favorable Oper Conditions 110 76
10 (b) Under the Most Adverse Oper Conditions 0 1
'11 Average Number of Employees 4 4
12 Net Generation, Exclusive of Plant Use - Kwh 243,379,000 287,612,000
13 Cost of Plant
't4 Land and Land Rights 875,318 768,366
15 Structures and lmprovements 1 1,970,406 1,204,436
16 Reservoirs, Dams, and Waterways 4,293,O75 9,264,107
17 Equipment Costs 32,352,657 9,851,554
't8 Roads, Railroads, and Bridges 839,276 486,477
't9 Asset Retirement Costs 0 0
20 TOTAL cost (Total of 14 thru 19)50,330,732 21,574,940
21 Cost per KW of lnstalled Capacity (line 20 / 5)545.2950 287.6659
22 Production Expenses
23 Operation Supervision and Engineering 231,008 711,269
24 Water for Power 1,63s,039 483,334
25 Hydraulic Expenses 't57,440 823,619
26 Electric Expenses 45,475 64,113
27 Misc Hydraulic Power Generation Expenses 340,392 439,728
28 Rents 183 4,496
29 Maintenance Supervision and Engineering 10,010 9,126
30 Maintenance of Structures 152,678 27,',t08
31 Maintenance of Reservoirs, Dams, and Waterways 't2,06'l 114,324
32 Maintenance of Electric Plant 323,002 212,224
33 Maintenance of Misc Hydraulic Plant 79,880 163,801
34 Total Production Expenses (total 23 thru 33)2,987,'174 3,053,142
35 Expenses per net KWh 0.0123 0.0106
FERC FORM NO.1 (REV.12-03)Page 406
Respondent
ldaho Power Company )An Original
A Resubmission
(Mo, Da,
(2)04t14t2017
Year/Period of Report
End of 20161Q4
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. 1971
Plant Name: Brownlee
(d)
FERC Licensed Prcject No. 2848
Plant Name: Cascade
(e)
FERC Licensed Project No.
Plant Name: Oxbow (fl
't971 Line
No.
Storage 1
Outdoor Outdoor Outdoor 2
1958 1983 1961 3
1980 1984 1961 4
s85.40 't2.42 190.00 5
527 14 209 6
8,760 8,742 8,760 7
I
747 15 221 I
220 ,|202 10
I 2 6 11
2,013,477,000 42,248,000 900,918,000 12
13
18,252,564 82,142 1,2',t2,767 14
33,065,915 7,328,252 11,245,847 15
67,618,609 3,145,630 30,502,861 16
81,231,487 13,090,143 20,01s,998 17
5',t8,4114 't22,668 585,876 18
0 0 0 19
200,687,019 23,768,835 63,563,349 20
u2.8203 1,913.7548 334_5439 21
22
761,656 217,394 503,635 23
27',t,359 104,837 169,876 24
1,027,992 356,152 663,155 25
33s,263 120,211 252j90 26
824,783 287,7',12 543,434 27
1'.t3,644 62 18,633 28
19,067 3,508 14,964 29
127,024 13,644 251,906 30
16,243 -10 16,802 31
281,651 61,939 't29,815 32
485,943 91,999 308,498 33
4,264,625 1,257,448 2,872,908 34
0.0021 0.0298 0.0032 35
FERC FORM NO. r (REV. 12-03)Page 407
Name of Respondent
ldaho Power Company
This
(1)
(2)
Report ls:
IAn Original
|-lA Resubmission
Date of Report
(Mo, Da, Yr)
o4t't412017
Year/Period of Report
End of 201'O|A4
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.
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
plant.
Line
No.
Item
(a)
FERC Licensed Project No. '197'l
Plant Name: Hells Canyon
(b)
FERC Licensed Project No. 2726
Plant Name: Malad
(c)
,|Kind of Plant (Run-of-River or Storage)
2 Plant Construction type (Conventional or Outdoor)Outdoor Outdoor
3 Year Originally Constructed 1967 1948
4 Year Last Unit was lnstalled 1967 1948
5 Total installed cap (Gen name plate Rating in MW)391.50 21.77
6 Net Peak Demand on Plant-Megawatts (60 minutes)426 24
7 Plant Hours Connect to Load 8,760 8,659
I Net Plant Capability (in megawatts)
I (a) Under Most Favorable Oper Conditions 445 25
10 (b) Under the Most Adverse Oper Conditions 137 21
11 Average Number of Employees 6 1
12 Net Generation, Exclusive of Plant Use - Kwh 1,792,718,OOO 1 16,384,000
13 Cost of Plant
14 Land and Land Rights 1,880,381 205,376
15 Structures and lmprovements 2,795,004 3,886,385
16 Reservoirs, Dams, and Watenvays 53,033,657 6,283,406
't7 Equipment Costs 19,945,556 15,331,362
18 Roads, Railroads, and Bridges 922,781 1,507,442
19 Asset Retirement Costs 0 0
20 TOTAL cost (Total of '14 thru 19)78,577,379 27,213,971
21 Cost per KW of lnstalled Capacity (line 20 / 5)200.7085 'r,2s0.0676
22 Production Expenses
23 Operation Supervision and Engineering 430,489 166,977
24 Water for Power 162,406 7',t7,775
25 Hydraulic Expenses 631,815 205,O27
26 Electric Expenses 229,330 28,600
27 Misc Hydraulic Power Generation Expenses 516,26't 'r66,478
28 Rents 30,994 0
29 Maintenance Supervision and Engineering 12,495 7A%
30 Maintenance of Structures 22,636 26,120
31 Maintenance of Reservoirs, Dams, and Watenvays 't 59,047 't 36,'t48
32 Maintenance of Electric Plant 9',1,522 206,236
33 Maintenance of Misc Hydraulic Plant 361,299 56,510
34 Total Production Expenses (total 23 thru 33)2,648,294 1,717,367
35 Expenses per net KWh 0.001s 0.0148
FERC FORM NO.1 (REV.12-03)Page t106.1
Name of Respondent
ldaho Power Company
This(1)
(2)
Report ls:
[]An Original
nA Resubmission
Date of Report(Mo, Da, Yr)
04t',!4t2017
Year/Period of Report
End of 2016/Q4
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6. Report as a separate plant any plant equipped with combinations of steam, hydro, intemal combustion engine, or gas turbine equipment.
FERC Licensed Project No. 2055
PlantName: CJStrike(d)
FERC Licensed Project No. 503
Plant Name: Swan Falls
(e)
FERC Licensed Project No.
Plant Name: Twin Falls(fl
18 Line
No.
Run-of-River Run-of-River Run-of-River 1
Outdoor Conventional Conventional 2
1952 1910 1935 3
1952 1994 1995 4
82.80 25.00 52.74 5
84 19 38 6
8,756 8,730 5,968 7
I
91 24 53 I
84 14 50 10
5 4 3 11
376,793,000 112,684,000 39,,t49,000 12
13
5,711,701 231,584 255,499 14
9,806,855 27,388,566 1 1 ,108,328 15
1',t,276,408 15,989,465 9,069,862 16
14,060,693 31,563,288 21,327,698 17
1,602,868 835,946 1,917,603 't8
0 0 0 19
42,458,525 76,008,849 43,678,990 20
512.7841,3,040.3540 828.1947 21
22
856,216 506,602 220,174 23
381,008 235,465 99,437 24
1,093,411 661.799 198,860 25
52,239 32,394 78,058 26
680,252 497,063 219,150 27
49,273 7,841 3,261 28
6,825 7,226 4,981 29
77,984 83,133 57,802 30
71,008 't2,905 29,O75 31
139,631 185,902 113,846 32
98,400 't27,805 81,705 33
3,506,247 2,358,135 1,106,349 34
0.0093 0.0209 0.0280 35
FERC FORM NO. 1 (REV. 12-03)Page 407.1
Name of Respondent
ldaho Power Company
This(1)
(2)
Reoort ls:
fiRn Originat
[-lA Resubmission
Date of Report(Mo, Da, Yr)
0411412017
Year/Period of Report
End of 20161Q4
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. ll 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.
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
plant.
Line
No.
Item
(a)
FERC Licensed Project No. 2777
Plant Name: Upper Salmon
(b)
FERC Licensed Poect No. 2778
Plant Name: Shoshone Falls
(c)
1 Kind of Plant (Runof-River or Storage)Run-of-River Run-of-River
2 Plant Construction type (Conventional or Outdoor)Outdoor Conventional
3 Year Originally Constructed 1937 1907
4 Year Last Unil was lnstalled 1947 't921
5 Total installed cap (Gen name plate Rating in MW)34.50 12.50
6 Net Peak Demand on Plant-Megawatts (60 minutes)35 13
7 Plant Hours Connect to Load 8,753 6,730
8 Net Plant Capability (in megawatts)
9 (a) Under Most Favorable Oper Conditions 39 14
10 (b) Under the Most Adverse Oper Conditions 32 1',l
11 Average Number of Employees 3 2
12 Net Generation, Exclusive of Plant Use - Kwh 176,762,000 54,752,000
13 Cost of Plant
't4 Land and Land Rights 202,399 313,328
15 Structures and lmprovements 2,4s6,980 1,253,635
16 Reservoirs, Dams, and Watenrvays 6,181,301 10,097,561
17 Equipment Costs 8,930,990 4,815,784
18 Roads, Railroads, and Bridges 29,359 51,383
19 Asset Retirement Costs 0 0
20 TOTAL cost (Total of 14 thru 19)17,801,029 16.53't,691
21 Cost per KW of lnstalled Capacity (line 20 / 5)s15.9719 1,322.5353
22 Production Expenses
23 Operation Supervision and Engineering 297,67'.1 167.994
24 Water for Power 132,433 73,325
25 Hydraulic Expenses 356,912 1 10,579
26 Electric Expenses 152,070 33,636
27 Misc Hydraulic Power Generation Expenses 252,672 209,089
28 Rents 0 87
29 Maintenance Supervision and Engineering 5,355 2.721
30 Maintenance of Structures 69,785 25,947
31 Maintenance of Reservoirs, Dams, and Waterways 55,'168 785
32 Maintenance of Electric Plant 69,086 56,964
33 Maintenance of Misc Hydraulic Plant 109,603 70,614
34 Total Production Expenses (total 23 thru 33)1,500,755 751,741
35 Expenses per net KWh 0.0085 0.0't37
FERC FORM NO.1 (REV.12-03)Page 406.2
Name of Respondent
ldaho Power Company
This(1)
(2)
Report ls:
IAn Original
EA Resubmission
Date of ReDort(Mo, Oa, Yi)
04t14t2017
Year/Period of Report
End of 20'l6lQ4
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. '1971
Plant Name: Common Facilities
(d)
FERC Licensed Project No. 2061
Plant Name: Lower Salmon
(e)
FERC Licensed Poect No. 2899
Plant Name: Milner
(f)
Line
No.
Run-of-Rivel Run-of-River 1
Outdoor Conventional 2
1949 1992 3
1949 't992 4
0.00 60.00 59.45 5
0 36 44 b
0 8,760 2,763 7
8
0 64 61 I
0 60 ,|'t0
0 5 2 1',l
0 190,509,000 27,473,000 12
13
1 14,368 424,428 138,100 14
41,383,976 2,869,695 't0,704,939 15
13,556,785 6,962,069 '17,u7,178 16
2,354,402 17,635,166 29,363,867 17
107,82 88,693 501,877 18
0 0 0 19
57,517 ,013 27,980,051 58,555,961 20
0.0000 466.3342 984.961s 21
22
0 3'.t5,441 190,615 23
0 149,610 1,370,918 24
7,688,417 456,008 130,597 25
0 118,062 40,445 26
0 363,699 252,646 27
0 3,172 3,711 28
0 7,500 4,025 29
0 17',t,514 4s,733 30
0 7,337 23,662 31
0 169,'t55 92,989 32
100,912 77,289 65,819 33
7,789,329 1,838,787 2,221,',t60 34
0.0000 0.0097 0.0808 35
FERC FORtt'l NO. 1 (REV. 12-03)Page 107.2
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)
041't4t2017
Year/Period of Report
20161Q4
FOOTNOTE DATA
106 Line No.:1 Column: b
Amer can Fal-ls generat ng capa
USBR.
endent upon water releases controlled by the
1 Column: eyisendent upon water rel-eases controlled by the USBR.
,Schedule Page:406 Line No.:
Cascade generating capacit
lschedule Page:406 Line No.:1 Column: f
Upstream storage in Brownlee Reservoir
€gnedule Page:106.1 Un l Column: b
Upstream storage in Brown.l-ee Reservoir
Sclredule 406.1 Line No.:7 Column: c
Lower Malad ma demand 15,000 Kw, Upper Mal-ad demand 9,000 Kw non-coincident.
FERC FORM NO. I (ED. 12-871 Page 450.1
Name
ldaho Power Company
(1)
(2)
An Original
A Resubmission
Date of Repod(Mo, Da, Yr)
0411412017
Year/Period of Report
End of 20161Q4
'1. Small generating plants are steam plants ol less than 25,000 Kw; intemal combustion and gas turbine-plants, conventional hydro plants and pumped
storage plants of less than 10,000 Kw installed capacity (name plate rating). 2. Designate any plant leased from others, operated under a license from
the Federal Energy Regulatory Commission, or operated as a joint facility, and give a concise statement of the facts in a footnote. lf licensed project,
give project number in footnote.
Line
No.
Name of Plant
(a)
Year
Orio.
ConEt.
(b)
rnslafleo uapaclty
Name Plate Ratinl
(ln MW)
(c)
Net Generation
ExcludinoPlant UsE
(e)
Cost of Plant
(f)
1 Hydro:
2 Clear Lakes 1937 2.50 ao 16,538 3,529,671
3 Thousand Springs 't912 8.80 6.6 16,303 9,843,459
4
5
6 lntemal Combustion:
7 't967 5.00 3.6 2C 909,259
8
9
10
11
12
13
14
15
16
'17
18
19
20
21
22
23
24
25
26
27
28
29
30
3'l
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO. 1 (REV. 12-03)Page tl10
Name of
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
04t1412017
Year/Period of Report
End of 2016/Q4
GEN PLANT STA
3. List plants appropriately under subheadings for steam, hydro, nuclear, intemal 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, specifying 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, orfor preheated combustion air in a boiler, report as one plant.
Plant Cost (lncl Asset
Retire. Costs) Per MW
(s)
Operation
Exc'|. Fuel
(h)
Frooucuon Expenses
Kind of Fuel
(k)
Fuel Costs (in cents
(per Million Btu)
fl)
Line
No.Fuel
(i)
Matntenance
fi)
1
1,41 1,868 't82,242 97,034 2
1,1't8,575 282,6',t5 102,U3 3
4
5
6
18 1 ,852 Diesel 7
I
I
10
't1
12
't3
'14
15
16
17
18
19
20
2',!
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
4',!
42
43
44
45
46
FERC FORM NO. 1 (REV. 12.03)Page 411
Name of Respondent
ldaho Power Comoanv
This Report is:
(1) X An Originalel A Resubmission
Date of Report
(Mo, Da, Yr)
04114t2017
Year/Period of Report
20't6tQ4
FOOTNOTE DATA
Schedule Page:410 Line No.:7 Column: a
Salmon units are c.l-assified as standby.
FERC FORM NO. 1 (ED. 12-871 Page 450.1
Name of Respondent
ldaho Power Company
This Report ls:(1) [An Original(2) flA Resubmission
Date of Report(Mo, Da, Yr)
04114t2017
Year/Period of Report
End of 20161Q4
TRANSMISSION LI NE STATISTICS
1. Reportinformationconcerningtransmissionlines,costoflines,andexpensesforyear. Listeachtransmissionlinehavingnominal voltageof 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 1 21 , 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. Reportincolumns(f)and(g)thetotal polemilesofeachtransmissionline. Showincolumn(f) thepolemilesoflineonstructuresthecostofwhichis
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 forthe line designated.
Line
No.
UtsSIGNA I IUN VUL I AUE (KV)(lndicate where'bther than
60 cvcle. 3 ohase)
Type of
Supporting
Structure
(e)
LENG IH (POIE MIIES(ln the tase.ofunderoround linesreport Eircuit miles)
)Number
of
Circuits
(h)
From
(a)
To
(b)
Operating
(c)
Designed
(d)
un Slructureof LineDesionated
fo
UN SITUCIUTESof AnotherLine(s)
1 Borah Midpoint 345.0(500 00 S Tower 62.35 1
2 Boardman Slat 500 0(500.00 S Tower 179 1
3 Summer lake 500 0(500.00 S Tower 0.08 1
4 Heminqway Midpoid 500.0(500.00 S Tower 0.15 I
5 Summer Lake Hemimmay .500.0(500.00 S Tower 53.09 1
o Hemingway Midtoint '".'500.0(s00.00 S Tower 47.83 1
7
I Jim Bridger Goshen .. : .t:,345.0(345 00 S Tower 66.13 1
I State Line Midpoint 345 0(345.00 S Tower 76.06 I
'10 Kinport Borah 345.0(345.00 S Tower 19.84 1
11 Jim Bridger Pooq'k s ',- 'l 345 0(345 00 S Tower 61.28 1
12 Populus Kinpod 345 0(345.00 S Tower 742 1
13 Jim Bridger Populu!345.0(345.00 S Tower 61 42 1
14 Populus Borah 345.0(345.00 S Tower 9.05 1
15 Goshen Kinport 345.0(345.00 S Tower 749 1
16 Midpoint 345.0(345.00 H Wood 51 07 1
'17 Midpoint Borah #2 345.0(345.00 H Wood 50.01 2
18 Adelaide Tap Adelaide 345.0(345.00 H Wood 1.72 I
19
20 Quartz LaGrande 230 0(230 00 H Wood 46.26 1
21 Midpoint Hunt 230.0(230.00 S Tower 0.70 2
22 Brady Antelope 230.0(230.00 H Wood 56.41 1
23 Brady Treasureton 230 0(230 00 H Wood 0.11 1
24 B,ady#1 &#2 Kinport 230 0(230 00 S Tower 17 94 2
25 Brownlee Ontario 230.0(230.00 S Tower 74.8C 1
26 Mora Bowmont 138.0(230 00 S P Wood 10.0i 1
27 Mora Bowmont 138 0(230 00 H Wood 8.75 I
28 Caldwell 710 Locust 230.0(230 00 SP Steel 18.6C 1
29 Boise Bench Caldwell 230.0(230.00 S Tower 7.72 I
30 Boise Bench Caldwell 230 0(230.00 H Wood $.4e 1
31 Boise Bench Cloverdale 230.0(230.00 S Tower 15.78 2
32 Boardman Sub 230 0(230 00 H Wood 1.6i 1
33 Brownlee 714 Oxbow 230.0(230.00 SP Steel 1 1.0{2
34 Caldwell Ontario 230.0(230.00 H Wood 30.1C ,l
35 Caldwell Ontario 230.0(230.00 S Tower 3.14 1
36 TOTAL 4,861.24 11.02 203
FERC FORM NO. 1 (ED. 12-87)Page 422
Name of ls:
ldaho Power Company
(1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
o411412017
Year/Period of Report
End of 20161Q4
I |{ANSM|SS|9N LINE S lA I lS I ICS (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 thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses bome by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures @lled for in columns (j) to (l) on the book cost at end of year.
Size of
Conductor
and Material
(i)
cosT oF LINE (lnclucle in column u) Land,
Land rights, and clearing rightof-way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES
Line
No.
Land
(i)
Construction and
Other Costs(k)
Total Cost
(t)
Operation
Expenses(m)
Maintenance
Expenses(n)
Rents
(o)
Total
Expenses(p)
t272 ACSR 256,38',15,978,03(16,234,411 1
1x1780 ACSR 446,70t 446,708 2
t272 ACSR 1,827,66t 1,827,665 1
t272 ACSR 4
}x1272 ACSR 17 ,991,88i 17,991,882 5
}xl272 ACSR 16,314,41(16,314,416 6
7
| 272 ACSR 483,30(5,295,24(5,778,549 I
I95 ACSR 571,97(1 1,108,161 1 1,680,14C I
I 272 ACSR 344,22(4,396,92t 4,741,148 10
I 272 ACSR 9,526,47i 9,526,473 11
I 272 ACSR 12
I 272 ACSR 9,253,81i 9,253,816 '13
I272 ACSR 14
2X,I272 ACSR 583,94i 583,94i 15
715.5 ACSR 283,141 8,600,241 8,883,384 '16
715.5 ACSR 64,851 13,423,35€13,488,20S 17
/15,5 ACSR 51,44t 224,244 275,697 18
19
/95 ACSR 62,21t 7,067,37!7,129,593 20
/15.5 ACSR 9,'14{998,45i 1,007,597 21
r272 ACSR 108,301 3,399,1 2:3,507,424 22
/95 ACSR 6,18€6,186 23
/,I5.5 ACSR 1 8,82{1,091,655 1 ,'l 10,484 24
2X954 ACSR 1,676,83t 20,541,791 22,218,628 25
715.5 ACSR 413,79i 2,209,978 2,623,772 26
715.5 ACSR 27
t590 ACSR 2,376,93(8,775,08€11,152,022 28
r272 ACSR 1,748,211 7,619,965 9,368,1 79 29
715.5 ACSR 30
t272 ACSR 3,062,81i 6,576,67a 9,639,487 31
/95 AAC 89,08!89,08S 32
354 ACSR 34,171 16,026,47C 16,060,644 33
2X954 ACSR 236,15i 9,386,097 9,622,249 34
1272 ACSR 35
33,098,328 592,880,317 625,978,645 6,975,99e 1 ,302,61:4,1 39,757 12,418,36(36
FERC FORM NO. 1 (ED. 12-87)Page 423
Name of Respondent
ldaho Power Company
Thi(1)
(2)
s Report ls:
IAn Original
[lA Resubmission
Date of Report(Mo, Da, Yr)
o411412017
Year/Period of Report
End of 2016/Q4
I RANSMISSION LINL S IA I IS I ICt'
'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 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 forwhich 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 (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 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.
Line
No.
UESIUNAIIUN VULIAL'E (AV)(lndicate wherebther than
60 cvcle. 3 ohase)
Type of
Supporting
Structure
(e)
LENGIH (POIE MIIES)(ln the tase.ofunderoround linesreport Eircuit miles)
Number
of
Circuits
(h)
From
(a)
To
(b)
Operating
(c)
Designed
(d)
un Slruclureof LineDesionatedf)
un Sructuresof AnotherLine(s)
1 Bennett Mtn PP Rattlesnake TS 230.0(230.00 SP Steel 4.43 1
2 Borah Hunt 230.0(230.00 H Steel 68.18 1
3 Danskin Hubbard 230.0(230.00 H Steel 36.2!I
4 Danskin Hubbard 230.0(230.00 SP Steel 1.4 I
5 Danskin Hubbard 230.0(230.00 SP Steel 1.3(2
b Danskin Bennett Mtn 230.0(230.00 SP Steel 5.3!1
7 Heminqway Bowmont 230.0(230.00 SP Steel 13.0i 1
I Langley Gulch Galloway Rd '138.0(230.00 SP Steel 14.1!1
o Galloway Rd Willis Tap '138.0(230.00 SP Steel 2.09 1
10 Walla Walla 230.0(230.00 H Wood 31.6€1
11 Boise Bench Midpoint #1 230.0(230.00 S Tower 0.87 1
12 Boise Bench Midpoint #1 230.0(230.00 H Wood 108.68 1
13 Brownlee QuarE Jct 230.0(230.00 S Tower 1.51 1
14 Brownlee QuarE Jct 230.0(230.00 H Wood 41 3C 1
15 Brownlee Boise Bench #1 &#2 230.0(230.00 S Tower 99.7€2
16 Oxbow Brownlee 230.0(230.00 S Tower 10.4C 2
17 Boise Bench Midpoint #2 230.0(230.00 S Tower 3.4!I
18 Boise Bench Midpoint #2 230.0(230.00 H Wood 102.17 I
19 Oxbow Pallette Jct 230.0(230.00 S Tower 20.11 2
20 Pallette Jct lmnaha 230.0(230.00 H Wood 24.43 2
2',!Hells Canyon Palette Jct 230.0(230.00 S Tower 9.05 2
22 Brownlee Boise Bench 230.0(230.00 S Tower 102.55 2
23 Boise Bench Midpoint #3 230.0(230.00 H Wood 106.2S 1
24 Palette Jct Enterprise 230.0(230.00 H Wood 29.6C 1
25 Borah Bndv #2 230.0(230.00 S Tower 0.46 1
26 Borah Brady #2 230.0(230.00 H Wood 3.s2 1
27 Borah Brady #1 230.0(230.00 H Wood 3.8i 1
28
29 Goshen 161.0(161.00 H Wood 40.93 1
30 Don Goshen 161.0(161.00 S Tower 237 2
31 Don Goshen 161.0(161.00 H Wood 48.42 2
32 Antelope 161.0(161.00 H Woorl 5.67 1
33 Goshen 161.0(161 .00 H Wood 10.94 1
34 Goshen 161.0(161.00 H Wood 7.87
35
36 IOIAL 4,861.24 11.02 203
FERC FORrr' NO. 1 (EO. 12-87)Page 122.1
Name of Respondent
ldaho Power Company
This(1)
(2)
Report ls:
[|An Original
1A Resubmission
Date of Report(Mo, Da, Yr)
0411412017
Year/Period ot Report
End of 2016/Q4
I RANSMISSION LINE SIATISTICS (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 thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, fumish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses bome by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
Size of
Conductor
and Material
(i)
uus r uF LINE (rncruoe rn uorumn u, Lano,
Land rights, and clearing right-of-way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES
Line
No.
Land
o
Construction and
Other Costs(k)
Total Cost
(t)
Operation
Expenses(m)
Maintenance
Expenses
(n)
Rents
(o)
Total
Exo,e;ses
t272 ACSR 81,70','1,666,35,4 1,748,055 1
1590 ACSR 624,91i 22,467,321 23,092,238,2
t590 ACSR 15,210,561 15,210,s61 3
1590 ACSR 4
r 590 ACSR 5
| 590 ACSR 3,528,03:3,528,033 6
1 590 ACSR 1,854,99(9,277,98(1 1,132,976 7
I59O ACSR 948,'16(9,080,89(10,029,056 I
1272 ACSR I
t272 ACSR 6,255,53€6,255,536 10
/15.5 ACSR 385,28;11,685,424 12,070,711 11
715.5 ACSR 12
/95 ACSR 53,06t 4,881,772 4,934,840 13
/95 ACSR 14
/ARIOUS 289,93,4 8,966,98i 9,256,92'l 15
1272 ACSR 14,81t 1,237,524 1,252,334 16
/15.5 ACSR 227,824 17,008,591 17,236,416 17
/ARIOUS 18
1272 ACSR 87,46r 3,902,140 3,989,608 19
1272 ACSR 171,08'1,673,662 1,844,74i 20
I 272 ACSR 44,68;1,252,134 1,296,81i 21
]54 ACSR 184,81;6,257,154 6,441,971 22
I,I5.5 ACSR 247,851 8,064,231 8,312,08t 23
t272 ACSR 84,01'1,903,192 1,987,20t 24
t272 ACSR 3,06{531 ,1 06 534,174 25
I,I5.5 ACSR 26
I272 ACSR 7,241 421,27i 428,521 27
28
15O COPPER 565,31 3,524,16t 4,089,47r 29
r15.5 ACSR 88,20r 2,654,351 2,742,55t 30
197.5 ACSR 3'r
)97.5 ACSR 784,65(784,65!32
I5O COPPER 203,53,{203,534 33
I5O COPPER 135,69(I 35,69C 34
35
33,098,328 592,880,31 7 625,978,645 6,975,99!1 ,302,613 4j35,757 12,418,36(36
FERC FORM NO. 1 (ED. 12.87)Page 123.'l
Name of Respondent
ldaho Power Company
This(1)
(2)
Reoort ls:
5]nn orlsinat
nA Resubmission
Date of Report(Mo, Da, Yr)
0411412017
Year/Period of Report
End of 20161Q4
I RANSMISSION LINE SIAIIS I ICS
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 forwhich plant costs are included in Account't21, 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.
Line
No.
utssit(,NAltuN VULIAUE IKVI(lndicate wtierebther than
60 cvcle. 3 ohase)
Type of
Supporting
Structure
(e)
LTNGIH (Pole miles)(ln the tase.ofunderoround linesreport Eircuit miles)
Number
of
Circuits
(h)
From
(a)
To
(b)
Operating
(c)
Designed
(d)
L,'N JITUCIUTEof LineDesionatedf)
un Sructuresof AnotherLine
(s)
1 American Falls Power Plant Adelaide 138.0(138.00 H Wood 15.72 2
2 American Falls Power Plant Adelaide 138.0(138.00 S P Wood 0.12 I
3 Minidoka Loop Adelaide 138.0(138.00 S Tower 1.14 2
4 Nampa Caldwell 138.0('138.00 S P Wood 10.0€2
5 Upper Salmon Mountain Home Jct 138,0(138.00 H Wood 54.4€I
6 Upper Salmon ctiff 138.0(138.00 H Wood 30.81 1
7 Eastgate Russet 138.0(138.00 S P Wood 2.06 1
I Brady Fremont 138.0(138.00 S Tower 1.04 I
9 Brady Fremont 138.0('138.00 H Wood 24.38 2
10 Brady Fremont 138.0(138.00 S P Wood 24.33 2
1',1 King Lower Malad r38.0('138.00 H Wood 84.74 2
12 Emmett Jct Payette 138.0(138.00 H Wood 66.4!2
13 Mountain Home AFB Tap 138.0(138.00 H Wood 6.2C 1
14 Ontario QuarE 138.0(138.00 H Wood 73.4C I
15 King American Falls PP 138.0('138.00 S Tower 0.93 2
't6 King American Falls PP 138.0(138.00 H Wood 142.41 1
't7 King American Falls PP 138.0('t38.00 S P Wood 3.71 1
18 Duffin Clawson 138.0(138.00 H Wood 6.23 I
19 American Falls Brady Tie 138.0(138.00 H Wood 0.33 1
20 Upper Salmon A-B King 138.0(138.00 H Wood 5,6€1
21 Upper Salmon B Wells 138.0(138.00 H Wood 125.56 I
22 King Wood River 138.0(138.00 H Wood 64.1 3 I
23 Toponis Pocket 138.0(138.00 S P Wood 9.8C 1
24 Boise Bench Grove 138.0(138.00 S P Wood 10.3S 2
25 Quartz John Day 138.0(138.00 H Wood 67.32 1
26 Sinker Creek Tap 138.0(138.00 H Wood 2.8C 1
27 Mora Cloverdale 138.0(138.00 H Wood 2.53 I
28 Mora Cloverdale 138 0(138.00 S P Wood 22.28 I
29 Mora Cloverdale 138.0(138.00 S P Steel 0.9€2
30 Stoddard Jct Stoddard Sub 138.0(138.00 S P Steel 3.8C I
31 Fossil Gulch Tap 138.0(138.00 H Wood 1.95 1
32 Wood River Midpoint 138.0(138.00 H Wood 53.08 2
33 Wood River Midpoint 138.0(138.00 S P Wood 16.63 2
34 Oxbow McCall 138.0(138.00 H Wood 37.15 1
35 Oxbow McCall 138.0(138.00 S P Wood 2.32 1
36 IOIAL 4,861.24 11.02 203
FERC FORM NO. 1 (ED.12-87)Page 122.2
Name of Respondent
ldaho Power Company
This Report ls:(1) []An Original
(21 ;_lA Resubmission
Date of Report(Mo, Da, Yr)
0411412017
Year/Period of Report
End of 2016/Q4
TRANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. 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 lransmission 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 statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses bome by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other pa(y 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 0) to (l) on the book cost at end of year.
Size of
Conductor
and Material
(i)
uuli I uF LINE (rncruoe rn uorumn u) Lano,
Land rights, and clearing right-of-way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES
Line
No.
Land
(i)
Construction and
Other Costs(k)
Total Cost
(t)
Operation
Expenses
(m)
Maintenance
Expenses
(n)
Rents
(o)
Total
Expenses(p)
Z5() COPPER 26,50i 38'1,162 407,66(1
250 COPPER 2
I15,5 ACSR 21,32i 249,232 270,55!1
I95 AAC 719,46:3,312,460 4,031,92:4
195 ACSR 78,078 4,097,356 4,175,434 5
/95 ACSR 43,56{2,779,262 2,822,83(6
/95 AAC ?70,82i 561,561 832,38,4 7
/ARIOUS 564,93'4,128,644 4,693,57i I
/ARIOUS I
/ARIOUS 10
/ARIOUS 76,82i 3,1 69,1 00 3,245,923 11
/ARIOUS 55,52'2,908,212 2,963,73:12
197.5 ACSR 5,27t 6,930 12,204 13
/ARIOUS 34,421 6,772,340 6,806,768 14
I15.5 ACSR 216,91(1 0,516,799 10,733,718 15
I15,5 ACSR 16
/15.5 ACSR 17
t\0 4,19 469,36(473,56C 18
)54 ACSR 96,921 96,921 19
I5O COPPER 2,74'753,92t 756,66e 20
/ARIOUS 28,49(3,501,40t 3,529,898 21
/ARIOUS '173,68i 17,045,84i 17,219,53N 22
197.5 ACSR 23
/ARIOUS 225,60"1,648,07!1,873,681 24
}97.5 ACSR 96,58'2,ss6,23i 2,6s2,81S 25
/ARIOUS 11,25:,133,32i 144,574 26
r15.5 ACSR 3,101,77t 8,719,127 11 ,820,905 27
/ARIOUS 28
r95AAC 29
| 272 ACSR 30
I5O COPPER 45(187,84t 188,298 3'r
197.5 ACSR 349,71"7.127.142 7,476,854 32
}97.5 ACSR 33
197.5 ACSR 141,53r 2,753,95€2,895,492 34
397.5 ACSR 35
33,098,328 592,880,31 7 625,978,645 6,975,99!1,302,613 4,1 39,75i 12,418,36(36
FERC FORM NO. I (ED. 12-87)Page 123.2
Name of Respondent
ldaho Power Company
This(1)
(2)
Report ls:
IAn Original
nA Resubmission
Date of Report(Mo, Da, Yr)
0411412017
Year/Period of Report
End of 20'l6lQ4
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 (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.
Line
No.
UE:'IUNAIIUN VUL IAL'E IKVI(lndicate wtierebther than
60 cvcle. 3 ohase)
Type of
Supporting
Structure
(e)
LENG lH (Pole mtlesl(ln the dase.ofunderoround linesreport Eircuit miles)
Number
of
Circuits
(h)
From
(a)
To
(b)
Operating
(c)
Designed
(d)
vn otruutureof LineDesionated
{1')
un Srucru]esof AnotherLine(s)
1 Lowell Jct Nampa 138.0(138.00 S P Wood 7.50 2
2 Hunt Milner 138.0(138.00 S P Wood 19.4(1
3 Strike Bruneau Bridge 138.0(138.00 H Wood 13.49 I
4 American Falls Kramer Sub 138.0(138.00 S P Wood 18.4€I
5 Pingree Haven 138.0(138.00 S P Wood 11.72 1
6 Midpoint Twin Falls 138.0(138.00 S P Wood 25.22 2
7 Twin Falls Russeft 138.0(138.00 S P Wood 1.71 1
8 Blackfoot Aiken 46.0(138.00 S P Wood 6-lt 2
I Peterson Tendoy 69.0(138.00 H Wood 57.1(1
'10 Eastgate Tap Eastgate 138.0(138.00 S P Wood 6.3€1
11 Kimberly Tap Kimberly 138.0(138.00 S P Steel 1.84 I
12 Boise Bench Mora 138.0(138.00 H Wood 13.14 2
13 Bowmont-Caldwell Simplot Sub 138.0(138.00 S P Wood 0.51 I
14 Gary Lane Eagle 138.0(138.00 S P Wood 6.6€I
15 Locust Grove Blackcat Sub 138.0(138.00 S P Steel 9.25 2.98 1
16 Boise Bench Butler 138.0(138.00 S P Wood 0.14 4.02 1
17 Eaqle Star 138.0(138.00 S PWood 6.74 1
18 Karcher Sub Zilog Tap 138.0('138.00 S P Steel 3.6t 1
't9 Cloverdale - 712 712 -tNye 138.0(138.00 S P Steel 0.42 4.02 1
20 Victory Jct Victory 138.0(138.00 S P Steel 1.88 1
21 Butler wve 138.0(138.00 S P Steel 2.94 1
22 Horseflat Starkey 138.0(138.00 H Wood 33.97 1
23 Starkey Mccall 138.0(138.00 S P Steel 223 2
24 Starkey Mccall 138.0('138.00 H Wood 3.8C 1
25 Starkey Mccall 138.0(138.00 S P Steel 1.5C 1
26 Starkey Mccall 138.0(138.00 S P Wood 17 .61 1
27 Chestnut Happy Valley 138.0('138.00 S P Steel 2.78 I
28 Gamet Ward 138.00
29 McCall Lake Fork 138.0(138.00 S P Wood 8.89 1
30 McCall Lake Fork 138.0(138.00 S Steel 2.9C
31 Caldwell Willis 138.0(138.00 S P Steel '1.3c 1
32 Caldwell Willis 138.0(138.00 S P Steel 1.5S 1
33 Caldwell Willis 138.0(138.00 S P Wood 0.87 1
34 Valivue Tap 138.0(138.00 S P Steel 0.8c 2
35 Bowmont Happy Valley 138.0(138.00 S P Steel 8.72 1
36 TOTAL 4,861.24 11.02 203
FERC FORM NO. 1 (ED. 12-87)Page 122.3
Name of Respondent
ldaho Power Company
This Report ls:(1) [An Original(2) ;-1A Resubmission
Date of Report
(Mo, Da, Yr)
04t14t20't7
Year/Period of Report
End of 2O16lQ4
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 thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses bome by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
1 0. 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)
uos I ul- LINE (lnclude rn uolumn u) Land,
Land rights, and clearing right-of-way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES
Line
No.
Land
(i)
Construction and
Other Costs(k)
Total Cost
(t)
Operation
Expenses
(m)
Maintenance
Expenses
(n)
Rents
(o)
Total
Exne;ses
/15.5 ACSR 211,13'1,454,879 1,666,01t 1
/15.5 ACSR 3,32t 1,426,231 1,429,555 2
]97.5 ACSR 14,921 616,667 631,59{3
r15.5 ACSR 13,731 1,073,502 1,087,23C 4
)97.5 ACSR 18,22i 1,281,344 1,299,56i 5
/ARIOUS 66,28(3,293,71(3,360,002 b
I15.5 ACSR 16,79(213,03:229,823 7
I,I5.5 ACSR 13,61r 529,75(543,372 I
]97.5 ACSR 395,69(3,504,32t 3,900,022 9
I15.5 ACSR 343,9s{2,221,801 2,56s,76{10
195 ACSR 11
'15.5 ACSR 14,69;862,36i 877,064 12
/95 AAC s0,31€50,31S 13
/95 AAC 489,03;2,454,55i 2,943,594 14
r272 ACSR 935,81 (3,551,49!4,487,309 15
t272 ACSR 34,68;838,60a 873,292 16
/15.5 ACSR 179,8'l;2,932,783 3,1 12,600 17
/95 AAC 43,034 434,341 477,376 18
I 272 ACSR 140,41i 2,577,071 2,717,487 t9
I 272 ACSR 20
/95 ACSR 134,471 1,405,436 1,539,S07 21
/15.5 ACSR 2,473,832 18,78'1,405 21,255,238 22
/15.5 ACSR 23
I15.5 ACSR 24
r15.5 ACSR 25
/15.5 ACSR 26
I 272 ACSR 78,57!2,219,508 2,298,081 27
40,58(40,58(28
I15.5 ACSR 331,53{4,682,879 5,014,41t 29
30
r272 ACSR 272,23'2,141,218 2,413,M4 31
I95 ACSR 32
r95 ACSR 33
795 ACSR 3s1,497 351 ,497 34
r272 ACSR 691,721 6,045,286 6,737,014 35
33,098,328 592,880,31 7 625,978,64a 6,975,999 1 ,302,613 4,139,757 12,418,36(36
FERC FORM NO. 1 (ED. 12-87)Page 423.3
Name of Respondent
ldaho Power Company
This(1)
(2t
Reoort ls:
5]en Originat
nA Resubmission
Date of Report
(Mo, Da, Yr)
o411412017
Year/Period of Report
End of 20161Q4
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 tmnsmission 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.
Line
No.
DESIGNATION VOLIAGE (KV}(lndicate wlierebther than
60 cvcle. 3 ohase)
Type of
Supporting
Structure
(e)
LENGTH (Pole miles)(ln the tase.ofunderoround lrnesreport Eircuit miles)
Number
of
Circuits
(h)
From
(a)
To
(b)
Operating
(c)
Designed
(d)
UN SIrucIUTCof LineDesionated
11')
un Sruc[uresof Another
Line(s)
1 Antelope 138.0(138.00 H Wood 0.12
2 American Falls 138.0(138.00 H Wood 1.05
3 Kinport Don #1 138.0('138.00 S Tower 1.32
4 Donn HOKU 138.0('138.00 S P Steel 2.72
5 HOKU Alamed 138.0(138.00 S P Steel 0.22 2
6 HOKU Alamed 138.0('138.00 S P Steel 0.23
7 HOKU Alamed 138.0(138.00 S P Steel 2.85 1
8 Rockland Jct Rockland Wind Farm '138.0(138.00 S P Steel 5.30 1
I King Justice 138.0(138.00 S P Wood 0.11 I
10 Northview Tap 138.0(138.00 S P Wood 6.17
1',!Twin Falls PP Tap 138.0(138.00 Fl Wood 0.99 1
12 American Falls PP Amercian Falls Trans ST 138.0(138.00 S P Steel 0.38 1
13 Lower Salmon King Tie 138.0(138.00 H Wood 0.11 1
14 C J Strike Strike Jct '138.0(138.00 S Tower 4.30
15 Strike Jct Mountain Home Jct 138.0(138.00 H Wood 23.42 I
'16 Strike Jct Bowmont 138.00 H Wood 0.05 I
17 Strike Jct Bowmont 138.0(138.00 S Tower 0.36 1
18 Strike Jct Bowmont 138.0('138.00 H Wood 58 16 1
19 Lucky Peak Lucky Peak Jct 138.0(138.00 H Wood 4.48 I
20 Bliss Kinq 138.0(r38.00 H Wood 10.47 1
21 Milner Deadend Milner PP 138.0(138.00 S P Wood 1.30 1
22 Swan Falls Tap 138.0(138.00 H Wood 1.00 1
23
24
25
26 Hines BPA (Harney)'115.0('115.00 H Wood 3.34 1
27
28
29 69 Kv Lines 69.0(69.00 H Wood 210.64 1
30 69 Kv Lines 69.0(69.00 S P Wood 928.71 I
31
32
33 46 Kv Lines 46.0(46.00 S P Wood 431 .1€,l
34
35 Total all lines 4,861.24 11.02 203
36 IO IAL 4,861.24 11.02 203
FERC FORM NO.1 (ED.12.87)Page 122.1
Name of Respondent
ldaho Power Company
This
(1)
(2)
Report ls:
IAn Original
[lA Resubmission
Date of Report(Mo, Da, Yr)
0411412017
Year/Period of Report
End of 2O16lQ4
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 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
anangement and giving particulars (details) of such matters as percent owrership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses bome by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
1 0. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
Size of
Conductor
and Material
(i)
L;()S I UF LINE (lncruoe rn Uorumn U) LanO,
Land rights, and clearing rightof-way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES
Line
No.
Land
0)
Construction and
Other Costs(k)
Total Cost
(t)
Operation
Expenses(m)
Maintenance
Expenses(n)
Rents
(o)
Total
Expenses
197.5 ACSR 71,018 71,01t 1
250 COPPER 96,431 96,431 2
I15.5 ACSR 1,174 206,258 207,432 3
I 272 ACSR 19(4,594 4,784 4
I 272 ACSR 5
195 ACSR 6
195 ACSR 7
195 ACSR -16,973 -16,97:I
r 590 ACSR 60,65S 60,65!9
r15,5 ACSR 105,93:4,125,054 4,230,98i 10
250 COPPER 5€63,264 63,32'11
I15,5 ACSR 179,047 179,041 12
]97.5 ACSR 4,406 4,406 '13
I15.5 ACSR 1,074 622,115 623,18!14
397.5 ACSR 6,33i 2,562,494 2,568,821 15
r15.5 ACSR 86,651 2,861,709 2,948,36(16
r15.5 ACSR 17
18
/15.5 ACSR I 279,481 279,48t 19
I15.5 ACSR 5,62(1,352,664 1,358,284 20
r1s.s AcsR 2,814 183,606 186,42(21
]97.5 ACSR 17,20i 261,512 278,71'22
23
24
25
197.5 ACSR 1,97t,63,404 65,382 26
27
28
/ARIOUS 1,699,73(70,925,208 72,624,944 29
/ARIOUS 30
31
32
/ARIOUS 194,53t 18,820,771 19,015,3r 3 33
6,975,999 1,302,613 4.139.757 12,418,36e 34
33,098,32t 592,880,31 i 625,978,645 6,975,999 1 ,302,613 4,139,757 12,418,36S 35
33,098,328 592,880,31 7 625,978,645 6,975,99!1 ,302,61:4,139,757 12,418,36!36
FERC FORM NO. 1 (ED. 12-87)Page 123.1
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t14t2017
Year/Period of Report
2016tQ4
FOOTNOTE DATA
Schedule 422 Line No.:1 Column: b
Th .IS 1neI is jointly owned WAth Pac fiCorp and Idaho Power owns 73.22 of this 85.4 mrle1Iine.
Schedule Page:422 Line No.: 2 Column: bThis llne i-s jointly owned with Portland Generat Electric and Idaho Power owns 10.0i: ofuhis 17.8 mile -L.ine.
Schedule Page:422 Line No.:3 Column: bThis line rs jointly owned with PacrfiCorp and Idaho Power owns 22.0? of this 241.3 mile
1lne.
Schedute Page:422 Line No.:4 Column: bThis lrne is jointly owned with PacrfiCorp and Idaho Power owns 37.02 of th-is 129.3 mileIrne.
Schedule Page:422 Line No.: 5 Column: bThrs line is jorntly owned wlth PacifrCorp and Idaho Power owns 22.0? of Lhis 241.3 milefine-
Schedute Page:422 Line No.: 6 Column: bThrs line is lorntly owned wlth PacifiCorp and Idaho Power owns 37.0? of this 129.3 mlfe
l- ine .
Schedule Page:422 Line No.: I Column: bThis line rs jolntly owned with PacifiCorp and Idaho Power owns 29.22 of LhLs 225.5 mi-Leline.
Schedule Page:422 Line No.: 10 Column: bThis lrne is jointly owned wrth PacrfiCorp and Idaho Power owns 73.22 of this 27.1 mil-eline.
Schedule Page:422 Line No.: 11 Column: b
Th:-s line is jointly owned with PacifiCorp and ldaho Power owns 29.23 of this
approximately 193 mile Iine.
Schedu/e Page:422 Line No.:12 Column: bThrs line is loj-ntly owned with PacifiCorp and Idaho Power owns 29-22 of this 41.2 mileline.
Schedule Page:422 Line No.: 13 Column: bThis line is lolntly owned with PacifiCorp and Idaho Power owns 29.21 of this
approximately 193 mile fine.
Schedule Page:422 Line No.: 14 Column: bThis line rs jointly owned wrth PacrftCorp and Idaho Power owns 29.2* of thi,s 47.3 mileIine.
Schedule Page:422 Line No.: 15 Column: bThis line is jointly owned with PacifiCorp and Idaho Power owns 18.32 of this 40.9 mileline.
Schedule Page: 422 Line No.: 16 Column: bThis line is lorntly owned with PaclfiCorp and Idaho Power owns 64.4't of this 79.5 mile
1ine.
Schedule Page:422 Line No.: 17 Column: bThrs line is lointly owned with PacifiCorp and Idaho Power owns 64.4e. of this 77.9 mileline.
Schedule Page:422 Line No.: 18 Column: bThis line is jointly owned with PacifiCorp and Idaho Power owns 64.41 of this 0.9 mrle
l-ine.
Schedule Page:422 Line No.:32 Column: bThis lrne is jointly owned with Portland General Electric and Idaho Power owns 10.0: ofthrs 16.7 mi I e Irne.
Schedule Page:422.1 Line No; 10 Column: bThis line is lointly owned with PacrfrCorp and Idaho Power owns 40.8? of this 77.6 mileline.
FERC FORM NO. 1 (ED. 12-871 Page 450.1
Name of Respondent
ldaho Power Comoanv
This Report is:
(1) X An OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
04t't4t20't7
Year/Period of Report
2016tO4
FOOTNOTE DATA
Schedule Page:422.1 Line No.: 29 Column: b
Thj-s line is jointly owned with PacifiCorp
28.9 mile segment, 3f.8% of the Jefferson-Big Grassy- State Line 40.9 mile segment.
Schedule Page:422.1 Line No.:32 Column: b
Idaho Power owns 37.8% of Goshen- Jefferson
Big Grassy 20.8 mife segment and 100% of the
Thj-s line is jointly owned with PacifiCorp and Idaho Power owns 2L.92 of this 25.8 mileline.
Schedule Page:422.1 Line No.: 33 Column: bThis fine is jointly owned with PacifiCorp.
28.9 mile segment , 3f - 8% of the Jefferson-
Idaho Powei
Big Grassy 2
owns 37.8? of Goshen- Jefferson
0.8 mile segment and 100% of theBig Grassy- State Line 40.9 mile segment.
Schedule Page:422.1 Line No.:34 Column: bThis line is jointly owned with PaclfiCorp. Idaho Power owns 3728.9 mile segment, 3f.8? of the Jefferson- Big Grassy 20.8 mileBig Grassy- State Line 40.9 mile segment.
Schedule Page:422.4 Line No.: 1 Column: bThis l-ine is jointly owned with PacifiCorp ana faaf,o Power owns
8)" of Goshen- Jefferson
segment and 100% of the
11.5% of this 1 mile line
Schedule lage:422.4 Line No.:2 Column: bThis l-j,ne is jointly owned with PacifiCorp and fdaho Power owns 7.22 of thls 29.1 mlle1ine.
FERC FORM NO. 1 (ED. 12-871 Page 450.2
Name of Respondent
ldaho Power Company
This Reoort ls:(1) fiAn Original(2) nA Resubmission
Date of(Mo, Da
Report
, Yr)
o4t'14t2017
Year/Period of Report
End of 2016/Q4
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 UESIGNAIIUN Ltilg
Length
tnMiles
(c)
SUPPI utt<uut ts PtsF{ s I t{uu I u}<
From
(a)
To
(b)
Type
(d)
AVeIaueNumbeiper
Miles
(e)
Present
(0
Ultimate
(s)
1 No new lines for 2016
2
4
E
€
7
€
c
'tc
11
12
13
14
15
'16
17
18
19
2A
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
QO
40
41
42
43
44 TOTAL
FERC FORM NO. I (REV. 12.03)Page 424
Name of Respondent
ldaho Power Company
ls:
(1)
(2)
An Original
A Resubmission
Date of ReDort
(Mo, Oa, Yi)
04t't4t2017
Year/Period of Report
End of 2O16lQ4
IRANSjMISSI(]N LINES ADUEL' L'UT(ING YEAf{
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.
CONDUCTORS Voltage
KV
(opelatins)
LINE COS I Line
No.Size
(h)
Specification
(i)
Confiouration
and Spacing
(i)
Land and
Land Rightsfl)
Poles, Towers
and Fixtures(m)
Conductors
and Devices(n)
Asset
Retire. Costs(o)
Total
(p)
I
2
a
4
E
6
7
I
o
't0
1',l
12
13
14
15
16
17
18
1g
20
21
22
23
24
25
26
27
28
29
30
3'r
32
33
34
35
36
37
38
39
40
41
42
43
44
FERC FORM NO. 1 (REV. 12.03)Page 425
Name of Respondent
ldaho Power Company
S:
(1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
04t1412017
Year/Period of Report
End of 2016/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 1 0 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
attendedorunattended. Attheendofthepage,summarizeaccordingtofunctionthecapacitiesreportedfortheindividual stationsin
column (f).
Line
No Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (ln MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 transmission 345.00 138.00 13.80
2 Aiken distribution 46.00 13.00
3 Alameda distribution 138.00 13.00
4 Alameda distribution 138.00 13.09
4 American Falls PP - attended transmission 138.00 13.80
6 American Falls transmission 138.00 46.00 12.47
7 Antelope transmission 230 00 161.00 13.80
8 Artesian distribution 46.00 13.00
I Bannock Creek distribution 46.00 13.00
10 Bennett Mountain Power Plant- attended transmission 230.00 '18.00
1',|Bennett Mountain Power Plant- attended distribution 18.00 4.16
12 Bethel Court distribution 138 00 13.00
13 B1g Grassy transmission 161 00
14 Black Cat distribution 138 00 13.09
15 Blackfoot distribution 46.00 '13.00
16 Blackfoot transmission 161 .00 46.00 12.47
17 Blackfoot distribution 161.00 138 00 12.98
18 Bliss - attended transmission 138.00 13.80
19 Blue Gulch distribution 138 00 35.00
20 Boise Bench - attended transmission 230.00 138.00 13.20
21 Boise Bench - attended distribution 138 00 35.00
22 Boise Bench - attended transmission 138.00 69.00 12.98
23 Boise Bench - attended transmission 230.00 138.00 13.80
24 Boise distribution '138.00 13 00
25 Borah transmission 345 00 230.00 13 80
26 Bowmont distribution 69.00 46.00 6.90
27 Bowmont distribution '138.00 35.00
28 Bowmont transmission 138.00 69.00 12.98
29 Bowmont transmission 138.00 69 00 12.47
30 Bowmont transmission 230.00 138.00 13.80
31 Brady transmission 230.00 138.00 13.80
32 Brady transmission 138.00 46.00 12.47
33 Brady distribution 46.00 13.00
34 Brownlee - attended transmission 230.00 13.80
35 Bruneau Bridge distribution 138.00 35.00
36 Bruneau Bridge distribution 138.00 36.20
37 Buckhorn distribution 69 00 35.00
38 Bucyrus distribution 46.00 7.20
39 Buhl distribution 46.00 13.20
40 Burley Rural distribution 69 00 13.00
FERC FORM NO. 1 (ED. 12-96)Page 426
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
04t14t2017
Year/Period of Report
End of 2016/Q4
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. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(ln Service) (ln MVa)
(o
Number of
Transformers
ln Service
(q)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EOUIPMENT Line
NoType of Equipment
(i)
Number of Units
(i)
Total Capacity
(ln MVa)(k)
2 1
20 2 2
't8 1 3
18 ,|4
72 I 5
25 1 6
224 1 7
10 'l E
10 1 I
135 1 1U
5 1 11
15 I 12
13
48 2 14
30 2 15
50 3 ,|16
80 1 17
69 3 18
15 ,|'t9
254 2 20
42 2 21
75 3 22
240 2 23
67 3 24
450 3 ,|25
8 3 26
18 1 27
25 I 28
25 1 29
360 2 30
312 3 31
1 32
15 1 6 33
721 5 1 34
18 1 35
24 1 36
20 1 3t
6 1 1 3E
,|39
12 1 40
FERC FORM NO. r GD. 12-96)Page 427
Idaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
04t14t2017
Year/Period of Report
End of 2016lA4
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 (0.
Line
No.Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (ln MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
I Butler distribution 138.00 13.09
2 Caldwell distribution 138.00 13.00
3 Caldwell transmission 230.00 138.00
4 Caldwell distribution 138.00 13.09
5 Caldwell transmission 138.00 69.00 12.47
6 Caldwell transmission 230.00 138.00 12.47
7 Caldwell distribution 13.00 4.16
I Canyon Creek distribution 138.00 35.00
o Canyon Creek transmission 138.00 69.00 12.98
'10 Cascade Power Plant - attended transmission 69.00 4.60
11 Cascade distribution 69.00 't3.00
12 Cascade distribution 69.00 '13.10
13 Cascade distribution 25.00
'14 Chestnut distribution 138.00 13.00
15 Chestnut distribution 138.00 13.09
16 Clear Lake - aftended transmission 46.00 2.40
17 ctiff transmission 138.00 46.00 12.50
18 criff transmission 138.00 46.00 12.95
19 Cloverdale distribution 138.00 13.00
20 Cloverdale distribution 138.00 13.09
21 Dale distribution 46.00 4.60
22 Dale distribution 46.00 13.00
23 Dale distribution 69.00 13.00
24 Dale distribution 138.00 36.20
25 Dale transmission 138.00 46.00 12.47
26 Danskin- attended transmission 230.00 18.00
27 Danskin- attended transmission 230.00 138.00 13.80
28 Danskin- attended distribution 't8.00 4.16
29 Danskin- attended transmission 138.0C 12.00
30 Danskin- attended distribution 35.0C 13.80
31 Don distribution 138.00 7.60
32 Don distribution 138.0C 13.20
33 Don distribution 138.0C 13.00
34 Don distribution 14.0C
35 DRAM distribution 138.0C 13.09
36 DRAM transmission 230.0c 138.00 13.80
37 DRAM distribution 138.0C 12.47
38 DRAM distribution 138.0C 13.00
39 Duffin distribution 138.0C 35.00
40 Eagle distribution 138.0C 13.09
FERC FORM NO. 1 (ED. 12-96)Page 126.'l
ldaho Power Company (1)
(2')
Original
Resubmission
Date of Report(Mo, Da, Yr)
041't412017
Year/Period of Report
End of 20161Q4
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 ownerchip or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(ln Service) (ln MVa)
(fl
Number ol
Transformers
ln Service
(q)
Number ol
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.Type of Equipment
(i)
Number of Units
(i)
Total Capacity
(ln MVa)(k)
48 2 1
15 1 2
120 1 3
24 ,|4
75 3 5
120 1 6
1 7
15 1 8
15 1 I
12 ,|10
5 1 11
't0 1 12
4 1 13
24 1 14
24 ,|15
4 ,|16
12 2 ,|17
4 1 18
24 ,|19
24 1 20
1 21
8 1 6 22
1 23
27 1 24
25 ,|25
140 1 26
180 ,|27
t)1 26
96 2 29
5 'l 30
1 31
108 b 1 32
26 ,|33
80 6 34
101 6 35
160 2 36
17 1 3t
17 ,|3E
36 2 39
38 2 40
FERC FORIUI NO. I (ED. 12-96)Page 127.1
Name of
ldaho Power Company
(1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
o411412017
Year/Period of Report
End of 20161Q4
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 (0.
Line
No.Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (ln MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 Eastgate distribution 138.00
2 Eastgate distribution 138.00 13.00
3 Eckert distribution 138.00 36.20
4 Eden distribution 138.00 36.20
5 Eden transmission 138.00 46.00 12.98
6 Elkhom distribution 138.00 't2.47
7 Elkhom distribution 138.00 't3.00
8 Elmore distribution 138.00 35.00
9 Elmore transmission 138.00 69.00 12.s0
10 Elmore transmission 138.00 69.00 12.98
't'l Emmett distribution 138.00
12 Emmett transmission 138.00 69.00 12.47
't3 Falls distribution 46.00 13.00
14 Falls distribution 46.00
15 Filer distribution 46.00 13.00
't6 Flat Top distribution 46.00 13.00
17 Flying H distribution 69.00 2.40
18 Fort Hall distribution 46.00 13.00
19 Fossil Gulch distribution '138.00 35.00
20 Fremont transmission 138.00 ,16.00 12.50
21 Gary distribution 138.00 13.09
22 Gary distribution 138.00 13.00
23 Gem distribution 69.00 13.00
24 Gem distribution 69.00
25 Gooding Rural distribution 46.00 13.00
26 Golden Valley distribution 69.00 13.00
27 transmission 345.00 161.00 69.00
28 Gowen Substation distribution 138.00 35.00
29 Grindstone distribution 35.00
30 Grove distribution 138.00 13.09
31 Grove distribution 138.00 13.00
32 Hagerman distribution 46.00 13.00
33 Hagerman distribution 69.00 13.00
34 Hailey distribution 138.00 13.00
35 Happy Valley distribution 138.00 13.09
36 Haven distribution 't 38.00 35.00
37 Haven transmission 138.00 ,16.00
38 transmission 500.00 230.00 34.50
39 Hewlett Packard distribution 138.0C 13.00
40 Hidden Springs distribution 138.00 13.00
FERC FORM NO. 1 (ED. 12-96)Page 126.2
Respondent
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
0411412017
Year/Period of Report
End of 20161Q4
5. Show in columns (l), (1), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(ln Service) (ln MVa)
(0
Number of
Transformers
ln Service
(s)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
NoType of Equipment
(i)
Number of Units
(i)
Total Capacity(ln MVa)
(k)
24 1 1
18 I 2
18 1 3
24 1 4
15 1 5
8 1 6
8 ,|
17 I a
15 1 I
't5 ,|10
24 1 11
25 1 12
8 1 13
10 1 14
10 1 15
13 2 16
15 2 't7
10 1 I 16
15 ,|19
50 3 1 20
20 ,|21
't7 ,|22
8 1 23
10 ,|24
15 2 25
10 1 1 26
908 4 2t
24 1 2E
10 2 29
48 2 30
24 1 31
10 ,|32
5 1 33
20 1 34
18 1 35
12 ,|36
25 1 37
600 3 1 38
20 1 39
8 ,|40
FERC FORM NO. 1 (ED. 12-96)Page 427.2
Name (1)
(2)
An Original
A Resubmissionldaho Power Company
Date of Report
(Mo, Da, Yr)
0411412017
Year/Period of Report
End of 201O|A4
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).
Line
No.Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (ln MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
I Highland distribution 138.00 13.00
2 HiI distribution 138.00 13.00
3 Hillsdale distribution 138.00
4 Hoku distribution 138.00 13.80
5 Homedale distribution 69.00 13.00
6 Horse Flat transmission 230.00 138.00 13.80
7 Horseshoe Bend distribution 3s.00
8 Horseshoe Bend distribution 69.00 36.20
I Horseshoe Bend distribution 69.00 25.00
10 Huston distribution 69.00 13.00
1',!Hulen distribution 46.00 13.00
't2 Hunt transmission 230.00 138.00 13.80
13 Hydra distribution 138.00 36.20
14 lsland distribution 69.00 13.00
't5 transmission 161.00
16 Jerome distribution 138.00 13.00
17 Jerome distribution 138.00 13.09
18 Julion Clawson distribution 't38.00 3s.00
't9 Joplin distribution 138.00 13.00
20 Joplin distribution 138.00 3s.00
21 Justice transmission 230.00 138.00 13.80
22 Karcher distribution 138.00 13.00
23 Kenyon distribution 69.00 13.00
24 Ketchum distribution 138.00 13.00
25 Kimberly distribution 138.00 13.09
26 Kinport transmission 16't.0c 46.00 13.20
27 Kinport transmission 230.0c 138.00 12.47
28 Kinport transmission 230.0c 138.00 13.80
29 transmission 345.0C 230.00 13.80
30 Kramer distribution 138.0C 35.00
31 Kramer distribution 138.0C 36.20
32 Kuna distribution 138.0C 13.00
33 Lake distribution 69.00 13.00
34 Lake Fork distribution 138.0C 36.20
35 Lake Fork transmission 138.0C 69.00 12.50
36 Lamb distribution 138.0C 13.00
37 Langley Gulch- attended transmission 230.0c 138.00 13.80
38 Langley Gulch- attended transmission 230.0c
39 Langley Gulch- attended distribution 4.16
40 Langley Gulch- attended distribution 13.0C 4.16
FERC FORM NO. 1 (ED. 12-96)Page 426.3
Respondent (1)
(2)
Originalldaho Power Company Resubmission
Date of Report
(Mo, Da, Yr)
04t't4t2017
Year/Period of Report
End of 20161Q4
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. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(ln Service) (ln MVa)
(f)
Number of
Transformers
ln Service
(o)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.Type of Equipment
(i)
Number of Units
(i)
Total Capacity
(ln MVa)(k)
18 ,|1
39 2 2
24 1 3
2 4
22 2 5
100 1 b
5 1 7
12 1 8
5 ,|I
10 1 10
10 1 11
300 3 12
48 2 13
12 1 14
15
20 1 16
20 ,|17
30 2 18
15 1 19
18 1 20
180 1 21
12 1 22
20 2 23
42 2 24
27 1 1 25
7 26
180 ,|27
180 1 2A
600 3 1 29
12 1 30
't8 1 31
't5 1 32
10 1 33
18 I 34
15 I 35
18 1 36
360 2 37
246 2 3E
12 1 39
12 ,|40
FERC FORM NO. 1 (ED. 12-96)Page 127.3
Name
ldaho Power Company
(1)
(2)
An Original
Resubmission
Date of Report(Mo, Da, Yr)
04t14t2017
Year/Period of Report
End of 20'l6lQ4
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).
Line
No.Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (ln MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 Langley Gulch- attended transmission 230.00 150.00
2 Lansing distribution 69.00 13.00
3 Lincoln distribution 138.00 13.09
4 Linden distribution 138.00 13.00
5 Locust distribution 138.00 36.20
o Locust transmission 230.00 138.00 13.80
7 Lower Malad - attended transmission 138.00 7.20
8 Lower Salmon - attended transmission 138.00 13.80
I Map Rock distribution 69.00 13.00
'10 McCall distribution 13.00 13.09
11 McCall distribution 138.00 36.20
'12 Meridian distribution 138.00 13.00
13 Micron distribution 138.00 13.09
14 Micron distribution 138.00 13.00
15 Midpoint transmission 230.00 138.00 13.80
16 Midpoint transmission 345.00 230.00 13.80
17 transmission 500.00 345.00
18 Midrose distribution 138.00 13.09
19 Milner transmission 138.00 69.00 12.47
20 Milner distribution 69.00 45.00 6.90
21 Milner distribution 138.0C 35.00
22 Milner PP - attended transmission 138.0C 13.80
23 Moonstone distribution 138.0C 35.00
24 Mora distribution 't38.0c 13.09
25 Mora distribution 138.0C 36.20
26 Moreland distribution 35.0C 13.00
27 Moreland distribution 46.0C 13.00
28 Moreland distribution 46.0C 35.00 12.47
29 Mountain Home distribution 69.0C 13.00
30 Mountain Home Air Force Base distribution 69.0C 13.00
3'r Mountain Home Air Force Base distribution 138.0C 13.00
32 Nampa transmission 230.0c 138.00 13.80
33 Nampa distribution 138.0C 13.00
34 New Meadows distribution 138.0C 36.20
35 New Plymouth distribution 69.0C 13.00
36 Northview distribution 138.0C
37 Notch Butte distribution 138.0C 13.0S
38 Orchard distribution 69.0C 36.20
39 Orchard distribution 69.0C 35.00 12.47
40 Orchard distribution 69.0C
FERC FORM NO. 1 (ED. 12-96)Page 426.4
ldaho Power Company (1)
(2t
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
o411412017
Year/Period of Report
End of 20161Q4
SUtsS IAIIONS
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 otheruise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(ln Service) (ln MVa)
(0
Number of
Transformers
ln Service
(q)
Number ot
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.Type of Equipment
(i)
Number of Units
(i)
Total Capacity
(ln MVa)(k)
,|1
't2 I 2
10 1 3
33 2 4
72 3 5
360 2 6
16 1 I
70 4 E
10 1 9
't2 1 't0
18 ,|1',!
36 2 12
24 2 13
24 2 14
120 1 15
840 2 1 16
860 3 1 1l
24 1 1E
75 3 1 19
8 3 1 20
29 2 21
36 1 22
12 1 23
24 ,|24
24 1 25
b 1 26
8 I 27
6 3 1 28
15 1 29
1 30
18 1 31
180 1 32
50 3 33
'12 1 34
10 ,|35
24 1 36
10 1 3t
6 1 36
10 3 39
,|40
FERG FORil NO. I (ED. 12-96)Page 127.1
ldaho Power Company
(1)
(2')
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
041't412017
Year/Period of Report
End of 2016/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).
Line
No.Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (ln MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 Parma distribution 69.00 '13.00
2 Parma distribution 69.00 35.00
3 Paul distribution 138.00 35.00
4 Paul distribution 138.00 36.20
5 Payette distribution 138.00 13.00
6 Pingree transmission 't38.00 46.00 12.50
7 Pingree distribution 138.00 35.00
I Pleasant Valley distribution 138.00 35.00
9 Pleasant Valley distribution 138.00 36.20
10 Pocatello distribution 46.00 13.00
1',!Pocket distribution 138.00 36.20
12 Poleline distribution 138.00 13.09
'13 transmission 345.00
14 Portneuf distribution 138.00 35.00
15 Portneuf distribution 46.00 35.00
16 Rockford distribution 46.00 '13.00
17 Russett distribution 138.00 13.00
18 Sailor Creek distribution 138.00 2.40
'19 Sailor Creek distribution 138.00 35.00
20 Salmon distribution 69.0C 13.00
21 Salmon distribution 69.00 34.50 12.47
22 Salmon distribution 69.0C 12.47
23 Salmon transmission 13.0C 2.40
24 Salmon distribution 69.0C 7.20
25 Shoshone distribution 46.0C 13.00
26 Shoshone distribution 46.0C 7.20
27 Shoshone Falls - attended transmission 46.0C 2.30
28 Shoshone Falls - attended transmission 46.0C 6.60
29 Silver distribution 't 38.0c 35.00
30 Simplot distribution 138.0C 13.00
31 Sinker Creek distribution 138.0C 35.00
32 Siphon distribution 138.0C 35.00
33 South Park distribution 46.0C 13.00
34 Star distribution 138.0C 13.09
35 Starkey transmission 138.0C 69.00 't2.47
36 State distribution 69.0C 13.00
37 Stoddard distribution 138.0C 13.00
38 Strike Power Plant - attended transmission 138.0C 13.80
39 Sugar distribution 138.0C 35.00
40 Swan Falls - aftended transmission 138.0C 6.90
FERC FORM NO. 1 (ED. 12-96)Page 426.5
Name
ldaho Power Company
(1)
(2)
An Original
A Resubmission
Date of Report
(Mo, Da, Yr)
04114t2017
Year/Period of Report
End of 2016/Q4
SUBSTATIONS
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. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(ln Service) (ln MVa)
(0
Number of
Transformers
ln Service
(s)
Number of
Spare
Transfonners
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.Type of Equipment
(i)
Number of Units
(i)
Total Capacity
(ln MVa)
(k)
10 ,|,|
12 1 2
't8 I 1 3
27 1 4
23 3 5
50 3 6
22 2 I
18 1 6
24 ,|I
36 2 10
24 1 1',\
18 1 12
13
18 ,|'t4
I 15
14 2 '16
18 1 17
15 2 16
15 1 19
10 1 3 20
't0 3 21
2 22
5 2 23
1 24
10 I 25
2 3 26
3 1 27
10 1 28
12 I 29
30 2 30
12 1 31
33 2 32
10 1 33
'18 I 34
18 1 35
33 2 36
15 I 37
83 3 38
20 2 39
18 1 40
FERC FORi' NO. 1 (ED. 12-96)Page 427.5
Name of Respondent
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report
(Mo, Da, Yr)
04t14t2017
YearlPeriod of Report
End of 20161Q4
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. lndicateincolumn(b)thefunctional characterofeachsubstation,designatingwhethertransmissionordistributionandwhether
attendedorunattended. Attheendofthepage,summarizeaccordingtofunctionthecapacitiesreportedfortheindividual stationsin
column (f).
Line
No Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (ln MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 Taber distribution 46.00 13.00
2 Ten Mile distribution 138.00 13.09
3 Terry distribution 138.00 13.09
4 Terry distribution '138.00 13.00
5 Thousand Springs - attended transmission 46.00 7.20
6 Thousand Springs - attended transmission 7.00 2.40
7 34s 00
8 Toponis distribution 138.00 33.00
9 Twin Falls distribution '138.00 '13.09
10 Twin Falls transmission '138 00 46.00 12.98
11 Twin Falls PP - attended transmission 138.00 7.20
12 Twin Falls PP - attended transmission 138.00 13.20
'13 Upper Malad - attended transmission 45.00 7.20
14 Upper Salmon- attended transmission 138.00 7.20
15 Ustick distribution 138.00 13.00
16 Vallivue distribution '138.00 13.09
17 Victory distribution "t38.00 13.00
18 Victory distribution "t38.00 13.09
19 Ware distribution 69.00 13.00
20 Weiser distribution 69.00 13.00
21 Weiser transmission 138.00 69.00 12.47
22 Wilder distribution 69 00 13.00
23 Willis distribution 138.0C 13.09
24 wye distribution 138.0C 13.00
25 wye distribution 138.0C 13.09
16 Zilog distribution 138.0C 13.09
27
28
29 The above are all State of ldaho
30
31 Montana
32 Mill Oeek transmission 230 0c
33 Peterson transmission 230.0c 69.00 13.20
34
35 Nevada:
36 Valmy - atiended transmission 345.0C 18.00
37 Valmy-&nded, : '.', transmission 345.0C 22.00
38 Wells transmission ''t38.0c 69.00 13 00
39
40 Oregon:
FERC FORM NO. 1 (ED. 12-96)Page 426.6
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of(Mo, Da
Report
, Yr)
04t14t2017
Year/Period of Report
End of 20'1610,4
SUBSTATIONS 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. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(ln Service) (ln MVa)
(fl
Number ot
Transformers
ln Service
(o)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.Type of Equipment
(i)
Number of ljnits
(i)
Total
(ln
Capacity
MVa)(k)
5 1 1
48 2 2
12 1 3
30 2 4
I 1 5
1 b
18 1 6
44 2 q
33 2 10
I 1 11
72 ,|12
I 1 13
36 4 14
44 2 15
18 1 16
24 1 17
18 1 16
12 1 1 19
20 2 20
25 ,|2',l
10 1 22
18 1 23
36 2 24
20 1 25
24 1 26
2t
2A
29
30
31
32
24 3 1 33
34
35
315 ,|36
300 ,|37
20 3 1 38
39
40
FERC FORM NO. 1 (ED. 12-96)Page 427.6
Respondent (1)
(2)ldaho Power Company An Original
A Resubmission
Date of Report(Mo. Da, Yr)
0411412017
Year/Period of Report
End of 20161Q4
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 1 0 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
attendedorunattended. Attheendofthepage,summarizeaccordingtofunctionthecapacitiesreportedfortheindividual stationsin
column (f).
Line
No.Name and Location of Substation Character of Substation
(b)
VOLTAGE (ln MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 transmission s00.0c 24.00
2 Boardman - atended transmission 230.0c 7.20
3 transmission 24.0C 7.20
4 Bums transmission 500 0c
5 Cairo distribution 69.0C 13.00
6 Hells Canyon - attended transmission 230.00 '13.80
7 Hells Canyon - attended distribution 69.00 0.50
I Hines transmission 138.00 115.00 12.47
9 F}nricane transmission 230.00
10 Malheur Butte distribution 69.00 34.50
11 Nyssa distribution 69.00 13.00
12 Ontario distribution 138.00 13.00
13 Ontario transmission 138.00 69 00 12.47
14 Ontario transmission 230.00 138.00 13.80
15 Ontario transmission 138.00 69.00 12.98
16 Ontario transmission '138.00 69.00 13.09
17 Ontario transmission 138.00 69.00 12.50
18 Ore-lda distribution 69.00 13.00
19 Oxbow - attended transmission 138.00 69.00 13.00
20 Oxbow - attended transmission 230 00 13.80
21 Oxbow - attended transmission 230.00 138.00 13 80
22 Quartz transmission 138.00 69.00 12.50
23 Quartz transmission 230.00 138.00 12.98
24 Quartz transmission 138.00 69 00 12.98
25 Surnmer Lake transmission 500.00
zo Vale distribution 69.00 13.00
27
28 Washington
29 transmission 230.0c
30
31 Wyoming
32 Jim Bridgrer - attend€d transmission 345 0C 22.OO 34.5C
33
34
35
36
37
38 Transformers-distribution substations under 10,000
39 KVA 82 unattended.
40
FERC FORM NO. I (ED. 12-96)Page 426.7
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Y0
04114t2017
Year/Period of Report
End of 2016/Q4
SUBSTATIONS
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. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(ln Service) (ln MVa)
(0
Number of
Transformers
ln Service
(o)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EOUIPMENT Line
No.Type of Equipment
(i)
Number of Units
(i)
Total Capacity
(ln MVa)
(k)
685 3 ,|
55 1 2
55 ,|3
4
12 1 5
500 3 ,|b
1 1
40 1 E
I
I 3 ,|10
20 2 11
38 2 12
25 1 1 13
240 2 14
50 2 15
1 16
,|1/
15 1 16
10 3 1 19
244 2 20
100 1 2',1
15 1 22
100 3 1 23
15 1 24
25
10 1 26
2t
2E
29
30
31
2244 4 32
33
34
35
36
37
38
321 39
40
FERC FORM NO.1 (ED.12-96)Page 127.7
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t1412017
Year/Period of Report
2016tQ4
FOOTNOTE DATA
Schedule 426 Line No.: 1 Column: a
Paci f Corp has an ownershi1interconnection equipmentvaries by terminal. 100% o
Schedule Page:426 Line No.:
For afl of column F:
Base rating capacity reported unfess otherwi-se noted.
Schedule Page:426 Line No.:7 Column: a
Idaho Power has an ownership interest in certain high-voltage transmissi-on related and
interconnection equipment located at Paci-fiCorp's Antelope station. Ownership interest
varies by termlnal. 100? of the top rating capacity reported.
Schedule Page:426 Line No.: 13 Column: a
Idaho Power has an ownership interest in certain high-voltage transmission related and
interconnection equipment located at PacifrCorp's Big Grassy station. Ownership interest
varles by terminal.
Schedule Page:426 Line No.: 25 Column: a
PacrfrCorp has an ownership interest in certaln hrgh-voltage transmission related and
interconnection equipment focated at Idaho Power's Borah station. Ownership interest
varies by terminal. 100% of the capacity is reported.
Schedule Page:426.2 Line No.: 27 Column: a
Idaho Power has an ownership -interest in certain high-voltage transmission related and
interconnection equipment focated at Pacj-fiCorp's Goshen station. Ownership interest
varies by terminal. 100? of the top rating capacity reported.
Schedule Page:426.2 Line No.:38 Column: a
PacifiCorp has an ownership interest in certain high-voltage transmission related and
interconnection equipment located at Idaho Power's Hemingway station. Ownership interest
varies by terminal. 1002 of the capacity j-s reported.
Schedule Page:426.3 Line No.: 15 Column: a
Idaho Power has an ownership interest in certain high-voltage transmission related andinterconnection equipment located at PaclflCorp's Jefferson station. Ownership interestvaries by terminal.
Schedule Page:426.3 Line No.:29 Column: aPacifiCorp has an ownership interest in certain high-voltage transmission related andj-nterconnection equipment located at Idaho Power's Kinport station. Ownershlp interestvaries by terminal. 1003 of the capacity is reported.
Schedule Page:426.4 Line No.: 17 Column: aPacifiCorp has an ownership interest in certain high-voltage transmission retaLed andinterconnection equipment locat-ed at Idaho Power's Midpoj-nt statj-on. Ownership interestvaries by terminal. 100% of the capacity rs reported.
Schedule Page:426.5 Line No.: 13 Column: a
Idaho Power has an ownership lnterest -in certain high-voltage transmission refated andinterconnection equipment located at PacifJ-Corp's Popu!-us station. Ownership interest
varies by termi-nal.
Schedule Page:426.6 Line No.:7 Column: a
Idaho Power has an ownership interest in certain high-voltage transmission refated andinterconnection equipment located at PacifiCorp's Three Mile Knofl station. Ownership
interest varies by terminal.
Schedule Page:426.6 Line No.: 32 Column: a
Idaho Power has 32% ownership interest in certain transmissj-on related equipment located
at Northwestern Energy's MiII Creek Station.
Schedule Page:426.6 Line No.:36 Column: aJointly owned with Sierra Pacific Power Company, d/b/a NV Energy. Idaho Power has a 50;
share of ownership. 100? of the top rating capacity reported.
Schedule Page:426.6 Line No; 37 Column: aJointly owned with Sierra Pacific Power Company, d/b/a NV Energy. Idaho Power has a 503
FERC FORM NO.1 D.12 450.1
p interest in certain hrgh-voltage transmission related and
located at Idaho Power's Adelaide statlon. Ownership interest
f the capacity is reported.1 Column: f
Name of Respondent
ldaho Power Companv
This Report is:
(1) X An OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
0411412017
Year/Period of Report
2016tQ4
FOOTNOTE DATA
share of ownersh-ip. 100% of the top rating capaclty reported.
Schedule Page:426.7 Line No.: 1 Column: a
Jointly owned with Portland General Electric, Power Resources Cooperative and BA Leasing
BCS, LLC. Idaho Power has a 102 share of the jointly owned capacity. 1002 of the topratinq capacity j-s reported.
Schedule Page:426.7 Line No.: 2 Column: aJointJ-y owned with Portland General- Electric, Power Resources Cooperative and BA Leasing
BCS, LLC. Idaho Power has a 10? share of the jointly owned capacity. 100? of the toprating capacity is reported.
Schedule Page:4?6.L Line No.: 3 Column: aJointly owned with Port1and General Electri-c, Power Resources Cooperative and BA Leasing
BCS, LLC. Idaho Power has a 10? share of the jointly owned capaclty. 100% of the toprating capacity is reported.
Schedule Page:426.7 Line No.:4 Column: a
Idaho Power has a 22"a ownership interest in certain high-voltage transmission related andinterconnection equipment located at PacifiCorp's Burns statj-on.
Schedule Page:426.7 Line No.:9 eotumn: a
Idaho Power has an ownership interest in certain high-vottage transmission reIaced and
interconnection equipment Iocated at PacifiCorp's Hurricane station. Ownership j-nterest
varies by terminal.
Schedule Page:426L7 Line No.: 25 Column: a
Idaho Power has an ownership i-nterest in certain high-voltage transmisslon refated andj-nterconnectj-on equipment located at PacifiCorp's Summer Lake station. Ownership interestvaries by terminal.
Schedule Page:426.7 Line No.:29 Column: a
Idaho Power has an ownership interest j-n certain high-voltage transmission related and
interconnectj-on equipment located at PacifiCorp's Wal-l-a Walla station. Ownership interest
varies by terminal.
Schedule Page:426.7 Line No.:32 Column: aJointly owned with PacifrcCorp. ldaho Power has a 33.3% share of ownership. 100% of thetop ratlng capaclty is reported.
FERC FORM NO. 1 (ED. 12.871 Page 450.2
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5]Rn orisinat(2) nA Resubmission
Date of Report(Mo, Da, Yr)
04t14t2017
Year/Period of Report
End of 2O16lQ4
COMPANIES
1. Report below the information called for concerning all non-power goods or services received from or provided to associated (affiliated) companies.
2. The reporting threshold for reporting purposes is $250,000. The threshold applies to the annual amount billed to the respondent or billed to
an associated/affiliated company for non-power goods and services. The good or service must be specific in nature. Respondents should not
attempt to include or aggregate amounts in a nonspecific category such as "general".
3. Where amounts billed to or received from the associated (affiliated) company are based on an allocation process, explain in a footnote.
Line
No.Description of the Non-Power Good or Service
(a)
Name of
Associated/Affiliated
Company
(b)
Account
Charged or
Credited
(c)
Amount
Charged or
Credited
(d)
1 Non-power Goods or Services Provided by Affiliated
2
3
4
5
b
7
8
I
10
1',!
12
't3
14
15
16
17
18
19
20 Non-power Goods or Services Provided for Affiliate
21 Managerial Expenses IDACORP,INC 417420 439,832
22 922000 48,696
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
FERC FORM NO.
FERC FORM NO.
1(New)
1-F (New)
Page 429
iiiI,:IVED December3l,2016
ANNUALREP.RT l, ; ,':ri is flil 9r 53
IDAHO SUPPLEMENT TO FERC FORIU 1 , ; ,jr l_l; - . .. - .)lr*,ll
MULTT€TATE ELEcrRrc coMpANlEs ;" ir'!\';ulr\',rt
lttDEx
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 Epenses
Number of Electric Department Employees
IOAHO SUPPLE]UIENT
ldaho Power Gompany
STATE OF IDAHO - ALLOCATED
An Original December 31, 2015
STATEMENT OF INCOME FOR THE YEAR
1. Reportamountsforaccounts4l2and4l3,RevenueandExpensesfromUtilityPlantLeasedtoOthers,inanotherutility
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. Repo( amounts in account 414, Other Utility Operating lncome, in the same manner as accounts 4'12 and 413 abo\re.
3. Report data for lines 7, 9, and '10 for Natural Gas companies using accounts 404.1,404.2,404.3,407.1, and 407.2.
4. Use page 1 22 for important notes regarding the state ment of income or any account thereof.
5. Give concise explanations concerning unsettled rate proceedings where a contingency odsts such that refunds of a
material amount may need to be made to the utility's customers or which may result in a material refund to the utility
with respect to power or gas purchases. State for each year affected the gross revenues or costs to which the contingency
relates and the tax effects together with an e,rplanation of retain such revenues or reco\rer amounts paid with respect
to po^rer and gas purchases.
6. Give concise e)elanations concerning significant amounts of any refunds made or received during the year.
Line
No.
Account
(a)
(Ref.)
Page
No.
(b)
TOTAL
Current Year Previous Year
(c)(d)
1
2
3
4
5
6
7
I
I
10
11
't2
13
14
15
16
17
18
't9
20
21
22
23
24
25
26
27
UTILITY OPERATING INCOME
Operating Revenues (400)....................... ..
Operating Expenses
Operation Expenses (401)....... .... . . .
Maintenance Expenses (402).............
Depreciation Expense (403)....................
Amort. & Depl. of Utility Plant (404-405)...
Amort. of Utility Plant Acq. Adi. (406)..
Amort. of Propeo Lo6ses, Unrecovered Plant and
Accretion Expense (41 I )......
Regulatory Study Costs (407)...
Amort. of Conversion Expenses (407).................
Regulatory Debits/Credits (407.3 & 407.4)........................
Taxes Other Than lncome Taxes (408.1)........
lncome Taxes - Federal (409.1)..
- Other (409.1)..
Provision for Deferred lncome Taxes (410.1 & 411.1) Net...
lnvestment Tax Credit Adj. - Net (411.4).................
(Less) Gains from Disp. of Utility Plant (41 1.6).....
Losses from Disp. of Utility Plant (411.7)
(Less) Gains from Disposition of Allo^/ances (41 1 .8)..............
Losses from Disposition of Allorances (41 1.9).................
TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 22).....
Net Utility Operating lncome (Enter Total of line 2 le6s 24).
11
15
15
2
2
2
2
2
$ 1 ,1 96,237,660 $ 1,208,201,834
695,609,784
63,704,243
'129,831 ,533
6,315.212
221.856
1,075,354
30,506,918
893,579
3,660,263
30,612,022
291.753
962,722,515
695,1 89,223
65,984,91'l
125,382,354
6,708,360
22',t,919
30,566,626
12,620,53'.1
5,825,567
27,032,456
471,51',!
970,003,458
$ 233,515,145 $ 238,198,376
IDAHO SUPPLEMENT Page 1
TAXES ALLOCATED TO IDAHO
Kind of Tax
Taxes Charged
Durino Year
Taxes Other Than lncome Taxes:
Labor Related:
FtcA............
FUT4...........
State Unemployment.......
Payroll Deduction & Loading....
Total Labor Related........
Property Taxes..........
Kilowatt-hour Tax............
Licenses......
Regulatory Commission Fees.................
lrrigation P1C..............
Canada Sales Tax....
Total Taxes Other Than lncome Taxes.....
$ 14,654,995
126,630
591,773
(15,373,397)
0
26,939,946
1,139,204
4,621
2,212,657
210,488
0
30,506,918
Federal lncome Taxes...,....,.
State lncome Taxes..........
Deferred lncome Taxes..........
lnvestment Tax Credit Adjustment - Net.
893,579
3,660,263
30,612,022
291,753
Total Taxes Allocated to ldaho.$ 65,964,534
ldaho Power Company
STATE OF IDAHO . ALLOCATED
An Original Oecember 31, 2016
IDAHO SUPPLEi,IENT Page 2
STATE OF IDAHO
An Original December 3'1, 2016ldaho Power Company
NOTES AND ACCOUNTS RECEIVABLE
Summary for Balance Sheet
Show separately by footnote the total amount of notes and accounts receivable
from directors, officers, and employees included in Notes Receivable (Account
141) and OtherAccounts Recei\rable (Account 143)
Line
No.
Accounts
(a)
Balance
Beginning of
Year
(b)
Balance
End of
Year
(c)
1
2
3
4
5
6
7
I
I
10
't1
't2
13
14
15
16
17
18
19
20
Notes Receivable (Account 141).
Customer Accounts Recei\rable (Account 142).
Other Accounts Receivable (Account 143)
(Disclose any capital stock subscription received)
Total..
Less: Accumulated Provision for Uncollectible
Accounts-Cr. (Account I 44\...........
Total, Less Accumulated Provision for
Uncollectible Accounts.
75,650,719
23,486,155
$ 99,136,874
1,355,042
$ 97,781,832
$(83,038)
73,276,818
25,535,458
$ 98,729,238
1 131.759
$ 97,597,479
ACCUMULATED PROVISION FOR UNCOLLECTIBLE ACCOUNTS - CR. (Account 144)
1. Report beloi\r the information called for conceming this accumulated provisim.
2. Explain any important adjustments of subaccounts.
3. Entries with respect to officers and employees shall not include items for utility sewices.
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
Balance Beg of Year:
Uncollectible Retail Electric Sales
Uncollectible Damage Claims
Uncollectibe Other Revenues
Balance end of year.....
$ 1,355,042
(210,769)
4,827
(1 7 340)
s b
$
$
$
$
$
1,355,042
(210,769)
4,827
(17,340)
$ 1,131,759 $$$$ 1,131,759
IDAHO SUPPLEMENT Page 3
RECEIVABLES FROM ASSOCIATED COMPANIES (Accounts 145, '146)
1. Report particulars of notes and accounts receivable from associated companies at end of year
2. Provide separate headings and totals for accounts 145, Notes Receivable from Associated Companies, and 146,
Accounts Receivable from Associated Companies, in addition to a total for the combined accounts.
3. For notes recei\rable list each note separately and state purpose for which received. Sho,\, also in column
(a) date of note, date of maturity and interest rate.
4. ll any note was received in satisfaction of an open account, state the period covered by such open account.
5. lnclude in column (f) interest recorded as income during the year, including interest on atccounts and notes
held at any time during the year.
6. Give particulars of any notes pledged or discounted, also of any collateral held as guarantee of payment
of any note or account.
Line
No.
Particulars
(a)
Balance
Beginning
of Year
(b)
Totals for Year Balance
End of Year
(e)
lnterest
For Year
(f)
Debits
(c)
Credits
(d)
1
2
3
4
5
6
7
I
I
10
't'l
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
Account 145:
|ERCO........
Total Account 145.
Account 146:
IDACORP, lnc.
Total Account'146............
$ 1,156,202 s 5,962,027 $ 7,118.229 b
1,156,202 5,962,027 7,118,229
$ 6,413,981 $ 6,413,981 $
$$ 6,413,981 $ 6,413,981 $
ldaho Power Company
STATE OF IDAHO
An Original D,ecember 31, 2015
IDAHO SUPPLEMEiIT Page 4
STATE OF IDAHO - TOTAL SYSTEM DATA
GAIN OR LOSS ON DISPOSITION OF PROPERTY (Acccunt 421 .1 and 421.2)
'1. Give a brief description of property creating the gain or loss. lnclude name of party acquiring the property (when
acquired by another utility or associated company) and the date transaction was completed. ldentif, 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 transactions disclosed in column (a).
3. Give the date of Commission approval of journal entries in cdumn (b), when approval is required. Where approval
is required but has not been received, give e)elanation folloring the item in column (a). (See account 102, Utility
Plant Purchased or Sold.)
Line
No.
Description of Property
(a)
Original Gost
of Related
(b)
Date Journal
Entry Appro\red
(When Required)
(c)
Accl421.1
(d)
Accl421.2
(e)
1
2
3
4
5
6
7
I
9
10
'11
't2
13
14
15
't6
17
18
19
20
21
22
23
24
25
26
27
28
29
30
3'l
Gain on dispcition of
property:
Boise Operations Center
" OPUC Approval IPUC Notification
Total gain..............
Total |oss......
$$$
$46, 1 45 2t23t2016"$(7,631)
$46,145 $(7,631)
0$$0
ldaho Pourcr Company
STATE OF IDAHO
An Original D,ecember 31, 2016
IDAHO SUPPLETIIENT Page 5
STATE OF IDAHO - TOTAL SYSTEM DATA
PROFESSIONAL OR CONSULTATIVE SERVICES - ITEMS $1O,OOO AND OVER
Line
No.
PAYEE
(a)
SERVICE TYPE
(b)
Amount
(c)
1
2
3
4
5
6
7
8I
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
ALTIVON
ADECCO
AERITAE CONSULTING GROUP LTD
AGREE TECHNOLOGIES AND SOLUTIO
AKIN GUMP STRAUSS HAUER & FELD
ALDER ASSOCIATES LLC
ANDERSON BANDUCCI PLLC
ANDERSON PERRY & ASSOCIATES
APPLIED ENERGY GROUP
BAKER BOTTS LLP
BARKER, ROSHOLT & SIMPSON LLP
BAYSWATER LLC
BIGGINS LACY SHAPIRO & CO., LL
BOARDVANTAGE, INC
BROWN AND CALDWELL
CASE FORENSICS CORPORATION
CGI TECHNOLOGIES AND SOLUTIONS
CLEAREDGE PARTNERS INC
CLEARESULT CONSULTING INC
CME, INC. OF IDAHO
COMPUNET,INC
COPPERLEAF TECHNOLOGIES INC
CORPORATE OFFICE INSTALLATIONS
DAVIS WRIGHT TREMAINE LLP
E SOURCE, INC.
ENERNOC INC
EVANS KEANE
EVERGREEN CONSULTING GROUP, LL
GIVENS PURSLEY LLP
GOOD TECHNOLOGY CORP.
HAWLEY TROXELL ENNIS & HAWLEY
HONEYWELL INTERNATIONAL INC
IDL
INTELLITECT
LEIDOS ENGINEERING LLC
MAINLINE INFORMATION SYSTEMS I
MCDOWELL RACKNER & GIBSON PC
MERRILL COMMUNICATIONS LLC
MIRANDE, MICHAEL
MORROW & FISCHER PLLC
MOVESAFE INC
NAVIGANT CONSULTING INC
NETIQ
NEXTATECHN
NIELSEN GROUP INC
Customer Service
Management Services
lT Services
Energy Efficiency Services
Legal Services
Management Services
Legal Services
Engineering Services
Management Services
Legal Services
Legal Services
Legal Services
Management Services
Management Services
Legal Services
Management Services
lT Services
Management Services
Energy Efficiency Services
Management Services
lT Services
Management Services
Management Services
Legal Services
Training Consultants
Management Services
Legal Services
Management Services
Legal Services
lT Services
Legal Services
Management Services
Management Services
Management Services
Engineering Services
Management Services
Legal Services
Legal Services
Legal Services
Legal Services
Training Consultants
Management Services
lT Services
lT Services
lT Services
$10,097
43,200
38,620
215,265
20,256
13,563
38,599
15,812
10,782
53.743
421,775
26,100
11,000
23,806
149,995
33,923
343,290
120,000
89,664
s0,538
75,877
138,728
112,826
1,122,914
13,950
515,613
11,512
414,368
89.724
28,880
23,251
431,038
25,1 90
248,720
97,478
84,000
596,124
16,761
37,896
15,478
18,813
108,750
49,200
53,000
191.923
ldaho Power Company
STATE OF IDAHO
An Original December 31, 2016
IDAHO SUPPLEMENT
Page 6
STATE OF IDAHO - TOTAL SYSTEM DATA
PROFESSIONAL OR CONSULTATIVE SERVICES - ITEMS $1O,OOO AND OVER
Line
No
PAYEE
(a)
SERVICE TYPE
(b)
Amount
(c)
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
7',|
72
73
74
75
76
77
78
79
80
81
82
83
84
85
86
87
PARSONS BEHLE & LATIMER
PERKINS COIE LLP
POWERPLAN CONSULTANTS INC
PRICEWATERHOUSE COOPERS LLP
PROFESSIONAL TRAINING SYSTEMS
RAMLOW & RUDBACH PLLP
REED HARRIS ENVIRONMENTAL LTD
RIGHT SYSTEMS, INC
RIVER MOSS TECHNOLOGIES
RM ENERGY CONSULTING
RUDEEN & ASSOCIATES
SCHWABE WILLIAMSON & WYATT
STANLEY ASSOCIATES, INC
STOEL RIVES LLP
SULLIVAN & CROMWELL
TATA AMERICA INTERNATIONAL COR
TIBCO SOFTWARE INC
TRINOOR LLC
TUERI LLC
UNIVERSITY OF IDAHO
WELLS FARGO SHAREOWNER SERVIC
XHANCE BUSINESS SOLUTIONS INC
Legal Services
Legal Services
Management Services
Management Services
Training Consultants
Legal Services
Environmental Services
lT Services
Consulting Services
Management Services
Management Services
Legal Services
lT Services
Legal Services
Legal Services
Management Services
lT Services
HR Consufting
Management Services
Management Services
Legal Services
Management Services
27,765
274,489
99,1 30
54,398
11,254
'16,184
18,037
17,225
24,998
295,984
149,555
61,865
273,747
233,941
208,561
1,322,703
11,980
126,330
72,990
381,869
13,706
35,855
TOTAL $ 9,984,607
ldaho Power Company
STATE OF IDAHO
An Original Oecember 31, 2016
IDAHO SUPPLEMENT
Page 6A
Line
No.
PROFESSIONAL OR CONSULTATIVE SERVICES
ITEMS $5.OOO OR MORE BUT LESS THAN $1O.OOO
PREDOMINANT
NATURE OF SERVICEPAYEE I nuourur
1
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
33u
35
36
37
38
39
40
4',|
40
41
42
43
44
ALEXANDER CLARK PRINTING
BETHKE LAW PLLC
BONFIRE TRAINING
CERTENT INC
CNET PRO SERVICES-DC
CUSTER AGENCY, INC
CYBER ARK SOFTWARE INC
ECOANALYSTS INC
GREENBERG TRAURIG LLP
IMB SOLUTIONS LLC
IVES TRAINING & COMPLIANCE GR(
JACKSON LEWIS PC
JONES GLEDHILL FUHRMAN GOURI
RESOLVE FINANCIAL GROUP INC
RISCH PISCA PLLC
SOFTWARE HOUSE
STREAMLINE IMAGING LLC
TEKSYSTEMS
TERRAGRAPH ICS ENVIRONMENTAI
TERRI HUGHES, LLC
TOWERS WATSON DELAWARE INC
TOWERS WATSON PENNSYLVANIA
Customer Service
Legal Services
Training Consultants
HR Consulting
lT Services
Legal Services
lT Services
Environmental Services
Legal Services
lT Services
Training Consultants
Legal Services
Legal Services
Legal Services
Legal Services
lT Services
Legal Services
lT Services
Legal Services
Management Services
HR Consulting
HR Consulting
9,854
6,638
5,000
7,500
8,760
6,832
6,000
6,750
5,725
7,069
5,090
6,981
7,280
6,265
6,239
9,1 50
8,301
9,548
8,886
7,000
9,800
7,000
45 TOTAL $ 161,666
ldaho Power Gompany
STATE OF IDAHO
An Original December 31, 2016
IDAHO SUPPLEMENT Page 68
STATE OF IDAHO. ALLOCATED
An Original December 31, 2016ldaho Power Company
ELECTRIC PLANT lN SERVICE (Accounts 101 , 102, 1 03 and 1 06)
1 . Report belofl the original cost of electric plant in service according to the prescribed accounts.
2. lnadditiontoAccountl0l,ElectricPlanlinService(Classified),thispageandthenextincludeAccountl02,ElectricPlant
Purchased or Sold; Account 1 03, Experimental Electric Plant Unclassified; and Account 1 05, Completed Construction
Not Classifled - Electric.
3. lnclude in column (c) or (d), as appropriate, corrections of additions and retlrements for the current or precedang year.
4. Enclose in parentheses credit adiustrnents of plant accounts to indicate the negative effect of such ae,crunts.
5. Classify Account 1 06 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 cf plant retirements the end of the year, include in
column (d) a tentative distribution of such retirements, on an estimated basis, with appropriate contra entry to the account
for acrumulated depreciation provision. lnclude also in column (d) reversals d tentative distributions of prior year of un-
classified retirements. Attach supplemental statement sho^ring the acrount distributions of these tentative classifications in
columns (c) and (d), including the reversals of the prior years tentalive account distributions of these amounts. Careful ob-
servance of the above instructions and he texts of Accounts 1 01 and 1 06 will avoid serious omissions of the reported amount
of respondent's plant actually in service at end of year.
Line
No.
Acc,ount
(a)
Beginning of year
(b)
Additions
(c)
,|
2
3
4
5
6
7
8
9
10
11
12
'13
14
15
't6
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
1. INTANGIBLE PLANT
(30 1 ) Or9anization...........................
(302) Franchises and Consents.............
(303) Miscellaneous lntangible P1ant................-....
TOTAL lnlangible Plant (Enter Total of lines 2, 3, and 4)...........................
2. PRODUCTION PLANT
A. Steam Production Plant
(310) Land and Land Ri9hts..........................
(31 1 ) Structures and lmprovements..............
(312) Boiler Plant Equipment...
(313) Engines and Engine Driven Generators
(314) Turbogenerator Units..........
(315) Accessory Electric Equipment............................
(316) Misc. Po,t/er Plant Equipment.....................
(3 1 7) Asset Retirement Costs for Steam Production... .
TOTAL Steam Production Plant (Enter Total of lines I thru 15).........................
B. Nuclear Production Plant
(320) Land and Land Rights........
(321) Structures and lmprovements
(322) Reactor Plant Equipment.......
(323) Turbogenerator Units............
(324) Accessory Electric Equipment............................
(325) Misc. Power Plant Equipment...................
(326) Asset Retirement Costs for Nuclear Production..
TOTAL Nuclear Prcductron Plant (Enter Total of lines 17 thru 24)....................
C. Hydraulic Production Plant
(330) Land and Land Ri9hts............... .
(332) Reservoirs, Dams, and Waterways..............,..
(333) Water Wheels, Turbines, and Generators......
(334) Accessory Electric Equipment...........................
(335) Misc. Poirer Plant Equipment...................
(336) Roads, Railroads, and Bridges.........
(337) Asset Retirement Costs for Hydraulic Production... ... ...
TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34)....-.....
D. Other Production Plant
(340) Land and Land Ri9hts..................
(341) Structures and lmprovements
(342) Fuel Holders, Products and Accessories.......
(344) Generators
(345) Accessory Eleclric Equipment............................
(346) Misc Poi,er Plant Equipment..........,.....
$5,464
28,537,018
27 ,30't,694
55,844,177
1 3,51 5,1 96
1,057,561 ,298
748,923,O70
IDAHO SUPPLEMENT
Page 7
ELECTRIC PLANT lN SERVICE (Accounts '101, 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 classifications arising from distribution d amounts
initially recorded in Account 102. ln sho,ving the clearanoe of Account 102, include in column (e) lhe
amounts with espect to accumulated provision for depreciation, acquisition adiustments, etc., and sholv
in column (D 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 shoiring subaccount classification of such plant conforming to the
requirements of these pages.
For each amount comprising the reported balance and changes in Account 102, state the property purchased
or sold, name of vendor or purchaser, and date of transaction. lf proposed ,iournal entries have been filed
with the Commission as required by the Uniform System of Accounts, give also date of such filing.
Retirements
(d)
Adjustrnents
(e)
Transfers
(f)
End ofYear
(s)
Line
No.
$5,457
28,735,693
21,722,267
(301)
(302)
(303)
50,463,418
14,807 ,729
(310)
(31 1)
(31 2)
(31 3)
(314)
(31 s)
(316)
(317)
'I ,1 31 ,205,806
(320)
(321)
(322)
(323)
(324)
(32s)
(326)
(330)
(331)
(332)
(333)
(334)
(33s)
(336)
(337)
784,225,545
(340)
(341 )
(342)
(343)
(3441
(345)
(34s)
,|
2
3
4
5
6
8
9
'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
37
38
39
40
41
42
43
STATE OF IDAHO -ALLOCATED
An Original December 31,2016ldaho Power Company
IOAHO SUPPLEMENT
ldaho Power Company
STATE OF IDAHO. ALLOCATED
An Original December31,2016
ELECTRIC PLANT lN SERVICE (Accounts 101, 102, 103 and '106) (Continued)
Line
No.
Account
(a)
Balance at
Beginning of year
(b)
Additions
(c)
44
45
46
47
48
49
50
5t
52
53
54
55
56
57
58
59
60
61
62
63
64
bc
66
67
68
69
70
71
72
73
74
75
76
77
7A
79
80
81
82
83
84
85
86
87
88
89
90
91
92
93
94
95
96
(346) Misc. Po\irer Plant Equipment......,..............
TOTAL Other Prcduction Plant (Enter Total of lines 37 thru 44)......................
TOTAL Production Plant (Enter Total of lines 16, 25, 35, and 45)...................
3. TRANSMISSION PLANT
(350) Land and Land Ri9hts..................
(352) Structures and lmprovements
(353) Station Equipment...........
(354) Toflers and Fixtures.
(355) Poles and Fixtures................
(356) Overhead Conductors and Devices.......
(357) Underground Conduit.......................
(358) Underground Conductors and Devices................
(359) Roads and Trails..
(359. 1 ) Asset Retirement Costs for Transmission Plant... ............ ..
TOTAL Transmission Plant (Enter Total of lines 48 thru 57)..........................,.
4, DISTRIBUTION PLANT
(360) Land and Land Ri9h1s..................
(361) Structures and lmprovements
(363) Storage Battery Equipmen1....,.....................................
(364) Poles, Tor/ers, and Fbdures....................
(365) Overhead Conductors and Devices........
(366) Underground Conduit.......
(367) Underground Conductors and Devices........................
(368) Line Transformers.................
(369) Services.
(370) Meters.......
(371) lnstallations on Customer Premises................
(372) Leased Property on Customer Premises.........................
(373) Street Lighting and Signal Systems...............
(374) Asset Retirement Costs for Distribution Plant. . . ... ... ... .. . ..
TOTAL Distribution Plant (Enter Total of lines 60 thru 74)................
5. GENERAL PLANT
(389) Land and Land Rights...
(390) Structures and lmprovements
(391 ) Otrice Fumiture and Equipment...........
(392) Transportation Equipment..................
(393) Stores Equipment........
(394) Tools, Shop, and Garage Equipment........
(395) Laboratory Equipment..........
(396) Power Operated Equipment..
(397) Communication Equipment,...............
(398) Miscellaneous Equipment......
SUBTOTAL (Enter Total of lines 77 thru 86).....
(399) Other Tangible Property
(399.1 ) Asset Retirement Costs for General Plant.. . ... ..
TOTAL General Plant (Enter Totsl of lines 87, 88 and 89)...........
TOTAL (Accounts 101 and 106).......
(102) Electric Plant Purchased
(Less) (1 02) Electric Plant Sold
(103) Experimental Plant Unclassified
TOTAL Electric Plant in Service......
$ 516,333,6'12
2,322,817,980
34,884,459
74,584,045
390,824,535
't77,042,687
15'l ,840,760
203,174,425
374,232
1,032,725,142
5,1 76,1 36
32,644,394
207,064,121
228,143,181
120,527,316
47,672,004
227,020,812
496,171,835
55,899,072
82,333,518
2,729,762
4,333,517
1,509,715,668
15,884,981
1 06,283,870
44,738,612
72,704,300
2,161,043
7,685,955
12,172,325
14,45',1,O45
53,096,779
5,718,032
334,896,942
334,896,942
5,255,999,909
$ 5,25s,999,909
IOAHO SUPPLEMENT
Page 9
ldaho Power Company
STATE OF IDAHO - ALLOCATED
An Original Docember3l,2016
ELECTRIC PLANT lN SERVICE (Accounts 1O1 , 1O2, 1 03 and 1 06) (Continued)
Retirements
(d)
Adjust nents
(e)
Transfers
(0
Balance at
End of Year
(s)
Line
No.
(346)44
45
46
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
t6
77
78
79
80
81
82
83
84
85
86
87
88
89
90
91
9?
93
94
95
96
$ 526,346,795
2,441,778,149
35.587,007
76,1Q4,269
393,495,642
189,547,402
167 .57 5.311
209,723,704
373,412
(350)
(3s2)
(3s3)
(354)
(3ss)
(3s6)
(357)
(3s8)
(3ss)
(359.1)
1,072,406,748
5,814,678
35,010,074
214,473,222
236,613,191
122,399,952
49,1'11,697
240,258,O34
514,889,065
56,597,017
84.220.95A
2,788,954
4,291.616
(360)
(361)
(362)
(363)
(364)
(36s)
(366)
(357)
(368)
(36s)
(370)
(371)
(372)
(373)
(374)
1,566,468,460
16.434.544
1 13,336,404
46,963,216
77 ,914,731
2,506,903
8,292,085
12.460,246
14,433,841
54,150,326
6,287,681
(38e)
(3e0)
(3s 1)
(3e2)
(3s3)
(3e4)
(3e5)
(3e6)
(3s7)
(3e8)
352,780,016
(3ee)
(3ss.1 )
352,780,0'16
5.483.896,790
(1 02)
(1 02)
(371)
$ 5,483.896,790
IDAHO SUPPLEMENT
Page 10
ldaho Power Company
STATE OF IDAHO -ALLOCATED
An Original Ilecember 31,2016
1,142,045,471
(13,865,518)
ELECTRIC OPERATING REVENUES (Account 400)
1 . Report belou, operating revenues for each prescribed account, and manufactured gas revenues in total.
2. Report number of custorners, 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 shonld be counted
for each group of meters added. The a\rerage number of customers means the aver4e of twelve figures at the clce
of each month.
3. lf pranious 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
Current Year
(b)
Amount for
Pre\rious Year
(c)
1
2
3
4
5
6
7
8
I
10
't1
12
13
14
15
16
17
18
't9
20
2'l
22
23
24
25
26
Sales of Electricity
(440) Residential Sa|es...............
(442) Commercial and lndustrial Sales
Small (or Commercialxsee lnstr. 4) (1 )........
Large (or lndustrialXSee lnstr. 4) (2)........
(444) Public Street and Highway lighting.............
(445) Other Sales to Public Authorities...................
(446) Sales to Railroads and Railways.....
(448) lnterdepartmental Sales....
TOTAL Sales to Ultimate Consumers.......
(447) Sales for Resale - Opportunity....Non-Firm On|y............
TOTAL Sales of Electricity
(449) Provision for Rde Refunds....
TOTAL Revenue Net of Provision for Refunds..................
Other Operating Revenues
(450) Forfeited Discounts....
(45't ) Miscellaneous Service Revenues..........
(453) Sales of Water and Water Polrer...........
(454) Rent from Electric Property..
(455) lnterdepartmental Rents.....
(456) Other Electric Re\renues.
TOTAL Other Operating Revenues..........................
TOTAL Electric Operating Revenues
$496,885,590
435,838,063
166,852,687
3,851,0'19
$494,611,468
447 ,471,324
166,580,123
3,905,1 50
1,103,427,358 -
24,028,928
1,'l 12,568,065
29,477,405
't,127,456,286
(10,706,040)
't,116,750,246 1 ,1 28,1 79,953
4,006,859
13,550,308
61,930,248
4,036,347
23,713,987
52,271,548
79,487,414 80,021,882
$I ,196,237,660 $1.208.201.8U
('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 SUPPLEMET{T
Page 11
ELECTRIC OPERATING 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, lmportant Changes During Year, for important na^, territory added and importiant rate increases or
decreases.
6. For lines 2,4,5, and 6, see page 304 for amounts relating to unbilled revenue by accounts.
7. lnclude unmetered sales. Provide details of such sales in a footnote.
KILOWATT HOURS SOLD AVERAGE NUMBER OF CUSTOMERS PER MONTH
Line
No.
Amount for
Cunent Year
(d)
Amount for
Previous Year
(e)
Amount for
Cunent Year
(0
Number for
Previous Year
(s)
4,825,036,794
5,691,721,809
2,981 ,154,794
30,473,840
4,803,995,27s
5,836,330,0S1
2,938,946,430
31.192.274
426.966
81,209
114
2.764
418,906
80,261
113
2,559
1
2
3
4
5
6
7
I
9
10
1',!
't2
't3
13,528,387,237 *
1,130,546,242
13,6't0,464,070
1,196,890,694
511,053
N/A
501,839
N/A
14,658,933,479 14,807,354,764 51 1,053 501,839
* lncludes $13,346,799 unbilled revenues.
** lncludes 132,593,327 KWH relating to unbilled revenues
Lines '1 1 through 21 are on an "allocated" basis
ldaho Porrer Company
STATE OF IDAHO -ALLOCATED
An Original D,ecember 31,2016
IDAHO SUPPLEMENT
Page 1la
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
lf the amount for previous year is not derived from previously reported figures, explain in footnotes.
Lrne
No.Account
(a)
Amount lor
Current Year
(b)
Amount rcr
Previous Year
(c)
1 1. POWER PRODUCTION EXPENSES
z
3
4
5
6
7
8
I
10
11
12
'13
14
15
16
17
18
19
20
21
22
23
24
25
lo
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
$1 ,108,81 5
131 ,264,237
8,552,599
1,397,666
8,704,375
197.814
$1,234,974
125,293,762
9,344,671
1,204,563
6,401,977
414,288
151,225,505 143,894,235
95,779
505,3 1 4
13,597.821
4,910,251
6,157,433
121,775
841,997
13,228,845
5,165,496
6,638,813
25,266,597 25,996,925
176,492,102 169,891,160
5,429,890
5,765,563
1 4,033,868
1,622,635
5,453,486
5,558,396
8,697,696
14,295,462
1,555,246
5,442,169
225,600
32,530,642 35,774,569
ldaho Power Company
STATE OF IDAHO . ALLOCATED
An Original December 31, 2016
IDAHO SUPPLEMENT
Page 12
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
lf the amount for previous year is not derived ftom previously reported figures, oelain in footnotes.
Lrne
No.Account
(a)
AmounI Ior
Current Year
(b)
Amount tor
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
81
82
83
84
85
86
87
88
89
90
9'1
92
93
94
95
96
97
98
99
100
101
102
103
C. Hydraulic Po^rer Generation (Continued)
Maintenance
(il'l) Maintenance Supervision and Engineering.
(542) Maintenance of Structures....
(543) Maintenance of Reservoirs, Dams, and Waterways.........
(544) Maintenance of Electric Plant..................
(545) Maintenance of Miscellaneous Hydraulic P|ant..................
TOTAL Maintenance (Enter Total of lines 53 thru 57).............-
TOTAL Po,ver Production Expenses-Hydraulic Po/ver (Enter Total of lines 50 and 58)
D. Other Por/er Generation
Operation
(546) Operatiofl Supervision and Engineering.
(547) Fuel..........
(548) Generation Expenses...........
(g g) Miscellaneous Other Povt/er Generation Epenses,.......
(550) Rents.. .....
TOTAL Operation (Enter Total of lines 62 thru 56).,............
Maintenance
(551) Maintenance Supervision and Engineering.
(552) Maintenance of Structures....
(553) Maintenance of Generating and Electric P|ant......,...........
(554) Maintenance of Miscellaneous Other Pover Generation Plant.......
TOTAL Maintenance (Enter Total of lines 69 thru 72).....,........
TOTAL Porer Production Expenses-Other Po,ver (Enter Total of lines 67 and 73)......
E. Other Porer Supply Epenses
(555) Purchased Poiver................
(556) System Control and Load Dispatching
(557) Other Expenses...........
TOTAL Other Poarer Supply Epenses (Enter Total of lines 76 thru 78)..-...................
TOTAL Pofler Production Expenses (EnterTotal of lines 21, 41,59,74, and 79)........
2. TRANSMISSION EXPENSES
Operation
(560) Operation Supervision and Engineering.
(561) Load Dispatching... ....
(562) Station Expenses...........
(563) Overhead Line E&enses....
(564) Underground Line Expenses
(565) Transmission of Electricity by Others...........
(566) Miscellaneous Transmission Epenses............
(567) Rents........
TOTAL Operation (Enter Total of lines 83 thru 90)..............
Maintenance
(568) Maintenance Supervision and Engineering.
(569) Maintenance of Structures....
(570) Maintenance of Station Equipment..........
(571 ) Maintenance of Overhead 1ines..................
(572) Maintenance of Underground lines..................
(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.
$111,688
1,165,830
629,906
2,100,451
2,244,052
$1 15,391
1,074,449
551,802
2,542,063
2,742,589
6,251,928 7,026,295
38,782,570 42,800,863
706.592
39,851,771
3,969,924
772,208
0
620,066
52,436,682
4,405,378
895,988
0
45,300,494 58,358,1 14
0
383,507
12'1 ,306
2,645,297
0
348,753
68,784
1 ,218,031
3,1 50,1 1 0 1,635,568
48,450,604 59,993,681
229,010,441
2.562
(3,886,233)
207,677,199
2,336
1 8,163,160
225,126,770 225,842,695
488,852,047 498,528,400
2,825,373
4,493,749
2,523,821
912,'113
5,255,921
7.148
3,960,651
3,966,098
2,817,822
2,524,933
927,497
5,992,521
2,268
2,957,854
20,018,776 1 9,1 88,991
162,484
901,331
2,124,188
1,083,753
0
1 50,586
894,294
3,1 51 ,054
2,814,416
0
4,271,756 7,01 0,350
24,290,532 26,1 99,341
4,044,090 4,1 02,960
ldaho Power Company
STATE OF IDAHO. ALLOCATED
An Original December 31, 2016
IDAHO SUPPLEi'ENT
Page 13
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
lf the amount for previous year is not derived from previously reported figures, e)elain in footnotes.
Lrne
No.Account
(a)
Amounl lor
Current Year
(b)
Amounr rcr
Previous Year
(c)
104
105
106
107
108
109
110
111
112
113
114
't 15
116
117
118
119
120
121
122
123
124
125
126
127
128
129
130
13'l
132
133
134
135
136
137
138
139
140
141
142
143
144
145
146
147
148
149
150
151
152
153
3. DISTRIBUTION EXPENSES (Continued)
(581 ) Load Dispatching........
(582) Station Expenses...........
(583) Overhead Line Expenses....
(584) Underground Line Expenses.
(585) Street Lighting and Signal System Expenses...........
(586) Meter Epenses...........
(587) Customer lnstallations Expenses...........
(588) Miscellaneous Distribution Expenses...........
(589) Rents........
TOTAL Operation (Enter Total of lines'l 03 thru 1 1 3)...................
Maintenance
(590) Maintenance Supervision and Engineering.
(591) Maintenance of Structures....
(592) Maintenance of Station Equipment..........
(593) Maintenance of Overhead Lines..................
(594) Maintenance of Underground lines..................
(595) Maintenance of Line Transformers.................
(596) Maintenance of Street Lighting and Signal Systems..
(597) Maintenance of Meters............
(598) Maintenance of Miscellaneous Distribution P|ant..................
TOTAL Maintenance (Enter Total of lines 116 thru 124)............
TOTAL Distribution Expenses (Enter Total of lines 114 and 125)...........-
4. CUSTOMER ACCOUNTS EXPENSES
Operation
(901) Supervision
(902) Meter Reading Expenses........................
(903) Customer Records and Collection Expenses...........
(904) Uncdlectible Accounts........
(905) Miscellaneous CustomerAccounts E&enses..
TOTALCustomerAccountsExpenses(EnterTotal of lines129thru133)...................
5. CUSTOMER SERVICE ANO INFORMATIONAL EXPENSES
Operation
(907) Supervision
(908) Customer Assistance Epenses...........
(909) lnformational and lnstructional Expenses........
(91 0) Miscellaneous Customer Service and lnformational Expenses......
TOTAL Cust. Serviceand lnficrmational E)eenses (EnterTotal of lines 137 thru 140)...
6. SALES EXPENSES
Operation
(91 1) Supervision
(91 2) Demonstrating and Sellang Expenses...... -....
(91 3) Advertising E&enses...........
(91 6) Miscellaneous Sales Expenses...........
TOTAL Sales Expenses (Enter Total of lines '144 thru 147)............
7. ADMINISTRATIVE AND GENERAL EXPENSES
Operation
(920) Administrative and General Salaries..............
(921) Otrce Supplies and Expenses.....
(Less) (922) Administrative Expenses Transferred-Credit..........
$3,863,491
1,489,971
3,341,544
3,034,028
78,799
4,553,1 70
829,907
7,194,670
291,921
3,750,022
1,279,072
3,676,494
2,850,1 98
83,895
4,606,1 98
724.519
5,778,592
250,686
$
28,721,590 27,102,636
(1,487,s77)
0
3,733,657
13,877,337
856,648
27,427
561 ,312
843,267
351,377
1 0,1 65
0
3,466,718
1 3,1 59,994
596,266
35,220
4U,372
741,737
267,593
18,763,447 18,742,066
47,485,037 45,844,703
584,522
1,291,407
14,113,296
3,718,544
(521)
466,780
1,764,385
14,953,292
3,128,782
379
19,707,249 20,313,618
744.559
38,536,315
392,796
41 9,876
758,841
35,331,512
409,488
691,250
40,093,546 37,1 91,091
Z5 76,081
23 76,081
77,526,927
14,066,090
(32,175,51 1)
69,806,988
1 4,063,954
(24,9s6,472)
ldaho Power Company
STATE OF IDAHO. ALLOCATED
An Original December 31, 2015
IDAHO SUPPLEMENT
Page 14
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
lf the amount for previous year is not derived from previously reported figures, a\plain in f@tnotes.
Lrne
No.Account
(a)
Amounr Tor
Current Year
(b)
Amounl Tor
Previous Year
(c)
154
155
156
157
158
159
160
'161
162
163
164
165
166
167
168
169
7. ADMINISTRATIVE AND GENERAL EXPENSES (Continued)
(923) Outside Services Employed...........
(924) Property lnsurance...........
(925) lnjuries and Damages.....
(926) Emplryee Pensions and Benefits.......
(927) Franchise Requirements.....
(928) Regulatory Commission Expenses...........
(929) Duplicate Charges-Cr........
(930. 1 ) General Advertising Expenses...........
(930.2) Miscellaneous General Epenses...........
(931) Rents........
TOTAL Operation (Enter Total of lines 151 thru 164)............
Maintenance
(935) Maintenance of General P|ant..................
TOTALAdmin and General Epenses (EnterTotal of lines 165-157)......,..
TOTAL Elec Op and Maint Exp Ootal of80, 100, 126,134,141, 148, 168)
$7,833,149
3,218,491
5,705,266
49,259,561
0
3,514,748
554,212
3,382,255
0
$7,813,43',1
3,242,063
6,348,690
41,999,742
0
3,334,101
590,563
5,202,216
'1.916
1 32,885,1 88 127 ,447,192
6,000,405 5,573,707
't 38,885,592 1 33,020,900
$759,314,027 $761,174,134
ldaho Power Company
STATE OF IOAHO. ALLOCATED
An Original
IDAHO ONLY
December 31, 2016
NUMBER OF ELECTRIC DEPARTMENT EMPLOYEES
1. The data on number of employees should be repo(ed for the payroll period ending nearest to October 31
or any payroll period ending 60 days before or afier October 31.
2. lf the respondent's payroll fur the reporting period includes any special construction personnel, include
such employees on line 3, and shov the number of such special construction employees in a fmtnote.
3. The number of employees assignable to the electric department from joint functions of combination utilities
may be determined by estimate, on the basis of employee equivalents. Shov the estimated number of equiv-
alent employees attributed to the electric department ftom joint functions.
1 Payroll Period Ended (Date).........................
2 Total Regular Full-Time Emp|oyees..............
3 Total Part-Time and Temporary Employees..
4 Total Employees
December 31, 2016
1,999
10
2,009
December 31 , 201 5
I OO?
19
2,012
IDAHO SUPPLEMENT
Page l5