2020Annual Report.pdf

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An lDAOORPCompanY
LISA D. NORDSTROM
Lead Counsel
[e-mail]
LDN:slb
Enclosures
IPC.E
April 15,2021
VIA ELECTRONIC FILING
Jan Noriyuki, Secretary
ldaho Public Utilities Commission
11331 W. Chinden Blvd., Bldg 8,
Suite 201-A (83714')
PO Box 83720
Boise, ldaho 83720-0074
Re: ldaho Power Company's2020 Annual FERC Form 1 Report
Dear Ms. Noriyuki
Pursuant to ldaho Code S 61.405, and Order No. 34622, attached for electronic filing
are ldaho PowerCompany's FERC Form 1 Reportand ldaho Supplementfortheyearending
December 31,2020. Also included is the IDACORP 2020 Annual Report.
!f you have any questions, please contact Regulatory Consultant Kelley Noe at208-
388-5736 or knoe@ida hooower.com
Very truly yours,
X* !.?(^t t,.*,
Lisa D. Nordstrom
THIS FILING IS
Item 1: E] An lnitial (Original)
Submission
OR tr Resubmission No. _
Form 1 Approved
OMB No.1902-0021
(Expires 1113012022)
Form 1-F Approved
OMB No.1902-0029
(Expires 1113012022)
Form 3-Q Approved
OMB No.1902-O2Os
(Expires 1113012022)
FERC FINANCIAL REPORT
FERC FORM No. 1: Annual Report of
Major Electric Utilities, Licensees
and Others and Supplemental
Form 3-Q: Quarterly Financial Report
These reports are mandatory underthe Federal PowerAct, Sections 3, 4(a), 304 and 309, and
18 CFR 141.1 and 141.400. Failure to report may result in criminal fines, civil penalties and
other sanctions as provided by law. The Federal Energy Regulatory Commission does not
consider these reports to be of confidential nature
Exact Lega! Name of Respondent (Company)
ldaho Power Company
Year/Period of Report
End of 20201Q4
FERC FORM No.1/3-Q (REV.02-04)
THIS FILING IS
Item 1: E An Initial(Original)
Submission
OR tr Resubmission No. _
Form 1 Approved
OMB No.1902-0021
(Expires 1'113012022\
Form 1-F Approved
OMB No.l902-0029
(Expires '1113012022)
Form 3-Q Approved
OMB No.1902-0205
(Expires 1113012022)
FERC FINANCIAL REPORT
FERC FORM No. 1: Annual Report of
Major Electric Utilities, Licensees
and Others and Supplemental
Form 3-Q: Quarterly Financial Report
These reports are mandatory underthe Federal PowerAct, Sections 3, 4(a), 304 and 309, and
18CFR141.1 and 141.400. Failuretoreportmayresultincriminal fines,civil penaltiesand
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 20201Q4
FERC FORM No.1/3-Q (REV.02-04)
Deloitte.Drlolth &Toudr llP
800 West Main Street
Suite 1400
Boise, lD 83702-7734
USA
Tel:[phone]
wwwdeloitte.com
INDEPENDENT AUDITORS' REPORT
ldaho Power Company
Boise,ldaho
We have audited the accompanying financial statements of tdaho Power Company (the "Company''),
which comprise the balance sheet-regulatory basis as of December 31, 2020, and the related
statements of income-regulatory basis, retained earnings-regulatory basis, and cash flows-
regulatory basis for the year then ended, included on pages 110 through 123 of the accompanying
Federal Energy Regulatory Commission Form 1, and the related notes to the financialstatements.
Management's Responsibility for the Financial Statements
Management is responsible for the preparation and fair presentation of these financial statements in
accordance with the accounting requirements of the Federal Energy Regulatory Commission as set forth
in its applicable Uniform System of Accounts and published accounting releases; this includes the design,
implementation, and maintenance of internal control relevant to the preparation and fair presentation
of financial statements that are free from material misstatement, whether due to fraud or error.
Auditors' Responsibility
Our responsibility is to express an opinion on these financial statements based on our audit. We
conducted our audit in accordance with auditing standards generally accepted in the United States of
America. Those standards require that we plan and perform the audit to obtain reasonable assurance
about whether the financial statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in
the financial statements. The procedures selected depend on the auditor's judgment, including the
assessment of the risks of material misstatement of the financial statements, whether due to fraud or
error. ln 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 internalcontrol. 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
ln our opinion, the regulatory-basis financial statements referred to above present fairly, in all material
respects, the assets, liabilities, and proprietary capital of ldaho Power Company as of December 31,
2020, and the results of its operations and its cash flows for the year then ended in accordance with the
accounting requirements of the Federal Energy Regulatory Commission as set forth in its applicable
Uniform System of Accounts and published accounting releases.
Basis of Accounting
As discussed in Note 1to the financial statements, these financial statements were prepared in
accordance with the accounting requirements of the Federal Energy Regulatory Commission as set forth
in its applicable Uniform System of Accounts and published accounting releases, which is a basis of
accounting other than accounting principles generally accepted in the United States of America. Our
opinion is not modified with respect to this matter.
Restricted Use
This report is intended solely for the information and use of the board of directors and management of
the Company and for filing with the Federal Energy Regulatory Commission and is not intended to be
and should not be used by anyone otherthan these specified parties.
D"UA,T)qL LLP
AprilL4,2O2L
-2-
This Page lntentionally Left Blank
FERC FORM NO. 1/3.Q:
IDENTIF!CATION
01 Exact Legal Name of Respondent
ldaho Power Company
02 Year/Period of Report
End of 20201Q4
03 Previous Name and Date of Change (if name changed during year)
ldaho Power Company tt
04 Address of Principal Office at End of Period (Sfreef, 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, CAO&Treasurer
07 Address of Contact Person (Sfreef, City, State, Zp 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) ffi An Original (2) fl A Resubmission
10 Date of Report
(Mo, Da, Yr)
04114t2021
ANNUAL CORPORATE OFFICER CERTIFICAT]ON
The undersigned officer certifies that:
I have examined this report and to the best of my knowledge, information, and belief all statements of fact contained in this report are conect 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
VP, Controller, GAO & Treasurer
03 Signature
Ken Petersen
04 Date Signed
(Mo, Da, Yr)
0411412021
Title 18, U.S.C. 1 001 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) 5l;Rn orisinat(2) l-lA Resubmission
Date of Report(Mo, Da, Yr)
041141202',1
Year/Period of Report
End of 2O2O|Q4
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 108-109
I Comparative Balance Sheet 110-113
9 Statement of lncome for the Year 1',t4-117
10 Statement of Retained Eamings for the Year 118-1't 9
11 Statement of Cash Flows 120-121
12 Notes to Financial Statements 122-123
13 Statement of Accum Comp lncome, Comp lncome, and Hedging Activities 't22(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(abl-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 256-2s7
34 Reconciliation of Reported Net lncome with Taxable lnc for Fed lnc Tax 261
35 TaxesAccrued, 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
ldaho Power Company
This Reoort ls:(1) 5]An orisinal(2) nA Resubmission
Date of Report(Mo, Da, Yr)
o411412021
Year/Period of Report
End of 2O2O|Q4
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
Line
No.
Title of Schedule
(a)
Reference
Page No.
(b)
Remarks
(c)
37 Other Defened Credits 269
38 Accumulated Deferred lncome Taxes-Accelerated Amortization Property 272-273 N/A
39 Accumulated Deferred lncome Taxes-Other Property 274-275
40 Accumulated Deferred lncome 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 310-31 1
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 E&enses 350-351
54 Research, Development and Demonstration Activities 352-353
55 Oistribution 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 Acc,ount 401
62 Monthly Peaks and Output 401
63 Steam Electric Generating Plant Statistics 402403
64 Hydroelectric Generating Plant Statistics 406-407
65 Pumped Storage Generating Plant Statistics 408-409 N/A
66 Generating Plant Statistics Pages 410411
FERC FORM NO.1 (ED. 12.96)Page 3
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5]Rn Orisinal(2) nA Resubmission
Date of Reoort(Mo, Da, Yi)
04t'14t2021
Year/Period of Report
End of 20201Q4
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none," "not applicable," or'NA".
Line
No.
Title of Schedule
(a)
Reference
Page No.
(b)
Remarks
(c)
67 Transmission Line Statistics Pages 422-423
68 Transmission Lines Added During the Year 424425
69 Substations 426-427
70 Transactions with Associated (Affi liated) Companies 429
71 Footnote Data 450
Stockholders' Reports Check appropriate box
f] Two copies will be submitted
E ruo 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 AnOriginal
(2) tr A Resubmission
Date of Report
(Mo, Da, Yr)
o41141202',1
Year/Period of Report
End of 2o2olQ4
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.
f,eD Petera€D, vice Presideat, Controller, CAO & Treasury, fdaho Power CompaDy
l22t w. Idaho St,reet,, P.O. Box 70, Bol.Be, 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.
Idabo, iruae 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 Appllcab1e
4. State the classes or utility and other services fumished by respondent during the year in each State in wttich
the respondent operated.
C1ass of Utlllty Servl.ce StsaEe
Electric Idaho
ElectrLc 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) ts No
FERC FORM No.l (ED.12-87)PAGE 101
Name of Respondent
ldaho Power Company
This Report ls:
(1) D0 An Original
(2) tr A Resubmission
Date of Report
(Mo, Da, Yr)
o411412021
Year/Period of Report
End of 2020tQ4
CONTROL OVER RESPONDENT
1. lf any corporation, business trust, or similar organization or a combination of such organizations jointly held
control over the repondent at the end of the year, state name of controlling corporation or organization, manner in
which control was held, and extent of control. lf control was in a holding company organization, show the chain
of ownership or control to the main parent company or organization. lf control was held by a trustee(s), state
name of trustee(s), name of beneficiary or beneficiearies for whom trust was maintained, and purpose of the trust.
ldaho Power Company is a subsidiary of IDACORP, INC
IDACORP owns 100% of ldaho Power Company's Common Stock.
IDACORP is a public utility Holding Company incorporated effective 10-1-1998
FERC FORM NO.1 (ED. t2-96)Page 102
Name of Respondent
ldaho Power Company
This(1)
(21
R6Dort
EAn
ls:
Original
nA Resubmission
Date of Report(Mo, Da, Yr)
04t14t2021
Year/Period of Report
End of 2O20lQ4
UUT{PUItA I IUNS UON I I{OLLEU BY RE,SPONDEN I
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 v'rho 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
13
14
15
16
17
18
19
20
21
22
23
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27
FERC FORM NO.1 (ED.12-96)Page 103
Name Respondent
ldaho Power Company )An (Mo, Da,
(2)A Resubmission 0411412021
Year/Period of Report
End of 20201Q4
OFFICERS
1. Report below the name, title and salary for each executive officer whose salary is $50,000 or more. An "executive officer" of a
respondent includes its president, secretary, treasurer, and vice president in charge of a principal business unit, division or function
(such as sales, administration or finance), and any other person who performs similar policy making functions.
2. lf a change was made during the year in the incumbent of any position, show name and total remuneration of the previous
incumbent, and the date the change in incumbency was made.
Ltne
No.
ilue
(a)
Name ol oftcer
(b)
salarvfor Yedr(c)
1 President & CEO, ldaho Power Company ('l)Darrel T. Anderson 930,000
2
3 President, ldaho Power Company Lisa A. Grow 675,000
4 President & CEO, ldaho Power Company (2)
5
6 Senior Vice President, CFO & Treasury (3)Steven R. Keen 480,000
7 Senior Vice President & CFO (4)
8
I Senior Vice President & General Counsel Brian R. Buckham 400,000
10
11 Senior Vice President & COO Adam J. Richins 400,000
12
13 Senior Vice President, Public Affairs Jefftey L. Malmen 335,000
14
15 Vice President, Power Supply (3)Tessia R. Park 315,000
16 Vice President, ldaho Power Company (4) and (8)
17
18 Vice President, Corporate Controller & CAO (3)Ken W. Petersen 285,000
19 Vice President, CAO & Treasurer (4)
20
21 Vice President, Regulatory Affairs Tim Tatum 245,000
22
23 Vice President, T&D Engineering & Construction (5)Ryan N. Adelman 225,000
24 Vice President, Power Supply (6)
25
26 Vice President, Human Resources Sarah E. Griffin 225,000
27
28 Vice President, Customer Operations & CSO Bo Hanchey 220,000
29
30 Corporate Secretary Patrick A. Hanington 235,000
31
32 Vice President, Corporate Services & Communiations Debra H. Leithauser 225,000
33
34 Vice President, Planning, Engineering & Construction (6)Mitch Colbum 200,000
35
36 Vice President, Power Supply (4) (7)Tom J. Harvey 220,000
37
38 Vice President, lnformation Technology & CIO (6)Jason C. Huszar 205,000
39
40 (1) Retired from position 5l30l20 (5) Vacated Position 8108120
41 Salary shows YTD wages (6) Appointed to position 8lOBl20
42 (2) Appointed to position 5l3Ol2O (7) Retired from position 8108120
43 (3) Vacated Position 3lo7l20 (8) Retired ftom position 410112020
44 (4) Appointed to position 3107120 Salaries show YTD wages
FERC FORM NO. 1 (ED. 12.96)Page 104
Name
ldaho Power Company
(1)
(2)
An Original
A Resubmission
(Mo, Da,
0411412021
Year/Period of Report
End of 2020tQ4
DIRECTORS
1. Report below the information called for conceming each director of the respondent who held ffice at any time during the year. lnclude in column (a), abbreviated
titles of the directors who are ofiicers of the respndent.
2. Designate members of the Executive Committee by a triple asterisk and the Chairman of the Executive Committee by a double asterisk.
LIIIENo Name (arl%i rue) or urreclor Fflnctpat E us r€ss Aodress
1 Judith A. Johansen 10446 E. Palo Brea Dr., Scottsdale, Arizona 85262
2
3 Christine King, Comp. Committee Chair,'**8527 East Old Field Rd
4 Scottsdale, Arizona 85266
5
6 Thomas E. Carlile 2719 North Woodview place, Boise ldaho 83702
7
I Danel T. Anderson President & CEO,'*'*'(2)1528 E. Garden Brook Drive, Eagle, ldaho 83616
I
10 Lisa A. Grow, President & CEO, ** *- (1) (3)ldaho Power Company, 1221 W.ldaho Street,
11 P.O. Box 70, Boise, ldaho 83707-0070
12
13 Richard J. Dahl, Board Chair & Corp Gov Chair, *'*P.O. Box 2052, McCall, ldaho 83638
14
15 Dennis L. Johnson 926 W Oakhampton Dr, Eagle, ldaho 83616
16
17 Ronald W. Jibson 417 Aerie Circle, North Salt Lake City, Utah 84054
18
19 Richard J. Navarro, Audit Chair, '*'1256 E. Candleridge Ct., Boise, ldaho 83712
20
21 Annette G. Elg 3475 E. Rivemest Lane, Boise, ldaho 83706-6928
22
23 Odette C. Bolano (4)1055 N. Curtis Rd., Boise, ldaho 83706
24
25 (1) Appointed to Board on February 13, 2020.
26 (2) Retired as President, CEO & Chair of Executive Committee
27 on May 30, 2020. Remained a Director of the Board
28 (3) Appointed President, CEO & Chair of Executive Committee
29 on May 30, 2020.
30 (4) Appointed to Board on September 16,2020.
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) [l A Resubmission
Date of Report(Mo, Da, Yr)
o41141202',1
Year/Period of Report
En6 61 2020/Q4
INFORMATION ON FORMULA RATES
FERC Rate Schedule/Tariff Number FERC Proceeding
Does the respondent have formula rates?[| ves
fl No
1 Please list the Commission accepted formula rates including FERC Rate Schedule or Tariff Number and FERC proceeding (i.e. Docket No)
accepting the rate(s) or changes in the accepted rate.
Lrne
No.FERC Rate Schedule or Tariff Number FERC Proceeding
1 FERC Electric Tariff
2
3
4
5
6
7
8
I
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
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28
29
30
31
32
33
34
35
36
37
38
39
40
41
FERC FORM NO. 1 (NEW. 12-08)Page 106
ls
ldaho Power Company ()An Original
A Resubmission(2)
Date of Report(Mo, Da, Yr)
0411412021
Year/Period of Report
gn6 61 2020/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 ves
ENo
2. lf yes, provide a listing of such filings as contained on the Commission's eLibrary website
Line
No.Accession No.
Document
Date
\ Filed Date Docket No.Description
Formula Rate FERC Rate
Schedule Number or
Tariff Number
1 20200828-5297 08t28t2020 ER09-1641-000 ldaho Power Compan FERC Electric Tariff
2 2020 Annue
3 lnformational Filin!
4 under ER09-1641-001
5
6
7
8
I
10
't1
12
13
't4
15
16
17
18
19
20
21
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43
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46
FERC FORM NO. r (NEW.12.08)Page 106a
This Page lntentionally Left Blank
Name of Respondent
ldaho Power Company
This Reoort ls:(1)E An Original
(2) [-1 A Resubmission
Date of Report(Mo, Da, Yr)
04t14t2021
Year/Period of Report
En6 e1 2020/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 ftom 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
I
I
10
11
12
't3
14
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FERC FORM NO.1 (NEW. 12-08)Page 106b
Name of Respondent
ldaho Power Company
This Report ls:
(1)
(2)
An Original
A Resubmission
L'ate ol Report
04114t2021
YeailPenod ot t(eport
End of 20201Q4
IMPORTANT CHANGES DURING THE OUARTER/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 joumal entries called for by the Uniform System of Accounts
were submitted to the Commission.
4. lmportant leaseholds (other than leaseholds for natural gas lands) that have been acquired or given, assigned or surrendered: Give
effective dates, lengths of terms, names of parties, rents, and other condition. State name of Commission authorizing lease and give
reference to such authorization.
5. 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 otherwise, 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 guarantees including issuance of short-term
debt and commercial paper having a maturity of one year or less. Give reference to FERC or State Commission authorization, as
appropriate, and the amount of obligation or guarantee.
7. Changes in articles of incorporation or amendments to charter: Explain the nature and purpose of such changes or amendments.
8. State the estimated annual effect and nature of any important wage scale changes during the year.
9. State briefly the status of any materially important legal proceedings pending at the end of the year, and the results of any such
proceedings culminated during the year.
10. Describe briefly any materially important transactions of the respondent not disclosed elsewhere in this report in which an officer,
director, security holder reported on Page 104 or 105 of the Annual Report Form No. 1, voting trustee, associated company or known
associate of any of these persons was a party or in which any such person had a material interest.
't1. (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
occurred during the reporting period.
14. ln the event that the respondent participates in a cash management program(s) and its proprietary capital ratio is less than 30
percent please describe the significant events or transactions causing the proprietary capital ratio to be less than 30 percent, and the
extent to which the respondent has amounts loaned or money advanced to its parent, subsidiary, or affiliated companies through a
cash management program(s). Additionally, please describe plans, if any to regain at least a 30 percent proprietary ratio.
PAGE 108 INTENTIONALLY LEFT BLANK
SEE PAGE 109 FOR REQUIRED INFORMATION
FERC FORM NO.1 (ED.12,96)Page 108
Name of Respondent
ldaho Power Comoanv
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t14t2021
Year/Period of Report
2020to,4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
1- None
2- None
3- None
4. None
5- None
6. ln June 202Q ldaho Power issued $gO million in principal amount of its 1.90 percent first mortgage
bonds, secured medium term notes, Series l, maturing July 15, 2O30. ln April 2O20, ldaho Power
issued an additional $230,0 million in principal amount of .?:ffiofirst mortgage bonds, secured
medium-term notes, Series K, maturing on March 1, 2048, bringing the total principal amount of
Series K bonds ouGtanding to $45O million. The bonds were issued at a premium of approximately
$Sa million. ln April and May 2019, ldaho Power received orders from the IPUC, OPUC, and WPSC
authorizing the company to issue and sellfrom time to time of up to Ssm million in aggregate
principal amount of debt securities and first mortgage bonds, subject to conditions specified in the
orders,
7- None
8. Effective LZl26l2O, a 2.75% general wage adjustment rcras implemented.
9. None
10- None
11. Reserved
12- None
13. Officer Changes in 2020:
r Darrel T. Anderson retired as CEO of ldaho Power on May 3O, 2020.
r Usa A. Grow was appointed CEO of ldaho Power on May 3q 2020.
Director Changes in 202O:
o Odette C. Bolano was appointed to the Board on September 16,2020.
o Darrel T. Anderson retired as Chair of the Executive Committee on May 30, 2020.r Lisa A. Grow was appointed Chair of the Executive Committee on May 30, 2020-
14- ldaho Power and its unregulated parent IDACORP have separate cash management programs (separate bank
accounts, liquidity facilities, short-term debt and investment programs). l{o money has been loaned or
advanced from ldaho Power to IDACORP through a cash management program.
FERC FORM NO. 1 (ED. 12.96)Pase 109.1
Name of Respondent
ldaho Power Company
This Report ls:
(1) tr An Original
(2) ! A Resubmission
Date of Report
(Mo, Da, Yr)
0411412021
Year/Period of Report
End of 202ola4
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Line
No.Title of Account
(a)
Ref.
Page No.
(b)
Cunent Year
End of QuarterfYear
Balance
(c)
Prior Year
End Balance
1213'.1
(d)
1 UTILITY PLANT
2 Utility Plant ('101-106, 114)200-201 6,287,898,77e 6,117,438,884
3 Construction Work in Progress (107)200-201 597,151,634 552,498,787
4 TOTAL Utility Plant (Enter Total of lines 2 and 3)6,885,050,41:6,669,937,671
5 (Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 11'1, 115)200-20'l 2,376,165,417 2,341,467,978
6 Net Utility Plant (Enter Total of line 4 less 5)4,508,884,99€4,328,469,693
7 Nuclear Fuel in Process of Ref., Conv.,Enrich., and Fab. (120.1)202-203 c 0
8 Nuclear Fuel Materials and Assemblies-Stock Account (120.2)c 0
I Nuclear Fuel Assemblies in Reactor (120.3)c 0
10 Spent Nuclear Fuel (120.4)c 0
11 Nuclear Fuel Under Capital Leases (120.6)c 0
12 (Less) Accum. Prov. for Amort. of Nucl. Fuel Assemblies (120.5)202-203 c 0
13 Net Nuclear Fuel (Enter Total of lines 7-11 less 12)c 0
14 Net Utility Plant (Enter Total of lines 6 and 13)4,508,884,99€4,328,469,693
15 Utility Plant Adjustments (116)c 0
16 Gas Stored Underground - Noncunent (1 1 7)c 0
17 OTHER PROPERTY AND ]NVESTMENTS
18 Nonutility Property (12'l )5,125,74C 3,653,100
19 (Less) Accum. Prov. for Depr. and Amoft. (122)3,613 0
20 lnvestments in Associated Companies (123)c 0
2',1 lnvestment in Subsidiary Companies (123.1)224-225 33,918,13C 25,515,916
22 (For Cost of Account 1 23.1 , See Footnote Page 224, line 42)
23 Noncurrent Portion of Allowances 228-229 c 0
24 Other lnvestments (124)c 0
25 Sinking Funds (125)c 0
26 Depreciation Fund (126)c 0
27 Amortization Fund - Federal (127)c 0
28 Other Special Funds (128)50,732,85C 42,737,920
29 Special Funds (Non Major Onlv) (129)c 0
30 Long-Term Portion of Derivative Assets (175)c 0
31 Long-Term Portion of Derivative Assets - Hedges (176)c 0
32 TOTAL Other Property and lnvestments (Lines 18-21 and 23-31\89,773,107 71,906,936
33 CURRENT AND ACCRUED ASSETSuCash and Workino Funds (Non-maior Only) (130)c 0
35 Cash (131)125,554,3't5 72,428,510
36 Special Deposits (132-134)2,702,913 4,254,912
37 Workins Fund (135)11,50C 1 1,500
38 Temporary Cash lnvestments (136)40,038,00s 26,510,194
39 Notes Receivable (141)c -81,730
40 Customer Accounts Receivable ('l 42)77,599,924 74,131,805
41 Other Accounts Receivable (143)10,22338/13,107,045
42 (Less) Accum. Prov. for Uncollectible Acct.-Credit (144)5,263,704 1,744,072
43 Notes Receivable ftom Associated Companies (145)10,088,722 20,021,988
44 Accounts Receivable from Assoc. Companies (146)c 0
45 Fuel Stock (151)227 31,645,944 57,447,554
46 Fuel Stock Expenses Undistributed (152)227 c 0
47 Residuals (Elec) and Extracted Products (153)227 c 0
48 Plant Materials and Operating Supplies (154)227 62,'t78,34C 54,238,962
49 Merchandise (155)227 c 0
50 Other Materials and Supplies (156)227 c 0
51 Nuclear Materials Held for Sale (157)202-203t227 (0
52 Allowances (158.1 and 158.2)228-229 (0
FERC FORM NO.1 (REV.12-O3l Page 110
Name of Respondent
ldaho Power Company
This Report ls:
(1) tr An Original
(2) tr A Resubmission
Date of Report
(Mo, Da, Yr)
04t14t2021
Year/Period of Report
End of 2o20t04
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBlTSlcontinued)
Line
No.Title of Account
(a)
Ref.
Page No.
(b)
Cunent Year
End of Quarterffear
Balance
(c)
Prior Year
End Balance
't2131
(d)
53 (Less) Noncunent Portion of Allowances (0
54 Stores Expense Undistributed (163)227 2,762,s2'l 2,420,600
55 Gas Stored Underground - Cunent (164.1)c 0
56 Liquefied Natural Gas Stored and Held for Processing (164.2-164.3)(0
57 Prepayments (165)20,05711e 17,520,138
58 Advances for Gas (166-167)(0
59 lnterest and Dividends Receivable (171)20,121 169,371
60 Rents Receivable (172)(0
61 Accrued Utility Revenues (173)72,461,180 64,545,373
62 Misccllaneous Current and Accrued Assets (174)0 0
63 Derivative lnstrument Assets (1 75)1,995,125 404,9',t7
64 (Less) Long-Term Portion of Derivative lnstrument Assets (175)0 0
65 Derivative lnstrument Assets - Hedses (176)0 0
66 (Less) Long-Term Portion of Derivative lnstrument Assets - Hedoes (176 0 0
67 Total Cunent and Accrued Assets (Lines 34 throuqh 66)452,075,418 405,387,067
68 DEFERRED DEBITS
69 Unamortized Debt Expenses (181)16,434,065 14,38/.,541
70 Extraordinary Property Losses (182.1 )23Oa 0 0
7',!Unrecovered Plant and Regulatory Study Costs (182.2)230b 0 0
72 Other Regulatory Assets (182.3)232 1,s58,894,709 1,383,0s9,324
73 Prelim. Survey and lnvestigation Charges (Electric) (183)0 0
74 Preliminary Natural Gas Survey and lnvestigation Charges 183.1)0 0
75 Other Preliminary Survey and lnvestigation Charges (183.2)0 0
76 Clearing Accounts (1 84)572,323 2,1',t1,199
77 Temporary Facilities (1 85)0 0
78 Miscellaneous Defened Debits (186)233 73,302,886 71,312,712
79 Def. Losses from Disposition of Utility Plt. (187)0 0
80 Research, Devel. and Demonstration Expend. (188)352-353 0 0
81 Unamortized Loss on Reaquired Debt (189)42,496,351 41,772,825
82 Accumulated Deferred lncome Taxes (190)2U 343,510,457 302,161,031
83 Unrecovered Purchased Gas Costs (191)0 0
84 Total Deferred Debits (lines 69 through 83)2,035,210,791 1 ,814,801 ,632
85 TOTAL ASSETS (lines 14-16, 32,67, and 84)7,085,944,312 6,620,565,328
FERC FORM NO.1 (REV.12-03)Page 111
Name of Respondent
ldaho Power Company
This Report is:
(1) tr An Original
(2) tr A Resubmission
Date of Report
(mo, da, yr)
o411412021
Year/Period of Report
end of 20201Q4
coMpARATtVE BALANCE SHEET (LlABtLtTrES AND OTHER CREDTTS)
Line
No.TiUe of Account
(a)
Ref.
Page No.
(b)
Current Year
End of Quarterffear
Balance
(c)
Prior Year
End Balance
1?,31
(d)
1 PROPRIETARY CAPITAL
2 Common Stock lssued (201)250-251 97,877,030 97,877,030
3 Prefened Stock lssued (204)250-251 0 0
4 Capital Stock Subscribed (202, 205)0 0
5 Stock Liability for Conversion (203, 206)0 0
6 Premium on Capital Stock (207)712,257,435 712,257,435
7 Other Paid-ln Capital (208-21 1)2s3 0 0
8 lnstallments Received on Capital Stock (212)252 0 0
I (Less) Discount on Capital Stock (213)254 0 0
10 (Less) Capital Stock Expense (214)254b 2,096,925 2,096,925
11 Retained Earninqs Q15, 215.1, 2'16\'t 18-119 1,567,699,558 1,480,751,865
12 Unappropriated Undistributed Subsidiary Eamings (216.1 )118-1't9 31,455,037 23,0s2,822
13 (Less) Reaquired Capital Stock (217)250-251 0 0
14 Noncorporate Proprietorship (Non-major only) (218)0 0
15 Accumulated Other Comprehensive lncome (219)122(alb\-43,357,680 -36,283,823
16 Total Proprietary Capital (lines 2 through 15)2,363,834,455 2,275,558,404
17 LONG-TERM DEBT
18 Bonds (221 )256-257 't,970,460,000 1,835,460,000
19 (Less) Reaquired Bonds (222)256-257 0 0
20 Advances ftom Associated Companies (223)256-257 0 0
21 Other Long-Term Debt (224)256-257 19,885,000 19,885,000
22 Unamortized Premium on Long-Term Debt (225)30,072,454 0
23 (Less) Unamortized Discount on Long-Term Debt-Debit (226)3,569,137 4,30't,181
24 Total Long-Term Debt (lines 18 through 23)2,016,848,317 1 ,85't ,043,8't9
25 OTHER NONCURRENT LIABILITIES
26 Oblisations Under Capital Leases - Noncunent (227)0 0
27 Accumulated Provision for Property Insurance (228.1)0 0
28 Accumulated Provision for lnjuries and Damages (228.2)2,484,902 1,748,351
29 Accumulated Provision for Pensions and Benefits (228.3)63/.,271,974 519,659,093
30 Accumulated Miscellaneous Operating Provisions (228.4)0 0
31 Accumulated Provision for Rate Refunds (229)169,094,604 152,686,978
32 Long-Term Portion of Derivative lnstrument Liabilities 0 23,99s
33 Long-Term Portion of Derivative lnstrument Liabilities - Hedges 0 0
34 Asset Retirement Obligations (230)27,691,367 28,',t91,027
35 Total Other Noncunent Liabilities (lines 26 through 34)833,542,U7 702,309,444
36 CURRENT AND ACCRUED LIABILITIES
37 Notes Payable (231)0 0
38 Accounts Pavable (2321 143,690,430 134,005,122
39 Notes Payable to Associated Companies (233)0 0
40 Accounts Payable to Associated Companies (234)1,720,105 2,0s3,220
41 Customer Deposits (235)1,206,944 1,070,057
42 Taxes Accrued (236)262-263 14,568,240 2,114,255
43 lnterest Accrued (237)24,229,679 21,222,675
44 Dividends Declared (238)0 0
45 Matured Long-Term Debt (239)0 0
FERC FORM NO.1 (rev.12-03)Page 112
Name of Respondent
ldaho Power Company
This Report is:
(1) tr AnOriginal
(2) tr A Resubmission
Date of Report
(mo, da, yf
04t1412021
Year/Period of Report
end of 20201Q4
COMPARATIVE BALANCE SHEET (LlABlLlTlES AND OTHER CREDIT$ntinued)
Line
No Tiile of Account
(a)
Ref.
Page No.
(b)
Cunent Year
End of Quarterl/ear
Balance
(c)
Prior Year
End Balance
't2t31
(d)
46 Matured lnterest (240)c 0
47 Tax Collections Payable (241)1,401,632 2,682,810
48 Miscellaneous Current and Accrued Liabilities (242)72,126,39C 68,348,276
49 Obligations Under Capital Leases-Cunent (243)c 0
50 Derivative lnstrument Liabilities (244)143,733 846,256
51 (Less) Long-Term Portion of Derivative lnstrument Liabilities c 23,995
52 Derivative lnstrument Liabilities - Hedses (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)259,087,153 232,318,676
55 DEFERRED CREDITS
56 Customer Advances for Construction (252)5,709,312 6,01 1,590
57 Accumulated Deferred lnvestment Tax Credits (255)266-267 97,626,76S 94,805,870
58 Deferred Gains from Disposition of Utility Plant (256)c 0
59 Other Defened Credits (253)269 9,649,332 8,035,785
60 Other Regulatory Liabilities (254)278 319,77S,04C 349,006,644
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)970,61 1,662 933,,+69,366
64 Accum. Defened lncome Taxes-Other (283)209,255,425 168,00s,730
65 Total Defened Credits (lines 56 through 64)1,612,631,54C 1,559,334,985
66 TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65)7.085,944,312 6,620,565,328
FERC FORM NO.1 (rev.12-03)Page 113
Name of Respondent
ldaho Power Company
This Report ls:(1) []An Original(2) nA Resubmission
Date of Reoort(Mo, Da, Yi)
04t't4t2021
Year/Period of Report
End of 202OlQ4
STATEMENT OF INCOME
Quarterly
1. Report in column (c) the current year to date balance. Column (c) equals the total of adding the data in column (g) plus the data in column (i) plus the
data in column (k). Report in column (d) similar data for the previous year. This information is reported in the annual filing only.
2, Enter in column (e) the balance for the reporting quarter and in column (f) the balance for the same three month period for the prior year.
3. Report in column (g) the quarter to date amounts for electric utility function; in column (i) the quarter to date amounts for gas utility, and in column (k)
the quarter to date amounts for other utility function for the cunent year quarter.
4. Report in mlumn (h) the quarter to date amounts for electric utility function; in column (j) the quarter to date amounts for gas utility, and in column (l)
the quarter to date amounts for other utility function for the prior year quarter.
5. lf additional columns are needed, place them in a footnote.
Annual or Quarterly if applicable
5. Do not report fourth quarter data in columns (e) and (f)
6. Report amounts for accounts 412 and 413, Revenues and Expenses from Utility Plant Leased to Others, in another utility columnin a similar manner to
a utility department. Spread the amount(s) over lines 2 thru 26 as appropriate. lnclude these amounts in columns (c) and (d) totals.
7. Report amounts in account 414, Other Utility Operating lncome, in the same manner as ac@unts 412 and 413 above.
Line
No
Title of Account
(a)
(Ref.)
Page No.
(b)
Total
Cunent Year to
Date Balance for
QuarterlYear
(c)
Total
Prior Year to
Date Balanca for
Quarlerffear
(d)
Cunent 3 Months
Ended
Quartedy Only
No 4th Quarter
(e)
Prior 3 Monhs
Ended
Quartedy Only
No 4h Quarter
(0
,|UTILITY OPERATING INCOME
2 Operating Revenues (400)300-301 1,347,383,706 1,343,223,427
3 Operaling Expenses
4 Operalion Expenses (401)320-323 771,917,303 774,637,775
5 Maintenance Expenses (402)320-323 5E,598,841 65,021,961
6 Depreciation Expense (403)336-337 162,750,617 160,145,693
7 Depreciation Expense for Asset Retirement Costs (403.1)336-337 431,877 566,665
8 Amort. & Depl. of Utility Plant (404-405)336-337 7,981,84E 7,169,554
9 Amort of Utility Plant Acq. Adj. (406)336-337 15,018 15,018
10 Amort. Property Losses, Unrecov Plant and Regulatory Study CosE (407)
11 Amorl of Conversion Expenses (407)
12 Regulatory Debits (407.3)8,81 1,905 8,730,s18
13 (Less) Regulatory Credits (407.4)3,815,566 3,221,217
14 Taxes Otrer Than lncome Taxes (408.1)262-263 33,047,693 34,045,010
15 lncome Taxes - Federal (409.1)262-263 26,204,174 18,660,529
16 - Other (409.1)262-263 6,286,25E 4,663,949
17 Provision br Defened lncome Taxes (410.1)234,272-277 27,020J24 25,440,561
18 (Less) Provision for Deferred lncome Taxes-Cr. (41 1.1 )234,272-277 33,253,251 15,033,334
't9 lnvestnent Tax Credit Adj. - Net (41 1.4)266 2,820,E99 2,016,034
20 (Less) Gains from Disp. of Utility Plant (41 1.6)
21 Losses tom Disp. of Utility Plant (41 1.7)
22 (Less) Gains from Disposition ofAllowances (41 1.8)269,3s4 284,s04
23 Losses from Disposition ofAllowances (411.9)
24 Accretion Expense (41 1 .1 0)176,633 232,951
25 TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24)1,067,861,265 1,073,479,265
26 Net Util Oper lnc (Enter Tot line 2 less 25) Carry to P9117 ,line 27 279,522,441 269,744,',t62
FERC FORM NO. 1r3-Q (REV.02-04)Pagc 114
Name of Respondent
ldaho Power Company (2)A Resubmission
Date of Report
(Mo, Da, Yr)
o4t't4t2021
Year/Period of Report
End of 2O20lQ4
STATEMENT OF INCOME FOR THE YEAR
9. Use page 122lor imgorlant notes regarding the statement of income for any account thereof.
10. Give concise explanations conceming unsettled rate proceedings where a contingency eists 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 nevenues 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.
I 1 Give concise explanations conceming significant amounE 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. lt any notes appearing in the report to stokholders are applicable to the Statement of lncome, such notes may be included algage'l'22.
1 3. Enter on page 122 a concise explanation of only those changes in accounting methods made during the year which had an effect on net income,
including the basis of allocations and apportionments from those used in the preceding year. Also, give the appropriate dollar effect of such changes.
14. Explain in a footnote if the previous year's/quarter's figures are different from that reported in prior reports.
15. 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.
Gunent Year to Date
(in dollars)
(s)
Previous Year to Date
(in dollars)
(h)
Cunent Year to Date
(in dollars)
(i)
Previous Year to Date
(in dollars)
0)
cunent Year to Date
(in dollars)
(k)
Previous Year to Date
(in dollam)
(t)
't
1,347,383,706 1,343,223,427 2
3
771,917,303 774,637,775 4
s8,598,841 65,021,961 5
162,7s0,617 160,145,693 6
431,877 566,665 7
7,981,848 7,169,554 I
15,018 15,018 o
10
11
8,811 ,90s 8,730,518 't2
3,81s,566 3,221,217 13
33,047,693 34,04s,010 14
26,204,174 18,660,529 15
6,286,258 4,663,949 16
27,020,124 25,440,561 't7
33,253,251 15,033,334 18
2,820,899 2,016,034 19
20
2',1
269,354 2U,504 22
23
176,633 232,951 24
't,067,861,265 1,073,479,265 25
279,522,U1 269,744,162 26
FERC FORM NO.1 (ED. 12-96)Page i15
This Page lntentionally Left Blank
Name of Respondent
ldaho Power Company
This Reoort ls:(1) fiRn Originat(2) ;-1A Resubmission
Date of Reoort
(Mo, Da, Yi)
04t14t2021
Year/Period of Report
End of 2O20lQ4
Line
No.
Title of Account
(a)
(Ref.)
Page No.
(b)
TOTAL
Ended
Quarterly 0nly
No 4h Quarter
(e)
Hnor J Monns
Ended
Quailedy Only
No 4h Quarter
(0
Cunent Year
(c)
Previous Year
(d)
27 Net Utility Operating Income (Canied forward from page '114)279,522,M1 269,744,162
28 Offter lncome and Deductions
29 O$er lncome
30 Nonulilty Operating Income
31 Revenue From Merchandisins, Jobbing and Conhac-t Work (415)4,409,044 3,913,358
32 (Less) Cosb and Exp. of Merchandisinq, Job. & Conbacl Work (416)4,633,866 4.427,209
33 Revenues From Nonulility Operations (417)20,293 22,503
34 (Less) Expenses of Nonutility Operations (4'17.1)60,764 30,125
35 NonoDerating Renlal lnome (41E)449 -53,401
36 Equity in EaminEs of Subsidiary Companies (418.1)119 8.402.214 8,489,145
37 lnterest and Dividend lnome (419)9,877,262 10,967,s95
38 Alloilance br Oher Funds Used Durinq Construc.tion (419.1)29,550,610 27,112,279
39 Miscellaneous Nonoperaling lncome (421 )993,561 43s,869
40 Gain on Disposition of Prop*ty (42'1.1)8,399
41 TOTAL Oher lncome (Enter Total of lines 31 hru 40)48,566,304 46,430,014
42 Oher lncome Deduclions
43 Loss on Disposition of Property (421.2)26,488
44 Miscellaneous Amortization (425)
45 Donations (426.1)1,876,276 824,587
46 Life Insurance (426.2)4,035,855 4,104,372
47 Penalties (426.3)16,172 56,757
48 Exp. for Certain Civic, Polilical & Related Aclivities (426.4)91 1,610 1,039,769
49 Oher Dedudions (426.5)8,737.704 7,2E3,056
50 TOTAL Oher lncome Dedudions (Total of lines 43 hru 49)7,532,395 5,099,797
51 Taxes Applic. to Other lncome and Deduc{ions
52 Taxes O$er Than lncome Taxes (408.2)262-263 19,147 23,370
53 lncome Taxes-Federal (409.2)262-263 406,255 893,1 17
il lncome Taxes0her (409.2)262-263 122,919 271,449
55 Provision hr Defened lnc. Taxm (410.2)234,272-277 I 1 1,185 7
56 (Less) Provision for Defened lncome Taxes-Cr. (41 1.2)234,272:277 726,433 1,2s0,246
57 lnvestment Tax Credit Adi.-Net (4'11.5)
58 (Less) lnvestment Tax Credib (420)
59 TOTAL Taxes on Oher lncome and Dedudions (Total oflines 52-58){6,927 $2,303
60 Net 0her lncome and Deduc'tions (Total of lines 41, 50, 59)41,1 00,836 41,392,520
61 lnterest Charges
62 lnterost on Long-Term Debt (427)84,250,809 82,457,050
63 Amort of Debt Disc. and Expense (428)1,433,636 1.318.427
64 Amortization of Loss on Reaquired Debt (428.1)2.735.194 2,530,546
65 (Less) Amorl of Premium on Debt4redit (429)823,920
66 (Less)Amortization of Gain on Reaquired Debt-Credit (429.1)
67 lnterest on Debt to Assoc. Companies (430)287,350
68 O$er lnter*l ExDonse (431)I 1,370.843 10,809,334
69 (Less) Allowance for Bonowed Funds Used Durino Constuclion-Cr. (432)11,577.828 10,702,847
70 Net lnterest Charges (Total of lines 62 hru 69)87.388.734 86,699,860
71 lncome Before Extaordinary ltems (Total of lines 27, 60 and 70)233,234,543 224,436,822
72 Extraordinary ltems
73 Exbaordinary lncome (434)
74 (Less) Extaordinary Deduciions (435)
75 Net Extraordinary ltems (Iotal of line 73 less line 74)
76 lncome Taxes-Federal and Oher (409.3)262-263
77 Extraordinary ltems After Taxes (line 75 less line 76)
78 Net lnome (Tohlof line 71 and 77)233,234,543 224,436,822
FERC FORM NO. 1/3-Q (REV. 02-04)Page ll1
ldaho Porer Company (21 A Resubmission
Date of Reoort(Mo, Da, Yi)
0411412021
Year/Period of Report
End of 2020/Q4
STATEMENT OF RETAINED EARNINGS
1. Do not report Lines 4$53 on the quarterly version.
2. Report all changes in appropriated retained eamings, unappropriated retained earnings, year to date, and unappropriated
undistributed subsidiary eamings for the year.
3. Each credit and debit during the year should be identified as to the retained eamings account in which recorded (Accounts 433, 436
- 439 inclusive). Show the contra primary account affected in column (b)
4. State the purpose and amount of each reservation or appropriation of retained 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
recunent, 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
Account Affected
(b)
Cunent
Quarterffear
Year to Date
Balance
(c)
Previous
QuarterlYear
Year to Date
Balance
(d)
UNAPPROPRIATED RETAINED EARNINGS (Account 2'l 6)
1 Balance-Beginning of Period 1.467.478.759 1,341,408,600
2 Changes
3 Adiustments to Retained Eaminos (Account 439)
4
5
6
7
8
I TOTAL Credits to Retained Eamings (Acct. 439)
10
'11
12
13
14
15 TOTAL Debits to Retained Eaminss (Accl. 439)
16 Balance Transfened from lncome (Account 433 less Account 418.1)224.832,329 215,947,677
17 Appropriations of Retained Eamings (Acct. 436)
18
19
20
21
22 TOTAL Appropriations of Retained Eamings (Acct. 436)
23 Dividends Declared-Prefened Stock (Account 437)
24
25
26
27
28
29 TOTAL Dividends Declared-Prefened Stock (Acct. 437)
30 Dividends Declared-Common Stock (Account 438)
31 -137,884,636 ( 129,877,s18)
32
33u
35
36 TOTAL Dividends Declared-Common Stock (Acct. 438)-137,884,636 ( 129,877,s18)
37 Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings 40,000,000
38 Balance - End of Period Ootal 1,9,15,16,22,29,36,37)1,554,426,452 1,467,47E,759
APPROPRIATED RETAINED EARNINGS (Account 215)
39
40
FERC FORM NO. tr3-Q (REv. 02-0/t)Page 118
ldaho Power Company (1)
(2)
(Mo, Da
A Resubmission 0411412021
Year/Period of Report
End of 2020/Q4
STATEMENT OF RETAINED EARNINGS
1. Do not report Lines 49-53 on the quarterly version.
2. Report all changes in appropriated retained earnings, unappropriated retained earnings, year to date, and unappropriated
undistributed subsidiary earnings for the year.
3. Each credit and debit during the year should be identified as to the retained eamings account in which recorded (Accounts 433, 436
- 439 inclusive). Show the contra primary account affected in column (b)
4. State the purpose and amount of each reservation or appropriation of retained eamings.
5. List first account 439, Adjustments to Retained Eamings, reflecting adjustments to the opening balance of retained 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 inmme tax effect of items shown in account 439, Adjustments to Retained Eamings.
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
Account Affected
(b)
Cunent
Quarterffear
Year to Date
Balance
(c)
Previous
Quarter/Year
Year to Date
Balance
(d)
41
42
43
44
45 TOTAL Appropriated Retained Eamings (Account 215)
APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Account 215.'l)
46 TOTAL Approp. Retained Eamings-Amort. Reserve, Federal (Acct. 215.1)1 3,273,1 06 I 3,273,106
47 TOTAL Approp. Retained Eamings (Acct. 215, 215.1) (Total 45,46)13,273,106 13,273,'106
48 TOTAL Retained Eaminqs (Acct.215, 215.1,2161(Total 38, 471(216.11 1,567,699,558 1,480,751,865
UNAPPROPRIATED UNOISTRIBUTED SUBSIDIARY EARNINGS (Account
Report only on an Annual Basis, no Quarterly
49 Balance-Beginning of Year (Debit or Credit)23,052,822 54,563,677
50 Equity in Eaminss for Year (Credit) (Account 41 8.1 )8,402,214 8,489,145
51 (Less) Dividends Received (Debit)40,000,000
52
53 Balance-End of Year (Total lines 49 thru 52)31,455,036 23,0s2,822
FERC FORM NO. 1/3.Q (REV. 02.04)Page 119
An (Mo, Da,ldaho Power Company (2t A Resubmission o411412021
Year/Period of Report
End of 202OlQ4
STATEMENT OF CASH FLOWS
(1 ) Codes to be used:(a) Net Proceeds or Payments(b)Bonds, debentures and other long-term d€bt; (c) lnclude commercial pape[ and (d) ldentiry separately such items as
investm€nts, fixed assets, intanglbles, etc.
Equivalsnts at End of Period'with related amounts on the Balarre Sheel
in those activities. Show in the Notes to the Financials the amounts of intorest paid (net of amount capitalized) and incomo 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 @st.
Line
No.
Description (See lnstruction No. 1 for Explanation of Codes)
(a)
Current Year to Date
QuarterfYear
(b)
Previous Year to Date
Quarter^fear
(c)
1 Net Cash Flow from Operating Activities:
2 Net lncome (Line 78(c) on page 1 17)233,234,543 224,436,822
3 Noncash Charges (Credits) to lncome:
4 Depreciation and Depletion 160,712,358
5 Amortization of '13,015,188 12,492,435
6
7
8 Defened lncome Taxes (Net)2,469,437 17,892,072
I lnvestment Tax Credit Adjustment (Net)977,780 698,798
10 Net (lncrease) Decrease in Receivables 1,633,004 -4,934,190
11 Net (lncrease) Decrease in lnventory 17,542,513 -11,114,3',12
12 Net (lncrease) Decrease in Allowances lnventory
13 Net lncrease (Decrease) in Payables and Accrued Expenses -8,690,771
14 Net (lncrease) Decrease in Other Regulatory Assets -54,530,690 -19,029,252
15 Net lncrease (Decrease) in Other Regulatory Liabilities 18,284,774 14,719,4',t2
16 (Less) Allowance for Other Funds Used During Construction 29,5s0,610 27,112,279
17 (Less) Undistributed Earnings fom Subsidiary Companies -1 ,531,052 €,936,420
18 Other (provide details in footnote):-23,495,357
19
20
21
22 Net Cash Provided by (Used in) Operating Activities (Total 2 thru 21)354,060,106 343,512,156
23
24 Cash Flows from lnvestment Activities:
25 Construction and Acquisition of Plant (including land):
26 Gross Additions to Utility Plant (less nuclear fuel)-305,819,097
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 -29,5s0,610 -27,112,279
31 Other (provide details in footnote):6,561,916
32
33
34 Cash Outflows for Plant (Total of lines 26 thru 33)-304,121,291 -272,144,902
35
36 Acquisition of Other Noncunent Assets (d)
37 Proceeds from Disposal of Noncunent Assets (d)
38
39 lnvestments in and Advances to Assoc. and Subsidiary Companies -81,730 -3,013
40 Contributions and Advances from Assoc. and Subsidiary Companies
41 Disposition of lnvestments in (and Advances to)
42 Associated and Subsidiary Companies
43
44 Purchase of lnvestment Securities (a)-33,381,754 -10,896,289
45 Proceeds from Sales of lnvestment Securities (a)25,794,940 5,080,351
FERC FORM NO.1 (ED. 12-96)Page 120
ldaho Power Company An
(2)A Resubmission
Date of Reoort(Mo, Da, Yi)
04t14t202'.1
Year/Period of Report
End of 20201o,4
STATEMENT OF CASH FLOWS
(1) Codes to be used:(a) Net Prcceeds or Paymonts;(b)Bonds, dobsnturBs and other long-term debt; (c) lncltda commerchl papgr; and (d) ldentify soporat€ly such itoms as
lnvostments, fix€d ass€ts, inhngibles, etc.
Equivalonb at End of Psriod'wlth r€lat€d amounts on the Balanc€ Shest
ln thoso activities. Shqiv ln the Nobs to th€ Flnancials tho amounts of lnterest paid (rrt of amount capiblized) and lncome taxes pald.
dollar amount of l€ases capilalized with he plant cost
Line
No.
Description (See lnstruction No. 1 br Explanation of Codes)
(a)
cunent Year to Date
QuanerfYear
(b)
Pr€vious Year to uate
Quarterf/ear
(c)
46 Loans Made or Purchased
47 Collections on Loans
48
49 Net (lncrease) Decrease in Receivables
50 Net (lncrcase ) 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 foohote):
54
55
56 Net Cash Provided by (Used in) lnvesting Activities
57 Total of lines 34 thru 55)-309,021,810 -277,963,853
58
59 Cash Flows ftom Financing Activities:
60 Proceeds from lssuance of:
61 Long-Term Debt (b)341,384,4(t'l 166,100,000
62 Prefened Stock
63 Common Stock
64 Other (provide details in footnote):
65
66 Net lncrease in Short-Term Debt (c)
67 Other (provide details in botrlote):
68
69
70 Cash Provided by Outside Sources (total 61 thru 69)341,384,'t61 166,100,000
71
72 Payments for Retirement of:
73 Long-term Debt (b)-175,000,000 -166,100,000
74 Prefened Stock
75 Common Stock
76 Other (provide detrails in footnote):-2,180,708
77
78 Net Decrease in Short-Term Debt (c)
79
80 Dividends on Prefened Stock
81 Dividends on Common Stock -137,884,636 -129,877,518
82 Net Cash Provided by (Used in) Financing Activities
83 (Total of lines 70 thru 81)21,615,324 -132,058,226
84
85 Net lncrease (Decrease) in Cash and Cash Equivalents
86 (Tolal of lines 22,57 and 83)66,653,620 46,s09,923
87
88 Cash and Cash Equivalents at Beginning of Period 98,950,204 '165,460,127
89
90 Cash and Cash Equivalents at End of period 165,603,824 98,950,204
FERG FORM NO. 1 (ED. 12.96)Page 121
Name of Respondent
ldaho Power Comoanv
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
041141202',1
Year/Period of Report
2020tQ4
FOOTNOTE DATA
Schedule Paoe: 120 Line No.:4 Column: b
Amortization
Plant
Unamodized deH expense
Unamortized discount
Water rights
Other
7,996,866
4,198,027
(273,481)
1,042,009
51 768
13,015,189
120 Line No.: 13 Column: b
Carh (receivedl paid durlng the period fon
lncome taxes
lnterest (net of amount capitalized)
28.495.758
81,036.821
Schedule Pase: 120 Line No.:18 Column: b
Cash Flow from Operatlng Activitier (Odreo
Pension and postretirernent benefit plan expense
Contributions to pension and postretirement benefit plans
Changes in unbilled revenues
Other cunent liabilities
Accrued interest
Changes in pepayments
Change in company owned life insurance
Other
28.954,995
(45,146,0es)
(7,256,195)
5,064.844
3,007,004
(5.367,7311
(3,459,379)
(491.842)
124,694.iO31
$chedule Pase: 120 Line No.:26 Column: b
l{on*arh lnverting Activhies
Additions to PP&E in accounts payable 45.004.219
Schedule Pase: 120 Line No.:31 Column: b
Other Carh Flowrfrom Plant
Payments received from joint funding partners
Sale of renewaHe energy certificates and emission allowances
Sale of utility property
3,197.133
3.087.585
531 183
6.815.901
120 Line No.: 53 Column: b
Other lnvesting Carh Flowr
Lifu insurance proceeds - net of premiums
Other Financing Cash Flows
2,769,025
Schedule Paoe: 120 Line No.:76 Column: b
FERC FORM NO.1 (ED. 12-871 Page 450.1
Name of Respondont
ldaho Pqror Comoanv
This Report is:
(1)el XAn Odginal
A Resubmission
Date of Report
(Mo, Da, Yr)
Ml14l2gt21
Year/Period of Report
2@Otod
FOOTNOTE DATA
Otter
Discount on debt issuance
(6,566,501)
(328.000)
(6,884,501)
FERC FORI' NO.I GD. 12{.71 Pase 450.2
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of ReDort(Mo, Da, Yi)
0411412021
Year/Period of Report
End of 20201Q4
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-todate basis.
Line
No.
Item
(a)
Unrealized Gains and
Losses on Available-
for-Sale Securities
(b)
Minimum Pension
Liability adjustment
(net amount)
(c)
Foreign Currency
Hedges
(d)
Other
Adjustments
(e)
1 Balance of Account 21 9 at Beginning of
Preceding Year ( 22,843,785)
2 Preceding QtrfYr to Date Reclassifications
from Acct 219 to Net lncome 't,952,226
Preceding Quarterf/ear to Date Changes in
Fair Value ( 15,392,264)
4 Total (lines 2 and 3)( 13,440,038)
(Balance ofAccount 219 at End of
Preceding Quarterl/ear ( 36,283,823)
6 Balance ofAccount 219 at Beginning of
Cunent Year ( 36,283,823)
7 Cunent Qtrffr to Date Reclassifcations
from Acct 219 to Net lncome 2,988,104
8 Cunent QuarterfYear to Date Changes in
Fair Value ( 10,061,961)
o Total (lines 7 and 8)( 7,073,857)
't0 Balance of Accpunt 219 at End of Cunent
Quarterffear ( 43,357,680)
FERC FORM NO.1 (NEW 0e02)Page 122a
ldaho Power Company (1)
(2)
An Original
A Resubmission
, Da,
0411412021
Year/Period of Report
End of 202OlA4
STATEMENTS OF ACGUMULATED GOMPREHENSIVE INCOME, COMPREHENSIVE INGOME, AND HEDGING ACTIVITIES
Line
No.
Other Cash Flow
Hedges
lnterest Rate Swaps
(0
Other Cash Flow
Hedges
flnsert Footnote at Line I
to speciryI
(s)
Totals for each
category of items
recorded in
Account 219
(h)
Net lncome (Canied
Forward from
Page 117, Line 78)
(i)
Total
Comprehensive
lncome
0)
1 ( 22,U3,7851
2 1,952,226
3 ( 15,392,264)
4 ( 13,/U0,038)224,4%,822 210,996,784
5 ( 36,283,823)
6 ( 36,283,823)
7 2,988,104
8 ( 10,061,961)
I ( 7,073,857)233,2U,543 226,160,686
10 ( 43,357,680)
FERC FORM NO.1 (NEW 06-02)Page 122b
Name of Respondent
ldaho Power Company
This Report ls:(1) E An Original(2) ! A Resubmission
Date of Report
04114t2021
Year/Period of Report
End of 20201Q4
NOI ES IO I-INANCIAL S IAI EMENIS
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 significant contingent assets or liabilities existing at end of year, including a brief explanation of
any action initiated by the lnternal Revenue Service involving possible assessment of additional income taxes of material amount, or of
a claim for refund of income taxes of a material amount initiated by the utility. Give also a brief explanation of any dividends in arrears
on cumulative preferred stock.
3. For Account 1 16, 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 1 89, 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 eamings 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 occuned.
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 OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
04114t2021
Year/Period of Report
20201Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
IDAHO POWERCOMPAT{Y
NOTES TO T'INA}ICIAL STATEMENTS
1. SUMMARY OF' SIGNIFICA}IT ACCOUNTING POLICIES
Idaho Power Company (Idaho Power) is the principal operating subsidiary of IDACORP, Inc. (IDACORP), a holding company formed
in 1998. Idaho Power is an electric utility 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 Idaho and eastem 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 (Jim Bridger plant) owned in part by Idaho Power.
Basis of Reporting
The financial statements include the assets, liabilities, revenues and expenses ofldaho Power and have been prepared in accordance
with the accounting requirements of the FERC as set forth in the applicable Uniform System of Accounts and published accounting
releases, which is a comprehensive basis ofaccounting other than accounting principles generally accepted in the United States of
America (U.S. GAAP). As required by the FERC, Idaho Power accounts for its investments in its majority-owned subsidiary on the
equity method rather than consolidating the assets, liabilities, revenues and expenses of the subsidiary as required by U.S GAAP. The
accompanying financial statements include Idaho Power's proportionate share of the utility plant and related operations resulting from
its interest in jointly-owned plants. In addition, under the requirements of the FERC, there are differences from U.S. GAAP in the
presentation of(l) current portion oflong-term debt, (2) assets and liabilities for cost ofremoval ofassets, (3) regulatory assets and
liabilities (4) defened 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 financial statements in conformity with generally accepted accounting
principles. These estimates and assumptions include those related to rate regulation, retirement benefits, contingencies, asset
impairment, income taxes, unbilled revenues, and bad debt. These estimates and assumptions affect the reported amounts of assets and
liabilities and the disclosure ofcontingent assets and liabilities at the date ofthe financial statements and the reported amounts of
revenues and expenses during the reporting period. These estimates involve judgments with respect to, among other things, future
economic factors that are difficult to predict and are beyond management's control. Accordingly, actual results could differ from those
estimates.
Regulation of Utility Operations
As a regulated utility, many of Idaho Power's fundamental business decisions are subject to the approval of governmental agencies,
including the prices that Idaho Power is authorized to charge for its electric service. These approvals are a critical factor in determining
Idaho Power's results ofoperations and financial condition.
Idaho Power meets the requirements under accounting principles generally accepted in the United States of America to prepare its
financial statements applying the specialized rules to account for the effects of cost-based rate regulation. tdaho Power's financial
statements reflect the effects of the different ratemaking principles followed by the jurisdictions regulating Idaho Power. Accounting
for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and
FERG FORM NO. 1 (ED.12.88)Pase 123.1
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2\ _A Resubmission
Date of Report
(Mo, Da, Yr)
0411412021
Year/Period of Report
2020tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
equipment; regulatory assets and liabilities; operating revenues; operation and maintenance expense; depreciation expense; and income
tax expense. The application ofaccounting principles related to regulated operations sometimes results in Idaho Power recording
expenses and revenues in a different period than when an unregulated enterprise would record such expenses and revenues. In these
instances, the amounts are deferred or accrued as regulatory assets or regulatory liabilities on the balance sheet. Regulatory assets
represent incuned 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 r€present amounts collected in
advance ofincurring an expense. The effects ofapplying these regulatory accounting principles to Idaho Power's operations are
discussed in more detail in Note 3 - "Regulatory Matters."
System of Accounts
The accounting records ofldaho Power conform to the Uniform System ofAccounts prescribed by the FERC and adopted by the
public utility commissions of Idaho, Oregon, and Wyoming.
Cash and Cash Equivalents
Cash and cash equivalents include cash on-hand and highly liquid temporary investments that mature within 90 days of the date of
acquisition.
Receivables and Allowance for Uncollectible Accounts
Customer receivables are recorded at the invoiced amounts and do not bear interest. A late payment fee of one percent per month may
be assessed on account balances after 30 days. An allowance is recorded for potential uncollectible accounts. The measurement of
expected credit losses on Idaho Power accounts receivable is based on historical experience, current economic conditions, and
forecasted information that may affect collections on the outstanding balance. Generally, this includes adjustments based upon a
combination of historical write-off experience, aging of accounts receivable, an analysis of specific customer accounts, and an
evaluation ofwhether there are current or forecasted economic conditions that might cause variation in collection from the historical
experience. Adjustments are charged to income. Customer accounts receivable balances that remain outstanding after reasonable
collection efforts are written off.
In response to the COVID-l9 public health crisis, Idaho Power provided certain relief to customers, including temporarily suspending
disconnections for customers and temporarily waiving late fees. This relief as well as the economic conditions created by the response
to the COVID- l9 public health crisis have resulted in higher aged accounts receivable and an increase in the number of late payments.
Idaho Power expects higher uncollectible account write-offs as a result of the COVID-I9 public health crisis and, accordingly,
increased its allowance for uncollectible accounts related to customer receivables at December 3l , 2020. The allowance for
uncollectible accounts increased to 6.1 percent of the total customer receivables balance at December 31,2020, compared with 1.9
percent at December 31,2019.
The following table provides a rollforward of the allowance for uncollectible accounts related to customer receivables (in thousands of
dollars):
FERC FORM NO.1 (ED.12.88)Page'123.2
Name of Respondent
ldaho Power Companv
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
o411412021
Year/Period of Report
2020to,4
NOTES TO FINANCIAL STATEMENTS (Continued)
Year Ended
December 31,
2020 2019
-
Balance at beginning of period
Additions to the allowance
Write-offs, net of recoveries
$1,401 $
\ )')')
(1,857)
1,725
2,250
Q,574\
Balance at end ofperiod $ 4,766 $ 1,401
Allowance for uncollectible accounts as a percentage ofcustomer receivables 6.1%1.9%
Other receivables are also reviewed for impairment periodically, based upon transaction-specific facts. When it is probable that Idaho
Power will be unable to collect all amounts due according to the contractual terms of the agreement, an allowance is established for the
estimated uncollectible portion of the receivable and charged to income.
There were no impaired receivables without related allowances at December 31,2020 and 2019. Once a receivable is determined to be
impaired, any further interest income recognized is fully reserved.
Derivative f inancial Instruments
Financial instruments such as commodity futures, forwards, options, and swaps are used to manage exposure to commodity price risk
in the electricity and natural gas markets. All derivative instruments are recognized as either assets or liabilities at fair value on the
balance sheet unless they are designated as normal purchases and normal sales. With the exception of forward contracts for the
purchase ofnatural gas for use at Idaho 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 unrealized changes in fair value ofderivative instruments related to power supply as
regulatory assets or liabilities.
Revenues
Operating revenues are generally recorded when service is rendered or energy is delivered to customers. Idaho Power accrues
estimated unbilled revenues for electric services delivered to customers but not yet billed at year-end. Idaho Power does not report any
collections of franchise fees and similar taxes related to energy consumption on the income statement. In addition, regulatory
mechanisms in place in Idaho and Oregon affect the reported amount of revenue. The effects of applying these regulatory mechanisms
are discussed in more detail in Note 4 - "Revenues."
Property, Plant and Equipment and Depreciation
The cost of utility plant in service represents the original cost of contracted services, direct labor and material, allowance for funds
used during construction (AFUDC), and indirect charges for engineering, supervision, and similar overhead items. Repair and
maintenance costs associated with planned major maintenance are expensed as the costs are incurred, as are maintenance and repairs of
property and replacements and renewals of items determined to be less than units of property. For utility property replaced or renewed,
the original cost plus removal cost less salvage is charged to accumulated provision for depreciation, while the cost of related
replacements and renewals is added to property, plant and equipment.
FERC FORM NO.1 (ED.12.88)Pase 123.3
Name of Respondent
ldaho Power Company
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
0411412021
Year/Period of Report
2020tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
All utility plant in service is depreciated using the straightJine method at rates approved by regulatory authorities. Annual depreciation
provisions as a percent of average depreciable utility plant in service approximated 2.9 percenlin2020 and 2019.
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 balance sheets. Ifthe project becomes
probable ofbeing abandoned, such costs are expensed in the period such determination is made. Idaho Power may seek recovery of
such costs in customer rates, although there can be no guarantee such recovery would be granted.
Long-lived assets are periodically reviewed for impairment when events or changes in circumstances indicate that the carrying amount
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
2020 or 2019.
Allowance for tr'unds Used During Construction
AFUDC represents the cost of financing construction projects with borrowed funds and equity funds. With one exception, for the Hells
Canyon Complex (HCC) relicensing project, cash is not realized currently from such allowance; it is realized under the ratemaking
process over the service life ofthe related property through increased revenues resulting from a higher rate base and higher
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 7.5 percent for 2020 and 7 .6 percent for 201 9.
Income Taxes
Idaho Power accounts for income taxes under the asset and liability method, which requires the recognition ofdeferred tax assets and
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), defened tax assets and liabilities are determined based on the differences between
the financial statements and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are
expected to reverse. In general, defened income tax expense or benefit for a reporting period is recognized as the change in deferred
tax assets and liabilities from the beginning to the end ofthe period. The effect ofa change in tax rates on deferred tax assets and
liabilities is recognized in income in the period that includes the enactment date unless Idaho Power's primary regulator, the Idaho
Public Utilities Commission (IPUC), orders direct deferral of the effect of the change in tax rates over a longer period of time.
Consistent with orders and directives of the PUC, unless contrary to applicable income tax guidance, Idaho Power does not record
deferred income tax expense or benefit for certain income tax temporary differences and instead recognizes the tax impact currently
(comrnonly referred to as flow-through accounting) for rate making and financial reporting. Therefore, Idaho Power's effective income
tax rate is impacted as these differences arise and reverse. Idaho Power recognizes such adjustments as regulatory assets or liabilities if
it is probable that such amounts will be recovered from or retumed to customers in future rates.
Idaho Power uses judgment, estimation, and historical data in developing the provision for income taxes and the reporting of
tax-related assets and liabilities, including development of current year tax depreciation, capitalized repair costs, capitalized overheads,
and other items. Income taxes can be impacted by changes in tax laws and regulations, interpretations by taxing authorities, changes to
accounting guidance, and actions by federal or state public utility regulators. Actual income taxes could vary from estimated amounts
and may result in favorable or unfavorable impacts to net incomeo cash flows, and tax-related assets and liabilities.
FERC FORM NO.1 (ED.12-88)Page 123.4
Name of Respondent
ldaho Power Company
This Report is:
(1) X An OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
04t14t2021
Year/Period of Report
2020tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
ln compliance with the federal income tax requirements for the use ofaccelerated tax depreciation, Idaho Power records deferred
income taxes related to its plant assets for the difference between income tax depreciation and book depreciation used for financial
statement purposes. Defened income taxes are recorded for other temporary differences unless accounted for using flow-through.
Investment tax credits eamed on regulated assets are defened and amortized to income over the estimated service lives of the related
properties.
Income taxes are discussed in more detail in Note 2 - "Income Taxes."
Other Accounting Policies
Debt discount, expense, and premium are deferred and amortized over the terms ofthe respective debt issuances. Losses on reacquired
debt and associated costs are amortized over the life ofthe associated replacement debt, as allowed under regulatory accounting.
New and Recently Adopted Accounting Pronouncements
In June 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASLD 2016-1 3, Financial
Instruments-Credit Losses Qopic 326): Measurement of Credit Losses on Financtal Instruments, to provide financial statement users
with more information about expected credit losses on financial instruments and other commitments. The ASU revises the incurred loss
impairment methodology to reflect current expected credit losses and requires consideration ofa broader range ofinformation to
estimate credit losses. Idaho Power adopted ASU 2016- 13 on January l, 2020. The adoption did not have a material impact on its
financial statements.
In August 2018, the FASB issued ASU 2018-l5,lntangibles-Good,vill and Other-lnlernal-Use Software (Subtopic 350-40):
Customer's Accountingfor Implementation Costs Incurred in a Cloud Computing Arrangemenl Thqt Is q Service Contract, to provide
guidance on implementation costs incurred in a cloud computing arrangement that is a service contract. ASU 2018-15 aligns the
recognition of such implementation costs with the accounting for costs incurred to implement an intemal-use software solution.
However, the balance sheet line item for presentation of capitalized implementation costs for a cloud arrangement that is a service
contract should be the same as that for the prepayment of fees related to the same arrangement, while capitalized implementation costs
for intemal-use software solutions are often included in property, plant, and equipment as an intangible asset. Idaho Power adopted
ASU 201 8-15 on January 1, 2020. The adoption did not have a material impact on its financial statements.
Subsequent Events
Management has evaluated the impact of events occurring after December 31,2020, up to February 78,2A27, the date that Idaho
Power Company's U.S. GAAP financial statements were issued and has updated such evaluation for disclosure purposes through April
14,2021 . These financial statements include all necessary adjustments and disclosures resulting from these evaluations.
FERC FORM NO.1 D.1 123.5
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2) A Resubmission
Date of Report
(Mo, Da, Yr)
o411412021
Year/Period of Report
20201Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
2. INCOME TA)GS
A reconciliation between the statutory federal income tax rate and the effective tax rate is as follows (dollars in thousands):
2020 2019
$ 55,068 $ 52,662Federal income tax expense at 2l%o statutory rate
Change in taxes resulting from:
Equity earnings of subsidiary companies
AFUDC
Capitalized interest
Investment tax credits
Bond rede,mption costs
Removal costs
Capitalized overhead costs
Capitalized repair costs
State income taxes, net of federal benefit
Depreciation
Excess deferred income tax reversal
Income tax return adjustments
Other, net
Iotal income tax expense
Effective tax rate
(1,7&)
(8,637)
1,04
(2,906)
(726)
(3,148)
(7,560)
(18,480)
9,052
13,589
(4,884)
(1,972\
316
(1,783)
(7,941)
976
(6,252)
0
(3,139)
(7,t40)
(18,480)
8,401
14,&l
(6,1 8 1)
l,l3 I
(s61)
$29,992 $
tt.t%
26,334
10.5o/o
The items comprising income tax expense are as follows (dollars in thousands):
ta:<es currently payable:
Federal
State
Total
ta:<es deferred:
Federal
State
Total
5,727
$$
$$
3 t9 6l
tax credits:
26,6t0
(2,607)
19,554
(8e7)
57
8,268
l6
Deferred
Restored
Total
income tax
FERC FORM NO. 1 (ED. 1248)Page 123.6
Name of Respondent
ldaho Power Comoany
This Report is:
(1) X An OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
0411412021
Year/Period of Report
20201o,4
NOTES TO FINANCIAL STATEMENTS (Continued)
tax assets:
$7 $
r0
75
14
101
et deferred tax liabilities
5
161
tax liabilities:
$ 95,883
22,s76
43,525
30,215
142,8&
282,983
687,628
0
286,s83
646,886
0
Regulatory liabilities
Deferred compensation
Deferred revenue
Tax credits
Retirement benefits
Other
Total
$ 96,599
21,946
39,039
24,489
tt4,t24
Property, plant and equipment
Regulatory assets
Power cost adjustment
Other
Total
The components ofthe net deferred tax liability are as follows (dollars in thousands):
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 and are reported as taxes accrued or income taxes
receivable, respectively, on the balance sheets of Idaho Power. See Note I - "Summary of Significant Accounting Policies" for further
discussion of accounting policies related to income taxes.
Uncertain Tax Positions
Idaho Power believes that it has no material income tax uncertainties for 2020 and prior tax years. Idaho Power 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 - United States federal and the State of Idaho. The open tax years
for examination are 2020 for federal and 2016-2020 for Idaho. The Idaho State Tax Commission began its examination of the
2016-2018 tax years in March of 2020.In May 2009, IDACORP formally entered the U.S. Internal Revenue Service (IRS)
Compliance Assurance Process (CAP) program for its 2009 tax year and has remained in the CAP program for all subsequent years.
The CAP program provides for IRS examination and issue resolution throughout the current year with the objective of return filings
containing no contested items. In 2020,the IRS completed its examination of the 2019 tax year with no unresolved income tax issues.
The IRS moved IDACORP from its current maintenance phase of CAP to a bridge year for the 2020 tax year.
3. REGULATORY MATTERS
Idaho Power's financial statements reflect the effects of the different ratemaking principles followed by the jurisdictions regulating
Idaho Power. Included below is a summary of Idaho Power's regulatory assets and liabilities, as well as a discussion of notable
regulatory matters.
Regulatory Assets and Liabilities
FERC FORM NO.1 (ED.12.88)Pase 123.7
Name of Respondent
ldaho Power Company
This Report is:
(1) X An OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
04114t2021
Year/Period of Report
2020to'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 those 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 31,2020
Remaining
Amortization
Period Total as of December 31,
Description 2020 2019
Earning a
Return(1)
Not Earning a
Return
Regulatory Assets:
lncome taxes(2)
Unfu nded postretirement
benefits(3)
Pension expense
defenals(4)
Energy efficiency program
cost.(5)
Fixed cost adjustment(6)
North Valmy plant
settlements(6)
Asset retirement
obligations(7)
Long-term service
agreement
Other
Total
Regulatory Liabilities:
Income ta:res(8)
Depreciation-related excess
defened income taxes(9)
Power supply costs(6)
Mark-to-market assets
Tax reform accrual for
future amortization( I 0)
Other
$$ 687,628 $ 687,628 $ 646,886
444,470 444,470 347,935
26,169 200,686 172,637
202r-2022
2021-2028
2021-2043
2021-2055
-
174,517
13,225
38,158
103,085
14,729
2,074
17,333
19,035
9,702
8,770
13,225
55,491
103,085
19,035
24,431
10,844
1,465
54,016
107,525
18,835
25,590
8,170
$ 345,788 $ 1,213,107 $ 1,558,895 $ 1,383,059
$$ 95,883 $
6,672
1,995
16,893
5,082
95,883 $96,599
202t-2022
178,997
8,397
178,997
15,009
1,995
16,893
11,002
183,881
48,492
9,139
10,8955,920
FERC FORM NO.1 (ED.12-88)Page 123.8
Name of Respondent
ldaho Power Company
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
0411412021
Year/Period of Report
2020tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Total $ 193,314 $ 126,464 $ 319,779 $ 349,006
(l ) Earning a retum includes either interest or a retum on the investueot as a component of rate base at the allowcd rate of retum.
(2) Represents flow-tbrough income tax accormting differences which have a corresponding defened tax liability disclosed in Note 2 - "lncome Taxes."
(3) RepresentstheunfundedobligationofldahoPower'spensionandpostretirementbenefitplans,whicharediscussedinNotel2-"BenefitPlans."
(4) Idaho Power recods a regulatory asset for the difference between net periodic pension cost and pension cost considered for rate-making purposes relating to Idaho
Powels defined benefit pension plan. In its Idaho jurisdiction, Idaho Power's inclusion ofpension costs for the establishment ofretail rates is based upon
contributions made to the pension plan. This regulatory asset accolmt represents the differeoce bstweetr cumulative cash contributions and amounts collected in
rates. Deferred costs are amortized into expense as tie amounts are provided for in Idaho retail revenues.
(5) TheenerryefficiencyassetincludesboththeldahoandOrcgonjurisdictionbalancesatDecemberSl,2020and20l9.
(6) This itern is discussed in more detail in this Note 3 - "Regulatory Matters."
(7) Asset retirement obligations are discussed in Note l3 - "Asset Retirement Obligations (ARO).'
(8) Represents the tax gross-up related to the depreciation-related excess deferred income taxes and investment tax credits included in this table and has a
corresponding deferred tax asset disclosed in Note 2 - "Income Taxes."
(9) la 2017 , income tax reform reduced deferred income tax assets and liabilities. For depreciation-related timing differences under the normalized tax accounting
method, this reduction will flow back to customgs under the statutorily prescribed average rate assumption method.
( I 0) Represents amount accrued under the May 20 I 8 Idaho Tax Reform Settlement Stipulation (described below) for the funre amortization of existing or future
unspecified regulatory deferrals that would otherwise be a future liability recoverable from Idaho customers.
Idaho Power's regulatory assets and liabilities are typically amortized over the period in which they are reflected in customer rates. In
the event that recovery ofldaho Power's costs through rates becomes unlikely or uncertain, regulatory accounting would no longer
apply to some or all of Idaho Power's operations and the items above may represent stranded investments. If not allowed full recovery
of these items, Idaho Power would be required to write offthe applicable portion, which could have a materially adverse financial
impact.
Power Cost Adjustment Mechanisms and Deferred Power Supply Costs
In both its Idaho and Oregonjurisdictions, 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 wholesale energy sales) against net power supply
costs being recovered in Idaho Power's retail rates. Under the power cost adjustment mechanisms, certain differences between actual
net power supply costs incuned by Idaho 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, fuel prices, and the levels of Idaho Power's
own generation. The Idaho defenal period or Idaho-jurisdiction power cost adjustment @CA) year runs from April I through March
31. Amounts defened during the PCA year are primarily recovered or refunded during the subsequent June I through May 3 I period.
Idaho Jurisdiction Power Cost Adjustment Mechanism.' In the Idaho jurisdiction, the annual PCA adjustment consists of (a) a
forecast component, based on a forecast ofnet power supply costs in the coming year as compared with net power supply costs
included in base rates; and (b) a tnre-up component, based on the difference between the previous year's actual net power supply costs
and the previous year's forecast. The latter component also includes a balancing mechanism so that, over time, the actual collection or
refund of authorized true-up dollars matches the amounts authorized. The PCA mechanism also includes:
a cost or benefit sharing ratio that allocates the deviations in net power supply expenses between customers (95 percent) and Idaho
Power (5 percent), with the exceptions of expenses associated with PURPA power purchases and demand response incentive
payments, which are allocated 100 percent to customers; and
a sales-based adjustment intended to ensure that power supply expense recovery resulting solely from sales changes does not
FERC FORM NO.1 1 123.9
a
Name of Respondent
ldaho Power Comoanv
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
0411412021
Year/Period of Report
20201Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
distort the results of the mechanism.
The table below summarizes the three most recent Idaho-jurisdiction PCA rate adjustments, which also include non-PCA-related rate
adjustments as ordered by the IPUC:
$ Change
Effective Date (millions) Notes
June 1,2020 $59.7 The $58.7 million increase in PCA rates reflects a return to a more normal level of power supply
costs as wholesale market energy prices came down from unusually high levels in the previous
year's PCA and a forecasted reduction in low-cost hydropower generation.
June 1,2019 $(50.1)The $50.1 million decrease in PCA rates includes a $5.0 million credit to customers for sharing
of 2018 earnings under the October 2014 Idaho Eamings Support and Sharing Settlement
Stipulation and a $2.7 million credit for income tax reform benefits related to Idaho Power's
OATT rate under a May 2018 Idaho tax reform settlement stipulation as described below in this
Note 3 - Regulatory Matters.
Oregon Jurisdiction Power Cost Adjustment Mechanism.' Idaho Power's power cost recovery mechanism in Oregon has two
components: an annual power cost update (APCU) and a power cost adjustment mechanism (PCAM). The APCU allows Idaho Power
to reestablish its Oregon base net power supply costs annually, separate from a general rate case, and to forecast net power supply costs
for the upcoming water year. The PCAM is a true-up filed annually in February. The filing calculates the deviation between actual net
power supply expenses incurred for the preceding calendar year and the net power supply expenses recovered through the APCU for
the same period. Oregon jurisdiction power supply cost changes under the APCU and PCAM during each of 2020 and 2019 did not
have a material impact on the companies'financial statements.
Notable Idaho Base Rate Adjustments
Idaho base rates were most recently established through a general rate case in2012, and adjusted in2014,2017,2018, and 2019
January 2012 und June 2014 ldaho Base Rate Adjustments: Effective January 7,zllz,Idaho Power implemented new Idaho base
rates resulting from IPUC approval of a settlement stipulation that provided for a 7 .86 percent authorized overall rate of retum on an
Idaho-jurisdiction rate base of approximately $2.36 billion. The settlement stipulation resulted ina4.07 percent, or $34.0 million,
overall increase in Idaho Power's annual Idaho-jurisdiction base rate revenues. Idaho base rates were subsequently adjusted again in
2012, in connection with Idaho Power's completion of the Langley Gulch power plant. tn June 2012, the IPUC issued an order
approving a $58.1 million increase in annual Idaho-jurisdiction base rates, effective July 1,2012. The order also provided for a $335.9
million increase in Idaho rate base. Neither the settlement stipulation nor the IPUC orders adjusting base rates specified an authorized
rate of return on equity or imposed a moratorium on Idaho Power filing a general rate case at a future date.
The IPUC issued a March 2014 order approving Idaho Power's request for an increase in the normalized or "base level" net power
supply expense to be used to update base rates and in the determination ofthe PCA rate that became effective June 1,2014.
October 2014 ldaho Earnings Support and Sharing Settlement Stipulation: In October 2014,the IPUC issued an order approving an
extension, with modifications, of the terms of a December 2011 Idaho settlement stipulation for the period from 2015 through 2079, or
until the terms are otherwise modified or terminated by order of the IPUC or the full $45 million of additional accumulated deferred
investment tax credits (ADITC) contemplated by the settlement stipulation has been amortized (October 2014 Idaho Eamings Support
and Sharing Settlement Stipulation). The provisions of the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation
FERC FORM NO.1 (ED.12-88)Page 123.10
Name of Respondent
ldaho Power Company
This Report is:
(1) [ An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
0411412021
Year/Period of Report
20201o.4
NOTES TO FINANCIAL STATEMENTS (Continued)
are described in the table below
May 2018 ldaho Tax Reform Settlement Stipulation: In December 2017,the Tax Cuts and Jobs Act was signed into law, which,
among other things, lowered the corporate federal income tax rate from 35 percent to 2l percent and modified or eliminated certain
federal income tax deductions for corporations. In March 2018, Idaho House Bill 463 was signed into law reducing the Idaho state
corporate income tax rate from 7.4 percent to 6.925 percent.
In May 2018, the IPUC issued an order approving a settlement stipulation (May 2018 Idaho Tax Reform Settlement Stipulation)
related to income tax reform. Beginning June I , 201 8, the settlement stipulation provided an annual (a) $ I 8.7 million reduction to
Idaho customer base rates and (b) $7.4 million amortization of existing regulatory deferrals for specified items or future amortization
of other existing or future unspecified regulatory deferrals that would otherwise be a future liability recoverable from Idaho customers.
Additionally, a one-time benefit of a $7.8 million rate reduction was provided to Idaho customers through the Idaho-jurisdiction power
cost adjustment (PCA) mechanism for the period from June 1, 2018 through May 31,2019, for the income tax reform benefits accrued
from January 1, 2018 to May 31,2018, and the income tax reform benefits related to Idaho Power's OATT rate. The amount provided
via the PCA mechanism decreased to $2.7 million on June 1,2079, for income tax reform benefits related to Idaho Power's OATT rate
and ceased on June 7, 2020, to reflect the impact of a full year of reduced OATT third-party transmission revenues.
The May 2018 Idaho Tax Reform Settlement Stipulation also provided for the indefinite extension, with modifications, of the October
2014 Idaho Earnings Support and Sharing Settlement Stipulation beyond its termination date of December 31, 2019.
The table below summarizes and compares the terms of the October 2014 Idaho Eamings Support and Sharing Settlement Stipulation
with the terms in the May 201 8 Idaho Tax Reform Settlement Stipulation that became applicable on January 1 ,2020.
October 2014 ldaho Earnings Support and Sharing
Settlement Stipulation
(Effective through December 3 l, 2019)
May 2018 Idaho Tax Reform Settlement Stipulation
(Effective January 1,2020, with no defined end date)
Ifldaho Powefs actual annual Idaho ROE in any year is less than
9.5 percent, then Idaho Power may record additional ADITC
amortization up to $25 million to help achieve a 9.5 percent Idaho
ROE for that year, and may record additional ADITC amortization
up to a total of $45 million over the 2015 through 2019 period. If
the $45 million of ADITC are completely amortize4 the revenue
sharing provisions below would no longer be applicable.
If Idaho Power's annual Idaho 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 Idaho customers as a rate
reduction to be effective at the time of the subsequent year's PCA,
and 25 percent to Idaho Power.
If Idaho Powels annual Idaho ROE in any year exceeds I 0.5
percent, the amount ofearnings exceeding a 10.5 percent Idaho
ROE will be allocated 50 percent to Idaho Power's Idaho
customers as a rate reduction to be effective at the time of the
Ifldaho Poweds actual annual Idaho ROE in any year is less
than 9.4 percent, then ldaho Power may amortize up to $25
million of additional ADITC to help achieve a 9.4 percent ldaho
ROE for that year, so long as the cumulative amount of ADITC
used does not exceed $45 million (ldaho Power will have
available and may continue to use any unused portion ofthe $45
million of additional ADITC from the October 2014 Idaho
Eamings Support and Sharing Settlement Stipulation); however,
Idaho Power may seek approval from the IPUC to replenish the
total amount of ADITC it is perrritted to amortize. If there are no
remaining amounts of ADITC authorized to be amortized, the
revenue sharing provisions below would not be applicable until
ADITC is replenished.
If ldaho Powefs annual Idaho ROE in any year exceeds I 0.0
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 80 percent to ldaho Power's Idaho customers as a rate
reduction to be effective at the time of the subsequent year's PCA,
and 20 percent to ldaho Power.
Ifldaho Poweds annual Idaho ROE in anyyearexceeds 10.5
percent, the amount of eamings exceeding a 10.5 percent Idaho
ROE will be allocated 55 percent to Idaho Power's Idaho
customers as a rate reduction to be effective at the time of the
FERC FORM NO.1 1 Page 123.11
Name of Respondent
ldaho Power Companv
This Report is:
(1) ! An Original
(2\ -A Resubmission
Date of Report
(Mo, Da, Yr)
041't412021
Year/Period of Report
20201Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
subsequent year's PCA, 25 percent to ldaho Poweds Idaho
customers in the fonn of a reduction to the pension regulatory
asset balancing account (to reduce the amount to be collected in
the future from Idaho customers), and 25 percent to Idaho Power.
In the event the IPUC approves a change to Idaho Power's allowed
annual Idaho ROE as part of a general rate case proceeding before
December 31,2019, the Idaho ROE thresholds will be adjusted on
a prospective basis as follows: (a) the ldaho ROE under which
Idaho Power will be permitted to amortize an additional amount
of ADITC will be set at 95 percent of the newly authorized Idaho
ROE, (b) sharing with customers on an 75 percent basis as a
customer rate reduction will begin at the newly authorized Idaho
ROE, and (c) sharing with customers on a 75 percent basis but
allocated 50 percent to a rate reduction, and 25 percent to a
pension expense deferral regulatory asset, will begin at 105
percent of the newly authorized Idaho ROE.
subsequent yea/s PCA, 25 percent to Idaho Poweds Idaho
customers in the fomr of a reduction to the pension regulatory
asset balancing account (to reduce the amount to be collected in
the future from Idaho customers), aud 20 percent to Idaho Power.
In the event the IPUC approves a change to Idaho Power's allowed
annual Idaho ROE as part ofa general rate case proceeding
effective on or after January 1,2020, the Idaho ROE thresholds
will be adjusted on a prospective basis as follows: (a) the Idaho
ROE under which Idaho Power will be permitted to amortize an
additional amount of ADITC will be set at 95 percent of the newly
authorized Idaho ROE, (b) sharing with customers on an 80
percent basis as a customer rate reduction will begin at the newly
authorized Idaho ROE, and (c) sharing with customers on an 80
percent basis but allocated 55 percent to a rate reduction, and 25
percent to a pension expense deferral regulatory asset, will begin
at 105 percent of the newly authorized Idaho ROE.
The May 2018 Idaho Tax Reform Settlement Stipulation did not impose a moratorium on Idaho Power filing a general rate case or
other form ofrate proceeding in Idaho during its respective term.
In 2020 and 2079,Idaho Power recorded no provision against current revenue for sharing with customers, as its full-year return on
year-end equity in the Idaho jurisdiction (Idaho ROE) was between 9.4 percent and 10.0 percent in2020 and between 9.5 percent and
10.0 percent in 2019. Accordingly, at December 31,2020, the full $45 million of additional ADITC remained available for future use
under the terms of the May 2018 Idaho Tax Reform Settlement Stipulation.
Valmy Base Rate Adjustment Settlement Stipulations: In May 2017,ihe IPUC approved a settlement stipulation allowing accelerated
depreciation and cost recovery for Idaho Power's jointly-owned North Valmy coal-fired power plant. The settlement stipulation
provides for an increase in Idahojurisdictional revenues of$13.3 million per year, and (l) levelized collections and associated cost
recovery through December 2028, (2) accelerated depreciation on unit I through 2019 and unit 2 through 2025, and (3) Idaho Power
to use prudent and commercially reasonable efforts to end its participation in the operation of unit I by the end of 2019 and unit 2 no
later than the end of 2025. The costs intended to be recovered by the increased jurisdictional revenues include current investments as
of May 31,2017, in both units, forecasted unit I investments from 2017 through 2019, and forecasted decommissioning costs for unit
I and unit 2, offset by forecasted operation and maintenance costs savings. The settlement stipulation also provides for the regulatory
accrual or deferral ofthe difference between actual revenue requirements and levelized collections, and provides for the regulatory
accrual or deferral ofthe difference between actual costs incurred (including accelerated depreciation expense on unit 1 through 2019
and unit 2 through 2025) compared with costs permitted to be recovered during the cost recovery period specified in the settlement
stipulation (including depreciation expense through 2028). If actual costs incurred differ from forecasted amounts included in the
settlement stipulation, collection or refund ofany differences would be subject to regulatory approval. In February 2019, Idaho Power
reached an agreement with I.[V Energy that facilitates the planned end of Idaho Power's participation in coal-fired operations at units I
and 2 of its jointly-owned North Valmy coal-fired power plant in 2019 and no later than2025, respectively. In May 2019, the IPUC
issued an order approving the North Valmy plant agreement and allowing Idaho Power to recover through customer rates the $1.2
million incremental annual levelized revenue requirement associated with required North Valmy plant investments and other exit costs,
effective June l, 2019 through December 31,2028.In December 2019, as planned, Idaho Power ended its participation in coal-fired
operations of North Valmy plant unit l.
FERC FORM NO. 1 (ED.12-88)Page 123.12
Other Notable Idaho Regulatory Matters
Name of Respondent
ldaho Power Company
This Report is:
(1) X An OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
041't4t2021
Year/Period of Report
20201o,4
NOTES TO FINANCIAL STATEMENTS (Continued)
Fked Cost Adjustment: The Idaho jurisdiction fixed cost adjustment (FCA) mechanisnr, applicable to Idaho residential and small
commercial customers, is designed to remove a portion of ldaho Power's financial disincentive to invest in energy efficiency programs
by separating (or decoupling) the recovery of fixed costs from the variable kilowatt-hour (kWh) charge and Iinking it instead to a set
amount per customer. Under Idaho Power's current rate design, recovery of a portion of fixed costs is included in the variable kWh
charge, which may result in over-collection or under-collection of fixed costs. To return over-collection to customers or to collect
under-collection from customers, the FCA mechanism allows Idaho Power to accrue, or defer, the difference between the authorized
fixed-cost recovery amount per customer and the actual fixed costs per customer recovered by Idaho Power during the year. The IPUC
has discretion to cap the annual increase in the FCA recovery at 3 percent ofbase revenue, with any excess deferred for collection in a
subsequent year.
The following table summarizes FCA amounts approved for collection in the prior three FCA years:
Annual Amount
FCA Year Period Rates in Effect (in millions)
2019
2018
2017
$35.5
$34.8
$r5.6
June l, 2020-May 31, 2021
June l, 2019-May 31, 2020
June l, 2018-May 31, 2019
llildfire Mitigation Cost Recovery: ln recent years, the western United States has experienced an increase in frequency and intensity
of wildfires. Idaho Power drafted a Wildfire Mitigation Plan (WMP) that outlines actions Idaho Power is taking or plans to implement
in the future to reduce wildfire risk and to strengthen the resiliency of its transmission and distribution system to wildfires. On January
22, 2027 ,Idaho Power filed an application with the IPUC requesting authorization to defer, for future amortization, the Idaho
jurisdictional share ofactual incremental O&M expenses and depreciation expense ofcertain capital investments necessaryto
implement the WMP, including incremental insurance costs. Idaho Power also requested authorization to record these O&M expenses
as a regulatory asset until the company can request amortization of the deferred costs in a future IPUC proceeding, at which time the
IPUC will have the opportunity to review actual costs and determine the amount of prudently incurred costs that can be recovered
through retail rates. As of the date of this report, the WMP case remains pending at the IPUC.
Notable Oregon Regulatory Matters
Oregon Base Rate Changes: Oregon base rates were most recently established in a general rate case in20l2.In February 2012, the
Public Utility Commission of Oregon (OPUC) issued an order approving a settlement stipulation that provided for a $ I .8 million base
rate increase, a return on equity of 9.9 percent, and an overall rate of return of 7 .7 57 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 Gulch power plant in Idaho Power's Oregon rate base. Additionally, in October 2020,the OPUC approved an increase in
Oregon customer rates of $0.4 million annually associated with amortization of defened Langley Gulch power plant revenue
requirement variances, effective November l, 2020 through October 31,2024.
In May 2018, the OPUC issued an order approving a settlement stipulation that provides for an annual $1.5 million reduction to
Oregon customer base rates beginning June I , 201 8, through May 3 1 , 2020, relaled to income tax reform. In May 2020, the OPUC
issued an order to approve the quantification of $1.5 million in annualized Oregon jurisdictional benefits associated with federal and
state income tax changes resulting from tax reform and adjusting customer rates to reflect this amount, effective June 1, 2020, until its
next general rate case or other proceeding where the tax-related revenue requirement components are reflected in rates.
FERC FORM NO. 1 (ED. 12-88)Page 123.13
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) - A Resubmission
Date of Report
(Mo, Da, Yr)
04114t2021
Year/Period of Report
2020to,4
NOTES TO FINANCIAL STATEMENTS (Continued)
In June 2017,the OPUC approved a settlement stipulation allowing for (1) accelerated depreciation of North Valmy plant units I and 2
through December 31,2025, (2) cost recovery of incremental North Valmy plant investments through May 31, 2017, and (3)
forecasted North Valmy plant decommissioning costs. The settlement stipulation provides for an increase in the Oregon jurisdictional
revenue requirement of $l.l million, effective JrlJy 1,2017, with yearly adjustments, if warranted. As part of the May 2018 settlement
stipulation associated with income tax reform described above, the OPUC also deemed prudent Idaho Power's decision to pursue the
end of its participation in coal-fired operations of unit I by the end of 201 9 and approved Idaho Power's request to recover annual
incremental accelerated depreciation relating to unit 1, beginning June l, 2018, and ending December 31,2019, resulting in a $2.5
million annualized revenue requirement. In October 2019, the OPUC approved the North Valmy plant agreement and authorized Idaho
Power to adjust customer rates in Oregon, effective January 7,2020, to reflect a decrease in the annual levelized revenue requirement
of $3.2 million, which mostly relates to the decrease in depreciation expense and other costs associated with the December 2019 end of
Idaho Power's participation in coal-fired operations of North Valmy plant unit l.
Federal Regulatory Matters - Open Access Transmission TariffRates
Idaho Power uses a formula rate for transmission service provided under its OATT, which allows transmission rates to be updated
annually based primarily on actual financial and operational data Idaho Power files with the FERC and allows Idaho Power to recover
costs associated with its transmission system. Idaho Power's OATT rates submitted to the FERC in Idaho Power's four most recent
annual OATT Final Informational Filings were as follows:
Applicable Period
OATT Rate (per
kW-year)
October 1,2020 to September 30,2021
October 1,2019 to September 30,2020
October 1,2018 to September 30,2019
Idaho Power's current OATT rate is based on a net annual transmission revenue requirement of $ I 1 7.7 million, which represents the
OATT formulaic determination of Idaho Power's net cost of providing OATT-based transmission service.
4. REVENUES
Revenues from Contracts with Customers
Revenues from contracts with customers are primarily related to Idaho Power's regulated tariflbased sales of enerry or related
services. Generally, tariff-based sales do not involve a written contract, but are classified as revenues from contracts with customers
Idaho Power assesses revenues on a contract-by-contract basis to determine the nature, amount, timing, and uncertainty, if any, of
revenues being recognized.
Retsil Revenues.. Idaho Power's retail revenues primarily relate to the sale of electricity to customers based on regulated tariff-based
prices. Idaho Power recognizes retail revenues in amounts for which it has the right to invoice the customer in the period when energy
is delivered or services are provided to customers. The total energy price generally has a fixed component related to having service
available and a usage-based component related to the demand, delivery, and consumption ofenergy. The revenues recognized reflect
the consideration Idaho Power expects to be entitled to in exchange for energy and services. Retail customers are classified as
residential, commercial, industrial, or irrigation. Approximately 95 percent of Idaho Power's retail revenue originates from customers
located in Idaho, with the remainder originating from customers located in Oregon. Idaho Power's retail customer rates are based on
FERC FORM NO.1 (ED.12.88)Page 123.14
$
$
$
29.95
27.32
31.25
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t14t2021
Year/Period of Report
202Uo,4
NOTES TO FINANCIAL STATEMENTS (Continued)
Idaho Power's cost of service and are determined through general rate case proceedings, settlement stipulations, and other filings with
the IPUC and OPUC. Changes in rates and changes in customer demand are tlpically the primary causes of fluctuations in retail
revenue from period to period. The primary influences on changes in customer demand for electricity are weather, economic
conditions (including growth in the number of Idaho Power customers), and energy efficiency. Idaho Power's utility revenues are not
earned evenly during the year.
Retail revenues are billed monthly based on meter readings taken throughout the month. Payments for amounts billed are generally due
from the customer within l5 days of billing. Idaho Power accrues estimated unbilled rovenues for energy or related services delivered
to customers but not yet billed at period-end based on actual meter readings at period-end and estimated rates.
Residential Customers: Idaho Power's energy sales to residential customers typically peak during the winter heating season and
summer cooling season. Extreme temperatures increase sales to residential customers who use electricity for cooling and heating,
compared with normal temperatures. Idaho Power's rate structure provides for higher rates during the summer when overall system
loads are at their highest, and includes tiers such that rates increase as a customer's consumption level increases. These seasonal and
tiered rate structures contribute to the seasonal fluctuations in revenues and earnings. Economic and demographic conditions can also
affect residential customer demand; strong job growth and population growth in Idaho Power's service area have led to increasing
customer growth rates in recent years. Residential demand is also impacted by energy efficiency initiatives. Idaho Power's FCA
mechanism mitigates some of the fluctuations caused by weather and energy efficiency initiatives. ln2020,Idaho Power's residential
customers used more enerry due to spending more time at home during the COVID-19 public health crisis.
Commercial Customers: Most businesses are included in Idaho Power's commercial customer class, as are small industrial companies,
and public street and highway lighting accounts. Idaho Power's commercial customers are less influenced by weather conditions than
residential customers, although weather does still affect commercial customer energy use. Economic conditions, including
manufacturing activity levels, and energy efficiency initiatives also affect energy use of commercial customers. In 2020, the economic
impacts of the COVD-I9 public health crisis reduced energy usage by Idaho Power's commercial customers.
Industrial Customers: Industrial customers consist of large industrial companies, including special contract customers. Energy use of
industrial customers is primarily driven by economic conditions, with weather having little impact on this customer class. In 2020, the
economic impacts of the COVID-I9 public health crisis reduced enerry usage by Idaho Power's industrial customers.
Irrisation Customers: Irrigation customers use electricity to operate irrigation pumps, primarily during the agricultural growing season.
The amount and timing of precipitation as well as temperature levels affect the timing and amounts of sales to irrigation customers,
with increased precipitation generally resulting in decreased sales.
Provision for Sharine: Idaho Power has regulatory settlement stipulations in Idaho that provide for the potential sharing between Idaho
Power and its ldaho customers of Idaho-jurisdictional earnings in excess of 10.0 percent of Idaho ROE. Based on full-year 2020 Idaho
ROE, Idaho Power recorded no provision against current revenues for sharing of earnings with customers for 2020. During 2019, no
provision was recorded. The regulatory settlement stipulations are described further in Note 3 - "Regulatory Mattsrs."
llholesale Energt Sales: As a public utility under the Federal Power Act (FPA), Idaho Power has the authority to charge
market-based rates for wholesale energy sales under its FERC tariff. Idaho Power's wholesale electricity sales are primarily to utilities
and power marketers and are predominantly short-term and consist ofa single performance obligation satisfied as energy is transferred
to the counterparty. Idaho Power's wholesale energy sales depend largely on the availability ofgeneration resources in excess ofthe
amount necessary to serve customer loads as well as adequate market power prices and demand at the time when those resources are
FERC FORM NO.1 1 123.'.t5
Name of Respondent
ldaho Power Company
This Report is:
(1) X An OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
0411412021
Year/Period of Report
20201Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
available. A reduction in any of those factors may lead to lower wholesale energy sales.
Transmission ll/heeling-Related Revenues: As a public utility under the FPA, Idaho Power has the authority to provide cost-based
wholesale and retail access transmission services under its OATT. Services under the OATT are offered on a nondiscriminatory basis
such that all potential customers have an equal opportunity to access the transmission system. Idaho Power's transmission revenue is
primarily related to third parties reserving capacity on Idaho Power's transmission system to transmit electricity through Idaho Power's
service area. Reservations are predominantly short-term contracts or on-demand when available, but may be part of a long{erm
capacity contract. Transmission wheeling-related revenues consist ofa single performance obligation satisfied as capacity on Idaho
Power's transmission system is provided to the third party. Transmission wheeling-related revenues are affected by changes in Idaho
Power's OATT rate and customer demand. Demand for transmission services can be affected by regional market factors, such as loads
and generation of utilities in Idaho Power's region.
Energt Effrciency Program Revenues; Idaho Power collects most of its energy efficiency program costs through an energy efficiency
rider on customer bills. The rider collections are deferred until expenditures are incurred. Energy efficiency program expenditures
funded through the rider are reported as an operating expense with an equal amount recognized in revenues, resulting in no net impact
on earnings. The cumulative variance between expenditures and amounts collected through the rider is recorded as a regulatory asset or
liability. A liability balance indicates that Idaho Power has collected more than it has spent, and an asset balance indicates that Idaho
Power has spent more than it has collected. At December 3l,2020,Idaho Power's energy efficiency rider balances were a $12.2
million regulatory asset in the Idaho jurisdiction and a $1.0 million regulatory asset in the Oregon jurisdiction. In December 2020,Lhe
IPUC authorized Idaho Power to increase the Idaho energy efficiency rider collection percentage from2.75 percent to 3.1 percent,
effective January l, 2021.
Alternative Revenue Programs and Derivative Revenues
While revenues from contracts with customers make up most of ldaho Power's revenues, the IPUC has authorized the FCA
mechanism, which may increase or decrease tariff-based rates billed to customers. The FCA mechanism is described in detail in Note 3
- "Regulatory Matters." The FCA mechanism revenues include only the initial recognition of FCA revenues when the
regulator-specified conditions for recognition have been met. Revenue from contracts with customers excludes the portion ofthe tariff
price representing FCA revenues that had been initially recorded in prior periods when regulator-specified conditions were met. When
those amounts are included in the price ofutility service and billed to customers, such amounts are recorded as recovery ofthe
associated regulatory asset or liability and not as revenues.
FERC FORM NO. 1 ED.1 123.16
Name of Respondent
ldaho Power Company
This Report is:
(1) [ An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
0411412021
Year/Period of Report
20201Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
5. LONG.TERM DEBT
The following table summarizes Idaho Power's long-term debt at December 3l (in thousands of dollars)
2020 2019
First mortgage bonds:
3.40% Series dur,2020
2.95% Series due2022
2.50% Series due2023
1.90% Series due 2030
6.00% Series due2032
5.50% Series due 2033
5.50% Series due 2034
5.875% Series due 2034
5.30% Series due 2035
6.30% Series due2037
6.25% Series dlue2037
4.85% Series due 2040
4.30% Series due2042
4.00% Series due 2043
3.65% Series due 2045
4.05% Series due2046
4.20% Series due 2048
$$ 1oo,00o
75,000
75,00075,000
80,000
100,000
70,000
50,000
55,000
60,000
140,000
100,000
100,000
75,000
75,000
250,000
120,000
450,000
100,000
70,000
50,000
55,000
60,000
140,000
100,000
100,000
75,000
75,000
250,000
120,000
220,000
Total first mortgage bonds 1,800,000 1,665,000
Pollution control revenue bonds;
1.45% Series due20240)
1.70% Series due 2026(l)
Variable Rate Series 2000 due 2027
49,800
116,300
4,360
49,800
I 16,300
4,360
Total pollution control revenue bonds 170,460 170,460
American Falls bond guarantee
Unamortized premium/discount
19,885
26,543
19,885
(4,301)
Total Idaho Power outstanding deb(2)2,016,848 1,851,044
( I ) Humboldt County and Sweetwater County Pollution Control Revenue Bonds are secured by the frst mortgage bonds, bringing the total first mortgage bonds
outstanding at December 31,2020, to $ I .966 billion. These two bonds were purchased and remarketed in August 201 9. See "I-ong-Term Debt lssuances,
FERC FORM NO.1 (ED.12.88)Page 123.17
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
Mt't4t2021
Year/Period of Report
2020to,4
NOTES TO FINANCIAL STATEMENTS (Continued)
Maturities, and Redemptions" below.
(2) AtDecember3l,2020and20l9,theoveralleffectivecostrateofldahoPower'soutstandingdebtwas4.40percentand4.50pefcent,respectively.
At December 31, 2020, the maturities for the aggegate amount of Idaho Power long-term debt outstanding were as follows (in
thousands ofdollars):
2021 2022 2023 2024 2025 Thereafter
$$$ 75,000 $ 49,800 $ 19,885 $ 1,845,660
Long-Term Debt Issuances, Maturities, and Redemptions
In April 2020, Idaho Power issued $230 million in principal amount of 4.20% first mortgage bonds, secured medium term notes, Series
I! maturing March l, 2048. The bonds were issued at a reoffer yield of 3.422 percent, which resulted in a net premium of 13.0 percent
and net proceeds to Idaho Power of $259.9 million. After this offering the aggegate principal amount of the 4.20o/o first mortgage
bonds is $450 million.
In June 2020, Idaho Power issued $80 million in principal amount of 1.90 percent first mortgage bonds, secured medium term notes,
Series L, maturing July 15, 2030. In July 2020,Idaho Power redeemed, prior to maturity, $75 million in principal amount of 2.95
percent first mortgage bonds, medium-term notes, Series H due in April 2022.|n 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 $3.3 million.
In August 2020, Idaho Power redeemed $100 million in principal amount of 3.40 percent first mortgage bonds due in November 2020
In August 2019, Idaho Power purchased and remarketed two ofits outstanding series ofpollution control tax-exempt bonds, one in the
aggregate principal amount of $49.8 million issued in 2003 by Humboldt County, Nevada and due in2024, and the other in the
aggregate principal amount of $116.3 million issued in 2006 by Sweetwater County, Wyoming and due in 2026. The bonds were
remarketed with substantially the same terms, but with lower term interest rates. The term interest rate of the series due in2024
decreased from 5.15 percent to 1.45 percent and the term interest rate of the series due in2026 decreased from 5.25 percent to 1.70
percent.
Idaho Power tr'irst Mortgage Bonds
Idaho Power's issuance of long-term indebtedness is subject to the approval of the IPUC, OPUC, and Wyoming Public Service
Commission (WPSC). In April and May 2019, Idaho Power received orders from the IPUC, OPUC, and WPSC authorizing the
company 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. Authority from the IPUC is effective through May 31, 2022, 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 for the debt securities or first mortgage bonds fall
within either (a) designated spreads over comparable U.S. Treasury rates or (b) a maximum interest rate limit of 7.0 percent.
In May 2019, Idaho Power filed a shelf registration statement with the SEC, which became effective upon filing, for the offer and sale
of an unspecified principal amount of its first mortgage bonds. The issuance of first mortgage bonds requires that Idaho Power meet
interest coverage and security provisions set forth in the Idaho Power's Indenture of Mortgage and Deed of Trust, dated as of October
1,1937, as amended and supplemented from time to time (Indenture). Future issuances of first mortgage bonds are subject to
FERC FORM NO. 1 (ED. 12.88)Page 123.18
Name of Respondent
ldaho Power Company
This Report is:
(1) [ An Original
(2) - A Resubmission
Date of Report
(Mo, Da, Yr)
04114t2021
Year/Period of Report
20201Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
satisfaction of covenants and security provisions set forth in the Indenture, market conditions, regulatory authorizations, and covenants
contained in other financing agreements.
ln June 2020, Idaho Power entered into a selling agency agroement with six banls named in the agreement in
connection with the potential issuance and sale from time to time of up to $500 million aggregate principal amount of first
mortgage bonds, secured medium term notes, Series L (Series L Notes), under Idaho Power's Indenture of Mortgage and Deed
of Trust, dated as of October I , 1937 , as amended and supplemente d (Indenture). Also in June 2020, Idaho Power
entered into the Forty-ninth Supplemental lndenture, dated effective as ofJune 5,2020,to the Indenture (Forty-ninth
Supplemental Indenture). The Forty-ninth Supplemental Indenture provides for, among other items, the issuance of up to
$500 million in aggregate principal amount of Series L Notes pursuant to the Indenture.
The mortgage ofthe Indenture secures all bonds issued under the Indenture equally and ratably, without preference, priority, or
distinction. First mortgage bonds issued in the future will also be secured by the mortgage of the Indenture. The lien constitutes a first
mortgage on all the properties of Idaho Power, subject only to certain limited exceptions including liens for taxes and assessments that
are not delinquent and minor excepted encumbrances. Certain ofthe properties ofldaho Power are subject to easements, leases,
contracts, covenants, worhnen's compensation awards, and similar encumbrances and minor defects common to properties. The
mortgage ofthe Indenture does not create a lien on revenues or profits, or notes or accormts receivable, contracts or choses in action,
except as permitted by law during a completed default, securities, or casl1 except when pledged, or merchandise or equipment
manufactured or acquired for resale. The mortgage of the Indenture creates a lien on the interest of Idaho Power in property
subsequently acquired, other than excepted property, subject to limitations in the case ofconsolidatiorL merger, or sale ofall or
substantially all ofthe assets ofldaho Power. The Indenture requires Idaho Power to spend or appropriate 15 percent ofits 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. Idaho Power may amend the Indenture and increase this amount without consent of the
holders ofthe first mortgage bonds. The amount issuable is also restricted by property, earnings, and other provisions ofthe Indenture
and supplemental indentures to the Indenture. The Indenture requires that Idaho Power's net earnings be at least twice the annual
interest requirements on all outstanding debt ofequal or prior rank, including the bonds that Idaho Power may propose to issue. Under
certain circumstances, the net earnings test does not apply, including the issuance ofrefunding bonds to retire outstanding bonds that
mature in less than two years or that are ofan equal or higher interest rate, or prior lien bonds.
As of December 3l,2020,Idaho Power could issue under its Indenture approximately $1.8 billion of additional first mortgage bonds
based on retired first mortgage bonds and total unfunded property additions. These amounts are further limited by the maximum
amount of first mortgage bonds set forth in the Forty-ninth Supplemental Indenture. As a result, the maximum amount of first mortgag€
bonds Idaho Power could issue as of December 31,2020, was limited to approximately $534 million under the Indenture.
6. NOTES PAYABLE
Credit tr'acilities
On December 6,z0l9,Idaho Power entered into amendments to its outstanding Credit Agreements, which provide credit facilities that
may be used for general corporate purposes and commercial paper backup. Idaho Power's credit facility consists of a revolving line of
credit, through the issuance ofloans and standby letters ofcredit, not to exceed the aggregate principal amount at any one time
FERC FORM NO.1 I 123.19
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) -A Resubmission
Date of Report
(Mo, Da, Yr)
04114t2021
Year/Period of Report
20201Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
outstanding of $300 million, including swingline loans in an aggregate principal amount at any time outstanding not to exceed $30
million, and letters of credit in an aggregate principal amount at any time outstanding not to exceed $50 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 rates for any borrowings under the facility are based on either (l) a floating rate that is equal to the highest of the prime
rate, federal funds rate plus 0.5 percent, or LIBOR Market Index rate plus 1.0 percent, or (2) the LIBOR Market Index rate, plus, in
each case, an applicable margin, provided that the federal funds rate and LIBOR rate will not be less than zero. An altemate
benchmark rate selected by the administrative agent for the credit facility and Idaho Power will apply during any period in which the
LIBOR rate is unavailable or unascertainable. The applicable margin is based on Idaho Power's, as applicable, senior unsecured
long-term indebtedness credit rating by Moody's Investors Service, Inc., Standard and Poor's Ratings Services, and Fitch Rating
Services, Inc., as set forth on a schedule to the credit agreement. Under the credit facility, the company pays a faciliry fee on the
commitment based on the company's credit rating for senior unsecured long-term debt securities. While the credit facility provides for
an original maturity date of December 6,2024, the credit agreement grants Idaho Power the right to request up to two one-year
extensions, subject to certain conditions.
At December 31,2020, no loans were outstanding under Idaho Power's facility. At December 3l,2020,Idaho Power had regulatory
authority to incur up to $450 million in principal amount of short-term indebtedness at any one time outstanding. Idaho Power's
short-term borrowings were zero at December 31,2020, and December 31,2019.
7. COMMON STOCK
Idaho Power Common Stock
No contributions were made to Idaho Power in 2020 or 201 9 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 their credit facility or Idaho Power's Revised Code of Conduct. A covenant under Idaho Power's credit
facility requires Idaho Power to maintain a leverage ratio of consolidated indebtedness to consolidated total capitalization, as defined
therein, ofno more than 55 percent at the end ofeach fiscal quarter. At December 31,2020, the leverage ratio for Idaho Power was 46
percent. Based on these restrictions, Idaho Power's dividends were limited to $ I .3 billion at December 3l ,2020. There are additional
facility covenants, subject to exceptions, that prohibit or restrict the sale or disposition ofproperty without consent and any agreements
restricting dividend payments to Idaho Power from any material subsidiary. At December 31,2020,Idaho Power were in compliance
with those covenants.
Idaho Power's Revised Policy and Code of Conduct relating to transactions between and among Idaho Power, IDACORP, and other
affrliates, which was approved by the IPUC in April 2008, provides that Idaho Power will not pay any dividends to IDACORP that will
reduce Idaho Power's common equity capital below 35 percent of its total adjusted capital without IPUC approval. At December 31,
2020, Idaho Power's common equity capital was 54 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 prefened stock
dividends are in arrears. As ofthe date ofthis report, Idaho Power has no preferred stock outstanding.
FERC FORM NO.1 (ED.12.88)Page 123.20
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04114t2021
Year/Period of Report
20201Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
In addition to contractual restrictions on the amount and payment ofdividends, the FPA prohibits the payment ofdividends 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 earnings.
In accordance with Section 10(d) of the Federal Power Act, Idaho Power has $13.3 million of amortization reserves established for
certain of its licensed hydroelectric facilities.
8. SHARE.BASED COMPENSATION
Through its parent company IDACORP, Idaho Power has one share-based compensation plan - the 2000 Long-Term Incentive and
Compensation Plan (LTICP). The LTICP (for officers, key employees, and directors) permits the grant of stock options, restricted
stock and restricted stock units (together, Restricted Stock), performance shares and performance-based units (together,
Performance-Based Shares), and several other types of share-based awards. At December 31,2020, the maximum number of shares
available under the LTICP was 552,913.
Restricted Stock and Performance-Based Shares Awards
Restricted Stock awards have tkee-year vesting periods and entitle the recipients to dividends or dividend equivalents, as applicable,
and voting rights, except that holders ofrestricted stock units do not have voting rights until the units are vested and seftled in shares.
Unvested awards are restricted as to disposition and subject to forfeiture under certain circumstances. The fair value of these awards is
based on the closing market price ofcommon stock on the grant date and is charged to compensation expense over the vesting period,
reduced for any forfeitures during the vesting period.
Performance-Based Shares awards have three-year vesting periods and entitle the recipients to voting rights, except that holders of
performance-based units do not have voting rights until the units are vested and settled in shares. Unvested awards are restricted as to
disposition, subject to forfeiture under certain circumstances, and subject to the attainment of specific performance conditions over the
three-year vesting period. The performance conditions are two equally-weighted metrics, cumulative eamings per share (CEPS) and
total shareholder return (TSR) relative to a peer group. Depending on the level ofattainment ofthe performance conditions and the
year issued, the final number ofshares awarded can range from zero to 200 percent ofthe target award. Dividends or dividend
equivalents, as applicable, are accrued during the vesting period and paid out based on the final number ofshares awarded.
The grant-date fair value ofthe CEPS portion is based on the closing market value at the date ofgrant, reduced by the loss in
time-value of the estimated future dividend payments. The fair value of this portion ofthe awards is charged to compensation expense
over the requisite service period based on the estimated achievement ofperformance targets, reduced for any forfeitures during the
vesting period. The grant-date fair value of the TSR portion is estimated using the market value at the date of grant and a statistical
model that incorporates the probability of meeting performance targets based on historical returns relative to the peer group. The fair
value of this portion of the awards is charged to compensation expeirse over the requisite service period, provided the requisite service
period is rendered, regardless of the level of TSR metric attained.
A summary of Restricted Stock and Performance-Based Shares award activity is presented below. Idaho Power share amounts
represent shares of IDACORP common stock:
FERC FORM NO. 1 ED.1 123.21
Name of Respondent
ldaho Power Comoanv
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
o411412021
Year/Period of Report
20201Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Idaho Power
Number of
Shares/Units
Weighted-A
verage
Grant Date
tr'air Value
Nonvested shareVunits at January 1,2020
Sharedunits granted
Sharedunits forfeited
Shares/units vested
201,820 $
94,078
(43,662',)
(96,223)
90.99
107.17
104.67
84.54
Nonvested shares/unis at December 31,2020 156,013 $ 100.90
The total fair value of shares vested was $10.5 million in2020 and $9.4 million in 2019. At December 3l,2020,Idaho Power had $5.8
million oftotal unrecognized compensation cost related to nonvested share-based compensation. These costs are expected to be
recognized over a weighted-average period of I .7 years. Original issue shares of IDACORP are used for these awards.
In2020, a total of 10,296 shares of IDACORP common stock were awarded to directors of IDACORP and Idaho Power at an average
grant date fair value of $95.23 per share. Directors elected to defer receipt of 2,276 of these shares, which are being held as deferred
stock units with dividend equivalents reinvested in additional stock units.
Compensatian Expense: The following table shows Idaho Power's compensation cost recognized in income and the tax benefits
resulting from the LTICP (in thousands of dollars):
2020 2019
Compensation cost
Income tax benefit
$ 7,339 $
l,ggg
8,639
2,224
No equity compensation costs have been capitalized. These costs are primarily reported within "Other operations and maintenance"
expense on the consolidated statements of income.
FERC FORM NO. 1 (ED. 12.88)Page 123.22
Name of Respondent
ldaho Power Company
This Report is:
(1) X An OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
o41141202',1
Year/Period of Report
2020to,4
NOTES TO FINANCIAL STATEMENTS (Continued)
9. COMMITMENTS
Purchase Obligations
At December 31, 2020,Idaho Power had the following long-term commitments relating to purchases of energy, capacity, transmission
rights, and fuel (in thousands of dollars):
2021 2022 2023 2024 2025 Thereafter
Cogeneration and power production
Fuel
$ 254,550
41,818
$ 258,369
14,529
$ 269,196
8,379
$ 272,955
8,370
$ 279As4
8,362
$ 2,s41,281
66,709
As of December 3l,2020,Idaho Power had 1,134 MW nameplate capacity of PURPA-related projects on-line, with an additional 6
MW nameplate capacity ofprojects projected to be on-line by 2022. The power purchase contracts for these projects have original
contract terms ranging from one to 35 years. Idaho Power's expenses associated with PLIRPA-related projects were approximately
$194 million in2020 and $187 million in 2019.
Idaho Power also has the following long-term commitments (in thousands of dollars):
2021 2022 2023 2024 2025 Thereafter
Joint-operating agreement payrrents(l)
Easements and other payments
Maintenance and service agxeements(l )
FERC and other industry-related fees(l)
$ 2,649 $ 2,649 $ 2,649 $ 2,649 $ 2,649 $
2,037 1,074 1,090 1,081 1,075
50,761 18,4'.12 9,427 7,5',13 5,737
14,394 12,886 13,090 13,303 13,524
t3243
17,272
50,705
68,766
(l) Approximately$26million,$2lmillion,and$l35millionoftheobligationsincludedinjoint-operatingagreementpayments,maintenanceandservice
agreernents, and FERC and other industry-related fees, respectively, have contracts that do not speciry terms related to expiration. As these contracts are preswned
to continue indefinitely, ten years of information, estimated based on current contact terms, has been included in the table for presentation purposes.
Idaho Power's expense for operating leases was not material for the years ended 2020 and 2019
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
(WDEQ), was $58.3 million at December 37,2020, representing IERCo's one{hird share of BCC's total reclamation obligation of
$175.0 million. BCC has a reclamation trust fund set aside specifically for the purpose of palng these reclamation costs. At
December 37,2020, the value of the reclamation trust fund was $183.3 million. During 2020,the reclamation trust fund made
$4.8 million of distributions 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 reseryes, BCC has the ability to, and does, add a per-ton surcharge to coal sales, all of which are made to the Jim Bridger
plant. Because of the existence of the fund and the ability to apply a per-ton surcharge, the estimated fair value of this guarantee is
minimal.
FERC FORM NO.1 (ED.12-88)Pase'123.23
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2) A Resubmission
Date of Report
(Mo, Da, Yr)
o411412021
Year/Period of Report
20201Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
In May 201 9, the state of Wyoming enacted legislation that limits a mine operator's maximum amount of self-bonding. Commencing
in the first quarter of2021, Idaho Power plans to post collateral in the form ofa surety bond purchasedjointly with the co-owner of
BCC to cover the projected mine reclamation costs pursuant to the laws of the state of Wyoming. As of the date of this report, Idaho
Power believes the cost of the surety bond required for this guarantee due to the new law will be immaterial to its financial statements.
Idaho Power enters into financial agreements and power purchase and sale agreements that include indemnification provisions relating
to various forms of claims or liabilities that may arise from the transactions contemplated by these agreements. Generally, a maximum
obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under
such indemnification provisions cannot be reasonably estimated. Idaho Power periodically evaluate the likelihood ofincurring costs
under such indemnities based on their historical experience and the evaluation of the specific indemnities. As of Decernber 31,2020,
management believes the likelihood is remote that Idaho Power would be required to perform under such indemnification provisions or
otherwise incur any significant losses with respect to such indemnification obligations. Idaho Power has not recorded any liability on
its balance sheets with respect to these indemnification obligations.
10. CONTINGENCIES
Idaho Power has in the past and exp€cts in the future to become involved in various claims, controversies, disputes, and other
contingent matters, some of which involve litigation and regulatory or other contested proceedings. The ultimate resolution and
outcome of litigation and regulatory proceedings is inherently difficult to determine, particularly where (a) the remedies or penalties
sought are indeterminate, (b) the proceedings are in the early stages or the substantive issues have not been well developed, or (c) the
matters involve complex or novel legal theories or a large number ofparties. In accordance with applicable accounting guidance, Idaho
Power, as applicable, establishes an accrual for legal proceedings when those matters proceed to a stage where they present loss
contingencies that are both probable and reasonably estimable. 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 for any developments that would
make the loss contingency both probable and reasonably estimable. As of the date of this report, Idaho Power's accruals for loss
contingencies are not material to its financial statements as a whole; however, future accruals could be material in a given period.
Idaho Power's determination is based on currently available information, and estimates presented in financial statements and other
financial disclosures involve significant judgment and may be subject to significant uncertainty. For matters that affect Idaho Power's
operations, Idaho Power intends to seek, to the extent permissible and appropriate, recovery through the ratemaking process ofcosts
incurred, although there is no assurance that such recovery would be granted.
Idaho Power is party to legal claims and legal, tax, and regulatory actions and proceedings in the ordinary course ofbusiness and, as
noted above, record an accrual for associated loss contingencies when they are probable and reasonably estimable. In connection with
its utility operations, Idaho Power is subject to claims by individuals, entities, and governmental agencies for damages for alleged
personal injury, property damage, and economic losses, relating to the company's provision of electric service and the operation of its
generation, transmission, and distribution facilities. Some of those claims relate to electrical contacts, service quality, property damage,
and wildfires. In recent years, utilities in the western United States have been subject to sigrrificant liability for personal injury, loss of
life, property damage, trespass, and economic losses, and in some cases, punitive damages and criminal charges, associated with
wildfires that originated from utility property, most commonly transmission and distribution lines. In recent years, Idaho Power has
regularly received claims by governmental agencies and private landowners for damages for fires allegedly originating from Idaho
Power's transmission and distribution system. As of the date of this report, Idaho Power believes that resolution of existing claims will
not have a material adverse effect on its financial statements. Idaho Power is also actively monitoring various pending environmental
regulations and executive orders related to environmental matters that may have a sigaificant impact on its future operations. Given
uncertainties regarding the outcome, timing, and compliance plans for these environmental matters, Idaho Power is unable to estimate
FERC FORM NO. 1 (ED. 12.88)Page'123.24
Name of Respondent
ldaho Power Company
This Report is:
(1) X An OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
o4l't412021
Year/Period of Report
202Uo'4
NOTES TO FINANCIAL STATEMENTS (Continued)
the financial impact of these regulations.
II. BENEFIT PLANS
Idaho Power sponsors defined benefit and other postretirement benefit plans that cover the majority of its employees. Idaho Power also
sponsors a defined contribution 401(k) employee savings plan and provides certain post-employment benefits.
Pension Plans
Idaho Power has pension plans-a noncontributory defined benefit pension plan (pension plan) and rwo nonqualified defined benefit
pension plans for 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 for
directors that was frozen in 2002. Remaining vested benefits from that plan are included with the SMSP in the disclosures below. The
benefits under these plans are based on years ofservice and the employee's final average earnings.
The following table summarizes the changes in benefit obligations and plan assets of these plans (in thousands of dollars)
Pension Plan SMSP
2020 2019 2020 2019
Change in projected benefit obligation:
Benefit obligation at January I
Service cost
Interest cost
Actuarial loss
Plan amendment
Benefits paid
$1,134,752
42,987
40,013
163,610
$ 951,857 $
34,061
42,312
147,784
122,443
213
4,350
13,420
130
(5,765)
$ 102,318
(l8l)
4,575
17,888
2,839
(4,996)(43,967) (41,262)
Projected benefit obligation at December 31 7,337,395 1,134,752 134,791 122,443
Change in plan assets:
Fair value at January 1
Actual return on plan assets
Employer contributions
Benefits paid
763,119
l12,45l
40,000
(43,967)
650,604
113,777
40,000
(41,262)
Fair value at December 3l 871,603 763,119
Funded status at end ofyear s (465,792) $ (371,633) $ (134,791) $(122,443)
Amounts recognized in the balance sheet consist of:
Other current liabilities $$$ (6,154) $ (5,91 l)
FERC FORM NO.I (ED.12.88)Pase 123.25
Name of Respondent
ldaho Power Companv
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
o4t14t2021
Year/Period of Report
202Uc'4
NOTES TO FINANCIAL STATEMENTS (Continued)
Noncurrent liabilities (465,792) (371,633) (128,637) (116,532)
Net amount recognized $ (46s,792\ $ (371,633) $ (134,791) $(t22,443)
Amounts recognized in accumulated other comprehensive income
consist of:
Net loss
Prior service cost
$437,859 S 347,785
49 56
$ 55,537 $
2,993
45,851
3,143
Subtotal 437,908 347,841 58,520 48,994
Less amount recorded as regulatory asset(l)(437,908) (347,841)
Net amount recognized in accumulated other comprehensive income $s $ 58,520 $ 48,994
Accumulated benefit obligation $1,115,923 $ 958,586 $ ll9,5l7 $ 109,966
( I ) Changes in the funded status of the pension plan that would be recorded in accumulated other comprehensive income for an unregulated entity are recorded as a
regulatory asset for Idaho Power as ldaho Power believes it is probable that an amount equal to the regulatory asset will be collected through the setting of future
rates.
The actuarial losses reflected in the benefit obligations for the pension and SMSP plans in 2020 are due primarily to decreases in the
assumed discount rates of both plans from December 31,2079, to December 31,2020. The actuarial losses affecting the benefit
obligations for the pension and SMSP plans in 2019 are due primarily to decrease s in the assumed discount rates from December 3 l,
2018, to December 31,2019. For more information on discount rates, see "Plan Assumptions" below in this Note 12.
As a non-qualified plan, the SMSP has no plan assets. However, Idaho Power has a Rabbi trust designated to provide funding for
SMSP obligations. The Rabbi trust holds investments in marketable securities and corporate-owned life insurance. The recorded value
of these investments was approximately $108.8 million and $97.6 million at December 31,2020 and 2019, respectively, and is
reflected in Investments and in Company-owned life insurance on the balance sheets.
The following table shows the components ofnet periodic benefit cost for these plans (in thousands ofdollars). For purposes of
calculating the expected retum on plan assets, the market-related value of assets is equal to the fair value of the assets.
Pension Plan SMSP
2020 2019 2020 2019
Service cost
Interest cost
Expected rotum on assets
Amortization of net loss
Amortization of prior service cost
$ 42,987
40,013
(56,239)
17,325
6
$ 34,061
42,312
(48,623)
13,564
6
$ 213
4,350
$ (l8l)
4,575
3,134
290
2,533
96
Net periodic pension cost
Regulatory deferral ofnet periodic benefit cos(l)
Previously deferred pension cost recognized(1 )
44,092
(42,042)
17,154
41,320
(39,379)
17,154
8,587 7,023
Netperiodicbenefitcostrecognizedforfinancialreporting(lX2) $ 19,204 $ 19,095 $ 8,587 $ 7,023
FERC FORM NO.1 (ED.12.88)Page 123.26
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2) A Resubmission
Date of Report
(Mo, Da, Yr)
041141202'l
Year/Period of Report
2020tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
( I ) Net periodic benefit costs for the pension plan are recognized for financial re,porting based upon the authorization of each regulatory jurisdiction in which Idaho
Power operates. Under IPUC order, the Idaho portion ofnet periodic benefit cost is recorded as a regulatory asset and is recognized in the income statement as
those costs are recovered through rates.
(2) Of total net periodic benefit cost recognized for financial repo(ing $ 1 5.9 million and $ 1 5. 1 million, respectively, was recopized in "Other operations and
maintenance" and $ I I .9 million and $ I I .0 million respectively, was recognized in "Other (income) expense, net" on the statements of income of the companies for
the twelve months ended Decernber 31,2020 and 2019.
The following table shows the components of other comprehensive (loss) income for the plans (in thousands of dollars):
Pension Plen SMSP
2020 2019 2020 2019
Actuarial (loss) gain during tho year
Plan amendment service cost
Reclassifi cation adjush€nts for:
Amortization of net loss
Amortization ofprior service cost
Adjustment for deferred tax effects
Adjustment due to the effects of regulation
$(107,399) $(82,631)$ (13,420)
(130)
$(17,888)
(2,839)
17,325
6
23,184
66,884
13,564
6
t7,776
51,285
3,734
290
2,452
2,533
96
4,658
Other comprehensive (loss) income recognized
related to pension benefit plans $$$ (7,074) $(13,,140)
The following table summarizes the expected future benefit payments of these plans (in thousands of dollars):
2021 2022 2023 2024 202s 2026-2030
Pension Plan
SMSP
$ 42,701 $
6,154
44,558 $
6,197
46,596 $
6,349
48,616 $
6,491
50,521 $
6,489
28243r
33,339
Idaho Power's funding policy for the pension plan is to contribute at least the minimum required under the Employee Retirement
Income Security Act of 1974 (ERISA) but not more than the maximum amount deductible for income tax purposes. 1n2020 and 2019,
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. As of the date of this
report, Idaho Power's minimum required contribution to the pension plan is estimated to be $4 million during 2021 . Depending on
market conditions and cash flow considerations in 2021, Idaho Power could contribute up to $40 million to the pension plan during
2021 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 underfunded position.
FERG FORM NO.1 (ED.12-88)Page 123.27
Postretirement Benefi ts
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
0411412021
Year/Period of Report
202Uo,4
NOTES TO FINANCIAL STATEMENTS (Continued)
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 qualifoing
dependents. Retirees hired on or after January 1,7999, have access to the standard medical option at full cost, with no contribution by
Idaho Power. Benefits for employees who retire after Decemb er 37 , 2002, are limited to a fixed amount, which has limited the growth
of Idaho Power's future obligations under this plan.
The following table summarizes the changes in benefit obligation and plan assets (in thousands of dollars):
2020 2019
Change in accumulated bene{it obligation:
Benefit obligation at January I
Service cost
Interest cost
Actuarial loss (gain)
Benefits paid(l)
$71,029 $
1,029
2,493
9,359
(2,958)
66,453
853
2,989
5,298
(4,564)
Benefit obligation at December 3l 80,952 71,029
Change in plan assets:
Fair value ofplan assets at January I
Actual return (loss) on plan assets
Employer contributions( 1 )
Benefits paid(l)
39,625
5,248
(604)
(2,958)
33,391
7,269
3,529
(4,564)
Fair value of plan assets at December 31 41,311 39,625
Funded status at end ofyear (included in noncurrent liabilities)$ (39,641) $ (31,404)
(l) Contributionsandbanefitspaidareeachnetof$3.4millionand$3.3millionofplanparticipantconkibutionsfor2020 and20l9,respectively.
Amounts recognized in accumulated other comprehensive income consist of the following (in thousands of dollars):
2020 2019
Net loss
Prior service cost
$6,434 $
t27
(81)
174
Subtotal
Less amount recognized in regulatory assets
6,561
(6,561)
93
(e3)
Net amount recognized in accumulated other comprehensive income $$
FERC FORM NO. 1 (ED.12.88)Page 123.28
Name of Respondent
ldaho Power Company
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
o4t14t2021
Year/Period of Report
20201Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
The net periodic postretirement benefit cost was as follows (in thousands of dollars):
2020 2019
Service cost
Interest cost
Expected return on plan assets
Amortization of prior service cost
$1,029 $
2,493
(2,404)
47
853
2,ggg
(2,220)
48
Net periodic postretirement benefit cost $ 1,165 $ 1,670
The following table shows the components of other comprehensive income for the plan (in thousands of dollars):
2020 2019
Actuarial loss during the year
Reclassifi cation adjustments for:
Reclassification adjustments for amortization of prior service cost
Adjustment for deferred tax effects
Adjustment due to the effects of regulation
$ (6,515) $ (249)
47
1,665
4,803
52
149
48
Other comprehensive income related to postretirement benefit plans $$
The following table summarizes the expected future benefit payments of the postretirement beneftt plan (in thousands of dollars):
2021 2022 2023 2024 2025 202G2029
Expected benefit payments $ 5,363 $ 5,245 $5,056 $ 4,843 $ 4,668 $ 20,211
Plan Assumptions
The following table sets forth the weighted-average assumptions used at the end ofeach year to determine benefit obligations for all
Idaho Power-sponsored pension and postretirement benefits plans:
Pension Plan SMSP
Postretirement
Benefits
2020 2019 2020 2019 2020 2019
Discount rate
Rate of compensation increase(l)
Medical trend rate
Dental trend rate
Measurement date
2.80%
4.43 %
3.60%
4.37 %
2.70%
4.7s %
3.6s%
4.75 %
2.70%3.60%
6.8%
4.0%
1213u2020
6.7 %
4.0%
t2/3U20191213y2020 t2l3y20t9 t2/3U2020 t2l3u20t9
FERC FORM NO. I (ED. 12-88)Page 123.29
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(21 A Resubmission
Date of Report
(Mo, Da, Yr)
0411412021
Year/Period of Report
20201Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
(l) The2020rateofcompensationincreaseassumptionforthepensionplanincludesaninflationcomponentof2.40Yopl:usa2.03%compositemeritincrease
component that is based on ernployees' years of service. Merit salary increases are assumed to be 8.0% for ernployees in thet first year of service and scale down to
0.6% for anployees in their fortieth year ofservice and beyond.
The following table sets forth the weighted-average assumptions used to determine net periodic benefit cost for all Idaho
Power-sponsored pension and postretirement benefit plans:
Pension Plan SMSP
Postretirement
Benefits
2020 2019 2020 2019 2020 2019
Discount rate
Expected long-term rate of return
on assets
Rate of compensation increase
Medical trend rate
Dental trend rate
3.60%
7.40%
4.43%
4.s5 %
7.50 %
4.37 %
3.65% 4.60%
4.7s % 4.75 %
3.60% 4.60%
6.50%
6.8 o/o
4.0%
6.75 %
-%
6.7 %
4.0%
The assumed health care cost trend rate used to measure the expected cost of health benefits covered by the postretirement plan was
6.8 percent in 2020 and is assumed to decrease to 6.0 percent in 2021 ,5.2 percent in 2022, 5. I percent in 2023 and to gradually
decrease to 3.9 percent by 2074. The assumed dental cost trend rate used to measure the expected cost of dental benefits covered by
the plan was 4.0 percent, or €qual to the medical trend rate if lower, for all years.
Plan Assets
Pension Asset Allocation Policy: The target allocation and actual allocations at December 31,2020, for the pension asset portfolio by
asset class is set forth below;
Asset Class
Target
Allocation
Actual
Allocation
December 31,
2020
Debt securities
Equity securities
Real estate
Other plan assets
24%
59 Yo
9%
8%
23%
64%
6%
n o/I /O
Total t00%100 o/o
Assets are rebalanced as necessary to keep the portfolio close to target allocations. The plan's principal investment objective is to
maximize total return (defined as the sum of realized interest and dividend income and realized and unrealized gain or loss in market
price) consistent with prudent parameters of risk and the liability profile of the portfolio. Emphasis is placed on preservation and
gowth of capital along with adequacy of cash flow sufficient to fund current and future payments to plan participants.
FERC FORM NO.1 (ED.12.88)Page 123.30
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t',t4t2021
Year/Period of Report
2020to'4
NOTES TO FINANCIAL STATEMENTS (Continued)
The three major goals in Idaho Power's asset allocation process are to:
o determine if the investments have the potential to eam the rate of return assumed in the actuarial liability calculations;
o match the cash flow needs ofthe plan. Idaho Power sets bond allocations suffrcient to cover approximately five years ofbenefit
pa).rnents. Idaho Power then utilizes gowth instruments (equities, real estate, venture capital) to fund the longer-term liabilities of
the plan; and
o maintain a prudent risk profile consistent with ERISA fiduciary standards.
Allowable plan investments include stocks and stock funds, investment-grade bonds and bond funds, 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/retum relationships among asset classes. The primary measure is
the historical risk premium each asset class has delivered versus the yield on the Moody's AA Corporate Bond Index. This historical
risk premium is then added to the current yield on the Moody's AA Corporate Bond Index. Additional analysis is performed to measure
the expected range of returns, as well as worst-case and best-case scenarios. Based on the current low interest rate environment, current
rate-of-return expectations are lower than the nominal retums generated over the past 30 years when interest rates were generally much
higher.
Idaho Power's asset modeling process also utilizes historical market refums to measure the portfolio's exposure to a "worst-case"
market scenario, to determine how much performance could vary from the expected "average" performance over various time periods.
This "worst-case" modeling, in addition to cash flow matching and diversification by asset class and investment style, provides the
basis for managing the risk associated with investing portfolio assets.
Fair Value of Plan Assets: Idaho Power classifies its pension plan and postretirement benefit plan investments using the three-level
fair value hierarchy described in Note 16 - "Fair Value Measurements." The following table presents the fair value of the plans'
investments by asset category (in thousands of dollars).
Levell Level2 Level3 Total
Assets at December 3Lr2020
Cash and cash equivalents
Intermediate bonds
Equity Securities: Large-Cap
Equity Securities: Mid-Cap
Equity Securities: Small-Cap
Equity Securities: Micro-Cap
Equity Securities: Global and International
Equity Securities: Emerging Markets
Plan assets measured at NAV (not subject to hierarchy disclosure)
Commingled Fund: Equity Securities: Global and Intemational
Commingled Fund: Equity Securities: Emerging Markets
$ 25,008
34,455
79,259
104,089
82,069
44,715
69,687
10,574
$-
163,000
$ 25,008
197,455
79,259
104,089
82,069
44,715
69,687
10,574
$
116,223
50,019
FERC FORM NO.1 ED.1 't23.31
Name of Respondent
ldaho Power Companv
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
04114t2021
Year/Period of Report
2020tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Real estate
Private market investments
54,630
37,875
Total $449,856 $ 163,000 $$ 871,603
Postretirement plan assets( I )$ 1,333 $ 39,978 $$ 41,311
Levell Level2 Level3 Total
Assets at December 31,2019
Cash and cash equivalents
Short-term bonds
Intermediate bonds
Equity Securities: I-arge-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)
Commingled Fund: Equity Securities: Global and International
Commingled Fund: Equity Securities: Emerging Markets
Commingled Fund: Commodities fund
Real estate
Private market investments
$ 10,878
21,628
22,369
92,852
81 ,663
67,075
31,469
13,817
8,245
134,931
$ 10,878
21,629
157,300
92,852
81 ,663
67,075
3l,469
13,817
8,245
rr4,97 5
40,059
34,793
47,570
40,795
$$
Total $349,996 $ 134,931 $$763,1 l9
Postretirement plan assets( 1 )
(l) The postretirement benefits assets are primarily life insurance contracts.
$ 641 $ 38,984 $$ 39,625
FortheyearsendedDecember3l,2020and2}l9,therewerenomaterialtransfersintooroutoflevels l,2,or3
Fair Value Measurement of Level 2 Plan assets and Plan assets measured at NAV:
Level 2 Bonds: These investments represent United States government, agency bonds, and corporate bonds. The United States
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 life 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
FERC FORM NO. 1 (ED. 12-88)Page 123.32
Name of Respondent
ldaho Power Company
This Report is:
(1) X An OriginalQ) A Resubmission
Date of Report
(Mo, Da, Yr)
04t1412021
Year/Period of Report
20201Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
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 global, international and emerging markets equity securities and commodities fund
meazured at NAV, ax€ not publicly traded, and therefore no publicly quoted market price is readily available. The values 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 for the fund company on a monthly or more frequent basis, and are based on market prices
of the assets held by each of the commingled funds divided by the number of fund 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 investments in open-end and closed-end commingled real estate funds. As the property
interests held in these real estate funds are not frequently traded, establishing the market value ofthe property interests held by the
fund, and the resulting unit value of fund shareholders, is based on unobservable inputs including property appraisals by the fund
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 real estate funds also furnish annual audited financial statements that are also used to further validate the information provided.
Redemptions on the open-end funds are generally available on a quarterly basis, with 10 to 35 days written notice, depending on the
individual fund. If the fund has sufficient liquidity, the redemption will be processed at the fund NAV or the fund's estimate of fair
value at the end of the quarter. 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 funds have no duty to liquidate or encumber funds to meet
redemption requests. The closed-end funds are formed for a stated life of 7 to 9 years. The fund can be further extended with the
approval of the limited partners. There are generally no redemption rights associated with these funds. The limited paxtner must hold
the fund for the life of the fund or find a third-party buyer.
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 of the underllng 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 funding 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 fair value within 60 days following
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 adjust 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
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 ofrecent funding ovents, or pending offers from other viable
entities. These private market investments fumish annual audited financial statements that are also used to further validate the
information provided. These funds are formed for a stated life of l0 to l5 years. The general partner can extend the fund life for 2 or 3
one-year periods. The fund 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 for the life of the fund or find a third-party buyer.
FERC FORM NO.1 (ED.12-88)Page 123.33
Employee Savings Plan
Name of Respondent
ldaho Power Company
This Report is:
(1) [ An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
04114t2021
Year/Period of Report
2020tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
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 approximately $7.9 million and $7.7 million in2020 and 2019, respectively.
Post-employment Benefi ts
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 benefits included in other deferred credits on ldaho Power's balance sheets at December 31,2020 and 2019, were
approximately $2 million.
12. PROPERTY, pl,Alrr AND EQUTPMENT AltD JOTNTLY-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 3l , 2020 and 20 I 9
(in thousands of dollars):
2020 2019
Balance
-
$ 2,529,708
1,272,360
1,969,752
517,079
3.23 % $ 2,535,938
1.88 % 1,220,703
2.26% 1,882,136
6.17 % 478,662
Avg Rate Balance Avg Rate
-
Production
Transmission
Distribution
General and Other
3.19 o/o
1.89 %
2.25%
6.17 %
Total in service
Accumulated provision for depreciation
6,2g7,ggg
(2,376,165)
2.88% 6,1t7A39
(2,341,468)
$ 3,775,971
2.87 o/o
In service - net $ 3,911,734
At December 3l,2020,Idaho Power's construction work in progress balance of $597.2 million included relicensing costs of $356.9
million for the HCC, Idaho Power's largest hydropower complex.In2020 and 2019, Idaho Power had IPUC authorization to include in
its Idaho jurisdiction rates $6.5 million annually ($8.8 million when grossed-up for the effect of income taxes) of AFUDC relating to
the HCC relicensing project. Collecting these amounts will reduce the amount collected in the future once the HCC relicensing costs
are approved for recovery in base rates. At December 37,2020,Idaho Power's regulatory liability for collection of AFUDC relating to
the HCC was $169.1 million.
Idaho Power's ownership interest in two 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 Statements of Income. These
jointly-owned facilities, including balance sheet amounts and the extent of Idaho Power's participation, were as follows at
FERC FORM NO. 1 (ED. 12.88)Page 123.34
Name of Respondent
ldaho Power Comoanv
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t1412021
Year/Period of Report
20201Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
December 31, 2020 (in thousands of dollars):
Name of Plant Location
Utitity
Plant in
Service
Construction
Work in
Progress
Accumulated
Provision for
Depreciation
Ownership
%Mw(lx2)
JimBridgerunits l-4
North Valmy unit 2(2)
Rock Springs, WY
Winnemucca, NV
$ 749,735 $
253,409
8,062 $
347
376,232
180,669
33
50
771
145
( I ) Idaho Power's share of nameplate capacity.
(2) Pursuant to an agreemott with NV Energy, Idaho Power's participation in coal-fued operations of North Valmy ended in December 201 9 at unit 1 and is planned to
end no later than the end of2025 at unit 2.
In October 2020, Idaho Power and co-owner Portland General Electric ceased coal-fired operations at their Boardman power plant
consistent with Idaho Power's continued path away from coal-fired generation. All depreciable property, plant and equipment
associated with Idaho Power's ownership in the Boardman power plant was fully depreciated as of December 31, 2020.
IERCo, Idaho Power's wholly-owned subsidiary, is a joint venturer in BCC. Idaho Power's coal purchases from the joint venture were
$68.3 million in2020 and $73.6 million in 2019.
Idaho Power has contracts to purchase the energy from four PURPA qualifying facilities that are 50 percent owned by lda-West. Idaho
Power's power purchases from these facilities were $9.3 million in2020 and $8.6 million in 2019.
13. ASSET RETIREMENT OBLTGATTONS (ARO)
The guidance relating to accounting for AROs requires that legal obligations associated with the retirement of property, plant, and
equipment be recognized as a liability at fair value when incurred and when a reasonable estimate of the fair value of the liability can
be made. Under the guidance, when a liability is initially recorded, the entity increases the carrying amount of the related longJived
asset to reflect the future retirement cost. Over time, the liability is accreted to its estimated settlement value and paid, and the
capitalized cost is depreciated over the useful life ofthe related asset. If, at the end ofthe asset's life, the recorded liability differs from
the actual obligations paid, a gain or loss would be 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. Accretion, depreciation, and gains or losses related to the Boardman generating facility have
been exempted from such regulatory treatment as Idaho Power collected amounts related to the decommissioning of Boardman in
rates. In October 2020, Idaho Power and co-owner Portland General Electric ceased coal-fired operations at their Boardman power
plant. At December 37,2020,Idaho Power has recorded a liability for estimated costs of decommissioning and retirement of
Boardman plant assets, which is included in the amounts in the table below.
Idaho Power's recorded AROs relate to the reclamation and removal costs at its jointly-owned coal-fired generation facilities.
Idaho Power also has additional AROs associated with its transmission system and generation facilities; however, due to the
indeterminate removal date, the fair value of the associated liabilities cunently cannot be estimated and no amounts are recognized in
the financial statements.
Idaho Power also collects removal costs in rates for certain assets that do not have associated AROs. Idaho Power is required to
classiS these removal costs as regulatory liabilities, see Note 3 - "Regulatory Matters" for the removal costs recorded as regulatory
FERC FORM NO.1 (ED.12.88)Pase 123.35
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(21 A Resubmission
Date of Report
(Mo, Da, Yr)
0411412021
Year/Period of Report
2020to'4
NOTES TO FINANCIAL STATEMENTS (Continued)
liabilities on Idaho Power's balance sheets as of December 31,2020 and 2019
The following table presents the changes in the carrying amount of AROs (in thousands of dollars):
2020 2019
Balance at beginning ofyear
Accretion expense
Revisions in estimated cash flows
Liability settled
$28,191 $
1,053
193
(1,746)
26,792
1,1 15
365
(81 )
Balance at end ofyear $ 27,691 $ 28,191
T4.INVESTMENTS
The table below summarizes Idaho Power's investments as of December 3l (in thousands of dollars):
2020 2019
Idaho Power investments:
IERCO
Exchange traded short-term bond funds and cash equivalents
Executive deferred compensation plan investments
$33,919 $
50,531
202
25,516
42,648
90
Total Idaho Power investments 84,651 68,254
Investments in Equity Securities
Investments in equity securities are reported at fair value. Any unrealized gains or losses on equity securities are included in income.
Unrealized gains and losses on equity securities were immaterial at December 31,2020 and December 31,2019. The following table
summarizes sales of equity securities (in thousands of dollars):
2020 2019
Proceeds from sales
Gross realized gains from sales
$ 25,795 $5,080 ;
15. DERIVATIVE F'INANCIAL INSTRUMENTS
Commodity Price Risk
Idaho Power is exposed to market risk relating to electricity, natural gas, and other fuel commodity prices, all of which are heavily
influenced by supply and demand. Market risk may be influenced by market participants' nonperformance of their contractual
obligations and commitments, which affects the supply of or demand for the commodity. Idaho Power uses derivative instruments,
such as physical and financial forward contracts, for both electricity and fuel to manage the risks relating to these commodity price
exposures. The primary objectives ofldaho Power's energy purchase and sale activity are to meet the demand ofretail electric
FERC FORM NO.1 (ED.12.88)Page 123.36
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t14t2021
Year/Period of Report
202Uo,4
NOTES TO FINANCIAL STATEMENTS (Continued)
customers, maintain appropriate physical reserves to ensure reliability, and make economic use of temporary surpluses that may
develop.
All of Idaho Power's derivative instruments have been entered into for the purpose of economically hedging forecasted purchases and
sales, though none ofthese instruments have been designated as cash flow hedges. Idaho Power offsets fair value amounts recognized
on its balance sheet and applies collateral related to derivative instruments executed with the same counterparty under the same master
netting agreement. Idaho Power does not offset a counterparty's current derivative contracts with the counterparty's long-term
derivative contracts, although Idaho Power's master netting arrangements would allow current and long-term positions to be offset in
the event of default. Also, in the event of default, Idaho Power's master netting arrangements would allow for the offsetting of all
transactions executed under the master netting arrangement. These types of transactions may include non-derivative instruments,
derivatives qualiffing for scope exceptions, receivables and payables arising from settled positions, and other forms ofnon-cash
collateral (such as letters ofcredit). These types oftransactions are excluded from the offsetting presented in the derivative fair value
and offsetting table below.
The table below presents the gains and losses on derivatives not designated as hedging instruments for the years ended December 3 l,
2020 and 2019 (in thousands ofdollars):
Location of Realized Gain(Loss) on
Derivatives Recognized in Income
Gain(Loss) on Derivatives Recognized in Income(l)
2020 2019
Financial swaps
Financial swaps
Financial swaps
Financial swaps
Forward contracts
Forward contracts
Forward contracts
Operating revenues
Purchased power
Fuel expense
Other operations and maintenance
Operating revenues
Purchased power
Fuel expe,nse
$2,173 $
(3,53 l)
(4,791\
421
(384)
(36)
904
(2,1 83)
13,811
285
(270)
555
-
(l ) Excludes rmrealized 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 revenues from contracts with
customers 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 16 - "Fair Value Measurements" for additional information
concerning the determination of fair value for Idaho Power's assets and liabilities from price risk management activities.
Derivative Instrument Summary
The table below presents the fair values and locations of derivative instruments not designated as hedging instruments recorded on the
balance sheets and reconciles the gross amounts of derivatives recognized as assets and as liabilities to the net amounts presented in the
balance sheets at December 31 , 2020 and 201 9 (in thousands of dollars):
FERC FORM NO.1 ED.1 123.37
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t',t4t2021
Year/Period of Report
20201Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Asset Derivatives Liability Derivatives
Balance Sheet Location
Gross
Fair
Value
Amounts
Offset
Net
Assets
Gross
tr'air
Value
Amounts
Offset
Net
Liabilities
December 31,2020
Current:
Financial swaps
Financial swaps
Forward contracts
Forward contracts
Long-term:
Financial swaps
Other current assets
Other current liabilities
Other current assets
Other current liabilities
Other liabilities
$ 2,028 S
187
5
J
(36)
(187)
(2)
(3)
$ 1,992 $ 36 $ (36) $
786 (652) trl
32(2)
13 (3)
56 (56) rrr
134
10
40 (40)
Total $ 2,263 $ (268) $ 1,995 $ 893 $ (749) $ r44
-
December 31,2019
Current:
Financial swaps
Financial swaps
Forward contracts
Forward contracts
Long-term:
Financial swaps
Other current assets
Other current liabilities
Other current assets
Other current liabilities
Other liabilities
$ (2,034)
(134)
3 (3)
$ 392 g 2,034
924
l3
32
$ (2,034)
(134)
27 (3)
$ 2,426
134
l3
$
790
32
24
Total $ 2,576 $ (2,171) $ 405 $ 3,017 $ (2,171) $ 846
-
-
(l) Currentandlong-termliabilityderivativeamountsoffsetinclude$0.5millionond$l6thousandofcollateralreceivableatDecember3l,2\z\,respectively
The table below presents the volumes of derivative commodity forward contracts and swaps outstanding at December 31, 2020 and
20 I 9 (in thousands of units):
December 31,
Commodity Units 2020 2019
Electricity purchases
Electricity sales
Natural gas purchases
Natural gas sales
MWh
MWh
MMBtu
MMBtu
74
7,923
775
91
138
14,053
78
FERC FORM NO. 1 (ED. 12.88)Page 123.38
Name of Respondent
ldaho Power Company
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
04114t2021
Year/Period of Report
2020to,4
NOTES TO FINANCIAL STATEMENTS (Continued)
Credit Risk
At December 3l,2020,Idaho Power did not have material credit risk exposure from financial instruments, including derivatives. Idaho
Power monitors credit risk exposure through reviews of counterparty credit quality, corporate-wide counterparty credit expozure, 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
afiiliates, as deemed necessary. Idaho Power's physical power contracts are commonly under WSPP, Inc. 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 typically 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 Idaho Power's derivative instruments contain provisions that require Idaho Power's unsecured debt to maintain an
investment grade credit rating from Moody's Investors Service and Standard & Poor's Ratings Services. If Idaho Power's unsecured
debt were to fall below investment grade, it would be in violation ofthese 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 features
that were in a liability position at December 31,2020, was $0.9 million. Idaho Power posted $0.5 million cash collateral related to this
amount. If the credit-risk-related contingent features underlying these agreements were triggered on December 3l,2020,Idaho Power
would have been required to pay or post collateral to its counterparties up to an additional $6.6 million to cover open liability positions
as well as completed transactions that have not yet been paid.
16. FAIR VALUE MEAST]REMENTS
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 1) and the lowest priority to unobservable inputs (Level 3). If the inputs used to moasure the financial instruments fall
within different levels ofthe 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 balance sheets are categorized based on the inputs to the valuation techniques as
follows:
Level I : Financial assets and liabilities whose values are based on unadjusted quoted prices for identical assets or liabilities in
an active market that Idaho Power has the ability to access.
Level 2: Financial assets and liabilities whose values are based on the following:
a) quoted prices for similar assets or liabilities in active markets;
b) quoted prices for identical or similar assets or liabilities in non-active markets;
c) pricing models whose inputs are observable for substantially the full term of the asset or liability; and
d) pricing models whose inputs are derived principally from or corroborated by observable market data through
correlation or other means for substantially the full term of the asset or liability.
FERC FORM NO.1 (ED.12.88)Paoe 123.39
Name of Respondent
ldaho Power Comoanv
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t1412021
Year/Period of Report
202Uo,4
NOTES TO FINANCIAL STATEMENTS (Continued)
Idaho Power Level 2 inputs for derivative instruments 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. There were no transfers between levels
or material changes in valuation techniques or inputs during the years ended December 31, 2020 and 20 I 9.
The following table presents information about Idaho Power's assets and liabilities measured at fair value on a recurring basis as of
December 31, 2020 and 2019 (in thousands of dollars):
December 31, 2020 December 31, 2019
Level I Level 2 Level 3 Total Level I Level 2 Level 3 Total
Assets:
Money mar*et funds and commercial p4er
Derivatives
Equity securities
Liabilities:
Derivatives
$40,038
1,995
50,733
$r34$l0s $1,t4$814$32$
$-$- s40,038
1,99s
50,733
$26,510
392
42,738
$- $26510
405
42,739
$ 846
$-
13
Idaho Power's derivatives are contracts entered into as part ofits management ofloads and resources. Elecricity derivatives are valued
on the Intercontinental Exchange with quoted prices in an active market. Natural gas and diesel derivatives are valued using New York
Mercantile Exchange and Intercontinental Exchange pricing, adjusted for location basis, which are also quoted under NYMEX and
ICE pricing. Equity securities consist of employee-directed investments related to an executive deferred compensation plan and
actively traded money market and exchange traded funds related to the SMSP. The investments are measured using quoted prices in
active markets and are held in a Rabbi trust.
The table below presents the carrying value and estimated fair value of frnancial instruments that are not reported at fair value, as of
December 31,2020 ard2019, using available market information and appropriate valuation methodologies (in thousands).
December 3112020 December 31,2019
Carrying
Amount
Estimated Fair
Value
Carrying
Amount
Estimated Fair
Value
(thousands of dollars)
Liabllities:
Long-term debt (including current portion)(l) $ 2,000,414 $ 2,466,967 $ 1,836,659 $ 2,083,931
FERC FORM NO.1 (ED.12.88)Pase'123.40
Name of Respondent
ldaho Power Comoanv
This Report is:
(1) X An OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
04t1412021
Year/Period of Report
2020to,4
NOTES TO FINANCIAL STATEMENTS (Continued)
(l) Long-termdebtiscategorizedaslevel2ofthefairvaluehierarchy,asdefinedearlierinthisNote16-"FairValueMeasurements."
Long-term debt is not traded on an exchange and is valued using quoted rates for similar debt in active markets. Carrying values for
cash and cash equivalents, deposits, customer and other receivables, notes payable, accounts payable, interest accrued, and taxes
accrued approximate fair value.
17. 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 31,2020 and 2019 (in thousands of
dollars). Items in parentheses indicate reductions to AOCI.
Year Ended December 31,
2020 2019
Defined benefit pension items
Balance at beginning of period $ (36,284) $ (22,844)
-
Other comprehensive income before reclassifications
Amounts reclassified out of AOCI to net income
(10,052)
2,988
(15,392)
1,952
Net current-period other comprehensive income (7,074) (13,,t40)
-
Balance at end ofperiod $ (43,358) $ (36,284)
The table below presents the effects on net income of amounts reclassified out of components of AOCI and the income statement
location of those amounts reclassified during the years ended December 31,2020 and 2019 (in thousands of dollars). Items in
parentheses indicate increases to net income.
Amount Reclassified from AOCI
Year Ended December 31,
2020 2019
Amortization of defined benefit pension items(l)
Prior service cost
Net loss
$290 $
3,734
96
2,533
Total before ta"r
Tax benefit(2)
4,024
(1,036)
2,988
2,629
(677)
1,952Net of tax
Total reclassification for the period $ 2,988 $ 1,952
( I ) Amortization of these itsrns is included in "Other (income) exp€nse, net" in the income statement of ldaho Power
(2) The ax benefit is included in "Income tax expense" in the income statements of Idaho Power.
FERC FORM NO.1 (ED.12.88)Pase 123.41
Name of Respondent
ldaho Pow6r Companv
This Report is:
(1) X An OriginalQ) A Resubmission
Date of Report
(Mo, Da, Yr)
0411412021
Year/Period of Report
2020tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
18. RELATED PARTY TRANSACTIONS
IDACORP: Idaho Power performs corporate fi.urctions such as financial, legal, and management services for IDACORP and its
subsidiaries. Idaho Power charges IDACOFJ for the costs of these services based on service agreements and other specifically
identified costs. For these services, Idatro Power billed IDACORP $0.7 million in2020 and $0.8 million in 2019.
At December 31, 2020 and 2019, Idaho Power had a $ I .5 million and $ I .9 million payable to IDACORP, respectively, which was
included in its accounts payable to affiliates balance on its balance sheets.
Ida-West: Ida-West Energy Company (Ida-West) is a wholly-owned subsidiary of IDACORP and is an operator of small hydropower
generation projects that satisff the requirements of the Public Utility Regulatory Policies Act of 1978. Idaho Power purchases all of the
power generated by four of Ida-West's hydropower projects located in Idaho. Idaho Power purchased $9.3 million in2020 and $8.6
million in 2019 of power from Ida-West.
FERC FORM NO. 1 (ED. 12.88)Page 123.42
ldaho Power Company (1)
(2t
An Original
A Resubmission
uat6 0l KeDon(Mo, Da, Yi)
0411412021
Yea/Penoo ot f{epon
End of 2O20lQ4
SUMMARY OF UTILITY PLANT 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), (0, and (g) report other (specfi) and in
column (h) common function.
Line
No.
Classification
(a)
Total Company for the
Cunent Year/Quarter Ended
(b)
Electric
(c)
1 Utility Plant
2 ln Service
3 Plant in Service (Classified)6,283,039,357 6,283,039,35i
4 Property Under Capital Leases
5 Plant Purchased or Sold
6 Completed Construction not Classified
7 Experimental Plant Unclassifi ed
I Total (3 thru 7)6,283,039,357 6,283,039,357
I Leased to Others
10 Held for Future Use 4,108,52S 4,108,52S
11 Construction Work in Progress 597,151,634 597,151,634
't2 Acquisition Adjustments 750,893 750,893
13 Total Utility Plant (8 thru 12)6,885,050,413 6,885,050,413
14 Accum Prov for Depr, Amort, & Depl 2,376,165,417 2,376,165,417
15 Net Utility Plant (13 less 14)4,508,884,996 4,s08,884,996
t6 Detail of Accum Prov for Depr, Amort & Depl
17 ln Service:
18 Depreciation 2,343,768,007 2,343,768,00i
19 Amort & Depl of Producing Nat Gas Land/Land Right
20 Amort of Undergrcund Storage Land/Land Rights
21 Amort of Other Utility Plant 32,319,817 32,319,8't7
22 Total ln Service (18 thru 21)2,376,087,824 2,376,087,824
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 77,593 77,593
33 Total Accum Prov (equals 14) (22,26,30,31 ,32)2,376,165,417 2,376,165,417
FERC FORM NO.1 (ED.12.89)Page 200
Name Respondent
ldaho Power Company An (Mo, Da,
(2)A Resubmission 04t14t2021
Year/Period of Report
End of 2O2O|Q4
1. Report below the original cost of electric plant in service according to the prescribed ac@unts.
2. ln addition to Account 101, Electric Plant in Service (Classified), this page and the next include Account 102, Electric Plant Purchased or Sold;
Account 103, Experimental Electric Plant Unclassified; and Account 106, Completed Construction Not Classified-Electric.
3. lnclude in column (c) or (d), as appropriate, conections of additions and retirements for the curent 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. Classifu Account 106 according to prescribed accounts, on an estimated basis if necessary, and include the entries in column (c). Also to be included
in column (c) are entries for reversals of tentative distributions of prior year reported in column (b). Likewise, if the respondent has a significant amount
of plant retirements which have not been classified to primary accounts at the end of the year, include in column (d) a tentative distribution of such
retirements, on an estimated basis, with appropriate contra entry to the account for accumulated depreciation provision. lnclude also in column (d)
Line
No.
ACCOunt
(a)
Additrons
(c)
1 1. INTANGIBLE PLANT
2 (301) Oroanization 5.703
3 (302) Franchises and Consents 34.282.'t60 1.098.380
4 (303) Miscellaneous lntansible Plant 36.042.325 8,214,299
5 TOTAL lntanqible Plant (Enter Total of lines 2, 3, and 4)70,330.188 9.312.679
6 2. PRODUCTION PLANT
7 A. Steam Production Plant
8 (310) Land and Land Riohts 1.722.421
I (3'll) Structures and lmDrovements 132.724.377 430,044
10 (312) Boiler Plant Eouioment 683,221.973 3.059.338
1'.!(313) Enoines and Enoine-Driven Generators
12 (3141 Turbooenerator Units 151.988.941 278.715
13 (315) Accessory Electric Equipment 57.779.612 306.493
14 (316) Misc. Porer Plant Equipment 18.753.687 1.531.049
15 (317) Asset Retirement Costs for Stoam Production 14.740.896 705,698
16 TOTAL Steam Prcduction Plant (Enter Total of lines 8 thru '15)1.060.931.907 6.31 1.337
17 B. Nuclear Production Plant
18 (320) Land and Land Rishts
19 (321) Structures and lmorovements
20 (322) Reactor Plant Eouioment
21 (323) Turbooenerator 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 31,924,330 17,803
28 (331) Structures and lmDrovements 208.163.696 20,547,490
29 (332) Reservoirs. Dams. and Wateruays 283.762.075 5.'113.813
30 (333) Water Wheels. Turbines. and Generators 291.872.691 39.762.758
3'l (334) Accessory Electric Equipment 65.604.942 1.405.8A1
32 (335) Misc. Power PLant Equipment 27.6',t8.291 1,155,478
33 (336) Roads. Railroads. and Bridqes 12,001,305 1,962,691
34 (337) Asset Retirement Costs for Hvdraulic Production
35 TOTAL Hvdraulic Prcduction Plant (Enter Total of lines 27 thru 34)920.947.330 69.965.887
36 D. Other Production Plant
37 (340) Land and Land Riohts 2.699.794
38 (341) Structures and lmDrovements 153,426,332 417.O23
39 (342) Fuel Holders. Products, and Accessories 10,438,248
40 (343) Prime Movers 222.138.5fi4 1.211.301
41 (3214) Generators 66.714.048 -15,568
42 (3451 Accessorv Electric EouiDment 91.996.423 6.165
43 (346) Misc. Power Plant Equipment 6.64s.124 92.097
44 (347) Asset Retirement Costs for Other Production
45 TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44)554.058,933 2,111,018
46 TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45)2.535.938.170 78.388.242
FERC FORM NO.1 (REV.12-05)Page 2U
Name of Respondent
ldaho Power Company
This(1)
(2t
Reoort ls:IAn Original
;-1A Resubmission
Date of Reoort(Mo, Da, Yi)
041't4t2021
Year/Period of Report
End of 202OlA4
distributions of these tentative classifications in columns (c) and (d), including the reversals of the prior years tentiative 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 repoded amount of
respondent's plant actually in seMce 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
classffications arising fiom distribution of amounts initially recoded in Account 102, include in column (e) the amounts wih respect to accumulated
provision for depreciation, acquisition adjustments, etc., and show in column (f) only the ofiset to the debits or credits distributed in column (f) to primary
account classifi cations.
8. For Account 399, state the nature and use of plant included in this account and if substantial in amount submit a supplementary stratement showing
subaccount classification of such plant conforming to the roquirement of these pages.
9. For each amount comprising the reported balance and changes in Account 102, state the property purchased or sold, name of vendor or purchase,
and date of tsansaction. lf poposed joumal enuies have been filed with the Commission as required by the Uniform System of Accounts, give also date
Retirements
(d)
Adjustments
(e)
Transfers
(0
Balance at
End flfear
Line
No.
1
5.703 2
241.023 35.139.517 3
3.260.725 40,995,899 4
3.501,748 76.141.119 5
6
7
1.722.421 I
12.825.782 120.328.639 I
45.487,063 640.794.248 10
11
13.735.984 138.531.672 12
4,733,279 53.3s2.826 13
2.492.796 17.791,940 't4
15./t46.594 15
79.274.904 987.968.340 16
17
18
19
20
21
22
23
24
25
26
31,942,133 27
1.21',t.700 227.499.486 28
166.712 288.709.176 29
405.270 331.230.179 30
380.952 66.629.M4 31
210,143 28,563,626 32
1.000 13.962.996 33u
2.375.777 988.537.440 35
36
2,699,794 37
2,750 154.240.605 38
10.438.248 39
2.875.191 220.475.O74 40
20.000 66.678.480 41
92,002,588 42
69,616 6,667,605 43
44
2.967.5s7 553.202.394 45
84.618.238 2.529.708.174 46
FERC FORM NO.1 (REV.12-0s)Page 205
1 An (Mo, Da,ldaho Power Company (2)A Resubmission o411412021
Year/Period of Report
End of 2O20lQ4
Ltne
No.
Account
(a)
Addltons
(c)
47 3. TRANSMISSION PLANT
48 (350) Land and Land Riohts 39.010.101 168.828
49 (352) Structures and lmDrovements 8't.631.852 4,088,297
50 (353) Station Equipment 437,090,965 27,294,211
51 (354) Towers and Fixtures 215,107,091 7.743.485
52 (355) Poles and Fixtures 206.989.944 11.119,620
53 (356) Overhead Conductors and Devices 240.482.s89 5.320.331
54 (357) Underoround Conduit
55 (358) Underoround 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)1.220.702.808 55,734,772
59 4. DISTRIBUTION PLANT
60 (360) Land and Land Riqhts 7.384.697 46,441
61 (361) Structures and lmorovements 47.760.416 3.310.881
62 (362) Station Eouioment 269.467.878 20,069,47C
63 (363) Storage Battery Equipment
64 (364) Poles, Towers, and Fixtures 283,516,948 12,502,639
65 (365) Overhead Conductors and Devices 144,332,885 5.32',t.22e,
66 (366) Underoround Conduit 54.244.353 -339.073
67 (367) Underground Conductors and Devices 29't,640,376 13,210,495
68 (368) Line Transformers 614,852,926 39,1 18,328
69 (369) Services 63.190.275 2.036.799
70 (370) Meters 97.890.964 9.819.235
71 (371) lnstallations on Customer Premises 3.195.799 919,429
72 (372) Leased Property on Customer Premises
73 (373) Street Lishtinq and Siqnal Systems 4,658,210 489,705
74 (374) Asset Retirement Costs for Distribution Plant
75 TOTAL Distribution Plant (Enter Total of lines 60 thru 74)1.882.135.727 106.505.581
76 5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT
77 (380) Land and Land Riqhts
78 (381) Structures and lmorovements
79 (382) Comouter Hardware
80 (383) Comouter Software
81 (384) Communication Eouipment
82 (385) Miscellaneous Resional Transmission and Market Operation Plant
83 (386) Asset Retirement Costs for Reoional Transmission and Market Oper
84 TOTAL Transmission and Market ODeration Plant ffotal lines 77 thru 83)
85 6. GENERAL PLANT
86 (389) Land and Land Riqhts 't7 1,056,'t18
87 (390) Structures and lmorovements 132 3.977,939
88 (391) Office Furniture and Eouioment 45.060.127 5.867.311
89 (392) Transoortation EouiDment 97 20.011.902
90 (393) Stores Equipment 3,535,33S 887,504
91 (394) Tools. Shoo and Garaqe Equipment 11.670.249 989,582
92 (395) Laboratory Eouioment 14.896.284 957,611
93 (396) Power Ooerated EouiDment 21 937 2.465.960
94 (397) Communication EouiDment 51.141.166 10.900.079
95 (398) Miscellaneous Eouioment 7.637.086 924.444
96 SUBTOTAL (Enter Total of lines 86 thru 95)403.709.39S 48.038.450
97 (399) Other Tanoible Property
98 (399.1) Asset Retirement Costs for General Plant
99 TOTAL General Plant (Enter Total of lines 96, 97 and 98)403.709.399 48.038.450
100 TOTAL (Accounts 101 and 106)6.112.816.292 297.979,724
't01 (102) Electric Plant Purchased (See lnstr. 8)
't02 (Less) (102) Electric Plant Sold (See lnstr. 8)
103 (103) Experimental Plant Unclassified
104 TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103)6,112,816,292 297.979,724
FERC FORM NO.1 (REV.12-05)Page 206
ldaho Power Company (1)
(21
An
A Resubmission 04t14t2021
Year/Period of Report
End of 202OlA4
ELECTRIC PLANT lN SERVICE (Account 101. '102. 103 and 106) (Continued)
Retirements
(d)
Adjustments
(e)
I ran$ers
(f)
tsalance at
End gffear
Line
No.
47
26.488 39.152.M1 48
192.077 85,528,072 49
2.078.276 462,306.900 50
222.850.576 51
738.335 217.371.229 52
1.042.285 244,760,635 53
54
55
390.266 56
57
4.077.461 1.272,360.'.t19 58
59
1,367 7.429.777 60
192.023 50.879.274 61
2.273.9U 287.263.fi4 62
63
2.876.923 293.142.664 64
2.333.349 147.320.762 65
339,062 53.566.218 66
1.875.122 302,975,749 67
6.338.44S 647,632,805 68
415,044 64.812.030 69
2.833.747 104.876.4s2 70
110.716 4.OO4.s12 71
72
299,395 4.848.520 73
74
19,889.181 1.968.752.127 75
76
77
78
79
80
81
82
83
84
85
18.862,345 86
652,124 1fi.316.242 87
7,213,847 43.713.s91 88
3.752.829 113.294.310 89
39.547 4.383,296 90
383.86S 12.275.962 91
994,778 14.859.1 1 7 92
696,669 23.706.548 93
1.522.239 60.s19.006 94
414.129 8.',147.401 95
1s.670.031 436.077.818 96
97
98
15.670.031 436.077.818 oo
127.756.659 6,283,039,357 100
101
102
103
127.756.659 6.283.039.357 104
FERC FORM NO.1 (REV. 12-05)Page 207
ldaho Power Company
(1)
(2)A Resubmission
Date of Reoort(Mo, Da, Yi)
0411412021
Year/Period of Report
End of 20201Q4
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.
LineNo.
uescflolon ano Looauon'ote6geo uare ungrnaily rncruoeo
in This Account(b)tn Service
Eatance at
End of Year(d)
1 Land and Rights:
2 Boise Operations Center 12131t82 2021 306,300
1 Production 109,961
4 Transmission Stations 423,089
E Transmission Lines 68,592
6 Distribution Stations 1,496,640
7 Homedale Substalion 2t29t08 2035 109,453
8 Line #854 500 Kv 3/31/09 2028 308,066
I Distribution Line 25,581
10 Line lB53 500 Kv 12116111 2026 330,495
11
12 Column B and C if no date listed it is various
13
14
15
't6
17
18
19
20
21 Other Property:
22 Transmission Stations 199,069
23 Distribution Stations 69,941
24 Homedale Substation u29l08 2035 2'.t7,797
25 Underground Vault, Blaine County 8/30/16 2024 443,545
26
27
28
29 Column B and C if no date listed it is various
30
31
32
33
u
35
36
37
38
39
40
4',1
42
43
44
45
46
47 Total 4,108,52S
FERC FORM NO.1 (ED. 12-96)Page 214
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date(Mo,
0411412021
Year/Period of Report
End of 2O20lQ4
1 . Report below descriptions and balances at end of year of projects in process of construction (1 07)
2. Show items relating to "research, development, and demonstration' projects last, under a caption Research, Development, and Demonstrating (see
Account 107 ofthe Uniform System ofAccounts)
3. Minor projects (5% of the Balance End of the Year for Account 107 or $1 ,000,000, whichever is less) may be grouped.
Line
No.
Description of Project
(a)
Construction work in progress -
Electric (Account 107)
(b)
1 ROLLUP RELIC COST BROWNLEE 131,918,209
2 ROLLUP RELIC COST HELLS CANYON 89,831,725
3 GATEWAY WEST sOOKV LINE 44,537,238
4 ROLLUP RELIC COST OXBOW 4',t,793,237
5 HELLS CANYON RELICENSING OUTSI 39,020,017
6 B2H PERMITTING 11/1/2011 & FOR 22,237,389
7 BOARDMAN. HEMINGWAY 5OO KV LI 10,827,495
I UPPER MALAD FISH LADDER 9,740,050
I HCC WATERSHED ENHANCEMENT PROG 9,178,008
10 WO HCC4O1 CERTIFICATION OPS AN 8,162,939
11 BROWNLEE UNIT 5 REWIND 7,090,s01
12 HELLS CANYON GENERATOR REFURBI 6,874,676
13 LEGAL DEPT. LABOR FOR RELICENS 6,778,405
14 LOWER SALMON UNIT 1 REFURBISHM 6,61 1 ,1 02
15 BAYHA ISLAND RESEARCH PROJECT 5,623,002
16 UPPER SALMON B REJECT GATES RE 5,044,055
17 NEWX1TOOO1 CDAL-HBRD 23OKV PHA 4,954,906
18 REL-HCC OREGON REAUTHORIZATION 4,701,807
19 BULL TROUT PROGRAM. ADMINISTR 4,676,225
20 MEBG . SKILLS TRAINING BUILDIN 4,675,831
21 HCC SNAKE RIVER ENHANCEMENT RE 3,955,061
22 B2H TLINE CONSTRUCTION COSTS 3,830,636
23 GRAND VIEW IRRIGATION UPGRADE 3,462,s61
24 WDRI-KCHM NEW 138KV 3,114,605
25 FALL CHINOOK PROGRAM - REDD SU 3,073,291
26 HBND-041:ALT LINE ROUTE TO GAR 3,071,735
27 WQ HCC4O1 APPLICATION, REVISIO 2,842,939
28 BOCB17OO34 - MBE 9 PURCHASE A 2,790,364
29 LOWER SALMON UNIT 3 REFURB 2,749,',t94
30 HC SEDIMENT PROGRAMS 2,699,652
31 HCC RELICENSING WATER QUALITY 2,562,665
32 REPORTING MODEL FOR SNAKE RIVE 2,473,875
33 WHITE STURGEON PROGRAM. HCC R 2,011,085
34 VARI16001 O . PIANNING, SCOPING 1,790,901
35 SMART KEY FOBS & CORES 1,710,526
36 BRIDGER 2O17C1OO CCR JB FGD PO 1,683,680
37 EAGLE BAR MAINTENANCE FACILITY 1,618,584
38 VARIl600lO - MOBILE VEHICLE RA 1,568,347
39 LSPR LOCAL SERVICE UPGRADE PHA 1,357,315
40 VARI18OO17. INSTALL SAT RADIO 1,33',t,924
41 SECURITY CAMERA AND USP LIFECY 1,310,932
42 VARIl9OOO1 ETHERNET SWITCH REP 1,308,206
43 TOTAL 597,1 51,634
FERC FORM NO.1 (ED. 12.87)Page 216
This Page lntentionally Left Blank
Name of Respondent
ldaho Power Company
This Reoort ls:(1) [iAn Orisinat
(21 l--1A Resubmission
Date of Reoort(Mo, Da, Yi)
o{t14t2021
Year/Period of Report
End of 2O2OIQ4
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 progress -
Electric (Account 107)
(b)
1 PROJECT UNITY (REMS REPLACEMEN 1,290,642
2 DANSKIN CT1 INLET AIR HEATING-1,171,163
3 OXBOW HATCHERY RENOVATION 1,169,138
4 HCPR19OOOI - HCPR PLANT MODERN 1,139,523
5 HELLS CANYON ROCK MITIGATION S 1,125,089
6 2O2O CAPITAL US34 TRASH RAKE R 't,110,423
7 BRIDGER 2019C091 U4 SCR CATALY 1,088,096
8 BOC SITE EXPANSION: NEW STC B 1,078,520
I VARII8OO17 - INSTALL SAT RADIO 1,064,375
10 HCC RELICENSING: HART AND 401 't,042,604
't1 Other Minor Projects Under $1,000,000 69,277,166
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 TOTAL 597,151,634
FERC FORM NO. I (ED. 12.87)Page 216.1
Name of Respondent
ldaho Power Company
This Reoort ls:(1) [An Original(2) ;-1A Resubmission
Date of Reoort(Mo, Da, Yi)
0411412021
Year/Period of Report
End of 2O2O|Q4
1. Explain in a footnote any important adjustments during year.
2. Eplain 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 servioe, pages 204-207, column 9d), excluding retirements of nondepreciable 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.
Sec{ion A" Balances and Changes Durlng Year
LINE
No.
rtem
(a)ntBF'Eregnc rranr rn
(c)
trtecmc Ftanr nelofor Future Use(d)
EIEGTNC rlANILeased to Others(e)
1 Balance Beginning of Year 2,3r3,565,686 2,313,565,686
I Depreciation Provisions for Year, Charged to
a (403) Depreciation Expens€162,7s0,617 162,750,617
4 (403.1) Depreciation Expense for Asset
Retirement Costs
431,877 431,877
E (413) Exp. of Elec. Plt. Leas. to Others
t Transportation Expenses-Clearing 5,059,1M 5,059,'l&
7 Other Clearing Accounts
t Other Accounts (Specify, details in footnote):
C Fuel Stock 172,571 '172,571
1(TOTAL Deprec. Prov for Year (Enter Total of
lines 3 thru 9)
167.550.415 167,550,415
11 Net Chalges for Plant Retired:
12 Book Cost of Plant Retircd 124,227,057 124,227,057
13 Cost of Removal 14,992,09S 14,992,09€
14 Salvage (Credit)4,001,807 4,001,80i
't5 TOTAL Net Chrgs. for Plant Ret. (Enter Total
of lines 12 thru 14)
135,2'17,349 135,217,U9
16 Other Debit or Cr. ltems (Desoibe, details in
footnote):
-2130,745
17
18 Book Cost orAsset Retirement Costs Retired
1S Balance End of Year (Enter Totals of lines 1 ,
10, 15, 16, and 18)
2,343,768,007 2,343,768,007
Section B. Balances at End of Year According to Functlonal Glagslficatlon
20 Steam Production 555,100,533 555,100,53!
21 Nuclear Prcduction
22 Hydraulic Production4onventional 459,910,553 459,910,55i
23 Hydraulic Prcduction-Pumped Storage
24 Other Production 135,243,439 13s,243,43!
25 Transmission 389,097,217 389,097,21i
26 Distribution 675,064,935 675,064,93r
27 Regional Transmission and Market Operation
28 General 129,35't,330 129,351,330
29 TOTAL (Enter Total of lines 20 thru 28)2,343,768,007 2,343,768,007
FERC FORM NO.1 (REV. 12-05)Page 2'i.9
Name of Respondent
ldaho Power Comoanv
This Report is:
(1) XAn Originalel A Resubmission
Date of Report
(Mo, Da, Yr)
0/,|1412021
Year/Period of Report
2020tQ4
FOOTNOTE DATA
219 Line No.:16 Column: c
Valmy aobligation activity.on ustments (ID 33771- and OR L7-2351, CIAC and Asset Ret rement
FERC FORM NO.I (ED. 1.2ATI Page 450.1
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5]en orisinat(2) nA Resubmission
Date of Report(Mo, Da, Yr)
0411412021
Year/Period of Report
End of 20201Q4
TNVESTMENTS tN SUESTDTARY GOMPANTES (Account 123.1)
1. ReportbelowinvestmentsinAccountsl23.l,investmentsinSubsidiaryCompanies.
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),(fl,(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
cunent 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 specifuing 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.
Line
No.
Descnpuon or lnvestmenl
(a)
Date Acquired
(b)
Amounl ot tnvestment at
Besin1tjls of Year
1 ldaho Energy Resources Company
2 Common Stock 02101174 500
3 Capital contributions 2,462,594
4 Equity in eamings 23,052,822
5
6 Subtotal ldaho Energy Resources Company 25,515,916
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 2,463,TOTAL 25,515,916
FERC FORM NO.1 (ED. t2-89)Page 221
Name of Respondent
ldaho Power Company
This Reoort ls:(1) ERn orisinat(2) nA Resubmission
Date of Report(Mo, Da, Yr)
o4l't412021
Year/Period of Report
End of 2O2O|Q4
4. For any securities, notes, or accounts that were pledged designate such securities, notes, or accounts in a footnote, and state the name of pledgee
and purpose ofthe 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 differencc between cost of the investment (or
the other amount at which canied 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
hquity in subsioiary
Eaminqs,of Year
t{evenues tor Year
(0
Amount ot lnvestment at
End pr,Year
Gain or Loss trom lnvestrnent
Disol,;ied of Line
No.
1
500 2
2,462,593 3
8,402,214 31,455,037 4
5
8,402,214 33,918,130 6
7
8
I
10
11
't2
13
't4
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
8,402,2'14 33,918,130 42
FERC FORM NO. 1 (ED. 12.89)Page 225
Name of Respondent
ldaho Power Company
This ReDort ls:(1) 5]Rn Orisinat(2) aA Resubmission
Date of Report
(Mo, Da, Yr)
o411412021
Year/Period of Report
End of 202OlQ4
MATERIALS ANO 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.) afiected debited or credited. Show separately debit or credits to stores exp€nse
clearing, if applicable.
Line
No.
Account
(a)
Balance
Beginning of Year
(b)
Balance
End ofYear
(c)
Department or
Departments which
Use Material(d)
1 Fuel Stock (Account 1 51 )57,447,554 31,645,944 Electric
2 Fuel Stock Expenses Undistributed (Account 152)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 Prcduction Plant (Estimated)18,044,916 17,2't4,885
I Transmission Plant (Estimated)7,751,239 12,fi4,087
I Distribution Plant (Estimated)27,522,183 31,201,394
10 Regional Transmission and Market Operation Plant
(Estimated)
11 Assigned to - Other (provide details in footnote)920,624
12 TOTAL Account 154 (Enter Total of lines 5 thru 1 1 )54,238,*i2 62,178,U0 Electric
13 llerchandise (Account 155)
14 Other Materials and Supplies (Account 156)
15 Nuclear Materials Held for Sale (Account 157) (Not
applic to Gas Util)
't6 Stores Expense Undistributed (Account 163)2,420,600 2,762,521
17
18
19
20 TOTAL Materials and Supplies (Per Balance Sheet)'114,107,116 96,586,805
FERC FORM NO.1 (REV.12.05)Page 227
Name of Respondent
ldaho Power Company
This Report is:
(1) X An OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
0411412021
Year/Period of Report
2020tQi4
FOOTNOTE DATA
Schedule Pase: 227 Line No.: 11 Column: cs amount represents mfunction.tory t s not yet ass toa
FERC FORM NO.1 (ED. 12471 Paoe 450.1
Name of Respondent
ldaho Power Company
This Reoort ls:
(1) E An original
(2) l-l A Resubmission
Date of Reoort(Mo, Da, Yi)
04t14t2021
Year/Period of Report
6n6 6 2020/Q4
Transmission Service and Generation lnterconnection Stud y Costs
1. Report the particulars (details) called for conceming the costs incuned and the reimbursements received for performing transmission service and
gener€rtor interconnection studies.
2. List each study separately.
3. ln column (a) provide the name of the study.
4. ln column (b) report the cost incurred to perform the study at the end of period.
5. ln column (c) report the account charged with the cost of the study.
6. ln column (d) report the amounts received for reimbursement of the study costs at end of period.
7. ln column (e) report the account credited with the reimbursement received for performing the study.
Lrne
No.Description
(a)
Costs lncuned During
Period
(b)
Account Charged
(c)
KetmDUrsements
Received During
the Period
(d)
Account Credited
With Reimbursement
(e)
1 Transmission Studies
2 lPcL TRANS StS 88754178 1,966 186623 186623
3 BPAP NETWORK SIS 90030618 33,560 186623 ( 27,903)186623
4 GREAT BAS|N (GBT) SWIP-NORTH TRANY 20,587 186623 ( s0,000)186623
5 BPA NETWORK92112952 12,295 186623 ( 33,885)186623
6 PWX LTF PTP 92117932 4,991 186623 ( 10,000)186623
7 PWX LTF PTP 921 17933 2,149 186623 ( 10,000)186623
8 PWX LTF PTP 92502052 STUDY 337 186623 ( 20,000)186623
I
't0
11
12
13
14
15
16
17
18
19
20
21 Gsneration Studies
22 CAT CREEK PUMP STORAGE #530 428 't86623 1 86623
23 GEM-VALE #534 3OOMW 2,421 't86623 132,813 186623
24 VERDE LIGHT POWER #532 3MW 186623 17,604 186623
25 OLD CAMP SOI.AR SOMW 186623 97,875 186623
26 MOONSTONE SOLAR #541 634 186623 3,767 186623
27 PRAIRIE CITY SOLAR #556 20,863 186623 186623
28 ARH SOLAR #558 18,167 186623 ( 48,472)186623
29 BLACK MESA ENERGY #557 6,833 186623 ( 103,228)186623
30 MC6 HYDRO #559 613 186623 1 86623
31 BENNETT SOLAR ,I #551 12,432 186623 ( 40,143)186623
32 BENNETT SOLAR 2 #552 186623 15,970 186623
33 BENNETT SOLAR 3 #553 186623 17,065 186623
34 BENNETT SOLAR 4 #560 7,586 186623 186623
35 COLEMAN HYDRO #548 1,189 186623 ( 23,483)186623
36 MIDPOINT SOLAR #561 10,1 18 186623 ( 60,000)186623
37 MOORE HOLLOW SOLAR #561 10,485 't86623 ( 50,000)186623
38 DURKEE SOLAR #546 9,271 186623 ( 30,000)186623
39 PLEASANT VALLEY SOLAR #568 26,352 186623 ( e8,756)186623
40 ARCO WIND 95OMW #563 2,452 186623 186623
FERC FORM NO. 1r1.Fr3.Q (NEW. 03-07)Page 231
Name
ldaho Power Company (1)
(2)
An Original
A Resubmission
(Mo, Da,
04t1412021
Year/Period of Report
En6 q1 2020/Q4
Transmission Service and Generation lnterconnection Stuc
Ltne
No.Description
(a)
Costs lncuned During
Period
(b)
Account Charged
(c)
KermDursementsReceived During
the Period
(d)
Account Credited
With Reimbursement
(e)
1 Transmission Studies
2
3
4
5
6
7
I
I
10
't1
12
13
14
't5
't6
17
't8
19
20
21 Generatlon Studies
22 ARCO SOLAR 950MW #s63 789 186623 186623
23 MOON CRATER SOLAR #57 6,076 186623 ( 50,000)1 86623
24 MAGIC VALLEY ENERGY #572 21,297 186623 ( 50,000)186623
25 OLD OREGON TRAIL ,t #568 4,798 186623 ( 50,000)186623
26 JACOBSON SOLAR #566 5,517 186623 ( 10,000)1 86623
27 WEST POINT NRG #576 3,078 186623 ( 31,000)186623
28 ARCO WIND 2 #580 6,490 186623 ( 60,000)186623
29 HIDDEN HOLLOW ENERGY #577 186623 ( 1,000)1 86623
30 MAG|C VALLEY W|ND (2) #581 186623 ( 50,000)1 86623
3'l PEASANT VALLEY SOLAR (2)#587 9,347 186623 ( 10,000)186623
32 APPALOOSA WIND & SOLAR #1 4OOMW 186623 ( 10,000)1 86623
33 APPALOOSA WIND & SOLAR #2 4OOMW #'t86623 ( 10,000)186623
34
35
36
37
38
39
40
FERC FORM NO. 1r1.F/3-Q (NEW.03.07)Page 231.1
This Page lntentionally Left Blank
Name of Respondent
ldaho Power Company
This Report is:
(1) X An OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
u|1412021
Year/Period of Report
20201Q4
FOOTNOTE DATA
231 No.:2Amounts represent ts rec c t amounts re totcounterparties (debit amounts). Refunds are initiated when studies are complete and theinitial deposit exceeds the final erq)enses.
FERG FORM NO.1 (ED. 12.871 Pase 450.1
s:
ldaho Power Company
(1)
(2)
An Original
A Resubmission
(Mo, Da,
04t14t2021
Year/Period of Report
End of 20201Q4
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 (5olo of the Balance in Account 182.3 al 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 ol
Cunent Quarter/Year
(0
Written ofl Dudng the
Quarbr ffear A@ount
charsed (d)
Wdtten ofi During
the Period Amount
(e)
1 Fixed Cost Adiustnent (FCA) ( 182302)35,20E,26i 2,9s0,124 38.158,387
2 IPUC Order Pending (Amort period 06/21 hru 05/22)
3
4 COVID lncremental Expenses-lD (182303)1,610,800 1,610,800
5 IPUC Order#34718
6
7 COVID lncremental Expenses-OR (182304)276,473 276,473
8 OPUC Order#20-377
I
10 AOCI lmpad of Unfunded Pension Liability 93,202 6,s15,629 2283 47,270 6,561,561
11 IPUC Order #30256 ('182320)
12
13 FCA Calendar Mo Adiusfnent (1 82308)2,940,850 400 1,769,851 1,170,999
14
15 Prior Year FCA (182309)15,867,414 400 15,867,414
16 IPUC Order #34346 (Amort period 06/19 hru 05/20)
17
18 Prior Year FCA (1E2309)35,498,8s6 400 19,336,457 16,162,399
19 IPUC 0rder #34685 (Amort period 06120 hru05121\
20
21 AOCI lmpact ol Unfunded Pension Liability 347,E41,34'l 107,399,006 22E3 17,331,902 437,908,44s
22 IPUC Order #30256 (182320)
23
24 Defened Pension Expense Net of Contributions 22,287,244 42,042,251 2283 38,160,686 26,168,809
25 IPUC Order #30333 fi82321\
26
27 FAS 109 Untunded ngn2zl 399,267,422 47,320,661 446,588,083
28 Accum Defened lncome Non@nent
29
30 ldaho Pension Cash - IPUC Oder #32248 (1823271 'ts0,349,758 41,321,448 401 17,153,713 174,517,493
31 Amort period 06/11 thru indefinite)
32
33 Mark- to Market Short Term (182330)822,261 244 212,690 609,571
34
35 Oregon Pension Expense Capitalized (182339)5,441,885 746,018 4073 173,813 6,014,090
36 OPUC Order#10-064
37
38 Asset Retirement Obligations (182341)18,789,487 245,367 19,034,854
39 IPUC Order #2941 4; OPUC Order #04-585
40
41 RA*lells Canyon-Baker Co ('182360)313,s06 313,506
42 IPUC Order #33948
43
FERC FORM NO. 1r3-Q (REV. 02-04)Page 232
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5]Rn Orisinat
(21 nA Resubmission
Date of Report(Mo, Da, Y0
04114t2021
Year/Period of Report
End of 202OlQ4
OTHER REGULATORY ASSETS (Account 182.3)
1. Report below the particulars (details) called for conoeming other regulatory assets, including rate order docket number, if applicable.
2. Minor items (5% of the Balance in Account 182.3 al 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)
tsalanoe at ts6ginnin!
of Cunent
QuarterlYear
(b)
Debits
(c)
CREDITS Balance at end of
Cunent Quarterffear
(0
Written oflDurirB tu
Quarbr fYear Account
charsed (d)
Written off During
$e Period Amornt
(e)
1 Oregon Copoate Ac{ivity Tax (182355)292,171 292,171
2 OPUC Order#20-397
3
4 Lidar Surveys-IPUC Order#32426 (182361)87,209 40?43,605 43,604
5 Amort period 01/12 ttru 12121
6
7 Oregon Community Solar (1E2378)'118,611 118,611
8 OPUC Order#16-410
I
10 lntervenor Fundinq-ldaho (182387)196,190 85,097 281,2E7
't'l Mulliple IPUC Orders
12
13 RA-CoNTRAOEF tNC TAX (1E2389)247,618,605 1,492,236 Various 8,070,476 24't,040,365
14
15 Langley Revenue Accrual (18239E)1,384,823 99,072 4073 61,529 1,422,366
16 OPUC Order#12-226
17
18 RA.OR LANGLEY REV INT RES (182399)( 197,E25)9,709 4190 35,'190 -223,306
19
20 Siemens Long Term Defened Rate Base (182410)9,906,955 4073 431,487 9,475,468
21 IPUC Order#33420 (Amort period 01/16 hru 1?43)
22
23 Siemens Lonq Term Defered Rate Based (182411)14,783,171 4073 643,867 14,139,304
24 IPUC Order #33420 (Amort period 01/16 hru 1?43)
25
26 Siemens Long Term Defened Rate Base(1824121 403,036 30,799 4073 44,046 389,i89
27 OPUC Order #15-387 (Amod period 01/'t6 thru 12/36)
28
29 Siemens Lons Term Deftred Rate Based (182413)629,052 4073 39,315 589,737
30 OPUC Order#15-387 (Amort period 01/16 thru 12136)
31
32 Siemens Long Term lnterest Reserve (182414)( 132,347)4190 30,799 -163,146
33
34 Valmy 0&M lD ('t82432)1,407,320 10,264,735 Various 10,564,416 1,107,639
35 IPUC Order#33771
36
37 Valmy Acc'ts Adj lD (182435)105,387,341 Various 3,966,227 101,421,114
38 IPUC Order#33771
39
40 Valmy Decomm Oreqon (182436)654,145 40,785 Various 132,134 562,796
41 OPUC Order#17-235 (Amort pedod 06117 tm 1212511
42
43
FERC FORM NO. 1/3-Q (REV. 02.04)Page 232.1
Name of Respondent
ldaho Power Company
This Reoort ls:(1) fiAn Originat(2) ;lA Resubmission
Date of Report(Mo, Da, Yr)
041't412021
Year/Period of Report
End of 20201Q4
OTHER REGULATORY ASSETS (Account 182.3)
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 Beginning
of Cunent
QuarterlYear
(b)
Debits
(c)
CREDITS Balance at end of
Cunent QuarterlYear
(0
Writ6n oll During tho
Ouarbr ff€ar Account
charsed (d)
Wriften ofiDuring
he Period Amount
(e)
1 31't,04s 1 1,919,329 12,230,374
2 IPUC Order#28661
3
4 Oregon DSM Rider 1,154,280 Various 1s9,240 995,040
5 OPUCAdviceflS{3
6
7 Minor ltems 0)243,687 117,017 Various 284,678 76,026
I
I
10
11
12
13
14
15
16
't7
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
4 TOTAL:1,383,059,324 310,396,190 134,560,E05 1,55E,E94,709
FERC FORl,r NO.1r3-Q (REV.02-04)Page 232.2
Name of Respondent
ldaho Power Comoanv
This Report is:
(1) { An Original
(2) - A Resubmission
Date of Report
(Mo, Da, Yr)
0411412021
Year/Period of Report
20201Q4
FOOTNOTE DATA
Schdule Paoe:232.2 Line No.:1 Column: a
During 2020, this balance was reclassed from a Regulatory Liability to a Regulatory Asset for financial statement
presentation.
FERG FORM NO.1 (ED. 12.871 Page 450.1
This Page lntentionally Left Blank
Name of Respondent
ldaho Power Company
This Reoort ls:(1) E:lAn orisinal(2) 1--1A Resubmission
Date of Report
(Mo, Da, Yr)
0411412021
Year/Period o, Report
End of 202OlQ4
1. Report below the particulars (details) called for conceming miscellaneous defened debits.
2. For any defened debit being amortized, show period of amortization in column (a)
3. Minor item (1% of the Balance at End of Year for Account 186 or amounts less than $100,000, whichever is less) may be grouped by
classes.
Line
No.
Description of Miscellaneous
Deferred Debits
(a)
Balance at
Beginning of Year
(b)
Debits
(c)
CREDITS Balance at
End of Year
(fl
Amount
(e)
1 Prepaid Credit Facilitv 186025 1.201.560 1 10.83r Various 380.977 931.418
2 Amortization oefiod 1 21 1 9-1 21 24
3
4 Prepaid Services (Ln 186052 3,064.137 2,886.530 Various 2.288.861 3.661,806
5 Amortization periods - multiole
6
7 Workers Comoensation 1 861 21 962.258 401 s3,034 909,224
8
9 Prepaid ROW (LD 186160 574,877 401 44.022 530.855
10 Amortization oeriods - multiole
11
12 Prepaid Services (LT) 186255 174,500 401 174,500
13 Amortization periods - multiple
14
15 CARB lnventory 186650 995,433 517.300 242 107.802 1.404.931
16
17 Coal Royalties 186709 871,945 151 51,769 820,176
'18
19 Stable Value Life lnv 186719 48.617.372 3.708.861 52.326.233
20
21 Security Plan 186720 6.307.751 87.796 4262 494,190 5,901,357
22 Net lnsurance Asset
23
24 Retiree Medical-COLI 1 86726 3,997,252 235,7'.t2 4262 78,799 4,154,165
25
26 American Falls Water Rts 186727 5.296.878 401 't.042.008 4.254.870
27 Amortization period 01 /06-02/25
28
29 American Falls Bond Refi 186770 247.996 401 47,99S 199,997
30 Amortization wrtod 1 2lO9-O2l 25
31
32 Reoulatory Reserves 186800 -1.186.996 1.237.883 Various 1.938.159 -1.887.272
33
34 Minor ltems (6)187.749 4.427.316 Various 4,519,939 95,126
35
36
37
38
39
40
41
42
43
44
45
46
47 Misc. Work in Progress
48 uererreo Kegutatory uomm.
Expenses (See pages 350 - 351 )
49 TOTAL 71,312,712 73,302,886
FERC FORM NO. I (ED. 12-94)Page 233
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5]en orisinat(2) ;-1A Resubmission
Date of ReDort
(Mo, Da, Yi)
o4t't4t2021
Year/Period of Report
Endof 2O2UQ4
1. Report the information called for below concerning the respondent's accounting for deEned income taxes
2. At Other (Specify), include deferrals relating to other income and deductions.
Ltne
No.
uescnpuon ano Locauon
(a)
Earancq
?r
6egrnrng
(b)
tsaEnoe at Enoof Year
{c)
1 Electric
2
4
C Other Electric (See footnote)84,487,160
6
7 Other (See footnote)198,768,052
I TOTAL Electric (Enter Total of lines 2 thru 7)283,255,212 323,878,220
!Gas
1C
11
't2
't3
14
15 Other
16 TOTAL Gas (Enter Total of lines 10 thru 15
17 Other Non Electric (See footnote)18,905,81S
18 TOTAL (Acct 190) (Total of lines 8, 16 and 17)302,16't,031 343,510,457
Notes
FERC FORil NO. r (ED.12-EE)Page 234
Name of Respondent
ldaho Power Comoanv
This Report is:
(1) X An Original
(2) -A Resubmission
Date of Report
(Mo, Da, Yr)
041't412021
Year/Period of Report
20201o,4
FOOTNOTE DATA
Schedule Paoe: 234 Line No.: 5 Column: c
Construction Advances
Postretirement Benefits
USBR-American Falls O&M Costs Settlement
Non-VEBA Pension and Benefits
Executive Deferred Compensation
Stock Based Compensation
Pension Expense-Oregon
Bridger Revenue Deferral
Asset Retirement Obligation (ARO)
lncentive Deferral-Profit Sharing-Not in Rates
OR Reconnect Fees Adv
Tax Reform Regulatory Stipulation
Employer FICA Tax Defenal-CARES Act
Rate Case Disallowance
Unrealized Loss on lnvestments
Provision for Rate Refunds
Prov for Rate Refund-HC Relicensing (AFUDC)
VEBA-Post Retirement Benefits
Deferred ldaho ITC
TotalOther Electric
Beginning Balance
1,262,434
419,012
55,478
(557,867)
4,341
3,036,306
3,378,637
652,901
1,629,409
3,464,858
1,718
2,497,753
0
1,191,952
129
349,943
39,039,171
8,714,850
19,346,135
Ending Balance
1,325,912
419,012
46,482
(629,527)
23,045
2,921,158
3,759,993
806,746
1,563,709
3,182,560
2,422
4,496,944
2,251,257
1,115,685
(128)
0
43,524,951
9,757,342
23,870,142
84,487,160 98,436,605
9chedule Paoe:231 Line No.:7 Column: c
Pension-FAS 158
Regulatory Liability-FAS 1 09
Minimum Pension Liability
Postretirement Plan-FAS 1 58
TotalOther
Beginning Balance
89,534,362
96,598,638
12,61'1,062
23,990
Ending Balance
112,806,488
95,883,179
15,063,002
1,688,946
198,768,052 225,441,615
Schedule Paoe: 231 Line No.: 17 Column: c
Senior Management Security Plan
TotalNon Electric
Beginning Balance
18,90s,819
Ending Balance
19,632,237
18,905,819 19,632,237
FERC FORM NO. I (ED. 12-871 Page 450.1
Name of Respondent
ldaho Power Company
This Reoort ls:(1) E]An orisinal(2) l-lA Resubmission
Date of Report
(Mo, Da, Yr)
041'1412021
Year/Period of Report
End of 20201Q4
1. Report below the particulars (details) called for concerning common and preferred stock at end of year, distinguishing separate
series of any general class. Show separate totals for common and preferred stock. lf information to meet the stock exchange reporting
requirement outlined in column (a) is available from the SEC 10-K Report Form filing, a specific reference to report form (i.e., year and
company title) may be reported in column (a) provided the fiscal years for both the 10-K report and this report are compatible.
2. Entries in column (b) should represent the number of shares authorized by the articles of incorporation as amended to end of year.
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 201
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
I
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
ldaho Power Company (1)
(2)
Original (Mo, Da,
Resubmission o411412021
Year/Period of Report
End of 202OlQ4
3. Give particularc (details) concerning shares of any class and series of stock authorized to be issued by a regulatory oommission
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(0 shares(s)L;OSt(h)Amountfi)
1
3S,150,812 97,877,030 2
3
39,1s0,812 97,877,030 4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
FERC FORM NO.1 (ED.12-88)Page 251
Name of Respondent
ldaho Power Company
(1)
(2)
An Original
A Resubmission
(Mo, Da,
0411412021
Year/Period of Report
Endof 202Uo,4
OTHER PAID-IN CAPITAL (Accounts 208-21 1, 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 Capitral 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.ArEfnt
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 21'l - Miscellaneous paid-in Capital - None
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 TOTAL
FERC FORM NO.1 (ED.12-87)Page 253
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5]Rn originat(2) l--1A Resubmission
Date of Reoort(Mo, Da, Yi)
0411412021
Year/Period of Report
End of 2O2OIQ4
1. Report the balance at end of the year of discount on capital stock for each class and series of capital stock.
2. lf any change occurred during the year in the balance in respect to any class or series of stock, attach a statement giving particulars
(details) of the change. State the reason for any chargeoff of capital stock expense and specifo the account charged.
Line
No.
glass and series of stocl(
(a)
E atanoe at Eno or Year
(b)
1 Common Stock 2,096,925
2
3
4
5
6
7
8
I
10 Explanation of Changes during the year:
11
12
13
14
15
16
17
18
19
20
21
22 TOTAL 2,096,925
FERC FORM NO. 1 (ED.12-87)Page 254b
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5]An orisinal(2) ;-1A Resubmission
Date of ReDort(Mo, Da, Yi)
04t14t2021
Year/Period of Report
End of 20201Q4
LONG- I ERM UEB I (Account 221, 222, 223 and 224)
1. Report by balance sheet account the particulars (details) conoerning 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 oompany as well as a description of the bonds.
4. For advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate
demand notes as such. lnclude in column (a) names of associated companies from which advances were received.
5. For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were
issued.
6. ln column (b) show the principal amount of bonds or other long-term debt originally issued.
7. ln column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued.
8. For column (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount.
lndicate the premium or discount with a notation, such as (P) or (D). The expenses, premium or discount should not be netted.
9. Fumish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with
issues redeemed during the year. Also, give in a footnote the date of the Commission's authorization of treatment other than as
specified by the Uniform System of Accounts.
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 Account 221
2 First Mortgage Bonds:
3 5.50% Series due 2033 70,000,000 728,701
4 36,400 D
5
6 100,000,000 1,'r 59,871
7 499,000 D
8
9 5.30% Series Due 2035 60,000,000 3,849,739
10 408,600 D
11
't2 4.00% Series due 2043 75,000,000 742,017
13 1%,250 D
14
15 6.00% Series due 2O32 100,000,000 1,'.tg'.t,216
't6 5,t4,000 D
17
18 5.875o/o Series due 2034 55,000,000 585,759
19 748,000 D
20
2'.1 5.50% Series due 2034 50,000,000 524,419
22 383,500 D
23
24 4.85% Series Due 2040 100,000,000 1,284,87'l
25 170,000 D
26
27 6.30% Series due 2037 140,000,000 1,500,031
28 278,600 D
29
30 6.25% Series due 2037 100,000,000 1,227,490
3'l 268,000 D
32
33 TOTAL 2,1 64,833,176
FERC FORM NO. t (ED. 12-96)Page 256
Name of Respondent
ldaho Power Company (1)
(21
Original Da,
Resubmission 0411412021
Year/Period of Report
End of 202OlQ4
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 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 of the 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 Accounl427, interest on
Long-Term Debt and Account 430, lnterest on Debt to Associated Companies.
16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.
Nominal Date
of lssue
(d)
Date of
Maturity
(e)
AMORTIZATION PERIOD lnterest for Year
Amount
(i)
Line
No.Date From
(0
Date To
(s)
1
2
5/13/03 410'U33 5/13/03 3t31t33 70,000,00(3,850,000 3
4
5
8/30/10 11t01t20 8/30/10 11t01t20 1,983,334 6
7
8
8t26t05 8/15/35 8t26t05 8/15/35 60,000,000 3,1 80,000 I
't0
11
4t08t13 4101143 4t08t13 4t01t43 75,000,000 3,000,000 12
13
14
11115tO2 11115132 11115102 11115132 100,000,000 6,000,000 15
16
't7
8116104 8t15t34 8t16t04 8l'15134 s5,000,000 3,231,250 18
19
20
3126104 3t1st34 3126l04 3115134 50,000,00c 2,750,000 21
22
23
8/30/10 8l't5140 8/30/'10 8t'15t40 100,000,00c 4,850,000 24
25
26
6t22t07 6t15t37 6122107 6115137 140,000,00c 8,820,000 27
28
29
10118107 10115137 10t18t07 10t15t37 100,000,00c 6,250,000 30
31
32
1,990,345,000 84,250,809 33
FERC FORM NO. 1 (ED. 12.96)Page 257
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5]An orisinat
(21 5A Resubmission
Date of Reoort(Mo, Da, Yi)
041141202'.1
Year/Period of Report
End of 2O20lQ4
1. Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221 , Bonds,222,
Reacquired Bonds, 223, Advanc;es from Associated Companies, and 224, Olher long-Term Debt.
2. ln column (a), for new issues, give Commission authorization numberc 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 Port of Monow Variable due 2027 4,360,000 189,597
2
3 Humboldt 1.45o/o due 2024 49,800,000 396,278
4
5 Sweetwater 1.70o/o due 2026 116,300,000 908,982
6
7 2.50% Series due 2023 75,000,000 648,267
8 374,250 D
I
10 4.30o/o Seiles Due 2042 75,000,000 802,240
11 49,500 D
12
13 2.95% Series Due 2022 75,000,000 708,490
14 128,250 D
15
16 3.65% Series Due 2045 250,000,000 2,559,510
17 1,715,000 D
18
19 4.05% Series Due 2046 120,000,000 1,311,383
20 309,600 D
21
22 1.90% Series Due 2030 80,000,000 980,949
23 328,000 D
24
25 450,000,000 4,629,516
26 ldaho Order #34302 (41101191 814,000 D
27 Oregon Order #19-120 (411'1119)31,654,900 P
28 Wyoming Docket #20005-38-ES-1 91 6 (5/06/1 9)
29
30 Subtotal Account 221 2,145,460,000 64,833,176
31
32 Account 222 - Reaquired Bonds
33 TOTAL 2,1 64,833,176
FERC FORM NO.1 (ED.12-96)Page 256.1
Name of Respondent
ldaho Power Company (1)
(2)
ls:
Original
Resubmission
Date of ReDort(Mo, Da, Yi)
04t14t2021
Year/Period of Report
End of 2O2O|Q4
and
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, Anorlization and Expense, or credited to Account 429, Premium
on Debt - Credit.
12. ln a footnote, give explanatory (details) for Accounts 223 and 224 of 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 \Jutslangtno(Total amount outstandino without' reduction for amounts hbld byres0l65dent)
lnterest for Year
Amount
(i)
Line
No.Date From
(0
Date To
(s)
5117100 2101t27 0s/17100 o2li'il27 4,360,00c 44,359 1
2
8t21t19 12101t24 8t21t19 12101124 49,800,00c 722,100 3
4
8121t19 7115126 8121l1S 7115126 116,300,00c 1,977,100 5
6
4108113 4lo1t23 4t08t13 4to1t23 75,000,00c 1,87s,000 7
8
I
4113112 4101t42 4t13t12 4t01t42 75,000,00c 3,225,000 10
11
12
4113112 4101t22 4113112 4t01122 1,278,333 13
14
15
3/06/15 3to1t45 3/06/1 5 3101145 250,000,00c 9,125,000 16
17
18
3/10/16 3101146 3/10/16 311146 120,000,00c 4,860,000 19
20
z',l,
6122t20 06/1s/30 6122120 06/1 5/30 80,000,00c 798,000 22
23
24
3t16t18 3101148 3116t18 3to1l48 450,000,00(16,431,333 25
26
27
28
29
1,970,460,00(84,250,809 30
31
32
1,990,345,000 84,2s0,809 33
FERC FORM NO.1 (ED. 12.96)Page 257.1
Name of Respondent
ldaho Porer Company
This Reoort ls:(1) 5]Rn Orisinat(2) nA Resubmission
Date of ReDort(Mo, Da, Yi)
o411412021
Year/Period of Report
End of 2O20lQ4
LONG-TERM DEBT (Account 221, 222, 2?3 and ?'24)
1. Report by balance sheet account the particulars (details) conceming long-term 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 oompany as well as a description of the bonds.
4. For advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate
demand notes as such. lnclude in column (a) names of associated companies from which advances were received.
5. For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were
issued.
6. ln column (b) show the principal amount of bonds or other long-term debt originally issued.
7. ln column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued.
8. For column (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount.
lndicate the premium or discount with a notation, such as (P) or (D). The expenses, premium or discount should not be netted.
9. Fumish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with
issues redeemed during the year. Also, give in a footnote the date of the Commission's authorization of treatment other than as
specified by the Uniform System of Accounts.
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 223: Advances for Associated Companies
3
4 Accn,unl224:
5 Bond Guarantee - American Falls 19,885,000
6 Subtotal Acaunt224 19,885,000
7
8
I
't0
't1
12
13
14
15
16
17
't8
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33 TOTAL 2,165,345,000 64,833,1 76
FERC FORM NO.1 (ED. 12.96)Page 256.2
Name of Respondent
ldaho Power Company (1)
(2)
An Original
A Resubmission
(Mo, Da,
04t14t2021
Year/Period of Report
End of 202OlQ4
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, Amortization and Expense, or credited to Account 429, Premium
on Debt - Credit.
12. ln a footnote, give explanatory (details) for Accounts 223 and 224 of 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 of the 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 Accounl427, interest on
Long-Term Debt and Account 430, lnterest on Debt to Associated Companies.
16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.
Nominal Date
of lssue
(d)
Date of
Maturity
(e)
AMORTIZATION PERIOD UUISIEINOINOfiotal amount outstantlino without' reduction for amounts h-eld by
res0lg5dent)
lnterest for Year
Amount
(i)
Line
No.Date From
(0
Date To
(s)
1
2
3
4
4t26tOO 2lo1t2s 19,885,00C 5
19,885,00C 6
7
8
I
10
't1
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
1,990,345,000 84,250,809 33
FERC FORM NO. 1 (ED.12.95)Page 257.2
This Page lntentionally Left Blank
Name of Respondent
ldaho Power Company
This Report is:
(1) X An OriginalQ) A Resubmission
Date of Report
(Mo, Da, Yr)
o411412021
Year/Period of Report
202ua4
FOOTNOTE DATA
Schedule Pade: 256 Line No.:6 Column: a
1
Schedule Paoe: 256.1 Line No.: 25 Column: a
3 .40 Ser at onB 2020
ono 4 bonds due 3 2048 ssued on 3 020 w tha
$31,654,900, bringing total 4.202 series outstanding to $450 million1 um of
FERC FORM NO.1 (ED. ,2ATI Pase 450.1
This Page lntentionally Left Blank
Name of Respondent
ldaho Power Company
This Reoort ls:(1) E]An Orisinal(2) IA Resubmission
Date of Reoort(Mo, Da, Yi)
04114t2021
Year/Period of Report
End of 2O20lQ4
RECONCILIATION OF REPORTED NET INCOME WITH TAXABLE INCOME FOR FEDERAL INCOME TA)GS
1. Report the reconciliation of reported net income for the year with taxable income used in computing Federal income tiax accruals and show
computation of such tax accruals. lnclude in the reconciliation, as far as practicable, the same detail as fumished on Schedule M-1 of the tax 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 retum, 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 return. Stiate 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.
une
No.
lJaruculars (ueEils,(a)Amount
(b)
233.2U.5431Net lncome for the Year (Page 'l 17)
2
3
4 laxable lncome Not Reported on Books
5
6
7
I
I Deductions Recorded on Books Not Deducted for Retum
10
11
12
13
14 lncome Recorded on Books Not lncluded in Retum
15
16
17
't8
't9 Deductions on Retum Not Charged Against Book lncome
20
21
22
23
24
25
26
27 Federal Tax Net lncome 173,828,995
28 Show Computation of Tax:
29 Tenative F ederal \ ax @ 21 o/o 36,504,089
30
31
32
33
g
35
36
37
38
39
40
4'l
42
43
M
261
Name of Respondent
ldaho Power Companv
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t't4t2021
Year/Period of Report
2020tQ4
FOOTNOTE DATA
261 .'5 Column: b
4OO3-CONSTRUCTION ADVANCES 302,278
4OOS.AVOIDED COST 4,969,510
4013-C|AC - TAXABLE - ACCT 107 3,385,641
4021-ENGINEERING FEES - TAXABLE -ACCT 107 573,323
,O66-BOARDMAN DECOMMISSION 32,121
Iotal 9.262.873
Schedule Paqe: 261 Line No.: 10 Column: b
lotal Federa! and State taxes deducted on books 28,992,130
5OO1.BAD DEBT EXPENSE 3,519,63s
5OO8-GAIN/LOSS ON REACQUIRED DEBT 273,234
5o24-NON.DEDUCTIBLE MEALS 200,000
5061-PENSION EXPENSE - OREGON 1,477,294
5077-VALMY DEPRECIAT]ON ADJ USTMENT 3,097,383
5078-TAX REFORM REGULATORY STIPULATION 7,766,865
sOSO.EMPLOYER FICA TAX DEFERRAL-CARES ACT 8,746,143
55o4-NON.DEDUCTIBLE POLITICAL EXPENSES 698,461
5505-SMSP - NET 2,822,137
/O.IO-PROV FOR RATE REFUND - HC RELICENSING (AFUDC)17,427,273
3OO1-VEBA - POST RETIREMENT BENEFITS 4,150,798
3OOg-DEPR TIMING DIFF - OPERATING - FEDERAL 104,006,634
3703-IPCO-1 62(m ) THRESHHOLD 3,602,800
]OO9-VALMYI BOOK BASIS ADJUSTMENT 3,081,950
Iotal 189.862.735
Schedule Pase:261 Line No.:15 Column: b
5074-VALMY SETTLEMENT ADJUSTMENT 24,766
5501-SMSP - INSURANCE COSTS 3,796,679
7501-REVERSE EOUITY EARNINGS OF SUBSIDIARIES 8,402,214
75o2-ALLOWANCE FOR OFUDC 29,550,610
TsO3.ALLOWANCE FOR BFUDC 11.577,828
75O9.SMSP - INSURANCE PROCEEDS 82,262
Iotal 53.434.359
Sclredule Paoe:261 Line No.:20 Column: b
36,000,0005022-263 A CAP ITAL IZE D OVE RH EADS
26,021,9575023-PENSION EXPENSE
329,1275o52-AMORTIZATION OF ACCOUNT 181
5053-STOCK BASED COMPENSATION 1,759,764
sOs8.FIXED COST ADJUSTMENT 1,475,254
5O6O-OREGON - PCAM 6,830
5067-ASSET RETIREMENT OBLIGATION (ARO 255,245
86,2185O7O-INCENTIVE DEFERRAL-CRI & RELIABILITY-INCLUDED IN RATES
1 -INCENTIVE DEFERRAL-PROFIT OT IN RATES 2,166,588
FERC FORM NO.1 (ED. 12.871 Page 450.1
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t14t202'.1
Year/Period of Report
20201Q4
FOOTNOTE DATA
5538-STOCK BASED COMP - STOCK 1,814,033
7OOg-PROVISION FOR RATE REFUNDS 1,019,647
3O2O-CONSERVATION EXPENSES 't't,144,997
3034-REMOVAL COSTS 14,992,099
3o42-GAIN/LOSS ON REACQUIRED DEBT 996,760
BOsg-SOFTWARE - LABOR COSTS DEDUCTED - ACCT 107 5,096,000
3o72-RELICENSING - LABOR COSTS DEDUCTED - ACCT 107 2,695,000
BO73-REPAIRS DEDUCTION 88,000,000
3077-PREPAID INSURANCE & OTHER EXPENSES 448,083
B7O2-STOCK BASED COMP - DIVIDENDS 634,894
3705-OR CAT 292,171
STATE INCOME TA)( DEDUCTED ON FEDERAL RETURN 9,862,130
fotal 205.096.797
FERC FORM NO.1 (ED. 12-871 Page 450.2
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5]Rn orisinat
(21 ;-1A Resubmission
Date of Reoort(Mo, Da, Yi)
0411412021
Year/Period of Report
End of 2O20lQ4
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 sdch 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 traxes accrued,
(b)amounts credited to proportions of prepaid taxes chargeable to cunent 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.
Ltne
No.
Kind of Tax
(See instruction 5)
(a)
BALANCE AT BEGINNING OF YEAR 'f
1
Adjust-
ments
(0
rreDato taxes(lnclude in Account 165)
1 Federal:
2 lncome -6,373,909 26,269,804 23,634,729
Social Security - (FOAB)940,962 16,486,184 8,774,638
4 Unemployment -447,169 44,858 -400,295
5 Subtotal Federal -5,880,116 42,800,846 32,009,072
o
7 State of ldaho:
8 lncome -2,736,522 5,874,581 4,385,869
9 Unemployment 16,002 191,454 209,61s
10 Property 9,629,156 21,063,164 21,29s,254
11 Non-Operating 10,684 17,173 10,678
't2 kwh 81,645 1,623,304 1,620,442
't3 Regulatory Commission 3,083,918 3,083,918
14 Business License - Sho Ban 150 150
15 Subtotal ldaho 7,000,965 31,853,744 30,605,926
16
17 State of Oregon
18 lncome -256,211 806,955 458,761
19 Unemployment 2,532 30,426 32,958
20 Property 1,913,496 3,903,806 3,978,754
21 Non-Operating Property 973 't,974 2,003
22 Regulatory Commission 257,789 280,929 23,140
23 Franchise 215,244 779,989 799,819
24 Subtotal Oregon -38,435 1,914,469 5,780,939 5,553,224 23,140
25
26 State of Montana:
27 Property 178,994 467,'t06 412,838
28 Subtotal Montana 178,994 467,106 412,838
29
30 State of Nevada:
31 Property 350,691 618,865 536,099
32 Subtotal Nevada 350,691 618,865 536,099
33
34 State of Wyoming
35 Property 673,450 1,430,690 1,388,795
36 Corporate License 4,196 4,196
37 Subtotal Wyoming 673,450 1,434,886 't,392,991
38
39
40
4',l TOTAL 2,114,255 2,26sJ60 66,230,501 -27,018
FERC FORi, NO.1 (ED. 12-96)Page 262
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5]en originat(2) 1-1A Resubmission
Date of Report
(Mo, Da, Yr)
o411412021
Year/Period of Report
End of 2O2O|Q4
5. lf any tax (exclude Federal and State income taxesl covers more then one year, show the required information separately for each tax year,
identifuing the year in column (a).
6. Enter all adjustments of the accrued and prepaid tax accounts in column (0 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 tiaxes or tiaxes collected through payroll deductions or othenrvise pending
transmittal of such tiaxes 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
pettaining 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 (necessiU) of apportioning such tiax.
BAl ANCF AT :ND OF YEAR Line
No.(Taxes accrued
eccoln| zs0)
Prepaid Taxes
(lncl. in Account 165)
Electdc(Account 408.1 , 409.1 )
Extraoroinary ltems
(Accou6t 40s.3)
AOtUSrmenE ro Ket.
Eamings (Account 439)
ft)
Other
0)
1
-3,738,834 26,204,174 2
8,652,508 16,486,184 3
-2,016 44,858 4
4,911 ,658 42,735,216 65,630 5
6
7
-1,247,810 s,760,357 8
-2,159 191,454 o
9,397,066 2',t,061,821 10
17,179 11
84,507 1,623,304 12
3,083,918 13
150 14
8,248,783 31,721,004 132,740 15
16
17
9't,983 508,753 18
30,426 1S
1,988,4,14 3.712.640 20
1,001 21
257,789 22
195,414 779,989 23
287,397 1,989,445 5,289,597 491,U2 24
25
26
233,262 467,'t06 27
233,262 467,106 28
29
30
267,925 618,86s 31
267,925 618,865 32
33
u
715,y4 1,430,690 35
4,1 96 36
715,U4 1,434,886 37
38
39
40
14,568,240 2,257,370 65,538,125 692,376 4'l
FERC FORM NO.1 (ED. 12.96)Page 263
Name of Respondent
ldaho Power Company (1)
(2)
An (Mo, Da,
A Resubmission 0411412021
Year/Period of Report
End of 2O20lQ4
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
1 . Give particulars (details) of the combined prepaid and accrued tax accounts and show the totrl 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 th€se taxes.
3. lnclude in column (d) taxes charged during the year, tiaxes charged to operations and other accounts through (a) accruals credited to taxes accrued,
(b)amounts credited to proportions of prepaid taxes chargeable to cunent 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.
Ltne
No.
Kind ofTax
(See instruction 5)
(a)
tsALANUE AI tsEGINNING OF YEAR I axesCharoed
R4}}s(d)
'F#r
R4}}s(e)
Adjust-
ments
(f)
I axes Accrued(Account 236)
(b)
PreDaro I axes(lnclude in Account 165)
'l State of Washington
Property 8,000 7,225 7,225
2 Subtotal Washington 8,000 7,225 7,225
4
C Other States lncome 179,208 19,8'12 16,399
6 Canada GST Tax -7,811 -39,144
7 Payroll Tax Credit -16,752,922
I
o
10
11
12
13
14
15
16
17
18
1g
20
21
22
23
24
25
26
27
2A
29
30
31
32
33
u
35
36
37
38
39
40
41 TOTAL 2,',t14,2ss 2,265,160 66,230,501 -27,0',t8
FERC FORM NO. r (ED. 12-96)Page 262.1
Name of Respondent
ldaho Pouer Company
This Reoort ls:(1) E]An Orisinal(2) l--1A Resubmission
Date of Report(Mo, Da, Yi)
04114t2021
Year/Period of Report
End of 2O20lQ4
5. lf any tax (exclude Federal and State income taxes)- c,overs more then one year, show the required information separately for each trax year,
identiffing the year in column (a).
6. Enter all adjustments of the accrued and prepaid tiax 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 othenrise pending
transmittal of such traxes to the taxing authority.
8. Report in columns (i) through (l) how the tiaxes were dishibuted. 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 :ND ()F YEAR Line
No.(Taxes accrued
Accolnj 236)
Prepaid Taxes
(lncl. in Account 165)
Electric(Account 408.1, 409.'l )
Extraordinary ltems
(Account 409.3)
Aotu$ments ro Ket.
Eamings (Account 439)
(k)
Other
(t)
1
8,000 7,225 2
8,000 7,225 3
4
182,621 17,148 5
-18,825 6
7
8
I
10
1',!
12
13
14
15
16
17
18
't9
20
21
22
23
24
25
26
27
28
29
30
3'l
32
33
u
35
36
37
38
39
40
14,568,240 2,257,370 65,538,125 692,376 41
FERC FORl,l NO.1 (ED. 12.96)Page 263.1
This Page lntentionally Left Blank
Name of Respondent
ldaho Power Comoanv
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
0411412021
Year/Period of Report
20201Q4
FOOTNOTE DATA
Schedule Paoe:262 Line No.:2 Column: IAccount 40
Account 42Account 40
Total
406,255- 6,305
-334,320
$65, 630
9.2
5.5
ol
$
$
$
Schedule Pase: 262 Line No.:8 Column: I
Account 409.2 $ L1-4,224
262 Line No.:10 Column: I
Account 107 l_, 343
9chedule Paoe:262 Line No.: 11 Column: I
Account 408.2 $l7,L73
262 Line No.: 18 Column: I
Account 409.2
Account 1,82.3
Total
$
6, 031
292,t71
$ 298,202
Schedule Pase:262 Line No.:20 Column: I
Account 107 t9t ,]-56<
Schedule Paqe:262 Line No.: 21 Column: IAccount 4o8.2 1,974$
262.1 Line No.: 5 Column: IAccount 409.2 $2 ,664
262.1 Line No.: 6 Column: f
262.1 Line No.:7 Column: i
GST san ustment cause o set account s noL a 500 expense
account
s amount s an offset to 1 3, 4, 9, and 1-9. Each month employer taxesinto various 408.1 accounts. In that same month these amounts are offset with a different408.1 account. These payroll taxes are then allocated back to the balance sheet and O&M
accounts based on current month labor charges.
FERC FORM NO.1 (ED.'12.871 Pase 450.1
Name ls:
Originalldaho Power Company (2t A Resubmission
Date of Report(Mo, Da, Yr)
0411412021
Year/Period of Report
End of 20201Q4
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.
Lln€
No.subdfyfions
BAEnce,SlJegrnnlng
(b)
Defened for Year AllOCaUOnS IOCunent Year's lncome Adjustments
(s)ACCOUnI NO.(c)Amount(d)ACOOUnI NO.(e)unt
1 Electric Utility
2 3o/o
2 4o/o 214,143 411.401 26,s2t
4 7Yo
100/'t 1,989,331 411.401 1.127,07t
6 15,859,617 192,40(
7 66,742,779 4',t1.402 5,726,591 41'.t.402 1,559,68(
8 IOTAL 94,80s,870 5,726,591 2,905,69i
o Other (List separately
and show 3Yo, 4o/o, 7o/o,
10% and TOTAL)
10 'l'lo/o 1,041,647 4',t1.401 22,27(
11 30o/o 14,817,970 411.401 411.401 170,13(
12 Totrl Line No.6 15,859,617 192,40(
13
14
15 State of ldaho 66,742,779 M1.402 5,726,591 411.402 1,559,68(
t6
17
18
1g
2A
21
22
23
24
25
26
2t
28
30
31
32
33
34
35
36
37
38
3S
4C
4'.l
42
43
44
45
46
47
48
FERC FORM NO.1 (ED. 12-89)Page 266
Name of Respondent
ldaho Power Company
This Reoort ls:(1) EIAn orisinal(2) nA Resubmission
Date of Report(Mo, Da, Yr)
0411412021
Year/Period of Report
End of 2O20lQ4
Balance at Endof Year
(h)
Averaoe Penodof Alfocation
to lncome(i)
ADJUSTMENT EXPLANATION Lrne
No.
,|
2
187,618 8.07 3
4
10,862,253 10.67 E
15,667,208 87.09 6
70,909,690 42.79 7
97,626,769 8
I
1,019,377 46.77 10
14,647,831 87.09 11
15,667,208 12
13
14
70,909,690 15
16
17
18
19
20
21
22
23
24
25
26
27
28
30
31
32
33u
35
36
37
38
39
40
4'l
42
43
44
45
,06
47
48
FERC FORM NO.1 (ED.12-89)Page 267
This Page lntentionally Left Blank
ldaho Power Company (1)
(2)
An (Mo, Da,
A Resubmission 04t't4t2021
Year/Period of Report
End of 20201Q4
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 (5olo 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
Gontra
Account(c)
Amount
(d)
1 PTP Transmission Deposits 253201 1,495,550 131 366,405 1,994,015 3,123,160
2
3 FTV Dark Fiber Rental 253202 866,666 400 400,000 466,666
4 Amortization period 03/98-0223
5
6 Escrow Deposits 253350 92,147 1U 92,187 40
7
8 Sho,Ban Scholarships 253480 127,500 242 15,000 112,500
I Amortization penod 01 I 0*1 Z 27
10
't1 Operations Accruals 253550 402,823 131 17,400 280,272 665,695
't2
13 Postretirement Benefits 253960 1,627,862 316,725 1,944,587
14
15 Directors Defened Compensation 3,423,237 131 311 ,500 224,987 3,336,724
16 253970-253999
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47 TOTAL 8,035,785 't,202,492 2,816,039 9,649,332
FERC FORM NO. I (ED.12-94)Page 269
FERC FORil NO. r (ED.12-96)Page 271
Name of Respondent
ldaho Power Company
This Reoort ls:(1) []An Original(2) nA Resubmission
Date of Reoort
(Mo, Oa, Yi)
0/,|14t2021
Year/Period of Report
End of 202OlQ4
1. Report the information called for below concerning the respondent's accounting for deferred income taxes rating to property not
subject to accelerated amortization
2. For other (Specify),include defenals relating to other income and deductions.
Line
No.
Account
(a)
Balance at
Beginning of Year
(b)
CHANGES DURING YEAR
Amounts Debited
to Account 4'10.1
(c)
Amountrs Credited
to Account 41 1.1
(d)
1 Account 282
2 Electric 7,573,682 16,058,808
3 Gas
4
5 TOTAL (Enter Total of lines 2 thru 4)281,6't7,312 7,573,682 16,058,808
6
7 Other - Regulatory Asset for I 646,886,027
8 Like Kind Exchange - Reclass N 4,966,027
I TOTAL Account 282 (Enter Total of lines 5 thru 933,469,366 7,573,682 16,058,808
10 Classification of TOTAL
11 Federal lncome Tax 749,308,583 7,513,402 15,961,029
12 State lncome Tax 184,160,783 60,280 97,779
13 Local lncome Tax
NOTES
ldaho Porer Company (1)
(2t
An Original
A Resubmission 0411412021
Year/Period of Report
Endof 2O2UQ4
3. Use footnotes as required.
CHANGES DURING YEAR ADJUSTMENTS
Balance at
End of Year
(k)
Line
No.
Amounts Debited
to Account 410.2
(e)
Amounts Credited
to Account 411.2
(0
Debits Credits
AC@Unt
Credited(g)
Amount
(h)
Acoount
Debited
{i)
Amount
(i)
1
282t254 s,106,69€278,238,88t 2
3
4
5,106,69€278,238,88t 5
6
182 40,742,421 687,628,'t4t 7
282 22'.t,651 4,744,321 8
221,691 45,8/]9,12(970,61't,66i 9
10
184254 u,u7,174 775,208,'.|3(11
182 11,280,24t 195,403,53i 12
13
NOTES (Continued)
FERC FORir NO. r (ED. t2-96)Page 275
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)
0411412021
Year/Period of Report
202Uo,4
FOOTNOTE DATA
9chdule Paoe:274 Line No,:2 Column: b
Account
(a)
2020 Chanses durins Year Adiustments Credits 2020
Beginning
Balance
b
DR to
410.1
c
CR to
411.1
d
Acct.
debited
i
Amount
i
Ending
Balance
k
)epreciation Timing Diff-Operating
-ike Kind Exchange - Reclass
tlon-Rate Base
ixcess Deferred Tax on
)epreciation (Reg Liab)
SlAC-Taxable-Acct 107
ing i neeri ng Fees-Taxable.Acct
t07
Software-Labor Costs
)educted-Acct 107
ntangible.Labor Costs
)educted-Acct 107
46/.,329,392
(4,966,027)
(183,881,576)
(7,67e,e38)
(60e,4e6)
2,048,323
12,376,634
1,3218,880
(52,602)
594,527
5,682,877 15,227,425
710,985
120,398
282'.t11
254967
221,698
4,885,001
454,7U,844
i4,744,3291
(178,996,s7s)
17,042,0431
(729,8941
L,995,721
L2,97L,L6L
rOTAL 28t,6L7,3L2 7,573,682 16,058,808 5,105,599 278,238,88s
FERC FORM NO.1 (ED. 12.871 Page 450.1
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5]An orisinat
(21 5A Resubmission
Date of ReDort(Mo, Da, Yi)
0411412021
Year/Period of Repo(
End of 20201Q4
1. Report the information called for below concerning the respondent's accounting for defuned 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 to Accoddlt 41 1.1
1 Account 283
2 Electric
3 Other Electric - See Note 17,265,217 1,063,773
4
5
6
7
I Other - See Note
s TOTAL Electric (Total of lines 3 thru 8)168,061,747 17,265,211 1,063,773
10 Gas
11
12
13
14
15
16
17 TOTAL Gas (Iotal of lines 11 thru 16)
18 Other - See Note 1l'.t,182 14
't9 TOTAL (Acct 283) (Enter Total of lines 9, 1 7 and 18)168,005,730 17,376,399 1,063,787
20 Classiffcation of TOTAL
21 Federal lnc,ome Tax 128,843,556 13,325,95G 798,288
22 State lncome Tax 39,162,174 4,050,443 265,49!
23 Local lncome Tax
NOTES
FERC FORir NO. r (ED. 12-96)Page 276
Name of Respondent
ldaho Porer Company (2t A Resubmission o4t't412021
Year/Period of Report
Endof 2O2UQ4
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.
l1HAN(?trS Nt IRING VtrAP
Balance at
End ofYear
(k)
Line
No.
Amounts Debited
to Account 410.2
(e)
Amounb Grcdited
to Account 41 1.2
(fl
Debits Gredits
Amount
ft)
ttGCOUntDebited(i)
,ttnount
fi)
1
2
94,704,U0 3
4
5
6
7
190 24,937,083 114,455,434 8
24,937,083 2@,200,274 I
10
11
12
13
14
15
16
17
55,151 18
24,937,083 209,255,425 19
20
190 15,124,243 160,495,467 2'.!
190 5,812,840 48,759,958 22
23
NOTES (Continued)
FERC FORM NO. I (ED. 12-96)Page 277
Name of Respondent
ldaho Power Comoany
This Report is:
(1) Xen OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
0d,|1412021
Year/Period of Report
20201Q4
FOOTNOTE DATA
276 Line
2020 Chances durins Year 2020
Account
(a)
Beginning
Balance
b
DR to
410.1
c
CR to
47t.L
d
Ending
Balance
k
Renewable Energy Certificates (REC) Sales
Royalty lncome
Gain/Loss on Reaqcuired Debt
Pension Expense
PCA Expense
lntervenor Funding Orders
Fixed Cost Adjustment
Oregon PCAM
2011 LIDAR Surveys Deferral
Boardman Decommission
Valmy Seftlement Adjustment
EIM Deferral
Valmy Depreciation Adjustment
Community Solar Deferral
Langley Revenue Accrual
Conservation Expenses
Siemens LTP Contract
Prepaid Credit Facility
Siemens OR DRB lnterest Reserve
Boardman Removal Costs
Oregon CAT Deferral
(366,723)
235,387
423,161
43,205,227
61,364
8,205,246
2,212
33,672
(328,785)
6,392,037
9,722
20,163,543
336,816
76,062
70,033
(25,885)
10,307
1,288,455
6,698,052
6,078,339
1,758
235,078
2,868,723
17,214
52,563
16,345
8,690
1,025,969
(75,205)
4,055
8,181
10,949
70,331
11,225
8,268
92L,732
224,438
3s2,830
49,903,279
57,309
14,283,585
3,970
22,447
(337,0s3)
6,627,115
9,722
19,L37,574
3,205,539
8,690
(34,065)
26,552
75,20s
93,276
122,596
TOTAL 78,503,395 L7,265,2t7 1,063,773 94,704,840
9chedule Paoe:276 Line No.:8 Column: b
2020 Adiustments Credits 2020
Beginning
Balance
Acct.
debited
Ending
BalanceAccountAmount
FERC FORi,t NO.1 (ED. 12-871 Page 450.'l
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
o4t14t2021
Year/Period of Report
202Uo,4
FOOTNOTE DATA
(a)b k
rension-FAS 158
rostretirement Plan-FAS 1 58
89,534,361
23,990
190
190
23,272,127
1,664,956
112,806,488
1,688,946
24,937,083 t14,495,434rOTAL89,558,351 190
Schedule Pase:276 Line No.:18 Column: b
Account
(a)
2020 Changes during Year 2020
Beginning
Balance
b
DR to
410.1
c
CR to
4tt.L
d
Ending
Balance
k
EDC-Unrealized Gain/Loss From Rabbit Trust
SMSP-Unrealized Gain/Loss From Rabbi Trust
Cregon Non-Op Prop Tax Adj
(316)
(55,966)
265
2,008
109,174
14
1,692
53,208
25L
rOTAL (s6,017)Itt,t82 t4 55,151
FERC FORM NO. 1 (ED. 12.871 Pase 450.2
Name of Respondent
ldaho Power Company (1)
(2)
Original
Resubmission
Date of ReDort(Mo, Da, Yi)
04t14t202',1
Year/Period of Report
End of 202010,4
1. Report below the particulars (details) called for concqrning 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 Cunent
Quarter/Year
(b)
DEBITS
Credits
(e)
Balance at End
of Cunent
Ouarternfear
(0
ACCOUntCredited
(c)
Amount
(d)
,|Market to Market Short Term (254001 )404,917 1,590,20!1.995.'126
2 IPUC Order#28661
3
4 Oreson Solar Rider (254005)110,442 401 32,932 37,781 145,n7
5 OPUC Order#10J98
6
7 BPA Credit Residential ldaho (254401)4,132,893 142 't9,381,085 18,693,143 3,444,951
I OPUC Advice #15-13
I
10 BPA Credit Residential Oregon (2544021 r46,607 142 663,1 17 67E,13t 1 6'1,628
't1 OPUC Advice #15-l'l
12
13 BPA Credit Farm ldaho (254403)885,855 142 3,028,486 2,882,98;740.35,(
14 OPUC Advice #15-13
15
16 BPA Credit Farm Oegon (254404)42,855 142 104,399 169,48t 1 07,944
17 OPUC Advice#15-.l1
18
19 Oregon Green TaEs (254415)n7,x1 40'l 190,70t 221,14(327,695
20 OPUC Order#1'l{86
21
22 ldaho Tax Settement (254451)9,1 39,472 7,753,'t1(16,89458€
23 IPUC Order#34071
24
25 Oreson Tax Settement (254452)564,308 13,74!578,05i
26 OPUC Order#18-199
27
28 Brklger Deprecialion (254800)3,1U,211 597,68(3.731.897
29 OPUC Order#12-296
30
3'l RL.WAQC CRYOVR (254901)1 56,790 615,09'771,U2
32 IPUC Order #29505
33
34 Unfunded Accum Def lncome Tax (254966)32,861,609 190 245,54S 1,n33X 33,839,38S
35 RLOEF rNC TAX-ARAM (254967)183,881,5r/n2 5,993,135 1,108,134 178.996.576
36
37 RLOEF tNC TAX-ARAM GROSS-UP (254968)63,737,029 190 2,077,U4 384,101 62.043.790
38
39 48,194,075 1823 33,512,702 '14,681,373
40 IPUC Order Pendinq
41 TOTAL 349,006,644 65,229,4s3 36,001,849 319,779,04(
FERC FORit NO. 1r3-Q (REV 02-04)Page 278
Name of Respondent
ldaho Power Company
This
(1)
(2)
Reoort ls:
fien originat
[-lA Resubmission
Date of ReDort(Mo, Da, Yi)
04t1412021
Year/Period of Report
End of 20201Q4
OTHER REGULATORY LIABILITIES (Account 254)
1. Report below the particularc (details) called for cone4rning 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 $1 00,000 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 Cunent
QuarterfYear
(b)
DEBITS
Credits
(e)
Balance at End
of Cunent
Quarter^fear
(0
Account
Credited
(c)
Amount
(d)
1
2 1,2n331 32,12i 1.309.454
3 OPUC Order #12-235, IPUC Order #32457
4
5 Minor ltems (2)9,412 Various 1,6n I 1,03!
6
7
8
o
't0
't'l
12
13
14
15
16
17
18
19
20
2'.1
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41 TOTAL 349,006,644 65,229,453 36,001,84S 319,779,04(
FERC FORM NO. 1/3.Q (REV 02-04)Page 278.1
This Page lntentionatly Left Blank
Name of Respondent
ldaho Power Company
This Report is:
(1) [ An OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
04t14t2021
Year/Period of Report
20201Q4
FOOTNOTE DATA
Schdule Paoe:278 Line No.:39 Column: a
The PCA deferral is comprised of multiple accounts aggregated into one line for clean presentation in the Financials
Schedule Paoe:278.1 Line No.:2 Column: a
The Boardman Decommissioning is comprised of multiple accounts aggregated into one line for clean presentation in
the Financials
FERC FORM NO.1 (ED. 12.871 Pase 450.1
ldaho Power Company
(1)
(2)A Resubmission
Date of Reoort(Mo, Da, Yi)
0411412021
Year/Period of Report
End of 202OlQ4
1 . Th€ fullowirE instuctions generally apply to the annual version of thes€ pages. Do not report quarterly data in columns (c), (e), (0, and (S). Unbilled rBvenues and lvlvvH
r€lated to unbilled revenuos n€ed not be r€ported separately as requir€d in the annual version of these pages,
2. Report b€low operating revenues br each prescribed account, and manufuctur€d gas rovenues in tolal.
3. Report numbe. of cusbmers, columns (0 and (g), on the basis of metsrs, in addition to the number of flat rate accrunts; except that wh€rB separate meter readings are added
for billirE purposes, one customer should be counted for each group of meto6 added. The -average numb€r of custom€rs means th€ average of tu,elve figures at the close of
each month.
4. lf incrBases or decreases ftom pr€vious period (columns (c),(e), and (g)), are not derived from previously r€ported figures, explain any inconsistencies in a botnote.
5. Disclose amounts of $250,000 or greater in a footnote for accounts 451 , 456, and 457.2.
Line
No.
Title of Account
(a)
Operaling Revenues Year
to Date Quarterly/Annual
(b)
OperaUng Revenues
Previous year (no Quarterly)
(c)
1 Sales of Electricity
2 (440) Residential Sales 548,813,944 528,572,308
3 (442) Commercial and lndustrial Sales
4 Small (or Comm.) (See lnstr. 4)445,695,226 428,953,227
5 Large (or lnd.) (See lnstr. 4)181 ,631,234 181 ,871,403
6 (444) Public Street and Highway Lighting 3,816,533 3,850,765
7 (445) Other Sales to Public Authorities
I (4'16) Sales to Railroads and Railways
I (448) lnterdepartmental Sales
10 TOTAL Sales to Ultimate Consumers 1,179,956,937 1,143,247 ,703
1',l (447) Sales for Resale 66,090,671 101,908,387
12 TOTAL Sales of Electricity 1,246,047,608 1,245,156,090
13 (Less) (449.1) Provision for Rate Retunds 7,774,230 8,440,245
14 TOTAL Revenues Net of Prov. for Refunds 1,238,273,378 1,236,715,845
15 Other Operating Revenues
16 (450) Forfeited Discounts
17 (451 ) Miscellaneous Service Revenues 4,66't,497
18 (453) Sales of Water and Water Power
19 (454) Rent from Electric Propefi 17,491,3',t4 16,936,'t79
20 (455) lnterdepartmental Rents
2',1 (456) Other Electric Revenues 41,061,301
22 (456.1) Revenues from Transmission of Electricity of Others 43,907,734 43,848,605
23 (457.1) Regional Control Service Revenues
24 (457.2) Miscellaneous Revenues
25
26 TOTAL Other Operating Revenues 109,1 10,328 106,507,582
27 TOTAL Electric Operating Revenues 1,347,383,706 1,343,223,427
FERC FORM NO. tr3.Q (REV. 12-05)Page 300
ldaho Power Company (2)A Resubmission
Date of Remrt(Mo, Da, Yi)
0411412021
Year/Period of Report
End of 2O20lQ4
ELECTRIG OPERATING REVENUES (ACCOUNI 4OO)
ln a footnote.)
7. S€epages108-lO9, lmportantChang€sDuringP6rlod,ficrlmportantn€wteritoryadd6dandimportantretoincroasoordocreasos.
8. For Lines 2,4,5,and 6, s€€ Pag6 3O4 for amounts r€latng to unbill€d rBv€nue by accounb.
9. lnclude unmetor€d sales. Provide details of such Sal€s in a botlob.
MEGAWATT HOURS SOLD AVG.NO. CUSTOMERS PER MONTH Line
No.Year to Date Quarterly/Annual
(d)
Amount Provious year (no Quartedy)
(e)
Cunent Year (no Quanefly)
(f)
Previous Year (no Quarterly)
(s)
1
5,462,557 5,272,659 48/.,432 471,298,2
3
5,960,256 5,819,993 91,470 90,'t64 4
3,369,260 3,412,410 127 127 5
30,187 31,652 3,767 3,48€6
7
8
I
14,828,260 14,536,714 579,796 565,077 10
1,887,139 2,850,922 11
16,715,399 17,387,636 579,796 565,077 12
13
16,715,399 17,387,636 579,796 565,077 14
Line 12, column (b) includes $
Line'12, column (d) includes
8,616,257
60,927
of unbilled revenues.
MWH relating to unbilled revonues
FERC FORM NO. lr3-Q (REV. 12-t,5)Page 301
Name of Respondent
ldaho Po^rer Company
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
u|1412021
Year/Period of Report
20201Q4
FOOTNOTE DATA
Line No.:17 Column: bThis amount consists of:Service EsEablishment/Connection charges(Includes late and afEer hour charges)Misc. Under $250,000
$4, 053, 657
298 473
Total Account 451
This amounE consists of:
DSM ActivitYAlternate Distribution ServiceMisc. Under $250,000
Total Account 455
352 130
$42 ,478 ,200737,409
143 s41
$43, 3s9, 1s0
300 Line No.:21 Column: b
FERC FORM NO. 1 (ED. 12.871 Page 450.1
Name of Respondent
ldaho Power Company
This Reoort ls:(1) E]An orisinal(2) nA Resubmission
Date of ReDort(Mo, Da, Yi)
04t'14t2021
Year/Period of Report
End of 202OlQ4
SALES OF ELECTRICITY tsY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311 .
2. Provide a subheading and total for each prescribd 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. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12
if all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Lrne
No.
NUmIrer ano I tIIe oT Kare scneouE
(a)
MWn JOIO
(b)
Kevenue
(c)
]\wnPer (Satesstomer F(evenue FerKWh Sold(0
1 440 - Residential Sales:
2 01 - Residential 5,360,99i 535,946,663 477,735 'l't,222 0.1000
1 03 - Residential Master Meter 4,69t 448,435 22 213,40S 0.0955
4 05-Residential -TOD 17,672 1,709,977 1,057 16,71 I 0.0968
E 06 - Residential On-Site Generati 29,144 3,',104,923 5,618 5,188 0.1 065
6 '15 - Dusk to dawn lighting 2,443 632,560 0.2s8s
7 Unbilled Revenues 47,606 6,113,448 0.128/,
8 Other Revenues 857,938
o Total 440 5,462,557 548,813,944 484,432 11,276 0.1005
't0
't1 442-Commercial & lndustrial Sales
12 07 - General service 148,392 18,349,943 31,730 4,677 0.1237
13 08 - General service On-Site Gene 159 20,781 57 2,789 0.1307
14 09P - General service 564,538 35,513,478 268 2,106,485 0.0629
15 09S - General service 3,232,808 232,047,274 36,801 87,846 0.0718
16 09T - General service 6,596 440,977 E 1,319,200 0.0669
17 15 - Dusk to Dawn Light 4,034 734,327 0.1820
18 19P - Uniform rate contracts 2,326,305 't29,2s7,6sC 124 19,385,875 0.0556
1S 19S - Uniform rate contracts 5,417 338,109 1 5,417,000 0.0624
2A 19T - Uniform rate contracts 1 34,1 30 7,828,627 .1 44,710,00C 0.0584
21 24S - lrrigation Pumping 1,987,418 155,954,692 21,535 92,288 0.0785
22 40 - General service 11,771 987,832 1,074 10,96C 0.0839
23 Special Contracts 900,479 43,771,704 .1 300,159,667 0.0486
24 Commercial & lndustrial Unbill 13,469 2,510,875 0.1864
25 Other Revenues -429,805
26 Total 442 9,335,516 627,326,46C 91,597 101 ,91S 0.0672
27
28 444 - Public Street Lighting:
29 40 - General service 793 66,871 479 1,656 0.0843
3C 4'l - Street lighting 26,7s4 3,579,998 2,583 10,358 0.1338
31 42 -Traffic control lighting 2,788 169,242 705 3,955 0.060i
5l Unbilled -148 -8,06€0.0545
)4 Other Revenues 8,488
34 fotal444 30,187 3,816,53:3,767 8,014 o.1264
EE
36
3i
38
ac
4C
41 TOTAL BiIIEd 14,767,33i 1 ,171.340,68(579.79(25,47C 0.0793
42 Total Unbilled Rev.(See lnstr. 6)60,92:8,616,257 (c o.1414
43 TOTAL 14,828,26(1,179,956,93i 579,79(25,57!0.0796
FERC FORM NO. 1 (ED. 12.95)Page 30tf
Name An Original
A Resubmissionldaho Power Company (1)
(2)
Date of Report
(Mo, Da, Yr)
0411412021
Year/Period of Report
End of 2O20lQ4
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 servioe 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 transaclions 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 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)
AveraoeMonthly CPDemanc
(0
,|3 Phases Renewables lnc.SF WSPP nle nla nla
2 ADM lnvestor Services, lnc.WSPP nle nla nla
3 Avangrid Renewables (IBERDROLA)OATT nla nla nla
4 AVANGRID RENEWABLES, LLC SF WSPP nle nla nla
5 Avista Corp.SF WSPP nle nla nla
6 Avista Corp. - WWP Div.OATT nle nla nla
7 Black Hills Power lnc.OATT nle nla nla
8 Black Hills Power lnc.SF WSPP nle nla nla
s Bonneville Power OATT nle nla nla
10 Bonneville Power Adm inisbation SF WSPP nle nla nla
11 BP Energy Company SF WSPP nle nla nla
12 Brookfield Renewable Trading & Marketin OATT ola nla nla
13 Brookfield Renewable Trading and Market SF WSPP nla nla nla
14 Califomia lndependent System Operator SF CAISO nle nla nla
Subtotal RQ c 0 0
Subtotal non-RQ c 0 0
Total 0 0 0
FERC FORlrt NO.1 (ED. 12-90)Page 310
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
0411412021
Year/Period of Report
End of 202OlQ4
SALE,]i FOR RESALE (Account 447
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. 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 fi). 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
NoDemand Charges
($)
(h)
Energy Charges
($)
(i)
Other Charges($)
(i)
262,925 8,596,734 8,s96,734 1
2,172,6ffi 2,',t72,60e 2
5,24C 5,24C 3
12,842 206,021 206,021 4
25,U2 357,916 357,91€5
34€34€6
504 504 7
6,567 60,070 60,070 8
2,521,02C 2,s21,020 I
86,573 1,589,594 1,589,594 10
23,555 1,488,950 1,488,950 11
62,334 62,334 12
6 -6 -E 13
479,125 19,491,674 19,491,674 14
0 0 0 0 0
1,887,139 0 s6,186,463 9,904,208 66,090,671
1,887,139 0 56,186,463 9,90,t,208 66,090,671
FERC FORM NO.1 (ED.12.90)Page 311
Name (1)
(2t
Originalldaho Power Company Resubmission
Date of Report(Mo, Da, Yr)
04t1412021
Year/Period of Report
End of 2O20lQ4
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. ln column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projected load for this service in its system resource planning). ln addition, the reliability of requirements service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be 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 Affi liations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule orTariff Number
(c)
Averaoe
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
'tveraoeMonthly NCP Demanr
(e)
Averaoe
Monthly CP-Demanc
(0
1 Calpine Energy Solutions LLC SF WSPP nla nla nla
2 Chelan Co PUD SF WSPP nle nla nla
3 Clatskanie PUD SF WSPP nla nla nla
4 Clean Power Alliance of Southem Califo SF WSPP nle nla nla
5 Direct Energy Business Marketing, LLC SF WSPP nle nla nla
6 DTE Energy Trading, lnc.SF WSPP nle nla nla
7 EDF Trading North America OATT nle nla nla
8 EDF Trading North America, LLC SF WSPP nle nla nla
I Energy Keepers, lnc SF WSPP nle nla nla
10 Energy Keepers, lnc.OATT nle nla nla
11 Eugene Water & Electric Board SF WSPP nle nla nla
12 Exelon Generation Company, LLC SF WSPP nle nla nla
13 Guzman Energy Group LLC OATT nle nla nla
14 Macquarie Energy LLC OATT nle nla nla
Subtotal RQ c 0 0
Subtotal non-RQ c 0 0
Total 0 0 0
FERC FORM NO. r (ED.12.90)Page 310.1
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
04t14t2021
Year/Period of Report
End of 20201Q4
OS - for other service. use this category only for those services wtrich 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 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 O. 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
4O1,iine24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours
Sold
(s)
REVENUE Total
(h+i
($)
+i)
(k)
Line
No.Demand Charges
($)
(h)
Energy Charges
($)
(i)
Other Charges
($)
(i)
1,389 23,516 23,s16 1
2,066 35,867 35,86i 2
383 6,069 6,06S 3
160,200 5,822,742 5,822,742 4
128,'150 3,276,033 3,276,033 5
645 24,641 24,641 6
1,547 1,547 7
507 10,493 10,493 8
10,400 205,920 20s,924 o
15,45€15,456 10
2,082 45,676 45,676 11
40 800 800 't2
21!215 13
1,30t 1,305 14
0 0 0 0 0
1,887,139 0 56,186,463 9,904,208 66,090,671
1,887,139 0 56,186,463 9,904,208 66,090,671
FERC FORM NO. I (ED.12-90)Page 311'l
Name (1)
(2)
An Original
A Resubmissionldaho Power Company
Date of ReDort(Mo, Da, Yi)
o4t14t2021
Year/Period of Report
End of 2O2O|Q4
1. Report all sales for resale (i.e., sales to purchasers other than ultimate eonsumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricig ( 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 resouroe 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
eadiest 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-tenn 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, mrjst 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 "intermediat+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 Billins
Demand (MW)
(d)
Actual Demand (MW)
AVeraoeMonthly NCF Demanr
(e)
AveraoeMonthly CPDemanc
(f)
1 Macquarie Energy LLC SF WSPP nle nla nla
2 MAG Energy Solutions OATT nle nla nla
3 Mercuria Energy America, LLC OATT nla nla nla
4 Morgan Stanley Capital Group lnc.OATT nle nla nla
5 Morgan Stanley Capital Group lnc.WSPP nle nla nla
6 Morgan Stanley Capital Group lnc.SF ISDA nle nla nla
7 Nevada Poler OATT nle nla nla
I Nevada Porer Company, dba NV Energy SF WSPP nle nla nla
I NextEra Energy Marketing, LLC SF WSPP nla nla nla
10 NorthWestem Energy SF WSPP nlz nla nla
11 PacifiCorp T-7 nla nla nla
12 PacifiCorp SF WSPP nle nla nla
't3 PacifiCorp lnc.OATT nla nla nla
14 Portland General Electric Company OATT nle 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 310.2
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report
(Mo, Da, Yr)
0411412021
Year/Period of Report
End of 2O20lQ4
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. Afier 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 (j). Explain in a footnote all components of the amount shown in column O. 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 RCUNon-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.
MegaWaft Hours
Sold
(o)
REVENUE Totar ($)
(h+i+j)
(k)
Line
No.Demand Charges
($)
(h)
Energy Charges
($)
(i)
other charges
($)
(i)
19,200 340,104 340,104 1
17,582 't7,582 2
4,361 4,361 3
1,277,607 1,277,607 4
35 175 175 5
7,552 70,763 70,761 6
654 654 7
3,395 524,580 524,58C I
184 500 50c I
8,943 158,784 158,784 10
2U 5,64C 5,64(1',l
64,679 564,718 564,71t 12
2,697,691 2,697,691 13
7,995 7,S95 14
0 0 0 0 0
1,887, t 39 0 56,186,463 9,904,208 66,090,671
'1,887,139 0 56,186,/t63 9,904,208 66,090,671
FERC FORM NO. 1 (ED.12.90)Page 311.2
of Respondent An Original
A Resubmissionldaho Power Company
(1)
(2t
Date of ReDort
(Mo, Da, Yi)
04t14t2021
Year/Period of Report
End of 20201Q4
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{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.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract,
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 Affi liations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule orTariff Number
(c)
Averaoe
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
Monthiy NCF-oeman
(e)
AveraoeMonthly CP-Demand
(0
1 Portland General Electric Company SF WSPP nla nle nla
2 Powerex Corp.OATT nla nle nla
3 Powerex Corp.SF WSPP nla nle nla
4 Puget Sound Energy, lnc.SF WSPP nla nle nla
5 Rainbow Energy Marketing Corporation OATT nla nle nla
6 Rainbow Energy Marketing Corporation SF WSPP nla nle nla
7 Seattle City Light SF WSPP nla nle nla
8 Shell Energy North America (US), L.P OATT nla nle nla
9 Shell Energy North America (US), L.P SF WSPP nla nle nla
10 Siena Pacific Power Co., dba NV Energy T-7 nla nle nla
11 Siena Pacific Power Co., dba NV Energy WSPP nla nle nla
12 Snohomish County PUD SF WSPP nla nle nla
13 Tacoma Power SF WSPP nla nle nla
14 TEC Energy lnc.OATT nla nle 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 Reoort(Mo, Da, Yi)
04t14t2021
Year/Period of Report
End of 20201Q4
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. Repo( 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 O. Explain in a footnote all components of the amount shown in column O. 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
40'1 , 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)
47,607 573,953 573,953 1
321,91t 321,918 2
6,1 93 52,579 52,579 3
14,401 304,191 304,191 4
59,18:59,183 5
20,430 220,576 220,576 b
33,24'.1 512,091 512,091 7
558,60€558,606 8
203,834 3,325,003 3,325,003 I
5 8t 85 10
239 1 1,55!11,553 11
't,120 21,869 21,869 12
3,103 55,744 55,744 13
OJ DJ 14
0 0 0 0 0
1,887,139 0 56,186,463 9,904,208 66,090,671
1,887,139 0 56,186,463 9,904,208 66,090,671
FERC FORM NO. 1 (ED. 12.90)Page 311'3
ldaho Power Company (1)
(2)
An Original
A Resubmission 04t14t2021
Year/Period of Report
End of 20201Q4
1 . Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. ln column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projected load for this service in its system resource planning). ln addition, the reliability of requirements service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five yearc or Longer and "firm" means that service cannot be intenupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.9., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contracl 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 availabilig 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)
AveraoeMonthly NCP Deman,
(e)
Averaoe
Monthly CPDemand
(0
1 Tenaska Power Services Co.OATT nla nla nla
2 Tenaska Power Services Co.SF WSPP nla nla nla
3 The Energy Authority, lnc.OATT nla nla nla
4 The Energy Authority, lnc.SF WSPP nla nla nla
5 TransAlta Energy Marketing (U.S.) lnc.OATT nla nla nla
6 TransAlta Energy Marketing (U.S.) lnc.SF WSPP nla nla nla
7 Transmission Penalty Distribution nla nla nla
8 Utah Associated Municipal Power Systems OATT nle nla nla
9 Utah Associated Municipal Power Systems SF WSPP nle nla nla
't0 Vitol lnc.OATT nle nla nla
11 Westem Area Power Administration (WAC 1-7 nle nla nla
12 Western Area Power Administration (WAC WSPP nla nla nla
13
14
Subtotal RQ c 0 0
Subtotal non-RQ (0 0
Total 0 0 0
FERC FORM NO.1 (ED. 12.90)Page 310.4
ldaho Power Company (1)
(2)
Original
Resubmission
Date of Reoort(Mo, Da, Yi)
ofit14t2021
Year/Period of Report
End of 2O2O|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. EnternTotal" 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 (i). Explain in a footnote all components of the amount shown in column O. 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
($)
(h)
Energy Gharges
($)
(i)
Other Charges
($)
fi)
3,584 3,584 1
16,316 219,822 219,822 2
7,502 7,502 3
182,249 6,732,946 6,732,9,10 4
118,452 118,452 5
18,938 393,349 393,34S 6
21,451 21,4s5 7
13t 136 I
31,740 872,180 872,18C 9
720 72C 10
't11 5,336 5,336 11
93 3,334 3,334 12
13
14
0 0 0 0 0
1,887,139 0 56,186,463 9,904,208 66,090,671
1,887,139 0 56,186,'[63 9,904,208 66,090,671
FERC FORM NO. 1 (ED. 12.90)Page 31'1.4
Name of Respondent
ldaho Power Company
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t'14t2021
Year/Period of Report
20201Q4
FOOTNOTE DATA
310 Line No.:3 Column: b
310 Line No.: 2
ADM Investor Se ces Inc Futures Account Document E 20]-5
c 1 ss on LoSSeS310 Line No.:6 Column: bIsson Losses
310 Line No.:7 Column: b
ss on Losses
310 Line No.:9 Column: b
ss on Losses
310 Line No.: 12 Column: b
ss on Losses
310.1 Line No.:7 Column: bFinancial Transmiss on Losses
Schedule Paoe:310.1 Line No.: 10 Column: bFinancial Transmission Losses
310.1 Line No.: 13 Column: b
1 ss on Losses
310.1 Line No.: 14 Column: b
1 ss on Losses
310.2 Line No.:2 Column: b
1 ss on Losses
310.2 Line No.:3 Column: b
ss On LOSSeS
310.2 Line No.:4 Column: b
ss on Losses
310.2 Line No.: 5 Column: b
Non-rm es
310.2 Line No.:7 Column: b
ssion Losses
or Reserves
Financial Transmiss on Losses
310.2 Line No.: 11 Column: b
310.2 Line No.: 13 Column: b
310.2 Line No.: 14 Column: b
310.3 Line No.:2 Column: b
1 on IJOSSeS
F 1 Trans SS on Losses
9cneaub Page: 910.3 Line N i O -- -- - 1Financi-a1 Transmission Losses
F nanc Trans SS on Losses
or Reserwes
or Reserves
F nanc Transm ss on LoSSeS
310.3 Line No.:8 Column: b
Line No.: 10
Line No.: 11
Column: b
Column: b
310.3
310.3
9chedule Pase: 310.3 Line No.:14 Column: b
310.4 Line No.: I Column: b
Financi Transm ssion Losses
310.4 Line No.:3 Column: b
Financi Transmiss on Losses
310.4 Line No.: 5 Column: b
F nanc al Transm ion Losses
FERC FORM NO. 1 (ED. 12-871 Page 450.'l
Name of Respondent
ldaho Power Company
This Report is:
(1) X An OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
04t14t2021
Year/Period of Report
2020to,4
FOOTNOTE DATA
310.4 Line No.:7 Column: b
310.1 Line It onc ts
F 1 Losses
310.4 Line No.:10 Column: b
F 1 Losses
Schedule Pase: 310.1 Line No.: 11 Column: brinning or Operatin
Scfiedule Pase:310.4 Line No.:12 Column: b
Reserwes
or Operat Reserves
FERC FORi' NO.1 (ED. 12-871 Pase 450.2
of Respondent
ldaho Power Company
(1)
(2t
An Original
A Resubmission o4t14t2021
Year/Period of Report
End of 2O20lQ4
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 brPrevious Year(c)
1 1. POWER PRODUCTION EXPENSES
2 A. Steam Power Generation
3 Ooeration
4 (5fi)) Ooeration Suoervision and Enoineerino 1.423.007 1,533,140
5 (501) Fuel 119,677,855 105,256.975
6 (502)Steam Exoenses 9.790.106 't0.783.230
7 (503) Steam ftom Other Sources
8 (Less) (504) Steam Transfened-Cr
I (505) Electric Expenses 1,754,1M 1.894.278
10 (506) Miscellaneous Steam Power Et@enses 9.778.684 9.195.043
1',|(50il Rents 220.267 224.649
12 (509) Allowances
13 TOTAL Operation (Enter Total of Lines 4 thru 12)142,644.63 128.887,315
14 Maintenance
15 (51 0) Maintenance Suoervision and Ensineerinq 9.350 139.168
16 (51 1) Maintenance of Structures 383.245 29s.201
17 {512) Maintenance of Boiler Plant 8.491.253 10,532,166
t8 (513) Maintenance of Electric Plant 3.148.003 4.078.463
19 (514) Maintenance of Miscellaneous Steam Plant 3.s97.407 6.024.870
20 TOTAL Maintenance (Enter Total of Lines 15 thru 19)15.629.2s8 21.063.868
21 TOTAL Power Production ExDens€s-Steam Power (Entr Tot lines 13 & 20)158.273.321 149,957,183
22 B. Nuclear Power Generation
23 Operation
24 (51il Ooeration Suoervision and Enqineerinq
25 (518) Fuel
26 (519) Coolants and Water
27 (520) Steam Expenses
28 (521) Steam ftom Other Sources
29 (Less) (522) Steam Transfened-Cr
30 (523) Electric Exoenses
31 (524) Miscellaneous Nuclear Power Expenses
32 (525) Rents
33 TOTAL Op€ration (Enter Total of lines 24 thru 32)u Maintenance
35 (528) Maintenance Suoervision and Enoineerino
36 (529) Maintenance of Struc{ures
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 Eloenses-Nuc. Pow€r (Entrtot lines 33 & 40)
42 C. Hydraulic Power Generation
43 Operation
44 (535) Ooeration Suoervision and Enoineerino 5.840.433 5.775.19C
45 (536) Water for Power 6,916,183 6,626,2s6
46 (537) Hvdraulic Exoenses 14.95s.630 14.697.1a2
47 (538) Electric Expenses 1 2,049.374
48 (539) Miscellaneous Hydraulic Power Generation Expenses 5,798.44S
49 (540) Rents 257 252,726
50 TOTAL Operation (Enter Total of Lines 44 thru 49)35.199.177
51 C. Hvdraulic Power Generation (Continued)
52 Maintenance
53 (541) Mainentance Supervision and Engineering 211,923 't34,465
54 (542) Maintenance of Structures 701,385 646.148
55 (543) Maintenance of Reservoirs. Dams, and Wateruavs 427,177 633.585
56 (544) Maintenance of Electric Plant 2.507.845 2.369.2s4
57 (545) Maintenance of Miscellaneous Hydraulic Plant 2.804.30S
58 TOTAL Maintenance (Enter Total of lines 53 thru 57)6.865.137 6,587,761
59 TOTAL Power Production Expenses-Hydraulic Power (tot of lines 50 & 58)41.870.224 41,786.938
FERC FORil NO. r (ED.12-93)Page 320
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5]Rn Originat
(21 ;lA Resubmission
Date of Reoort(Mo, Da, Yi)
04t1412021
Year/Period of Report
End of 2O20lQ4
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)
60 D. Other Power Generation
61 Ooeration
62 (546) Ooeration Suoervision and Enoineerino 673,850 671.349
63 (54D Fuel 53,062,458 51.615.143
64 (548) Generation Expenses 4,617,761 4,39s,345
65 (549) Miscellaneous Other Power Generation Expenses 839,793 633.622
66 (550) Rents
67 TOTAL Operation (Enter Total of lines 62 thru 66)59,193,862 57.315.459
68 Maintenance
69 (551 ) Maintenance Supervision and Enqineerinq
70 (552) Maintenance of Structures 174,834 207,999
7',\(553) Maintenance of Generatino and Electric Plant 135,593 260.734
72 (554) Maintenance of Miscellaneous Other Power Generation Plant 1,865,786 2.840.749
73 TOTAL Maintenance (Enter Total of lines 69 thru 72)2,176,2'.t3 3,309,482
74 TOTAL Power Production Expenses-Other Power (Enter Tot of 67 & 73)61 60.624,941
75 E. Other Power Suoolv Exoenses
76 (555) Purchased Power 292 280.320.697
77 (556) System Control and Load Dispatchins 6,313 4.948
78 (557) Other Expenses -28,389.336 6,759.64S
79 TOTAL Other Power Supplv Exp (Enter Total of lines 76 thru 78)264.526.834 287.085.294
80 TOTAL Power Production Exoenses ffotal of lines 21.41.59.74 &791 s26.040.454 539.454.356
81 2. TRANSMISSION EXPENSES
82 Operation
83 (560) Operation Supervision and Enqineerinq 2,861,348 3,163,972
84
85 (561. 1 ) Load DisDatch-Reliabilitv 't9.380 22.832
86 (561.2) Load Dispatch-Monitor and Operate Transmission System 2,732,930 2.389.656
87 (561.3) Load Dispatch-Transmission Service and Schedulins 995,649 1,042,766
88 (561.4) Scheduling, System Control and Dispatch Services 9,834 9.944
89 (56'1.5) Reliability, Plannins and Standards Development
90 (561.6) Transmission Service Studies 3,416
91 (561.7) Generation lnterconnection Studies 41,502 30,393
92 (561.8) Reliability. Planninq and Standards Develooment Services 1.054.598 2.001.275
93 (562) Station Exoenses 2.782.705 2.816.318
94 (563) Overhead Lines Expenses 884,293 896.240
s5 (564) Underground Lines Expenses
96 (565) Transmission of Electricitv bv Others 4.027.56 2.844.842
97 (566) Miscellaneous Transmission Expenses 1.000.000
98 (567) Rents 4.011.443 3.934.696
99 TOTAL Ooeration (Enter Total of lines 83 thru 98)20.424.684 19.'ts2.934
100 Maintenance
101 (568) Maintenance Supervision and Enqineerinq 153,823 40,993
102 (569) Maintenance of Structures
103 (569.1) Maintenance of Comouter Hardware 34.9'10
104 (569.2) Maintenance of Comouter Software 1,300,103 1.176.214
105 (569.3) Maintenance of Communication Equipment 24,014 16,080
106 (569.4) Maintenance of Miscellaneous Reoional Transmission Plant
107 (570) Maintenance of Station Equipment 1.862,9s9 1,616,13i
108 (571) Maintenance of Overhead Lines 1.437.562 991.062
109 (572) Maintenance of Underoround Lines
110 (573) Maintenance of Miscellaneous Transmission Plant 486 47C
111 TOTAL Maintenance (Total of lines 101 thru 110)4,814,604 3,793,88C
112 TOTAL Transmission Expenses (Total of lines 99 and 1 1 1)25.239.288 22.946.814
FERC FORM NO. r (ED.12-93)Page 321
1 (Mo, Da,ldaho Porer Company (2)A Resubmission o4t14t2021
Year/Period of Report
End of 20201Q4
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 brPrevious YEar(c)
113 3. REGIONAL MARKET EXPENSES
114 Operation
115 (575.'l ) Operation Supervision
116 (575.2) Dav-Ahead and Real-Time Market Facilitation
117 (575.3) Transmission Riohts Market Facilitation
118 (575.4) Capacity Market Facilitation
119 (575.5) Ancillarv Services Market Facilitation
120 (575.6) Market Monitorinq and Compliance
121 (575.7) Market Facilitation. Monitorino and Comoliance Services 515.586 611.254
122 (575.8) Rents
123 Total Operation (Lines 115 thu122)515,586 611,254
124 Maintenance
125 (576.'t) Maintenance of Structures and lmprovements
126 (576.2) Maintenance of Comouter Hardware
127 (576.3) Maintenance of Computer Software
128 (576.4) Maintenance of Communication Equipment
129 (576.5) Maintenance of Miscellaneous Market Ooeration Plant
130 Total Maintenance (Lines 125 thru 129)
13't TOTAL Regional Transmission and Market Op Epns (Total 123 and 130)s15,586 611,254
132 4. DISTRIBUTION E)(PENSES
133 Operation
1U (580) Ooeration Suoervision and Enoineerino 4.070.045 4.38s.764
13s (581 ) Load DisDatchino 4.963.433 4,529,601
't36 (582) Station Expenses 't.671.271 1,601.059
137 (583) Overhead Line Expenses 4.236.429 4.095.135
138 (584) Underqround Line Exoenses 4.293.014 3.628.04'l
't39 (585) Street Liohtino and Sional Svstem Exoenses 8.448 61.704
140 (586) Meter Expenses 4,608,642 4,402,350
141 (587) Customer lnstallations Eloenses 1.022.228 1.231.750
142 (588) Miscellaneous Exoenses 4.135.289 4.492.746
143 (589) Rents 329.158 332.74
144 TOTAL Ooeration (Enter Total of lines 134 thru 143)29.337.S63 28.760.914
14s Maintenance
146 (590) Maintenance Suoervision and Enqineerino 14,730 -274.492
147 (59'l) Maintenance of Structures 68.8s0
148 (592) Maintenance of Station Eouioment 3.827.943 4.143.359
149 (593) Maintenance of Overhead Lines 15,988,062 16,936,900
't50 (594) Maintenance of Underqround Lines 533,170 726,528
1sl (595) Maintenance of Line Transformers 48,699 51,099
152 (596) Maintenance of Street Liohtino and Sional Svstems 270.062 260.970
153 (597) Maintenance of Meters 839.202 910.486
1il (598) Maintenance of Miscellaneous Distribution Plant 139,835 198,923
155 TOTAL Maintenance (Total of lines 146 thru 154)21,661.703 23.022.623
156 TOTAL Distribution ExDenses ffotal of lines 1,{4 and 155)50.999.666 51.783.537
157 5. CUSTOMER ACCOUNTS EXPENSES
158 Operation
159 (901) Suoervision 719.969 941.128
160 (902) Meter Readins E)oenses 1,962,900 1,801,856
161 (903) Customer Records and Collection Expenses 14.723,735 13,233.844
162 (904) Uncollectible Accounts 5.224.630 2.249.077
163 (905) Miscellaneous Customer Accounts ExDenses 130 114
164 TOTAL Customer Accounts Exoenses fiotal of lines 159 thru 163)22.631.#4 18.226.O19
FERC FORm r{O.1 (ED.12-93)Page322
Name of Respondent
ldaho Power Company
This Reoort ls:(1) E]An orisinal(2) nA Resubmission
Date of Reoort(Mo, Da, Yi)
o4t't4t202'l
Year/Period of Report
End of 2O2O|Q4
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 Ooeration
167 (907) Supervision 727.173 786.744
't68 (908) Customer Assistanc€ Expenses 49,413,907 47,188,829
169 (909) lnformational and lnstructional ExDenses 2Wi,792 165,868
170 (910) Miscellaneous Customer Service and lnformational Expenses 737,634 619,951
171 TOTAL Customer Service and lnformation Exoenses fiotal 167 thru 170)51.1 75.506 48.761.392
172 7. SALES EXPENSES
173 Operation
174 (91 1) Supervision
175 (912) Demonstratino and Sellino Exoenses
't76 (9131 Advertisino Eroenses
177 (916) Miscellaneous Sales Expenses
178 TOTAL Sales Expenses (Enter Total of lines 174 thru 177)
'179 8. ADMINISTRATIVE AND GENERAL EXPENSES
180 Ooeration
181 (920) Administrative and General Salaries 86.989.18't 89.843.262
182 (921 ) Office Supplies and Expenses I 3.634,146 14.655.584
183 (Less) (922) Administrative Expenses Transfened-Credit 29.768,610 33,154,579
184 (923) Outside Services Emploved 6.803.893 9.431.043
185 (924) Prooertv lnsurance 4.10s.815 3.437.586
186 (925) lniuries and Damaoes 6.029.651 5.349.936
187 (926) Emoloyee Pensions and Benefits 48.877,499 52,072,747
188 (92il Franchise Reouirements
189 (928) Reoulatory Commission Expenses 5,320.883
190 (929) (Less) Duolicate Charoes-Cr
191 (930.1 ) General Advertisino Er<oenses 168.222 46.762
192 (930.2) Miscellaneous General Expenses 3.634.788
193 (931 ) Rents
194 TOTAL Operation (Enter Total of lines 181 thru 193)146,462,353 150,638,018
195 Maintenance
196 (935) Maintenance of General Plant 7.451.927 7.238.346
197 TOTAL Administrative & General Exoenses fiotal of lines 194 and 196)1s3.914.280 157.876.364
198 TOTAL Elec Oo and Maint Exons (Total 80.112.131.156.164.17'1.178.1971 830.516.144 839.659.736
FERC FORM NO.1 (ED. 12-93)Page 323
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
04114t2021
Year/Period of Report
End of 20201Q4
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 servioe in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.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
servioe, 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 (MW)
Average
Monthly NCP Demanr
(e)
AVerage
Monthly CP Demand
(0
1 American Falls Solar, LLC LU N/A N/A N/A
2 American Falls Solar ll, LLC LU N/A N/A N/A
3 Allan Ravenscroft/Malad River LU N/A N/A N/A
4 Baker City Hydro LU N/A N/A N/A
5 Bannock County, ldaho LU N/A N/A N/A
6 Bennett Creek Wind Farm LU N/A N/A N/A
7 Benson Creek Wind Farm LU N/A N/A N/A
8 Bettencourt DryCreek Biofactory LU N/A N/A N/A
I Big Sky West Dairy Digester LU N/A N/A N/A
10 Black Canyon Bliss LU N/A N/A N/A
11 Blind Canyon Hydro LU N/A N/A N/A
12 Branchflower - Trout Company LU N/A N/A N/A
13 Burley Bufte Wind Park LU N/A N/A N/A
14 CAFCO ldaho Refuse Management LLC - Sl LU N/A N/A N/A
Total
FERC FORM NO. I (ED.12-90)Page 326
ldaho Power Company (1)
(2)
Original
Resubmission
Date of ReDort
(Mo, Da, Yi)
o4t14t2021
Year/Period of Report
End of 2O20lQ4
AD - for outof-period adjustment. Use this code for any acoounting 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 wtrich 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 olumn (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column O, energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (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 ensrgy 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 reguired and provide explanations following all required data.
Megawatt Hours
Purchased
6)
POWER EXCHANGES GOST/SETTLEMENT OF POWER Line
No.Megawatt Hours
Received(h)
Megawatt Hours
Delivered
(D
uemand charges
($)
U)
Energy Charges
fll
other charges
($)
(t)
Total (i+k+l)
of Settlement ($)
(m)
46,66r 1,452,251 1,452,247 1
47,62(1,357,44e 1,357,437 2
2,14i,122,794 't22,794 3
25t 16,68:16,683 4
1 1,58i 772,57i 772,577 5
41,175 2,877,6*2.877,6fi 6
28,205 1,740,88(1,740,880 7
6,237 337,54:337,542 8
8,93t 644,15t 6,t4,158 I
201 7,30t 7,308 't0
5,18i 289,96t 289,968 11
792 56,08:56,083 12
62,60(3,973,83!3,973,839 't3
17,664 624,811 624,811 14
5,057,577 67,U7 1M,67',!282,392,22A 10,s17,63i 292,909,85i
FERC FORM NO. r (ED.12-90)Page 327
ldaho Power Company (1)
(2\
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
0411412021
Year/Period of Report
End of 20201Q4
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. ln column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). ln addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be Interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.9., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
lF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for sho(-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.
Iine
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
AVerage
Monthly NCP Deman
(e)
AVerage
Monthly CP Demanc
(f)
1 Camp Reed Wind Park LU N/A N/A N/A
2 Cassia Wind Farm LLC LU N/A N/A N/A
3 CCP OR Tenant 1, LLC
4 Grove Solar Center, LLC LU N/A N/A N/A
5 Hyline Solar Center, LLC LU N/A N/A N/A
6 Open Range Solar Center, LLC LU N/A N/A N/A
7 Railroad Solar Center, LLC LU N/A N/A N/A
I Thunderegg Solar Center, LLC LU N/A N/A N/A
I Vale Air Solar Center, LLC LU N/A N/A N/A
10 Central Rivers Power US LLC
11 Barber Dam LU N/A N/A N/A
12 Dietrich Drop LU N/A N/A N/A
13 Lowline #2 LU N/A N/A N/A
14 City of Hailey LU N/A N/A N/A
Total
FERC FORM NO.1 (ED. 12-90)Page 326.1
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Reoort(Mo, Da, Yi)
0411412021
Year/Period of Report
End of 20201Q4
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 (6Gminute 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
NoMegawatt Hours
Received
(h)
Megawatt Hours
Delivered
(i)
Demand uharges
(8i
Energy Charges
fil
omer uharges
($)
(t)
lotal 0+K+lof Seftlement
(m)
)($)
69,69(5,848,95l 5,848,954 1
18,971 1,173,46i 1,173,461 2
3
13,461 894,50€894,50t 4
20,281 1,348,574 1,348,574 5
22,76t 1,5',14,28C 1,514,281 6
10,091 670,26e 670,26t 7
22,52r 1,495,191 1,495,191 8
22,32!1,488,01i 1,488,017 I
10
4,852 244,Bst 2M,850 11
15,031 822,53i 822,533 't2
77 4,562 2,366 13
94 5,824 5,824 14
5,057,577 67,U7 1M,671 282,392,22C 10,517,637 292,909,85i
FERC FORM NO.1 (ED.12-90)Page 327.1
Name of Respondent
ldaho Power Company
(1)
(2)
Original
A Resubmission
Date of Reoort(Mo, Da, Yi)
04t14t202',1
Year/Period of Report
End of 20201Q4
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 servioe is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). ln addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.9., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
lF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long{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 Afliliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
AVerage
Monthly NCP Demanr
(e)
Average
Monthly CP Demand
(0
1 City of Pocatello LU N/A N/A N/A
2 Clear Springs Food lnc.LU N/A N/A N/A
3 Clifton E. Jenson - Birch Creek LU N/A N/A N/A
4 Cold Springs Windfarm LU N/A N/A N/A
5 College of Southem ldaho - Pristine S LU N/A N/A N/A
6 College of Southem ldaho - Pristine S LU N/A N/A N/A
7 Crystal Springs LU N/A N/A N/A
8 Curry Cattle Company LU N/A N/A N/A
I Cycle Horseshoe Bend Wind, LLC LU N/A N/A N/A
10 David R Snedigar LU N/A N/A N/A
11 Desert Meadow Windfarm LU N/A N/A N/A
12 Durbin Creek Windfarm LU N/A N/A N/A
13 Eightmile Hydro Project LU N/A N/A N/A
14 Enerparc Solar Development LLC
Total
FERC FORM NO.1 (ED.12-90)Page 326.2
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Reoort(Mo, Da, Yi)
o4114t2021
Year/Period of Report
End of 2O2O|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, tarffis 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
outof-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 COSI/SEITLEMENI OF POWER Line
No.Megawatt Hours
Received(h)
Megawatt Hours
Delivered
(i)
Demand Charges
($)
0)
hnergy charges
tt)
otrler uharges
t?l
Iotal u+l(+l)of Settlement ($)
(m)
1,661 121,70"121,702 1
3,11(200,42i 200,427 2
36(20,17t 20,174 3
50,921 4,109,36(4,109,366 4
731,44,29(44,29C 5
't,61(92,59(92,59C 6
11,771 798,01/798,014 7
76t 63,091 63,09i 8
22,MI 1,432,161 1,432,161 I
1,65(81,1 9;81,19i 10
57,741 4,68s,96:4,685,963 1'.l
24,78i,1,529,78(1,529,78C 12
1,483 86,41(86,41C 13
14
5,057,577 67,347 144,671 282,392,22(10,517,63i 292,909,85i
FERC FORM NO. r (ED.12-90)Page 327.2
Name of Respondent
ldaho Power Company
s:
(1)
(2)
An Original
A Resubmission
Date of ReDort
(Mo, Da, Yi)
04114t2021
Year/Period of Report
End of 20201Q.4
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 seMce to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be intemrpted for
economic reasons and is intended to remain reliable even under adverse conditions (e.9., the supplier must attempt to buy emergency
energy from third paffes 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 servics. 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 (MW)
Average
Monthly NCP Demanr
(e)
Average
Monthly CP Demand
(0
1 Baker Solar Center LU N/A N/A N/A
2 Brush Solar LU N/A N/A N/A
3 Morgan Solar LU N/A N/A N/A
4 Ontario Solar Center LU N/A N/A N/A
5 Vale I Solar LU N/A N/A N/A
6 Faulkner Ranch LU N/A N/A N/A
7 Fisheries Development LU N/A N/A N/A
I Fossil Gulch Wind LU N/A N/A N/A
I G2 Energy Hidden Hollow LU N/A N/A N/A
10 Golden Valley Wind Park LU N/A N/A N/A
't'l Grand Mew PV Solar Two LU N/A N/A N/A
't2 Hammett Hill Windfarm LU N/A N/A N/A
13 Hazelton B N/A N/A N/A
14 High Mesa Wind Project LU N/A N/A N/A
Total
FERC FORM NO. 1 (ED. 12-90)Page 326.3
Name of Respondent
ldaho Power Company (1)
(21
An Original
A Resubmission
Da
04t'14t2021
Year/Period of Report
End of 2O2O|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 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 EXCHANGES COST/SETTLEMENT OF POWER Line
No.Megawatt Hours
Received
(h)
Megawatt Hours
Delivered(i)
Demand Charges
,8i
Energy Charges
8]
other charges
($)
(t)
Total U+k+l)of Settlement ($)
(m)
30,85t 992,33{992,326 1
6,05t 163,17i 163,172 2
5,171 144,90i 144,907 3
5,59(139,40t 139,408 4
2,67e 81,65(81,65C 5
3,584 277,851 277,852 6
48t 7,59t 7,595 7
27,352 1,746,531 1,746,526 8
25,994 1,846,16t 1,846,16s I
33,17(2,102,36(2,102,360 10
186,33t 10,347,59t 10,347,596 '11
57,71i 4,660,202 4,660,202 12
26,'.t4t 1,811 ,75t 1,81 1 ,755 13
96,314 5,285,54(5,285,549 't4
5,057,577 67,347 144,671 282,392,22C 10,517,637 292,909,85'.i
FERC FORM NO.1 (ED.12-90)Page 327.3
Name Respondent (1)
(2)
An Original
A Resubmissionldaho Power Company
Date of ReDort
(Mo, Da, Yi)
0411412021
Year/Period of Report
End of 20201Q4
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 supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.9., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
lF - for intermediate.term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for intermediate.term service from a designated generating unit. The same as LU service expect that "intermediate.term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
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)
Average
Monthly CP Demanc
(0
1 H.K. Hydro Mud Creek S & S LU N/A N/A N/A
2 Horseshoe Bend Hydro LU N/A N/A N/A
3 Hot Springs Wind Farm LU N/A N/A N/A
4 Hydroland
5 Elk Creek LU N/A N/A N/A
6 Rock Creek #2 LU N/A N/A N/A
7 lD Solar 1 LU N/A N/A N/A
8 ldaho Winds - Sawtooth Wind Project LU N/A N/A N/A
I J R Simplot Co.LU N/A N/A N/A
10 J.M. Miller/Sahko Hydro LU N/A N/A N/A
11 Jett Creek Windfarm LU N/A N/A N/A
't2 John R LeMoyne LU N/A N/A N/A
13 Kootenai Electric Cooperative - Fighti LU N/A N/A N/A
14 Koosh lnc. Geo Bon #2 LU N/A N/A N/A
Total
FERC FORM NO.1 (ED. 12-90)Page 326.4
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of ReDort(Mo, Da, Yi)
o411412021
Year/Period of Report
End of 2O2O|Q4
AD - for outof-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. Repo( 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 charyes in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. lf more energy was delivered than received, enter a negative amount. lf the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWaft Hours
Purchased
(s)
POWER EXCHANGES COST/SETTLEMENT OF POWER Line
No.Megawatt Hours
Received(h)
Megawatt Hours
Delivered(i)
Demand Charges
t}t
Energy Uharges
t[l
other charges
($)
(t)
Iotal u+l(+lof Settlement
(m)
)($)
1,72C 105,38€105,38€1
42,191 3,038,35(3,038,35(2
37,314 2,628,131 2,628,131 3
4
60(52,402 52,402 5
4,621 260,25(53,374 6
94,43f 3,995,777 3,995,76(7
57,991 5,232,304 5,232,304 8
52,8'.t1 2,680,727 2,680,71t I
1,38!125,39!125,39t 10
26,424 1,6s0,1 17 1,650,1 17 11
64'1 37,779 37,775 12
15,18t 1,322,81t 1,322,81t 13
3,85:287,68i 287,684 't4
5,057,577 67,U7 144,671 282,392,224 10,517,63i 292,909,857
FERC FORM NO. r (ED. 12-90)Page 327.1
ldaho Power Company (1)
(2)
Original
Resubmission 04t14t2021
Year/Period of Report
End of 20201Q4
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. ln column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). ln addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.9., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
lF - for intermediate.term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
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 (MW)
Average
Monthly NCP Deman
(e)
AVerage
Monthly CP Demanc
(0
1 Koyle Small Hydro LU N/A N/A N/A
2 Lateral #10 LU N/A N/A N/A
3 Lemhi Hydro Power Co.- Schaffner LU N/A N/A N/A
4 Lime Wind Energy LU N/A N/A N/A
5 Liftle Mac Power Co./Cedar Draw LU N/A N/A N/A
6 Little Wood River lnigation District LU N/A N/A N/A
7 Mainline Windfarm LU N/A N/A N/A
8 Marco Ranches LU N/A N/A N/A
I Marysville Hydro Partners- Falls River N/A N/A N/A
10 McCollum Enterprises -Canyon Springs LU N/A N/A N/A
11 Milner Dam Wind Park LU N/A N/A N/A
12 Mountain Home Solar l, LLC LU N/A N/A N/A
13 Mud Creek White Hydro, lnc LU N/A N/A N/A
14 Murphy Flat Power, LLC LU N/A N/A N/A
Total
FERC FORM NO.1 (ED.12-90)Page 326.5
Name of Respondent
ldaho Power Company (1)
(21
An Original
A Resubmission
Date of Reoort(Mo, Da, Yi)
04t1412021
Year/Period of Report
End of 20201Q4
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 eplumns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column O, energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (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 EXGHANGES COST/SETTLEMENT OF POWER Line
No.Megawatt Hours
Received
(h)
Megawatt Hours
Delivered(i)
Demand Gharges
($)
0)
Energy Charges
fil
Other Gharges
($)
(t)
Total (l+1+1;
of Settlement ($)
(m)
3,61(202,tfic 202,960 1
7,70!396,17i 396,'t77 2
1,421 't 08,32i 108,321 3
5,19€420,76i 420,763 4
6,32!348,68!348,689 5
2,82C 72,'.t19 72,',t19 6
56,53'4,565,431 4,56s,431 7
3,1 3C 206,663 206,663 8
47,47C 3,184,03'3,1 84,032 I
651 41,321 41,325 10
58,94(3,726,403 3,726,403 11
50,831 1,786,54(1,786,538 12
53C 35,564 35,564 13
45,892 1,419,251 1,419,243 't4
5,057,577 67,U7 144,671 282,392,22A 10,517,637 292,909,85i
FERC FORM NO.1 (ED.12.90)Page 327.5
ldaho Power Company (1)
(2)
Original
Resubmission
Date of ReDort(Mo, Da, Yi)
04t14t2021
Year/Period of Report
End of 2O20lQ4
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 p@ects load for this servioe in its system resource planning). ln addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be intenupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.9., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the 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 expecl 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 (MW)
Average
Monthly NCP Deman,
(e)
Average
Monthly CP Demand
(0
1 New Energy One - Rock Creek Dairy LU N/A N/A N/A
2 North Gooding Main Hydro LU N/A N/A N/A
3 North Side Energy Company lnc
4 Bypass LU N/A N/A N/A
5 Hazelton A LU N/A N/A N/A
6 Head ofU Canal Project LU N/A N/A N/A
7 Orchard Ranch Solar, LLC LU N/A N/A N/A
8 Oregon Trail Wind Park LU N/A N/A N/A
I Owyhee lnigation District
10 Mitchell Butte LU N/A N/A N/A
11 Owyhee Dam Cspp LU N/A N/A N/A
12 Tunnel #1 LU N/A N/A N/A
13 Payne's Ferry Wind Park LU N/A N/A N/A
14 Pico Energy - 86 Anaerobic Digester LU N/A N/A N/A
Total
FERC FORIUI NO.1 (ED. 12-90)Page 326.6
Name of Respondent
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of ReDort(Mo, Da, Yi)
04114t2021
Year/Period of Report
End of 20201Q4
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 servioe, 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 (6Gminute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawafthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. lf more energy was delivered than received, enter a negative amount. lf the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreemenl, 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
repo(ed 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 Gharggs
.8r
Energy Charges
ffil
Other Charges
tli
Total (j+k+l)
of Settlement ($)
(m)
7,30:391,024 391,023 1
4,93€425,611 425,6't'.l 2
3
30,45I 1,594,868 1,594,868 4
27,214 2,126,902 2,126,898 5
4,577 4't8,15t 418,158 6
47,171 't,359,48€1,359,482 7
40,411 2,591,387 2,591,387 8
9
6,314 187,54(187,ilo 10
21,$e 480,64t 480,645 11
18,874 625,482 625,482 12
66,83t 5,625,718 5,625,718 13
14,861 786,144 786,144 14
5,057,577 67,U7 144,671 282,392,220 10,517,63i 292,909,8si
FERC FORM NO.1 (ED.12-90)Page 327.6
Name of Respondent
ldaho Power Company
)ort ls:
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
04t14t2021
Year/Period of Report
End of 20201A4
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 servioe. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). ln addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be intenupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.9., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contracl
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 (MW)
Average
Monthly NCP Demanr
(e)
Average
Monthly CP Demand
(0
1 Pigeon Cove Power LU N/A N/A N/A
2 Pilgrim Stage Station Wind Park LU N/A N/A N/A
3 Prospector Windfarm LU N/A N/A N/A
4 Reynolds lrrigation LU N/A N/A N/A
5 Richard Kaster
6 Box Canyon LU N/A N/A N/A
7 Briggs Creek LU N/A N/A N/A
8 Riverside Hydro - Mora Drop LU N/A N/A N/A
I Riverside lnvestments
10 Arena Drop LU N/A N/A N/A
11 Fargo Drop Hydroelectric LU N/A N/A N/A
12 Rockland Wind Farm LU N/A N/A N/A
13 Ryegrass Windfarm LU N/A N/A N/A
14 Salmon Falls Wind LU N/A N/A N/A
Total
FERC FORM NO.1 (ED. 12.90)Page 326.7
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report
(Mo, Da, Yr)
o4t14t2021
Year/Period of Report
End of 2O20lQ4
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 O, 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)
POWET{ EXCHANGL,S COST/SETTLEMENT OF POWER Line
No.MegaWatt Hours
Received(h)
Megawatt Hours
Delivered
(i)
Demand uharges
(81
tnergy charges
fll
other charges
($)
(t)
Iotal U+k+l)of Settlement ($)
(m)
8,552 468,46i 468,462 1
34,404 2,202,591 2,202,stfi 2
25,43a 1,567,30(1,567,309 3
1,30€96,44(96,/t40 4
5
'r,88r '120,66C 120,660 6
3,61!246,88{246,888 7
4,68!321,261 321,261 8
I
1,61€154,89(154,890 10
3,361 220,362 220,368 11
257,981 18,235,63t 18,235,635 12
53,81'4,346,054 4,346,054 13
65,96!4,z',t4,424 4,214,424 14
5,057,577 67,U7 144,671 282,392,224 10,517,637 292,909,857
FERC FORM NO.1 (ED. 12.90)Page 327.7
Name
(1)
(21
Originalldaho Power Company Resubmission
Date of ReDort(Mo, Da, Yi)
04t14t2021
Year/Period of Report
End of 20201Q4
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. ln column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). ln addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.9., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meels 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 (MW)
AVerage
Monthly NCP Deman
(e)
Average
Monthly CP Demanc
(0
1 Shingle Creek LLC LU N/A N/A N/A
2 Shorock Hydro lnc.
3 Rock Creek #1 LU N/A N/A N/A
4 Shoshone CSPP LU N/A N/A N/A
5 Shoshone #2 LU N/A N/A N/A
6 Simcoe Sotar, LLC LU N/A N/A N/A
7 Snake River Pottery LU N/A N/A N/A
I South Forks Joint Venture-Lowline Cana ffiE-= ltffi N/A N/A N/A
I Tamarack Energy Partnership LU N/A N/A N/A
10 Tasco - Nampa N/A N/A N/A
11 Tasco - Twin Falls N/A N/A N/A
12 Thousand Springs Wind Park LU N/A N/A N/A
't3 Tiber Montana LLC - Tiber Dam LU N/A N/A N/A
14 Tuana Gulch Wind Park LU N/A N/A N/A
Total
FERC FORM NO. 1 (ED.12.90)Page 326.E
Name of Respondent
ldaho Power Company
(1)
(2)
An Original
A Resubmission
Date of Reoort
(Mo, Da, Yi)
04t14t2021
Year/Period of Roport
End of 2O2O|Q4
AD - for out-of-period adjustment. Use this code for any acoounting adjustments or "true.ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. ln column (c), identifu the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract, On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (0. For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the 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 seftlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401 ,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWaft Hours
Purchased
(s)
POWER EXCHANGES COST/SETTLEMENT OF POWER Line
No.Megawatt Hours
Received(h)
Megawatt Hours
Delivered(i)
Demand Charges
(81
Energy Charges
tfl
Other Charges
t?i
Total (i+k+l)
of Settlement ($)
(m)
1,121 66,66r 66,664 1
2
10,79t 653,74t 653,745 3
't,54a 92,01t 92,012 4
2,544 176,891 176,891 5
48,49(1,532,904 1,532,897 6
47(25,96(25,96S 7
29,43(2,174,07i 2,174,072 8
26,611 1,508,05(1,508,055 I
I 10
11
34,13(2,192,sX 2,192,536 12
29,481 1,872,13i 1,872,133 't3
31,61(2,030,24t 2,030,248 14
5,057,57i 67,U7 144,671 282,392,22C 10,517,637 292,909,85i
FERC FORM NO. r (ED. t2-90)Page 327.8
Name of Respondent
ldaho Power Company
ort ls:
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
04114t2021
Year/Period of Report
End of 20201Q4
PURCHASED POWER (Acr(lncluding power exchan
1. Report all power purchases made during the year. Also repo( 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 servioe. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). ln addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and '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
servioe, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for intermediat+'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)
Average
Monthly CP Demanc
(0
1 Tuana Springs Expansion LU N/A N/A N/A
2 Twin Falls Energy-Lowline Midway Hydro LU N/A N/A N/A
3 Two Ponds Windfarm LU N/A N/A N/A
4 White Water Ranch LU N/A N/A N/A
5 William Arkoosh-Littlewood/Arkoosh LU N/A N/A N/A
6 William Arkoosh- Littlewood River Ranc LU N/A N/A N/A
7 Willow Spring Windfarm LU N/A N/A N/A
8 Wilson Power Company N/A N/A N/A
I Wood Hydro
10 Black Canyon #3 LU N/A N/A N/A
11 Jim Knight LU N/A N/A N/A
12 Magic Reservoir LU N/A N/A N/A
13 Mile 28 LU N/A N/A N/A
14 Sagebrush LU N/A N/A N/A
Total
FERC FORM NO. 1 (ED. 12-90)Page 326.9
(1)
(2)
An Original
A Resubmissionldaho Power Company
s:Date of Report(Mo, Da, Yr)
04t14t2021
Year/Period of Report
End of 2O2O|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 (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.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column O, energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (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.
POWER EXCHANGES COST/SETTLEMENT OF POWERMegaWatt Hours
Purchased
(s)
Megawatt Hours
Received(h)
Megawatt Hours
Delivered(i)
Demand Charges
($)
(,)
Energy Charges
tt)
Other Charges
tft
Total 0+k+l)of Settlement ($)
(m)
Line
No.
74,U(6,152,69{6,151,258 I
9,312 s44,63t 5,t4,636 2
60,327 4,864,96!4,864,963 3
781 52,39t 52,398 4
3,78'l 280,641 280,641 5
4,291 302,314 302,314 6
29,63(1,816,76!1,816,769 7
29,872 2,080,34t 2,080,348 8
I
424 33,631 33,631 't0
11
10,851 561,74i 561,74't 12
7,634 498,074 498,074 13
14
5,057,577 67,347 144,671 282,392,22C 10,517,637 292,909,85;
FERC FORM NO.1 (ED.12.90)Page 327.9
Name of Respondent
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
o411412021
Year/Period of Report
End of 20201Q4
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. ln column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). ln addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for longterm 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 commilment 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
Dem Monthly
(e)(0
1 Yahoo Creek Wind Park LU N/A N/A N/A
2 Scheduling Deviation
3 3 Phases Renewables lnc.SF WSPP N/A N/A N/A
4 ADM lnvestor Services, lnc.)S WSPP N/A N/A NiA
5 Arizona Public Service Co.SF WSPP N/A N/A N/A
6 AVANGRID RENEWABLES, LLC OS WSPP N/A N/A N/A
7 AVANGRID RENEWABLES, LLC SF WSPP N/A N/A N/A
8 Avista Corp.os r-'t2 N/A N/A N/A
I Avista Corp.os WSPP N/A N/A N/A
't0 Avista Corp.SF WSPP N/A N/A N/A
11 Bonneville Power Adm inistration )S WSPP NiA N/A N/A
12 Bonneville Power Adm inistration OS WSPP N/A N/A N/A
13 Bonneville Power Adm inistration SF WSPP N/A N/A N/A
14 BP Energy Company SF WSPP N/A N/A N/A
Total
FERC FORM NO.I (ED.12-90)Page 326.10
ldaho Power Company (1)
(2t
An Original
A Resubmission
Dat6 of ReDort
(Mo, Da, Yi)
o{t14t2021
Year/Period of Report
End of 20201Q4
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 servioe, 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 seftlement. Do not report net exchange.
7. Report demand charges in column O, energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (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 EXGHANGES GOST/SETTLEMENT OF POWER Line
No.Megawatt Hours
Received
(h)
Megawatt Hours
Delivered(i)
Demand charges
($)
0)
Energy Gharges
tfll
Other Charges
tft
Total (i+k+l)
of Settlement ($)
(m)
67,731 5,679,41i 5,679,412 1
2,311 2
80t 29,09€29,096 3
3,306,55t 3,306,558 4
12,80(259,77e 259,776 5
82 82 6
48,90(76S,73€769,736 7
t 158 158 8
197,592 197,592 I
4,98(78,85(78,850 10
4t 1,144 1,'145 't1
159,403 159,403 12
38,26t 570,31i 570,317 13
686,87r 23,047,46e 23,047,466 14
5,057,577 67,347 144,671 282,392,224 10,517,637 292,909,85i
FERC FORM NO.1 (ED. 12.90)Page 327.10
s:
ldaho Power Company (1)
(2)
An Original
A Resubmission 0411412021
Year/Period of Report
End of 2O20lQ4
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 wtrich the supplier plans to provide on an ongoing basis (i.e., the
supplier includes p@ects load for this service in its system resource planning). ln addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.9., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
lF - for intermediate'term firm service. The same as LF service expect that "intermediate.term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above.defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
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
(e)(0
1 Brookfield Renewable Trading and Marke SF WSPP N/A N/A N/A
2 California lndependent System Operator SF cArso N/A N/A N/A
3 Calpine Energy Solutions LLC SF WSPP N/A N/A N/A
4 Chelan Co PUD WSPP N/A N/A N/A
5 Chelan Co PUD SF WSPP N/A N/A N/A
6 Citigroup Energy lnc.ISDA N/A N/A N/A
7 Clatskanie PUD SF WSPP N/A N/A N/A
8 Clean Power Alliance of Southem Calif SF WSPP N/A N/A N/A
I ConocoPhillips Company SF WSPP N/A N/A N/A
10 Direct Energy Business Marketing, LLC SF WSPP N/A N/A N/A
11 DTE Energy Trading, lnc.SF WSPP N/A N/A N/A
12 EDF Trading North America, LLC SF WSPP N/A N/A N/A
13 Energy Keepers, lnc SF WSPP N/A N/A N/A
14 Eugene Water & Electric Board SF WSPP N/A N/A N/A
Total
FERC FORM NO.1 (ED.12-90)Page 326.11
ldaho Power Company (1)
(2)
Original
Resubmission
Date of ReDort
(Mo, Da, Yi)
0411412021
Year/Period of Report
Endof 202Uo,4
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in pilor 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 oontract 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 supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column fi), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as 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, EXGHANGES GOST/SETTLEMENT OF POWER Line
NoMegawatt Hours
Received
(h)
Megawatt Hours
Delivered
(i)
Demand Charges
,8t
Energy Charges
ttl
Other Charges
($)
(t)
Total 0+k+l)of Settlement ($)
(m)
40(-34{-34€1
152,071 1,662,42(1,662,42C 2
9,80(329,U1 329,34€3
29 2S 4
100,40(2,085,80i 2,085,803 5
7,300 7,30(6
31(6,17t 6,1 7t 7
61(17,70',1 '17,703 8
7,60C 468,52(468,52(o
121 8,711 8,71C 10
18,00(743,511 743,51C 11
1't,104 633,57'633,571 12
60c 12,781 12,782 13
40c 5,20(5,20(14
5,057,577 67,347 144,671 282,392,22C 10,517,63i 292,909,85i
FERC FORM NO. I (ED.12.90)Page 327.1'l
Name of Respondent
ldaho Power Company
(1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
0411412021
Year/Period of Report
End of 20201Q4
PURCHASED POWER (Ac((lncluding power exchant
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 servie,e is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). ln addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.9., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
lF - for inlermediate-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 Demani
(e)
Average
Monthly CP Demand
(0
1 Exelon Generation Company, LLC SF WSPP N/A N/A N/A
2 Grant CO Public Utility District #2 -3$WSPP N/A N/A N/A
3 Gridforce Energy Management, LLC WSPP N/A N/A N/A
4 J.Aron & Company LLC 3S ISDA N/A N/A N/A
5 Macquarie Energy LLC SF WSPP N/A N/A N/A
6 Morgan Stanley Capital Group lnc"SF ISDA N/A N/A N/A
7 Neal Hot Springs Unit #1 LU N/A N/A N/A
I Nevada Power Company, dba NV Energy os. .," 'N/A N/A N/A
I Nevada Power Company, dba NV Energy SF WSPP N/A N/A N/A
10 NextEra Energy Marketing, LLC SF WSPP N/A N/A N/A
11 NorthWestern Energy N/A N/A N/A
't2 NorthWestem Energy SF WSPP N/A N/A N/A
13 NorthWestern Energy (Transmission)WSPP N/A N/A N/A
14 Oregon Solar Customers N/A N/A N/A
Total
FERC FORM NO. 1 (ED. 12.90)Page 326.'|2
Name Respondent
ldaho Power Company
(1)
(2)
An Original
A Resubmission
Date of
(Mo, Da
Report
, Yr)
04t1412021
Year/Period of Report
End of 2O2O|A4
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 (fl. 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
agreemenl, 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
($)
(i)
Energy Charges
tt)
Other Charges
($)
(t)
Total U+k+l)
of Settlement ($)
(m)
80(17,401 17,400 1
82 82 2
C 129 129 3
216,983 216,983 4
2,60(53,85(53,856 5
3,00(8,14t 8,144 6
't92,10(22,558,044 22,558,U4 7
1,169 1 ,169 8
60(5,70(5,700 o
34,824 617,774 617,774 10
e 1st 't 58 11
40(8,20(8,20C 12
21,70!21,705 13
762 21,95',1 21,951 14
5,057,577 67,347 144,671 282,392,22C 10,517,637 292,909,85i
FERC FORM NO.1 (ED. 12.90)Page 327.12
Name Originalldaho Power Company (1)
(2)Resubmission
Date of Reoort
(Mo, Da, Yi)
0411412021
Year/Period of Report
End of 2O20lQ4
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 servioe is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). ln addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.9., the supplier must aftempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
lF - for intermediate.term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availabilfty 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 (MW)
Average
Monthly NCP Demanr
(e)
Average
Monthly CP Demanc
(0
1 PacifiCorp T-13 N/A N/A N/A
2 PacifiCorp SF WSPP N/A N/A N/A
3 PacifiCorp lnc.WSPP N/A N/A N/A
4 Portland General Electric Company T-14 N/A N/A N/A
5 Portland General Electric Company SF WSPP N/A N/A N/A
6 Powerex Corp.SF WSPP N/A N/A N/A
7 Puget Sound Energy, lnc.ir-e N/A N/A N/A
8 Puget Sound Energy, lnc.SF WSPP N/A N/A N/A
9 Raft River Energy I LLC LU N/A N/A N/A
10 Rainbow Energy Marketing Corporation SF WSPP N/A N/A N/A
11 Seattle City Light WSPP N/A N/A N/A
12 Seattle City Light SF WSPP N/A N/A N/A
13 Shell Energy North America (US), L.P SF WSPP N/A N/A N/A
14 Siena Pacific Power Co., dba NV Energ T-55 N/A N/A N/A
Total
FERC FORM NO.1 (ED. 12-90)Page 326.13
Name of Respondent
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Reoort(Mo, Da, Yi)
04114t2021
Year/Period of Report
End of 20201Q4
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 servioe 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 (Q
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 ce(ain 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 reguired 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
t[l
Other Charges
($)o
Total (i+k+l)
of Settlement ($)
(m)
3i 837 837 1
'17,44t 423,59t 423,59€2
33,668 33,668 3
11 3't6 316 4
32,431 509,95i 509,953 5
26,35(1,275,67!1,275,671 6
(242 242 7
73,67('t,874,3',t1 1,874,314 8
90,57i 6,402,93t 6,402,935 I
3,11t 51,68r 51,68€10
I 105 105 1'l
7,73t 156,73(156,73(12
10,221 396,23r 396,234 13
2i 717 717 14
5,057,577 67,347 144,671 282,392,22C 10,517,63i 292,909,85i
FERC FORM NO.1 (ED. 12-90)Page 327.13
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of ReDort(Mo, Da, Yi)
04t14t2021
Year/Period of Report
End of 2O20lQ4
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 servioe. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes pCIects 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{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 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)(f)
1 Snohomish County PUD SF WSPP N/A N/A N/A
2 Tacoma Power WSPP N/A N/A N/A
3 Tacoma Power SF WSPP N/A N/A N/A
4 Telocaset Wind Power Partners LLC LU APP.A N/A N/A N/A
5 Tenaska Power Services Co.SF WSPP N/A N/A N/A
6 The Energy Authority, lnc.SF WSPP N/A N/A N/A
7 TransAlta Energy Marketing (U.S.) lnc.SF WSPP N/A N/A N/A
8 Western Area Power Administration (WA WSPP N/A N/A N/A
I PacifiCorp lnc.
10 Siena Pacific Power Co., dba NV Energ
11 Clatskanie PUD 153
12 Acctg Valuation of Clatskanie PUD 0 N/A N/A N/A
13 Demand Response Avoided Energy N/A N/A N/A
14
Total
FERC FORM NO.1 (ED. 12.90)Page 326.14
Name of Respondent
ldaho Power Company (1)
(2)
Original
Resubmission
Date of Reoort
(Mo, Da, Yi)
0411412021
Year/Period of Report
End of 2O2O|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 servioe 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 (6Gminute 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. Repo( in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column O, energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (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
($)
0)
Energy Charges
t[l
Other Charges
($)
(t)
Total (i+k+l)
of Settlement ($)
(m)
1,00c 23,20t 23,20C ,|
1 29 2e 2
2,00c 34,55(34,55f 3
296,004 19,947,54t 19,947,54t 4
24,082 618,36r 618,364 5
43,'t5€1,734,561 1,734,564 b
13,55:355,66/355,664 7
14 37C 37(I
88,996 o
2,650 10
67,U7 53,025 11
223,779 223,775 12
6,533,734 6,533,734 13
14
5,057,577 67,U7 1M,671 282,392,220 10,517,63i 292,909,85i
FERC FORM NO. I (ED.12-90)Page 327.14
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
0411412021
Year/Period of Report
2020to,4
FOOTNOTE DATA
Schedule Paoe:326 Line No.: 1 Column: I
ICE Price Ad ustment from 2020
ICE P ce 2020
ICE P ce 2020
326.1 Line No.:2 Column: I
ICE ce 2020
ICE P ce 2020
ICE P ce 2020
ICE P ce ustment from 2020
ICE P ce ustment from 2020
Ida West., a subsid of rdaCorp
ects.
(Idaho Power Company's parent company), has a1
326 Line No.: 2 Column: I
ustment from
ustment from
326 Line No.:8 Column: I
ustment
326.1 Line No.: 13 I
ustmenL
326.2 Line No.:9 Column: I
ustmenL
326.3 Line No.: 1 Column: I
326.3 Line No.: 8 Column: I
326.3 Line No.: 13 Column: b
owne of these
326.4 Line No.: 6 Column: INet Ene
ICE PT ce o20
326.4 Line No.:9 Column: I
ICE P ce ustment rom 2020
Ida West, a idiary of ldaCorp (Idaho Power Company's parent company), has partial
owner of these ects
ICE PT ce 2020
rCE Pr 2020
ICE PT 2020
ICE PT ustment from 2020
Page: 326.6 Line No.:7 Column: I
326.4 Line No.:7 I
ustment rom
326.5 Line No.:9 Column: b
326.5 Line No.: 12 Column: I
ustment rom
326.5 Line No.:14 Column: I
ustment rom
326.6 Line No.: 1 Column: I
ustmenL rom
326.6 Line No.: 5 Column: I
326.8 Line No.:4 Column: I
326.8 Line No;6 Column: I
326.8 Line No.: I Column: b
ICE Price ,A.d ustment from
ICE PT ce Ad ustment from
ICE PT ustment from
Ida West, a
ownershi of these
2020
2020
2020
ary of ldacorp (Idaho Power Company's parent company), has partial
ects
lCE PT
Non F rm
2020
CS
326.8 Line No.:9 Column: I
ustment rom
326.8 Line No.: 10 b
Schedule Paqe: 326.8 Line No.: 11 Column: b
Non Firm Purchases
Schedule Pase: 326.9 Line No.: 1 Column: I
Del"a Da
326.9 Line No.: I Column: b
FERC FORM NO. 1 (ED. 12.871 Paoe 450.1
Name of Respondent
ldaho Power Companv
This Report is:
(1) X An Originalel A Resubmission
Date of Report
(Mo, Da, Yr)
04t14t2021
Year/Period of Report
2020tQ4
FOOTNOTE DATA
Ida West, a subsidiary of IdaCorp (Idaho Power Company's parent company), has partial
ownershi of these ro ects.
326.10 Line No;2 Column: bfference between booked and scheduled
ADM InvesLor Serv ces, Inc Futures AccounL Document, dated Ma 5, 2015
or Reserves
or Reserves
F nanc a e6 on Losses
nn1 or Reserves
F aI Transmission Losses
or a Reserves
ISDA Master t th t dated March 7, 2OLl
326.12 Line No.:2 Column: b
or Reserves
1nn or Reserves
ISDA Master t t ,J. Aron &30 2014
F a Tr SS on Losses
or Reserves
326.12 Line No.: 13 Column: b
F aI Transmission Losses
326.10 Line No.:4 Column: b
326.10 Line No.:6 Column: b
326.10 Line No.:8 Column: b
326.10 Line No.:9 Column: b
326.10 Line No.: 11 Column: b
326.10 Line No.: 12 b
326.12 Line No.:8 Column: b
326.11 Line No.:4 Column: b
326.11 Line No.:6 Column: b
326.12 Line No.:3 Column: b
326.12 Line No.:4 Column: b
326.12 Line No.: 11 Column: b
326.13 Line No.: 1 Column: b
326.13 Line No.: 3 Column: b
9chedule Pase:326.12 Line No.:14 Column: bSchedule 88 Solar
or at Reserves
F a Transm ss on Losses
or t Reserves
or ri Reserves
or at Reserves
or at Reserves
or at Reserves
326.14 Line No.:8 Column: bortReserves
caI Transm on Losses
cal Transm on Losses
326.13 Line No.:4 Column: b
326.13 Line No.:7 Column: b
326.13 Line No.: 11 Column: b
326.13 Line No.:14 Column: b
326.14 Line No.: 2 Column: b
326.14 Line No.:9 Column: b
326.14 Line No.:10 Column: b
326.14 Line No.:11 Column: b
1nn
FERC FORM NO.1 (ED. 12-871 Page 450.2
This Page lntentionally Left Blank
Name of Respondent
ldaho Power Company
This Report is:
(1) !An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
04114t2021
Year/Period of Report
2020tQ4
FOOTNOTE DATA
between Clatskanie PIJD and Idaho Power
en PUD Power
Incent ve program for customers to reduce demand dur peak hours
at. Arrowrock Dam
at Arrowro Dam
326.11 Line No.:12 Column: b
9chdule Paoe:326.14 Line No;13 Column: b
FERC FORM NO. 1 (ED. 12.871 Pase 450.3
Name of Respondent
ldaho Power Company
S:
(1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
o4t14t2021
Year/Period of Report
End of 20201Q4
tf(ANi
AS
ccounl 4co.1 )
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. ln column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General lnstruction for definitions of codes.
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 Authorig)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
1 Bonneville Power Administration - OTEC Bonneville Power Administration Oregon Trails Electric Co-op FNO
2 Bonneville Power Administration - USBR Bonneville Power Administration United States Bureau of Reclamati FNO
3 Bonneville Power Administration - PF Bonneville Power Administration Priority Firm Customers FNO
4 Milner lnigation District United States Bureau of Reclamati Milner lrrigation District OLF
5 Morgan Stanley Capital Group lnc.Seattle City Light Bonneville Power Administration OS
6 PacifiCorp PacifiCorp West PacifiCorp West FNO
7 United States Bureau of lndian Affairs Bonneville Power Adm inistration United States Bureau of lndian Af OS
8 Cycle Horseshoe Bend Wind, LLC PacifiCorp East PacifiCorp East OS
I Cycle Horseshoe Bend Wind, LLC PacifiCorp East PacifiCorp East OS
10
't1 PacifiCorp lnc.PacifiCorp East Bonneville Power Adm inistration LFP
12 PacifiCorp lnc.PacifiCorp East PacifiCorp West LFP
13 PacifiCorp lnc.PacifiCorp East PacifiCorp West LFP
14 Morgan Stanley Capital Group lnc.ldaho Power Company Bonneville Power Administration LFP
15 Bonneville Power Adm inistration PacifiCorp West PacifiCorp East LFP
16 Bonneville Power Administration PacifiCorp West PacifiCorp East LFP
17
18 American Falls Solar NF
19 Avangrid Renewables, LLC NorthWestern/Pacifi Corp East Sierra Pacific Power NF
20 Avangrid Renewables, LLC PacifiCorp East Sierra Pacific Power NF
21 Avangrid Renewables, LLC Bonneville Power Adm inistration PacifiCorp East NF
22 Avangrid Renewables, LLC Bonneville Power Administration Sierra Pacific Power NF
23 Avangrid Renewables, LLC Avista PacifiCorp East NF
24 Avangrid Renewables, LLC Avista Sierra Pacific Power NF
25 Avangrid Renewables, LLC Sierra Pacific Power Bonneville Power Administration NF
26 Avangrid Renewables, LLC PacifiCorp West PacifiCorp East NF
27 Avangrid Renewables, LLC PacifiCorp West Sierra Pacific Power NF
28 Avangrid Renewables, LLC ldaho Power Company PacifiCorp East NF
29 Avista Corporation Avista PacifiCorp East NF
30 Baker City Solar NF
31 Black Hills Power lnc.NorthWestern/Pacifi Corp East PacifiCorp East NF
32 Black Hills Power lnc.NorthWestern/Pacifi Corp East PacifiCorp East NF
33 Black Hills Power lnc.PacifiCorp East Sierra Pacific Power NF
34 Black Hills Power lnc.Bonneville Power Administration PacifiCorp East NF
TOTAL
FERC FORM NO. 1 (Eo. 12-90)Page 328
ldaho Power Company (1)
(21
An Original
A Resubmission
Date of Report
(Mo, Da, Yr)
0411412021
Year/Period of Report
End of 2O2O|Q4
as r 4a(rxuonunueo,
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 wtere energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and fi) the total megawatthours received and delivered.
FERC Rate
Schedule of
Tarlff 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.Megawa[ Hours
Received(i)
Megawafi Hours
Delivered
0)
337,221 337,221 1
I 204,476 2U,47e 2
I 1,343,269 1,343,26!3
Minidoka, ldaho Various in ldaho 1 1,604 1 1,604 4
255,968 255,96€5
9 1,969 1,96!6
Legacy LaGrande, Oregon Various in ldaho 16,51'l 16,511 7
BRDY IPCOEAST 2,372 2,372 8
5/6 JEFF IPCOEAST 19,765 19,765 I
10
BORA LAGRANDE 1,077,227 1,077,227 11
718 KPRT HURR 620,4't0 620,41C 12
718 BORA HURR 851,032 851,03i 13
718 LYPK LAGRANDE 8,658 8,65€14
718 M500 KPRT 97,O21 97,021 15
718 SMLK KPRT 394,659 394,6s!16
17
18
7t8 BPAT.NWMT M345 1,171 1,171 19
7t8 BRDY M345 12 12 20
7t8 LAGRANDE BORA 302 302 21
7t8 LAGRANDE M345 2,943 2,94i 22
7t8 LOLO BORA 96 9€23
7t8 LOLO M34s 252 252 24
7t8 M345 LAGRANDE 26s 26!25
7t8 SMLK BORA 658 65t 26
718 SMLK M345 34C 34(27
718 WALLAWALLA BORA 1,303 1,30:28
718 LOLO BRDY 805 80r 29
11 30
il8 AVAT.NWMT BRDY 6C 6(31
7t8 BPAT.NWMT JBSN 13C 13(32
il8 JBSN M345 4C 4C 33
7t8 LAGRANDE JBSN 417 41i 34
0 8,2'[8,909 E,24E,90!
FERC FORM NO. r (ED. 12.90)Page 329
Name of Respondent
ldaho Power Company (1)
(21
An Original
A Resubmission
Date of ReDort
(Mo, Da, Yi)
041141202'l
Year/Period of Report
End of 2O20lQ4
I KANi as ccount 45o.1 )
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utilig 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 - Outof-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 Black Hills Power lnc.Avista PacifiCorp East NF
2 Bonneville Power Administration NorthWestem/Pacifi Corp East PacifiCorp East NF
3 Bonneville Power Administration Northwestern/Pacifi Corp East Bonneville Power Administration NF
4 Bonneville Power Administration Bonneville Power Administration PacifiCorp East NF
5 Bonneville Power Administration Bonneville Power Adm inistration PacifiCorp East NF
6 Bonneville Power Administration Bonneville Power Administration Bonneville Power Adminisbation NF
7 Bonneville Power Administration Bonneville Power Adm inistration Siena Pacific Power NF
8 Bonneville Power Administration Avista PacifiCorp East NF
I Bonneville Power Administration Avista PacifiCorp East NF
10 Bonneville Power Administration Avista Bonneville Power Administration NF
11 Bonneville Power Administration PacifiCorp West PacifiCorp East SFP
12 Bonneville Power Administration PacifiCorp West Bonneville Power Administration NF
13 Bonneville Power Administration PacifiCorp West Siena Pacific Power NF
't4 Bonneville Power Administration PacifiCorp West Siena Pacific Power SFP
't5 Brookfield Renewable Trading & Marketing PacifiCorp East NorthWestem/Pacifi Corp East SFP
16 Brookfield Renewable Trading & Marketing PacifiCorp East Bonneville Power Administration NF
17 Brookfield Renewable Trading & Marketing Northwestem/Pacifi Corp East Siena Pacific Power NF
18 Brookfield Renewable Trading & Marketing NorthWestem/Pacifi Corp East Siena Pacific Power SFP
19 Brookfield Renewable Trading & Marketing PacifiCorp East Siena Pacific Power NF
20 Brookfield Renewable Trading & Marketing PacifiCorp East Sierra Pacific Power SFP
21 Brookfield Renewable Trading & Marketing PacifiCorp East PacifiCorp East NF
22 Brookfield Renewable Trading & Marketing PacifiCorp East PacifiCorp East SFP
23 Brookfield Renewable Trading & Marketing PacifiCorp East Siena Pacific Power NF
24 Brookfield Renewable Trading & Marketing PacifiCorp East Siena Pacific Power SFP
25 Brookfield Renewable Trading & Marketing Bonneville Power Administration Siena Pacific Power NF
26 Brookfield Renewable Trading & Marketing Bonneville Power Administration Siena Pacific Power SFP
27 Brookfield Renewable Trading & Marketing ldaho Power Company PacifiCorp East NF
28 Brookfield Renewable Trading & Marketing ldaho Power Company Sierra Pacific Power NF
29 EDF Trading North America, LLC Bonneville Power Adm inistration ldaho Power Company NF
30 EDF Trading No(h America, LLC Siena Pacific Power PacifiCorp East NF
31 Energy Keepers, lnc.PacifiCorp East Siena Pacific Power SFP
32 Energy Keepers, lnc.PacifiCorp East PacifiCorp East SFP
33 Energy Keepers, lnc.PacifiCorp East Bonneville Power Administration SFP
34 Grandview Solar NF
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.1
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of ReDort
(Mo, Da, Yi)
0411412021
Year/Period of Report
End of 20201Q4
as
I 4Ct'XUOnUnUeO)
5. ln column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or @ntract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. ln column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
cpntract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and 0) the total megawatthours received and delivered.
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(0
Point of Delivery
(Substation or Other
Designation)
(s)
Billing
Demand
(MW)
(h)
TRANSFER OF ENERGY Line
No.Megawafi Hours
Received(i)
Megawa[ Hours
Delivered(i)
718 LOLO JBSN 1,130 1,13(1
7t8 BPAT.NWMT ANTE I I 2
718 BPAT.NWMT LAGRANDE 3,020 3,02(3
7t8 LAGRANDE BORA 264 264 4
718 LAGRANDE KPRT 266 26e 5
718 LAGRANDE LAGRANDE 943 94:6
7t8 LAGRANDE M345 2,848 2,84t 7
718 LOLO BORA 1 1 8
7t8 LOLO KPRT 14 14 I
718 LOLO LAGRANDE 2,698 2,69t 10
7t8 SMLK BORA 73,36C 73,36(11
7t8 SMLK LAGRANDE 11 11 't2
718 SMLK M345 20c 20(13
718 SMLK M345 84,992 84,99i 14
718 BORA BPAT-NWMT 't,550 1,55(15
7t8 BORA LAGRANDE 40c 40(16
718 BPAT.NWMT M345 31C 31('t7
7t8 BPAT.NWMT M345 7,071 7,071 18
718 BRDY M345 556 55€19
718 BRDY M345 35,391 35,391 20
7t8 JEFF BRDY 124 12!21
718 JEFF BRDY 3&3&22
7t8 JEFF M345 34C 34(23
7t8 JEFF M345 16C 16(24
7t8 LAGRANDE M345 57C 57(25
7t8 LAGRANDE M345 20,84C 20,84(26
718 WALLAWALLA BRDY 162 16i 27
7t8 WALLAWALLA M345 1 ,018 1,01t 28
7t8 LAGRANDE IPCOEAST 64 6,4 29
7t8 M345 BRDY 28C 28(30
7t8 BRDY M345 12,76C 12,76t 31
718 JEFF BORA 39C 39(32
7t8 JEFF LAGRANDE 12C 12(33
't1 34
0 8,248,909 8,248,90!
FERC FORM NO. r (ED. 12-90)Page 329.1
Name of Respondent
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Reoort(Mo, Da, Yi)
04t14t2021
Year/Period of Report
End of 20201Q4
I t(ANi as ccount 45tt.1)
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. ln column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General lnstruction for definitions of codes.
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 Guzman Energy Group LLC Northwestem/Pacifi Corp East PacifiCorp East NF
2 Guzman Energy Group LLC Bonneville Power Administration PacifiCorp East NF
3 Huntington Wind NF
4 Macquarie Energy, LLC NorthWestem/Pacifi Corp East PacifiCorp East NF
5 Macquarie Energy, LLC NorthWestem/Pacifi Corp East Siena Pacific Power NF
6 Macquarie Energy, LLC PacifiCorp East PacifiCorp East NF
7 Macquarie Energy, LLC PacifiCorp East Siena Pacific Power NF
8 Macquarie Energy, LLC PacifiCorp East Sierra Pacific Power SFP
9 Mag Energy Solutions ldaho Power Company PacifiCorp East NF
10 Mag Energy Solutions PacifiCorp East Siena Pacific Power NF
11 Mag Energy Solutions PacifiCorp East Sierra Pacific Power SFP
12 Mag Energy Solutions PacifiCorp East Sierra Pacific Power NF
13 Mag Energy Solutions PacifiCorp East Siena Pacific Power NF
14 Mag Energy Solutions Siena Pacific Power PacifiCorp East NF
15 Mercuria Energy America, LLC PacifiCorp East Sierra Pacific Power NF
16 Mercuria Energy America, LLC Siena Pacific Power PacifiCorp East NF
17 Mercuria Energy America, LLC ldaho Power Company PacifiCorp East NF
18 Mercuria Energy America, LLC ldaho Power Company Sierra Pacific Power NF
't9 Morgan Solar NF
20 Morgan Stanley Capital Group lnc.Northwestem/Pacifi Corp East PacifiCorp East NF
21 Morgan Stanley Capital Group lnc.NorthWestern/Pacifi Corp East Bonneville Power Administration NF
22 Morgan Stanley Capital Group lnc.NorthWestem/Pacifi Corp East Siena Pacific Power NF
23 Morgan Stanley Capital Group lnc.NorthWestem/Pacifi Corp East Siena Pacific Power SFP
24 Morgan Stanley Capital Group lnc.PacifiCorp East Bonneville Power Administration NF
25 Morgan Stanley Capital Group lnc.NorthWestern/Pacifi Corp East PacifiCorp East NF
26 Morgan Stanley Capital Group lnc.Northwestem/Pacifi Corp East PacifCorp East SFP
27 Morgan Stanley Capital Group lnc.NorthWestem/Pacifi Corp East PacifiCorp East NF
28 Morgan Stanley Capital Group lnc.NorthWestem/Pacifi Corp East Siena Pacific Power NF
29 Morgan Stanley Capital Group lnc.NorthWestem/Pacifi Corp East Siena Pacific Power SFP
30 Morgan Stranley Capital Group lnc.PacifiCorp East NorthWestern/Pacifi Corp East NF
31 Morgan Stanley Capital Group lnc.PacifiCorp East PacifiCorp East NF
32 Morgan Stanley Capital Group lnc.PacifiCorp East PacifiCorp East SFP
33 Morgan Stanley Capital Group lnc.PacifiCorp East Bonneville Power Administration NF
34 Morgan Stanley Capital Group lnc.PacifiCorp East Avista NF
TOTAL
FERC FORM NO. 1 (ED. 12-90)Page 32E.2
ldaho Power Company (1)
(2)
Original
Resubmission
Date of(Mo, Da:fPf*
04t14t2021
Year/Period of Report
End of 20201Q'4
as
r 4crrr(uon[nueo,
5. ln column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or oontract
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 reoeived 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 U) 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.Megawalt Hours
Received(i)
Megawatl Hours
Delivered
U)
7t8 BPAT.NWMT BRDY 79 7t 1
718 LAGRANDE BORA 287 28i 2
11 3
7t8 BPAT.NWMT BORA 94 9t 4
7t8 BPAT.NWMT M345 3{3t 5
718 BRDY BORA 344 341 6
718 BRDY M345 31C 3't(7
7t8 BRDY M345 833 83:I
7t8 BGSY JEFF 1 I
718 BRDY M345 4,26C 4,26(10
718 BRDY M345 31 31 11
7t8 JBSN M345 't37 13i 12
718 JEFF M345 50,50i 13
7t8 M345 GSHN 1 14
7t8 BORA M345 231 231 15
718 M345 BORA 141 141 16
718 WALLAWALLA BORA 143 14i 17
7t8 WALLAWALLA M345 3,92€3,92(18
11 19
7t8 AVAT.NWMT BORA 't,231 1,231 20
7t8 AVAT.NWMT LAGRANDE 294 29 21
718 AVAT.NWMT M345 2,021 2,021 22
7t8 AVAT.NWMT M345 s0,860 50,86(23
7t8 BORA LAGRANDE 125 12a 24
7t8 BPAT.NWMT BORA 381 381 25
718 BPAT.NWMT BORA 2,446 2,44(26
7t8 BPAT.NWMT BRDY 146 141 27
7t8 BPAT.NWMT M345 1 1,168 1 1 ,16t 28
718 BPAT.NWMT M345 1 55,754 '155,751 29
718 BRDY AVAT.NWMT 8S 8(30
7t8 BRDY BORA 1,298 1,29t 31
7t8 BRDY BORA 9,687 9,68i 32
7t8 BRDY LAGRANDE 1,701 1,701 33
718 BRDY LOLO 20 2C 34
0 9,249,909 8,2'18,90!
FERC FORM NO.1(ED. 12.90)Page 329.2
Name of Respondent
ldaho Power Company (1)
(2\
Original
Resubmission
Date of
(Mo, Da
Reoort
,YO
0411412021
Year/Period of Report
End of 2020rc4
I KAN:as ccounl 4co.1,
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each oompany 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.PacifiCorp East Siena Pacific Power NF
2 Morgan Stanley Capital Group lnc.PacifiCorp East Siena Pacific Power SFP
3 Morgan Stanley Capital Group lnc.PacifiCorp East PacifCorp East NF
4 Morgan Stanley Capital Group lnc.PacifiCorp East Siena Pacific Power NF
5 Morgan Stanley Capital Group lnc.PacifiCorp East PacifiCorp East NF
o Morgan Stanley Capital Group lnc.PacifiCorp East PacifiCorp East SFP
7 Morgan Stanley Capital Group lnc.PacifiCorp East PacifiCorp East NF
8 Morgan Stanley Capital Group Inc.PacifiCorp East Bonneville Power Administration NF
9 Morgan Stanley Capital Group lnc.PacifiCorp East Avista NF
10 Morgan Stanley Capital Group lnc.PacifiCorp East Siena Pacific Power NF
11 Morgan Stanley Capital Group lnc.PacifiCorp East Siena Pacific Power SFP
12 Morgan Stanley Capital Group lnc.Bonneville Power Adm inistration PaciliCorp East NF
13 Morgan Stanley Capitial Group lnc.Bonneville Power Administration PacifiCorp East NF
14 Morgan Stanley Capital Group lnc.Bonneville Power Administration Sierra Pacific Power NF
15 Morgan Stanley Capital Group lnc.Bonneville Power Administration Siena Pacific Power SFP
16 Morgan Stanley Capital Group lnc.Avista PacifiCorp East NF
17 Morgan Stanley Capital Group lnc.Avista PacifiCorp East SFP
18 Morgan Stanley Capital Group lnc.Avista PacifiCorp East NF
19 Morgan Stanley Capital Group lnc.Avista Bonneville Power Administration NF
20 Morgan Stanley Capital Group lnc.Avista Siena Pacific Power NF
21 Morgan Stanley Capital Group lnc.Avista Siena Pacific Power SFP
22 Morgan Stanley Capital Group lnc.ldaho Power Company PacifiCorp East NF
23 Morgan Stanley Capital Group lnc.ldaho Power Company PacifiCorp East SFP
24 Morgan Stanley Capital Group lnc.ldaho Power Company Northwestem/Pacifi Corp East NF
25 Morgan Stanley Capital Group lnc.ldaho Power Company PacifCorp East NF
26 Morgan Stanley Capital Group lnc.ldaho Power Company Siena Pacific Power NF
27 Morgan Stanley Capital Group lnc.ldaho Power Company Siena Pacific Power SFP
28 Morgan Stanley Capital Group lnc.Sierra Pacific Power NorthWestern/Pacifi Corp East NF
29 Morgan Stanley Capital Group lnc.Sierra Pacific Power PacifiCorp East NF
30 Morgan Stanley Capital Group lnc.Siena Pacific Power Bonneville Power Administration NF
31 Morgan Stanley Capital Group lnc.PacifiCorp West PacifiCorp East NF
32 Morgan Stanley Capital Group lnc.PacifiCorp West PacifiCorp East SFP
33 Morgan Stanley Capitral Group lnc.PacifiCorp West PacifiCorp East NF
34 Morgan Stanley Capital Group lnc.PacifiCorp West Sierra Pacific Power NF
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.3
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of ReDort
(Mo, Da, Yi)
o4114t2021
Year/Period of Report
End of 2O2O|Q4
AS
rI 4COXUOnUnUeO)
5. ln column (e), identify 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 U) 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.Megawa[ F1ouEi
Received(i)
Megawa[ Hours
Delivered
U)
718 BRDY M345 22,101 22,101 1
7t8 BRDY M345 126,259 126,2s8 2
718 JBSN BORA 3,059 3,05!3
7t8 JBSN M345 993 9S:4
7t8 JEFF BORA 22,fi6 22,fie 5
718 JEFF BORA 1,062 1,062 6
7t8 JEFF BRDY 52C 52e 7
7t8 JEFF LAGRANDE 345 34r 8
7t8 JEFF LOLO I t I
7t8 JEFF M345 102,787 't02,78i 10
7t8 JEFF M345 8,624 8,624 1'.l
7t8 LAGRANDE BORA 9,65C 9,65(12
7t8 LAGRANDE BRDY 2,515 2,51!13
718 LAGRANDE M345 69,99r 69,99:14
7t8 LAGRANDE M345 9,637 9,63i 15
7t8 LOLO BORA 25,08t 2s,08t 16
718 LOLO BORA 8,262 8,26i 17
7t8 LOLO BRDY 63t 63t 18
718 LOLO LAGRANDE 37C 37(19
718 LOLO M345 306,732 306,73i 20
718 LOLO M345 31,356 31,35t 21
7t8 LYPK BORA 472 47i 22
7t8 LYPK BORA 68,585 68,58t 23
7t8 LYPK BPAT.NWMT 348 34t 24
7t8 LYPK BRDY 2,700 2,70(25
il8 LYPK M345 2,117 2,11i 26
7t8 LYPK t\4345 172,056 172,05(27
718 M345 BPAT.NWMT 347 34i 28
7t8 M345 BRDY 288 28t 29
7t8 M345 LAGRANDE 1,018 1,01{30
7t8 SMLK BORA 156,316 156,31(31
718 SMLK BORA 8,876 8,87(32
7t8 SMLK BRDY 36s 36t 33
7t8 SMLK M345 3,879 3,87(34
0 8,248,90S 8,2't8,90!
FERC FORM NO.1 (ED. 12.90)Page 329.3
of Respondent (1)
(2)
Originalldaho Power Company Resubmission
Date of
(Mo, Da
Report
, Yr)
04t1412021
Year/Period of Report
End of 2O20lQ4
I KANI
as
ccounl 4co. I ,
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 crlumn (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.ldaho Power Company PacifiCorp East NF
2 Morgan Stanley Capital Group lnc.ldaho Power Company PacifiCorp East NF
3 Morgan Stanley Capital Group lnc.ldaho Power Company Sierra Pacific Power NF
4 Nevada Power Company Avista Sierra Pacific Power NF
5 Northwestem Energy NF
6 Ontario Solar NF
7 Orchard Ranch Solar NF
8 PacifiCorp lnc.PacifiCorp East Avista NF
I PacifiCorp lnc.PacifiCorp East Avista SFP
10 PacifiCorp lnc.PacifiCorp East PacifiCorp East NF
1'.!PacifiCorp lnc.PacifiCorp East PacifiCorp East SFP
12 PacifiCorp lnc.PacifiCorp East PacifiCorp East SFP
13 PacifiCorp lnc.PacifiCorp East PacifiCorp West NF
14 PacifiCorp lnc.PacifiCorp East Bonneville Power Administration NF
15 PacifiCorp lnc.PacifiCorp East Avista NF
16 PacifiCorp lnc.PacifiCorp East Sierra Pacific Power SFP
17 PacifiCorp lnc.PacifiCorp East NorthWestem/Pacifi Corp East NF
18 PacifiCorp lnc.PacifiCorp West PacifiCorp East NF
19 PacifiCorp lnc.PaciliCorp West PacifiCorp East NF
20 PacifiCorp lnc.PacifiCorp West Bonneville Power Administration NF
21 PacifCorp lnc.PacifiCorp East ldaho Power Company NF
22 PacifCorp lnc.Bonneville Power Administration PacifiCorp East NF
23 PacifiCorp lnc.Bonneville Power Administration PacifiCorp East NF
24 PacifiCorp lnc.Avista PacifiCorp East NF
25 PacifiCorp lnc.Avista PacifiCorp East SFP
26 PacifCorp lnc.Avista PacifiCorp East NF
27 PacifiCorp lnc.Avista PacifiCorp West NF
28 PacifiCorp lnc.PacifiCorp West PacifiCorp East NF
29 PacifiCorp lnc.ldaho Power Company PacifiCorp East NF
30 PacifiCorp lnc.ldaho Power Company PacifiCorp East NF
31 Pilgrim Stage Station Wind NF
32 Portland General Electric PacifiCorp East Bonneville Power Adm inistration NF
33 Portland General Electric Siena Pacific Power Bonneville Power Adm inistration SFP
34 Powerex Corporation PacifiCorp East Bonneville Power Administration NF
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.4
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
0411412021
Year/Period of Report
Endof 202UQ'4
to as t 4Sttxuontinued)
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)
(f)
Point of Delivery
(Substation or Other
Designation)
(s)
Billing
Demand
(MW)
(h)
TRANSFER OF ENERGY Line
No.Megawa[ nours
Received(i)
Megawa[ Hours
Delivered
0)
7t8 WALLAWALLA BORA 1,358 1,35t 1
7t8 WALLAWALLA BRDY 49 4(2
7t8 WALLAWALLA M345 225 22!3
718 LOLO M345 675 67t 4
7t8 5
11 6
11 7
7t8 BORA LOLO 4,556 4,55(8
718 BORA LOLO 12,4'.tC 12,4'.t(I
7t8 BRDY BORA 5,509 5,50(10
718 BRDY BORA 1,03C 1,03(11
718 BRDY BRDY 5,527 5,52i 12
7t8 BRDY HURR 35C 35('t3
7t8 BRDY LAGRANDE 15,744 15,74t 14
7t8 BRDY LOLO 1,219 1,211 15
718 BRDY M34s '128 12t 16
7t8 BRDY MLCK 9C 9(17
718 HURR BORA 1,503 1,50:18
7t8 HURR BRDY 291 291 19
718 HURR LAGRANDE 909 90(20
7t8 JEFF BGSY 1,463 1,46:21
7t8 LAGRANDE BORA 2,316 2,31(22
7t8 LAGRANDE BRDY 1,159 1,15(23
7t8 LOLO BORA 46,542 46,542 24
7t8 LOLO BORA 1,272 1,272 25
7t8 LOLO BRDY 2,134 2,134 26
718 LOLO HURR 245 24t 27
718 SMLK BRDY 322 32i 28
7t8 WALLAWALLA BORA 1 15,95C 1 15,95(29
718 WALLAWALLA BRDY 10c 10(30
11 31
7t8 BORA LAGRANOE 1 32
7t8 M345 LAGRANDE 8,40C 8,40(33
718 BORA LAGRANDE 144 144 34
8,248,90!
FERC FORM NO.1 (ED. 12-90)Page 329.4
Name of Respondent
ldaho Power Company
(1)
(2)
An Original
A Resubmission
Date of Report
(Mo, Da, Yr)
0411412021
Year/Period of Report
End of 20201Q4
I KANI as ccount 4ctr.1 )
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. ln column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior repo(ing 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 Powerex Corporation PacifiCorp East Siena Pacific Power NF
2 Powerex Corporation PacifiCorp East Sierra Pacific Power SFP
3 Powerex Corporation NorthWestem/Pacifi Corp East PacifiCorp East NF
4 Powerex Corporation NorthWestem/Pacifi Corp East Bonneville Power Administration NF
5 Powerex Corporation Northwestern/Pacifi Corp East Siena Pacific Power NF
6 Powerex Corporation Northwestem/Pacifi Corp East Sierra Pacific Power SFP
7 Powerex Corporation PacifiCorp East PacifiCorp East NF
8 Powerex Corporation PacifiCorp East Northwestem/Pacifi Corp East NF
I Powerex Corporation PacifiCorp East Bonneville Power Adm inishation NF
10 Powerex Corporation PacifiCorp East Sierra Pacific Power NF
11 Powerex Corporation PacifiCorp East Siena Pacific Power SFP
12 Powerex Corporation PacifiCorp West PacifiCorp East NF
13 Powerex Corporation PacifiCorp West PacifiCorp East NF
14 Powerex Corporation PacifiCorp West Sierra Pacific Power NF
15 Powerex Corporation PacifiCorp East PacifiCorp East NF
16 Powerex Corporation PaciliCorp East PacifiCorp East SFP
17 Powerex Corporation PacifiCorp East PacifiCorp East NF
18 Powerex Corporation PacifiCorp East Bonneville Power Administration NF
19 Powerex Corporation PaciliCorp East Sierra Pacific Power SFP
20 Powerex Corporation Bonneville Power Administration PacifiCorp East NF
2'.1 Powerex Corporation Bonneville Power Administration PacifiCorp East NF
22 Powerex Corporation Bonneville Power Administration PacifiCorp East NF
23 Powerex Corporation Bonneville Power Administration Siena Pacific Power NF
24 Powerex Corporation Avista PacifiCorp East NF
25 Powerex Corporation Avista Sierra Pacific Power NF
26 Powerex Corporation Avista Sierra Pacific Power SFP
27 Powerex Corporation Siena Pacific Power PacifiCorp East NF
28 Powerex Corporation Siena Pacific Power Bonneville Power Adm inistration NF
29 Powerex Corporation PacifiCorp West PacifiCorp East NF
30 Powerex Corporation PacifiCorp West PacifiCorp East SFP
31 Powerex Corporation PacifiCorp West PacifiCorp East NF
32 Powerex Corporalion PacifiCorp West Sierra Pacific Power NF
33 Powerex Corporation PacifiCorp West Sierra Pacific Power SFP
34 Powerex Corporation ldaho Power Company PacifiCorp East NF
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.5
Name of Respondent
ldaho Power Company (1)
(2',)
An Original
A Resubmission
Date of ReDort
(Mo, Da, Yi)
041141202',1
Year/Period of Report
End of 20201Q4
as r 4coxuon(nueo)
5. ln column (e), identify 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 (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.Megawa[ Hours
Received(i)
Megawa[ Hours
Delivered
0)
718 BORA M345 136 13(1
7t8 BORA M345 24 2t 2
7t8 BPAT.NWMT BRDY 60 6(3
7t8 BPAT.NWMT LAGRANDE 83 83 4
7t8 BPAT.NWMT M345 24 24 5
718 BPAT.NWMT M345 1,304 1,304 6
718 BRDY BORA 219 219 7
718 BRDY BPAT.NWMT C E 8
718 BRDY LAGRANDE 1,475 1,471 I
718 BRDY M345 2,000 2,00c 10
7t8 BRDY M345 57,505 57,50[11
7t8 HURR BORA 39,324 39,324 12
718 HURR BRDY 10c 10(13
718 HURR M345 144 144 14
7t8 JEFF BORA 928 92a 15
7t8 JEFF BORA 2 /16
7t8 JEFF BRDY 133 13!17
7t8 JEFF LAGRANOE 98 9t 18
718 JEFF M345 76C 76(19
7t8 LAGRANDE BORA 3,538 3,53t 20
718 LAGRANDE BRDY 444 444 21
718 LAGRANDE JBSN 3€3t 22
718 LAGRANDE M345 943 94:23
718 LOLO BORA 42,931 42,934 24
7t8 LOLO M345 10,45t 10,45t 25
7t8 LOLO M345 12,20C 12,20(26
718 M345 BORA 19t 19t 27
7t8 M345 LAGRANDE 2,350 2,35(28
718 SMLK BORA 56,488 56,48t 29
7t8 SMLK BORA 8,763 8,76:30
718 SMLK BRDY 198 19t 31
7t8 SMLK M345 5,554 5,55r 32
718 SMLK M345 2,891 2,891 33
718 WALLAWALLA BORA 57,599 57,59(34
0 g,24g,gog 8,2'18,90S
FERC FORM NO. 1 (ED. 12-90)Page 329.5
ldaho Power Company
(1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)
o411412021
Year/Period of Report
End of 20201o,4
It<ANt
to as ,ccount 45tr.1)
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Repo( 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
Classif-
cation
(d)
1 Powerex Corporation ldaho Power Company Siena Pacific Power NF
2 Rainbow Energy Marketing Corp PacifiCorp East Siena Pacific Power NF
3 Rainbow Energy Marketing Corp PacifiCorp West PacifiCorp East NF
4 Rainbow Energy Marketing Corp PacifiCorp West Bonneville Power Administration NF
5 Rainbow Energy Marketing Corp.PacifiCorp East PacifiCorp East NF
6 Rainbow Energy Marketing Corp.PacifiCorp East Siena Pacific Power NF
7 Rainbow Energy Marketing Corp.PacifiCorp East PacifiCorp East NF
I Rainbow Energy Marketing Corp.PacifiCorp East PacifiCorp East SFP
9 Rainbow Energy Marketing Corp.PacifiCorp East Sierra Pacific Power NF
10 Rainbow Energy Marketing Corp.Bonneville Power Adm inistration PacifiCorp East NF
11 Rainbow Energy Marketing Corp.Bonneville Power Administration Siena Pacific Power NF
12 Rainbow Energy Marketing Corp.Avista PacifiCorp East NF
13 Rainbow Energy Marketing Corp.Avista Sierra Pacific Power NF
14 Rainbow Energy Marketing Corp.Avista Sierra Pacific Power SFP
15 Rainbow Energy Marketing Corp.Siena Pacific Power PacifiCorp East NF
16 Rainbow Energy Marketing Corp.PacifiCorp West PacifiCorp East NF
17 Rainbow Energy Marketing Corp.ldaho Power Company PacifiCorp East NF
18 Rainbow Energy Marketing Corp.ldaho Power Company Sierra Pacific Power NF
19 Rockland Wind NF
20 Sawtooth Wind NF
21 Shell Energy North America (US), L.P PacifiCorp East PacifiCorp East NF
22 Shell Energy North America (US), L.P PacifiCorp East PacifiCorp East SFP
23 Shell Energy North America (US), L.P PacifiCorp East Bonneville Power Administration NF
24 Shell Energy North America (US), L.P PacifiCorp East Siena Pacific Power NF
25 Shell Energy North America (US), L.P PacifiCorp East Siena Pacific Power SFP
26 Shell Energy North America (US), L.P PacifiCorp East PacifiCorp West NF
27 Shell Energy North America (US), L.P NorthWestern/Pacifi Corp East PacifiCorp East NF
28 Shell Energy North America (US), L.P NorthWestem/Pacifi Corp East PacifiCorp East NF
29 Shell Energy North America (US), L.P NorthWestem/Pacifi Corp East Siena Pacific Power NF
30 Shell Energy North America (US), L.P PacifiCorp East Bonneville Power Administration NF
31 Shell Energy North America (US), L.P PacifiCorp East Sierra Pacific Power NF
32 Shell Energy North America (US), L.P PacifiCorp West PacifiCorp East NF
33 Shell Energy North America (US), L.P PacifiCorp West Bonneville Power Administration NF
34 Shell Energy North America (US), L.P PacifiCorp East Bonneville Power Administration NF
TOTAL
FERC FORM NO.I (ED. 12-90)Page 328.6
Name of Respondent
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of ReDort(Mo, Da, Yi)
0411412021
Year/Period of Report
End of 20201Q4
as
It 4btrxuonunueo)
5. ln column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or oontract
designations under which servioe, 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. Repo( 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
Tarifi 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)
Megawatt Hours
Delivered(i)
7t8 WALLAWALLA M345 231 231 1
718 BORA M345 19S 19!2
7t8 HURR BORA 771 777 3
7t8 HURR LAGRANDE 5t JI 4
7t8 JBSN BORA 4 4 5
7t8 JBSN M345 123 124 6
718 JEFF BORA 937 93i 7
7t8 JEFF BORA 48C 48(8
7t8 JEFF M345 508 50t 9
718 LAGRANDE BORA 755 75t 10
7t8 LAGRANDE M345 'r,560 1,56(11
7t8 LOLO BORA 9,490 9,49(12
7t8 LOLO M345 4,241 4,241 13
718 LOLO M345 1,000 1,00(14
718 M345 BORA 456 45t 15
718 SMLK BORA 1,73C 1,73(16
718 WALLAWALLA BORA 28,ffiA 28,664 17
7t8 WALLAWALLA M345 2,30C 2,30(18
11 19
11 20
7t8 BORA BRDY 36 3t 21
7t8 BORA BRDY 36C 36(22
718 BORA LAGRANDE 2,313 2,31i 23
7t8 BORA M345 1,568 1,56t 24
718 BORA M345 1,038 1,03t 25
7t8 BORA M500 883 88:26
7t8 BPAT.NWMT BORA 211 21!27
718 BPAT.NWMT BRDY 50€50(28
718 BPAT.NWMT M345 2,982 2,582 29
7t8 BRDY LAGRANDE 1,322 1,32i 30
7t8 BRDY M345 7,81C 7,81(31
718 HURR BORA 33C 33(32
7t8 HURR LAGRANDE 7e 7t 33
718 JBSN LAGRANDE 48€48(34
(g,24g,gog 8,2'f8,90!
FERC FORM NO.1 (ED.12.90)Page 329.6
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Reoort(Mo, Da, Yi)
o411412021
Year/Period of Report
End of 20201Q4
I F(ANi MIDiIUN UT ELEU IT(IUI I Y TUl( L,, I NEl(5 tf
I ncludino transactions referred to as'wheelino'ccount 45ti.1 )
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General 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 East Siena Pacific Power NF
2 Shell Energy North America (US), L.P PacifiCorp East Sierra Pacific Power NF
3 Shell Energy North America (US), L.P Bonneville Power Administration PacifiCorp East NF
4 Shell Energy North America (US), L.P Bonneville Power Administration PacifiCorp East NF
5 Shell Energy North America (US), L.P.Bonneville Power Administration Siena Pacific Power NF
6 Shell Energy North America (US), L.P Bonneville Power Administration Siena Pacific Power SFP
7 Shell Energy North America (US), L.P Avista PacifiCorp East NF
8 Shell Energy North America (US), L.P Avista PacifiCorp East SFP
9 Shell Energy North America (US), L.P Avista PacifiCorp East NF
10 Shell Energy North America (US), L.P Avista PacifiCorp East SFP
11 Shell Energy North America (US), L.P Avista Siena Pacific Power NF
12 Shell Energy North America (US), L.P Avista Sierra Pacific Power SFP
13 Shell Energy North America (US), L.P Sierra Pacific Power PacifiCorp East NF
14 Shell Energy North America (US), L.P Siena Pacific Power PacifiCorp East SFP
15 Shell Energy North America (US), L.P Siena Pacific Power PacifiCorp East NF
16 Shell Energy North America (US), L.P Sierra Pacific Power Bonneville Power Administration NF
17 Shell Energy North America (US), L.P PacifiCorp West PacifiCorp East NF
18 Shell Energy No(h America (US), L.P PacifiCorp West PacifiCorp East NF
19 Shell Energy North America (US), L.P PacifiCorp West PacifiCorp East SFP
20 Shell Energy North America (US), L.P PacifiCorp West PacifiCorp East NF
21 Shell Energy North America (US), L.P PacifiCorp West PacifiCorp East SFP
22 Shell Energy North America (US), L.P PacifiCorp West PacifCorp East NF
23 Shell Energy North America (US), L.P PaciliCorp West PacifiCorp East SFP
24 Shell Energy North America (US), L.P PacifiCorp West Siena Pacific Power NF
25 Shell Energy North America (US), L.P ldaho Power Company PacifiCorp East NF
26 Shell Energy North America (US), L.P ldaho Power Company PacifiCorp East SFP
27 Shell Energy North America (US), L.P ldaho Power Company PacifiCorp East NF
28 Shell Energy North America (US), L.P ldaho Power Company PacifiCorp East SFP
29 Shell Energy North America (US), L.P ldaho Power Company Sierra Pacific Power NF
30 Shell Energy North America (US), L.P ldaho Power Company Siena Pacific Power SFP
31 Shell Energy North America (US), L.P NF
32 Simcoe Solar NF
33 TEC Energy lnc.PacifiCorp East Siena Pacific Power NF
34 TEC Energy lnc.Sierra Pacific Power PacifiCorp East NF
TOTAL
FERC FORM NO.1 (ED. 12.90)Page 328.7
Name of Respondent
ldaho Power Company
s:
(1)
(2)
An Original
A Resubmission
Date of Reoort(Mo, Da, Yi)
04t14t2021
Year/Period of Report
End of 202OlA4
to as t 4boxuontnueo)
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 servioe. ln column (f), repo( 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)
(s)
Billing
Demand
(MW)
(h)
TRANSFER OF ENERGY Line
No.Megawatt Hours
Received(i)
Megawatt Hours
Delivered
0)
7t8 JBSN M345 261 261 1
7t8 JEFF M345 317 31i 2
718 LAGRANDE BORA 3,787 3,78i 3
7t8 LAGRANDE BRDY 3,758 3,75t 4
7t8 LAGRANDE t\r345 44,114 44,111 5
7t8 LAGRANDE t\4345 3,577 3,57;6
7t8 LOLO BORA 25,723 25,72i 7
7t8 LOLO BORA 60 6(I
7t8 LOLO BRDY 1,463 1,46i I
718 LOLO BRDY 6,086 6,08t 10
718 LOLO M345 105,454 105,43 11
7t8 LOLO M345 12,071 12,07'.12
7t8 M345 BORA 17,784 17,78(13
7t8 M345 BORA 1,665 1,66{14
7t8 M34s BRDY 928 92t 15
718 M345 LAGRANDE 2,',t26 2,121 '16
7t8 M500 BORA 16,151 16,15'17
7t8 M500 BRDY 1,554 1,554 18
7t8 M500 BRDY 81S 81!19
7t8 SMLK BORA 8,344 8,344 20
7t8 SMLK BORA 1,877 1,877 21
7t8 SMLK BRDY 1,688 1,688 22
718 SMLK BRDY 2,308 2,308 23
7t8 SMLK M34s 3,479 3,475 24
718 WALLAWALLA BORA 76,800 76,80C 25
7t8 WALLAWALLA BORA 124 12C 26
7t8 WALLAWALLA BRDY 27 344 27,UC 27
7t8 WALLAWALLA BRDY 1 1,354 11,354 28
7t8 WALLAWALLA M345 173,325 173,324 29
7t8 WALLAWALLA M345 37,382 37,382 30
11 31
11 32
7t8 BRDY M345 108 10t 33
718 M345 BRDY o c u
0 8,248,909 8,2'08,90!
FERC FORM NO.1 (ED. 12-90)Page 329.7
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
o4t14t2021
Year/Period of Report
End of 2O20lA4
I KANi to as ccount 45ti.1 )
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. ln column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true.ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General lnstruction for definitions of codes.
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 Tenaska Power Services PacifiCorp East Sierra Pacific Power NF
2 Tenaska Power Services NorthWestem/Pacifi Corp East PacifiCorp East NF
3 Tenaska Power Services PacifiCorp East Siena Pacific Power NF
4 Tenaska Power Services Bonneville Power Administration PacifiCorp East NF
5 Tenaska Power Services Siena Pacific Power PacifiCorp East NF
6 Tenaska Power Services ldaho Power Company PacifiCorp East SFP
7 Tenaska Power Services ldaho Power Company PacifiCorp East NF
I The Energy Authority, lnc.PacifiCorp East Bonneville Power Adm inistration NF
I The Energy Authority, lnc.PacifiCorp East PacifiCorp West NF
10 The Energy Authority, lnc.NorthWestem/Pacifi Corp East PacifiCorp East NF
11 The Energy Authority, lnc.Northwestern/Pacifi Corp East Sierra Pacific Power NF
12 The Energy Authority, lnc.PacifiCorp East Bonneville Power Administration NF
13 The Energy Authority, lnc.PacifiCorp East Siena Pacific Power NF
14 The Energy Authority, lnc.Bonneville Power Administration PacifiCorp East NF
15 The Energy Authority, lnc.Bonneville Power Administration Sierra Pacific Power NF
16 The Energy Authority, lnc.Avista PacifiCorp East NF
17 The Energy Authority, lnc.Avista PacifiCorp East NF
18 The Energy Authority, lnc.Siena Pacific Power NorthWestem/Pacifi Corp East NF
19 The Energy Authority, lnc.Sierra Pacific Power PacifiCorp East NF
20 The Energy Authority, lnc.Sierra Pacific Power Bonneville Power Administration NF
2',1 The Energy Authority, lnc.PacifiCorp West PacifiCorp East NF
22 The Energy Authority, lnc.PacifiCorp West PacifiCorp East NF
23 The Energy Authority, lnc.PacifiCorp West PacifiCorp East NF
24 The Energy Authority, lnc.ldaho Power Company PacifiCorp East NF
25 The Energy Authority, lnc.ldaho Power Company PacifiCorp East NF
26 The Energy Authority, lnc.ldaho Power Company Siena Pacific Power NF
27 Thousand Springs Wind NF
28 Transalta Energy Marketing (U.S.) lnc.NorthWestern/Pacifi Corp East PacifiCorp East NF
29 Transalta Energy Marketing (U.S.) lnc.PacifiCorp East NorthWestern/Pacifi Corp East NF
30 Transalta Energy Marketing (U.S.) lnc.PacifiCorp East PacifiCorp West NF
31 Transalta Energy Marketing (U.S.) lnc.PacifiCorp East Bonneville Power Administration NF
32 Transalta Energy Marketing (U.S.) lnc.NorthWestern/Pacifi Corp East PacifiCorp East NF
33 Transalta Energy Marketing (U.S.) lnc.NorthWestem/Pacifi Corp East PacifiCorp East NF
34 Transalta Energy Marketing (U.S.) lnc.Northwestern/Pacifi Corp East Bonneville Power Administration NF
TOTAL
FERC FORM NO.1 (ED. 12.90)Page 328'8
Name of Respondent
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
0411412021
Year/Period of Report
End of 20201Q4
as rt 45ttxuonunueo)
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 servioe, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. ln column (0, report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. ln column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and 0) the total megawatthours received and delivered.
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(0
Point of Delivery
(Substation or Other
Designation)
(g)
Billing
Demand
(MW)
(h)
TRANSFER OF ENERGY Line
No.Megawatt Hours
Received(i)
Megawatt Hours
Delivered
U)
718 BORA M345 24 2t 1
718 BPAT.NWMT BRDY 54 5t 2
7t8 BRDY M345 53 5i 3
7t8 LAGRANDE BRDY 17 11 4
718 M345 BRDY 655 65f 5
718 MDSK GSHN 2,003 2,00i 6
718 WALLAWALLA BRDY 968 96t 7
718 BORA LAGRANDE 100 10(8
7t8 BORA M500 E a 9
718 BPAT.NWMT BRDY 640 64(10
718 BPAT,NWMT tu345 1,882 1,88i 11
718 BRDY LAGRANDE 234 23(12
718 JEFF tvt345 60 6(13
7t8 LAGRANDE BRDY 25 2t 't4
7t8 LAGRANDE M345 1,378 1,37t 15
718 LOLO BORA 205 20t 16
718 LOLO BRDY 1s0 15('t7
718 M345 BPAT.NWMT E a 18
7t8 M345 BRDY 100 't0(19
718 M345 LAGRANDE 2,804 2,801 20
718 M500 BRDY 282 281 2'.1
7t8 SMLK BORA 354 35u 22
7t8 SMLK BRDY 55 tt 23
718 WALLAWALLA BORA 745 741 24
718 WALLAWALLA BRDY MA 14(25
718 WALLAWALLA tv345 352 35:26
11 27
7t8 AVAT.NWMT BRDY 50 5(28
7t8 BORA AVAT.NWMT 177 171 29
718 BORA H500 78 7t 30
718 BORA LAGRANDE 1,648 1,64{31
718 BPAT.NWMT BORA 38 3{32
718 BPAT,NWMT BRDY 194 19r 33
7t8 BPAT.NWMT LAGRANDE 4 a 34
0 8,248,909 8,2118,909
FERC FORM NO. I (ED. 12.90)Page 329.8
Name of Respondent
ldaho Power Company
I his Reoon ls:(1) []Rn orisinal(2) llA Resubmission
Date of Report
(Mo, Da, Yr)
0411412021
Year/Period of Report
End of 20201Q4
I KAN|as ccounl 4co.1,
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. ln column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General lnstruction for definitions of codes.
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 Transalta Energy Marketing (U.S.) lnc.NorthWestem/Pacifi Corp East Siena Pacific Power NF
2 Transalta Energy Marketing (U.S.) lnc.PacifiCorp East PaciliCorp East NF
3 Transalta Energy Marketing (U.S.) lnc.PacifiCorp East Bonneville Power Administration NF
4 Transalta Energy Marketing (U.S.) lnc.PacifiCorp East Sierra Pacific Power NF
5 Transalta Energy Marketing (U.S.) lnc.PacifiCorp West PacifiCorp East NF
6 Transalta Energy Marketing (U.S.) lnc.PacifiCorp West PacifiCorp East NF
7 Transalta Energy Marketing (U.S.) lnc.PacifiCorp West Siena Pacific Power NF
8 Transalta Energy Marketing (U.S.) lnc.ldaho Power Company PacifiCorp East NF
I Transalta Energy Marketing (U.S.) lnc.ldaho Power Company Bonneville Power Adm inistration NF
10 Transalta Energy Marketing (U.S.) lnc.PacifiCorp East PacifiCorp East NF
11 Transalta Energy Marketing (U.S.) lnc.PacifiCorp East Bonneville Power Administration NF
12 Transalta Energy Marketing (U.S.) lnc.PacifiCorp East Siena Pacific Power NF
13 Transalta Energy Marketing (U.S.) lnc.PacifiCorp East PacifiCorp West NF
14 Transalta Energy Marketing (U.S.) lnc.PacifiCorp East PacifiCorp East NF
15 Transalta Energy Marketing (U.S.) lnc.PacifiCorp East PacifiCorp East NF
16 Transalta Energy Marketing (U.S.) lnc.Bonneville Power Administration PacifiCorp East NF
17 Transalta Energy Marketing (U.S.) lnc.Bonneville Power Administration PacifiCorp East NF
18 Transalta Energy Marketing (U.S.) lnc.Bonneville Power Administration Sierra Pacific Power NF
19 Transalta Energy Marketing (U.S.) lnc.Avista PacifiCorp East NF
20 Transalta Energy Marketing (U.S.) lnc.Avista Siena Pacific Power NF
21 Transalta Energy Marketing (U.S.) lnc.Sierra Pacific Power NorthWestem/Pacifi Corp East NF
22 Transalta Energy Marketing (U.S.) lnc.Sierra Pacific Power Bonneville Power Administration NF
23 Transalta Energy Marketing (U.S.) lnc.PacifiCorp West PacifiCorp East NF
24 Transalta Energy Marketing (U.S.) lnc.PacifiCorp West PacifiCorp East SFP
25 Transalta Energy Marketing (U.S.) lnc.PacifiCorp West PacifiCorp East NF
26 Transalta Energy Marketing (U.S.) lnc.PacifiCorp West PacifiCorp East NF
27 Transalta Energy Marketing (U.S.) lnc.PacifiCorp West Siena Pacific Power NF
28 Transalta Energy Marketing (U.S.) lnc.PacifiCorp West PacifiCorp West NF
29 Transalta Energy Marketing (U.S.) lnc.ldaho Power Company PacifiCorp East NF
30 Transalta Energy Marketing (U.S.) lnc.ldaho Power Company PacifiCorp East NF
31 Transalta Energy Marketing (U.S.) lnc.ldaho Power Company Bonneville Power Adm inistration NF
32 Transalta Energy Marketing (U.S.) lnc.ldaho Power Company Sierra Pacific Power NF
33 Utah Associated Municipal Power Systems PacifiCorp East Siena Pacific Power NF
34 Vale Solar NF
TOTAL
FERC FORi' NO.1 (ED. t2-90)Page 328.9
Name of Respondent
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of ReDort(Mo, Da, Yi)
o4l't4t2021
Year/Period of Report
End of 20201Q4
as t 4btrxuomnueo)
5. ln column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or oontract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. ln column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. ln column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j) the total megawatthours received and delivered.
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(0
Point of Delivery
(Substation or Other
Designation)
(s)
Billing
Demand
(MW)
(h)
TRANSFER OF ENERGY Line
No.Megawatt Hours
Received(i)
Megawalt Hours
Delivered
0)
7t8 BPAT,NWMT M345 180 18(1
7t8 BRDY BORA 56 5(2
7t8 BRDY LAGRANDE 475 47!3
7t8 BRDY M345 60 6(4
7t8 HURR BORA 2,310 2,3',1(5
7t8 HURR JBSN 7A 7(6
7t8 HURR M345 247 241 7
7t8 IPCOGEN JBSN 50 5(8
7t8 IPCOGEN LAGRANDE 75 7!I
7t8 JBSN BORA 't44 14t 10
7t8 JBSN LAGRANDE 193 19i 't'l
718 JBSN M345 57 5;12
718 JBSN POP 't47 14t 13
7t8 JEFF BORA 464 461 't4
718 JEFF BRDY 175 17!15
718 LAGRANDE BORA 6,256 6,25(16
718 LAGRANDE BRDY 'tu 184 't7
7t8 LAGRANDE M345 6,702 6,702 18
718 LOLO BORA 4,362 4,36:19
7t8 LOLO M34s 2,664 2,664 20
7t8 M345 BPAT.NWMT 204 20c 21
7t8 M34s LAGRANDE 1,521 1,s21 22
718 SMLK BORA 31,280 31,28C 23
718 SMLK BORA 862 862 24
718 SMLK BRDY 400 40c 25
7t8 SMLK JBSN 695 695 26
718 SMLK M345 3,332 3,332 27
7t8 SMLK POP 160 16C 28
718 WALLAWALLA BORA 38,215 38,214 2S
718 WALLAWALLA BRDY 50 5C 30
7t8 WALLAWALLA LAGRANDE 135 13[31
7t8 WALLAWALLA M345 3,454 3,454 32
7t8 BORA M345 133 133 33
11 34
0 8,2,08,909 8,2'{8,90!
FERC FORM NO.1 (ED. 12-90)Page 329.9
Name of Respondent
ldaho Power Company (1)
(2)
Original
Resubmission
Date of Reoort(Mo, Da, Yi)
o4t14t2021
Year/Period of Report
End of 20201Q4
I KANi as ccount 456.1 )
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or 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 Mtol lnc.ldaho Power Company Siena Pacific Power SFP
2
3
4
5
6
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
34
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.10
Name Respondent
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
o411412021
Year/Period of Report
End of 202OlQ4
to as
5. ln column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations underwhich servioe, 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 megawafts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j) the total megawatthours received and delivered.
FERC Rate
Schedule of
Tarifi 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.Megawa[ Hours
Received0
Megawa[ Hours
Delivered(i)
718 MDSK M345 631 631 1
2
3
4
5
6
7
I
o
10
't1
12
13
't4
15
't6
17
18
19
20
2'l
22
23
24
25
26
27
28
29
30
31
32
33
34
0 8,2'[8,909 8,2'18,90S
FERC FORM NO.1 (EO.12-90)Page 329.10
ldaho Power Company
(1)
(2t
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
0411412021
Year/Period of Report
End of 20201Q4
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 0) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401 , Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Gharges
($)
o
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Lrne
No.
1,527,900 130,076 1,657,976 1
1,579,227 't31,720 't,710,947 2
6,251 ,138 452,093 6,703,231 3
18,798 18,798 4
83,000 83,000 5
9,658 883 10,541 6
54,857 54,857 7
1,700 1,700 8
14,'t68 14,168 I
10
4,056,767 4,056,767 11
2,839,235 2,839,235 12
6,742,626 6,742,626 13
2,825,914 2,825,910 14
2,797,77A 2,797,770 15
2,797,774 2,797,770 16
17
263 263 18
6,089 6,089 't9
oz 62 20
1,570 1,570 2',1
15,304 15,304 22
499 499 23
1 ,310 1,310 24
1,378 1,378 25
3,422 3,422 26
1,768 1,768 27
6,776 6,776 28
5,815 5,815 29
10,233 10,233 30
315 315 31
683 683 32
2',t0 2',to 33
2,194 2,190 u
9,367,923 34,539,8't'l 0 43,507,734
FERC FORM NO.1 (ED. 12-90)Page 330
of Respondent
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
04t14t2021
Year/Period of Report
End of 2O2O|A4
as
9. ln column (k) through (n), report the revenue amounts as shown on bills or vouchers. ln column (k), provide revenues from demand
charges related to the billing demand reported in column (h). ln column (l), provide revenues from energy charges related to the
amount of energy transferred. ln column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). lf no monetary settlement was made, enter zero (1 101 1) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401 , Lines 16 and 1 7, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(t)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Ltne
No.
5,933 5,933 1
1 1 2
938 938 3
82 82 4
83 83 5
293 293 6
88s 885 7
8
4 4 o
838 838 10
22,789 22,789 11
3 3 12
62 62 13
26,403 26,403 14
9,490 9,490 15
2,449 2,449 16
1,898 1,898 17
43,294 43,294 18
3,404 3,404 19
216,690 216,690 20
765 765 21
2,35',1 2,351 22
2,082 2,082 23
980 980 24
3,490 3,490 25
127,598 127,598 26
992 992 27
6,233 6,233 28
348 348 29
1,523 1,523 30
44,547 44,547 31
1,362 't,362 32
419 419 33
2,802 2,802 34
9,367,923 34,539,81 1 0 13,907,7U
FERC FORM NO. I (ED. 12.90)Page 330.1
Name of Respondent
ldaho Power Company
(1)
(2)
Original
Resubmission
Date of ReDort
(Mo, Da, Yi)
0411412021
Year/Period of Report
End of 20201Q4
as
9. ln column (k) through (n), report the revenue amounts as shown on bills or vouchers. ln column (k), provide revenues from demand
charges related to the billing demand reported in column (h). ln column (l), provide revenues from energy charges related to the
amount of energy transferred. ln column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). lf no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and 0) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(t)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Line
No.
362 362 1
1,314 1,314 2
23,389 23,389 3
988 988 4
357 357 5
3,616 3,616 6
3,259 3,259 7
8,757 8,757 I
8 8 9
35,414 35,4',t4 10
2s8 258 11
1,139 1,139 12
4,173 4,',tl3 13
8 8 14
1,517 1,5',t7 15
926 926 16
939 939 17
2s,80s 25,809 18
9,107 9,107 19
2,835 2,835 20
677 677 21
4,655 4,655 22
1',17,143 117,143 23
288 288 24
878 878 25
5,634 5,634 26
336 336 27
25,723 25,723 28
358,740 358,740 29
205 205 30
2,990 2,990 31
22,312 22,312 32
3,918 3,918 33
46 46 u
9,367,923 34,539,81't 0 '[3,907,73'{
FERC FORM NO. r (ED.12-90)Page 330.2
ldaho Power Company (1)
(2)
Original
Resubmission
Date of(Mo, Da
Report
, Yr)
04t14t2021
Year/Period of Report
End of 20201Q4
as
9. ln column (k) through (n), report the revenue amounts as shown on bills or vouchers. ln column (k), provide revenues from demand
charges related to the billing demand reported in column (h). ln column (l), provide revenues from energy charges related to the
amount of energy transferred. ln column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). lf no monetary settlement was made, enter zero (1 101 1) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and 0) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401 , Lines 16 and 17 , respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(t)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Llne
No.
50,904 50,904 1
290,806 290,806 2
7,046 7,046 3
2,287 2,287 4
s1,975 51,975 5
2,446 2,446 6
1,212 1,212 7
795 795 I
18 't8 I
2%,744 2%,744 10
19,863 19,863 11
22,226 22,226 12
5,793 5,793 13
16'.t,216 161,216 14
22,196 22J94 15
57,777 57,777 16
't9,029 19,029 17
1,463 1,463 18
866 866 19
706,479 7otr,479 20
72,22',1 72,221 21
1,087 1,087 22
157,968 157,968 23
802 802 24
6,219 6,219 25
4,876 4,876 26
396,287 396,287 27
799 799 28
663 663 29
2,345 2,345 30
360,034 360,034 31
20,444 20,444 32
841 841 33
8,934 8,934 u
9,367,923 34,539,811 0 43,907,73t1
FERC FORM NO.1 (ED. 12-90)Page 330.3
Name Respondent
ldaho Power Company
(1)
(2)
An Original
A Resubmission
Date of Reoort(Mo, Da, Yi)
0411412021
Year/Period of Report
End of 2O2O|Q4
as
9. ln column (k) through (n), report the revenue amounts as shown on bills or vouchers. ln column (k), provide revenues from demand
charges related to the billing demand reported in column (h). ln column (l), provide revenues from energy charges related to the
amount of energy transferred. ln column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). lf no monetary settlement was made, enter zero (1 101 1) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(t)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Ltne
No.
3,128 3,128 1
113 113 2
518 518 3
3,979 3,979 4
84 84 5
1 1,909 1 1,909 6
613 613 7
38,669 38,669 8
105,329 105,329 I
46,757 46,757 10
8,742 8,742 't'l
46,910 46,910 12
2,971 2,971 13
133,634 133,634 14
10,346 10,346 15
1,086 1,086 16
764 764 17
12,757 '12,757 18
2,470 2,470 19
7,7'.ts 7,715 20
12,417 12,4',t7 21
19,657 't9,657 22
9,837 9,837 23
395,021 395,021 24
10,796 10,796 25
18,112 18,112 26
2,O79 2,079 27
2,741 2,741 28
984,114 984,114 29
849 84S 30
2,496 2,45fi 31
4 4 32
30,025 30,025 33
914 914 34
9,367,923 34,539,811 0 43,907,734
FERC FORM NO.1 (ED. 12-90)Page 330.4
Name of Respondent
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Reoort(Mo, Da, Yi)
041141202'.1
Year/Period of Report
End of 20201Q4
as
9. ln column (k) through (n), report the revenue amounts as shown on bills or vouchers. ln column (k), provide revenues from demand
charges related to the billing demand reported in column (h). ln column (l), provide revenues from energy charges related to the
amount of energy transfened. ln column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). lf no monetary settlement was made, enter zero (1 101 1) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(t)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Lrne
No.
864 864 ,|
152 152 2
381 38'l 3
527 527 4
1s2 152 5
8,280 8,280 6
1,391 1,391 7
32 32 8
9,365 9,365 o
12,699 12,699 10
365,126 365,126 11
249,686 249,686 12
635 635 13
914 914 14
5,873 5,873 l5
13 13 16
844 844 17
622 622 18
4,826 4,826 19
22,464 22,464 20
2,819 2,819 21
241 24',\22
5,988 5,988 23
272,614 272,6'.14 24
66,384 66,384 25
77,463 77,463 26
't,257 1,257 27
14,921 14,921 28
358,668 358,668 29
55,640 55,640 30
1,257 1,257 3'l
35,265 35,265 32
18,356 18,356 33
365,723 365,723 34
9,367,923 34,539,81 1 0 43,907,734
FERC FORM NO.1 (ED. 12.90)Page 330.5
ldaho Power Company
(1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
041141202',1
Year/Period of Report
End of 20201Q4
as
9. ln column (k) through (n), report the revenue amounts as shown on bills or vouchers. ln column (k), provide revenues from demand
charges related to the billing demand reported in column (h). ln column (l), provide revenues from energy charges related to the
amount of energy transfened. ln column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). lf no monetary settlement was made, enter zero (1 101 1) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
'10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401 , Lines 16 and 17 , respectively.
1't. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
o
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Lrne
No.
1,467 1,467 1
'1,'141 't,141 2
4,455 4,455 3
183 183 4
23 23 5
705 705 6
5,372 5,372 7
2,7s2 2,752 8
2,913 2,913 I
4,329 4,329 10
8,944 8,944 11
54,409 54,409 12
24,315 24,315 13
5,733 5,733 14
2,614 2,614 15
9,919 9,919 16
164,340 164,340 17
13,187 13,',!87 18
8,482 8,482 19
7,750 7,750 20
155 155 21
1,550 1,550 22
9,956 9,956 23
6,749 6,749 24
4,468 4,468 25
3,801 3,801 26
925 925 27
2,178 2,178 28
12,835 12,835 29
5,690 5,690 30
33,616 33,616 31
1,420 't,420 32
336 336 33
2,092 2,092 34
9,367,923 34,539,81 1 0 43,907,7U
FERC FORM NO.1 (ED. 12-90)Page 330.6
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of ReDort
(Mo, Da, Yi)
041141202',1
Year/Period of Report
End of 202OlQ4
as
9. ln column (k) through (n), report the revenue amounts as shown on bills or vouchers. ln column (k), provide revenues from demand
charges related to the billing demand reported in column (h). ln column (l), provide revenues from energy charges related to the
amount of energy transferred. ln column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). lf no monetary settlement was made, enter zero (1 101 1) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and O must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401 , Lines 16 and 17 , respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(t)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Lrne
No.
1j23 't,123 1
1,364 1,364 2
16,300 16,300 3
16,175 1 6,1 75 4
189,878 189,878 5
15,396 15,396 6
110,718 '110,718 7
258 258 8
6,297 6,297 I
26,196 26,196 10
453,901 453,901 11
51,957 51,957 12
76,530 76,530 't3
7,167 7,167 14
3,994 3,994 15
9,151 9,151 16
69,518 69,518 17
6,689 6,689 18
3,525 3,525 't9
35,915 35,91s 20
8,079 8,079 21
7,266 7,266 22
9,934 9,934 23
'14,975 't4,975 24
330,567 330,567 25
517 517 26
117,678 117,678 27
48,871 48,871 28
746,035 746,035 29
160,902 160,902 30
8,760 8,760 31
2,277 2,277 32
1,480 1,480 33
123 123 34
9,367,923 34,539,81 1 0 43,907,734
FERC FORM NO.1 (ED. 12-90)Page 330.7
Name of Respondent
ldaho Power Company
(1)
(2)
An Original
A Resubmission
Date of Reoort(Mo, Da, Yi)
04t14t202',1
Year/Period of Report
End of 202OlQ4
as
9. ln column (k) through (n), report the revenue amounts as shown on bills or vouchers. ln column (k), provide revenues from demand
charges related to the billing demand reported in column (h). ln column (l), provide revenues from energy charges related to the
amount of energy transferred. ln column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). lf no monetary settlement was made, enter zero (1 101 1) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and 0) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401 , Lines 16 and 17 , respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(t)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Ltne
No.
108 108 1
243 243 2
238 238 3
76 76 4
2,945 2,945 5
9,006 9,006 6
4,352 4,352 7
500 500 I
25 25 I
3,202 3,202 10
9,41s 9,415 11
1,'t'',l.1,'t51 12
300 300 13
125 125 14
6,894 6,894 15
1,026 1,026 16
750 750 17
25 25 18
500 500 19
't4,027 14,027 20
't,411 1,411 21
1,771 1,771 22
275 275 23
3,727 3,727 24
700 700 25
1,761 1,761 26
10,978 10,978 27
326 326 28
1,155 1,155 29
509 509 30
10,754 10,754 31
248 248 32
1,266 1,266 33
33 33 34
9,367,923 34,539,81 1 0 43,907,734
FERC FORM NO.1 (ED.12-90)Page 330.8
Name
ldaho Power Company
(1)
(2)
An Original
A Resubmission
Date of ReDort(Mo, Da, Yi)
0411412021
Year/Period of Report
End of 2O2O|Q4
to as
9. ln column (k) through (n), report the revenue amounts as shown on bills or vouchers. ln column (k), provide revenues from demand
charges related to the billing demand repo(ed in column (h). ln column (l), provide revenues from energy charges related to the
amount of energy transferred. ln column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). lf no monetary settlement was made, enter zero (1 1011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and O must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401 , Lines 16 and 17 , respectively.
1'l . Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
0)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Lrne
No.
1,',t75 1,175 1
365 365 2
3,100 3,1 00 3
392 392 4
15,074 15,074 5
457 457 6
1,612 1,612 7
326 326 I
483 489 I
940 940 10
1,259 '1,259 11
372 372 12
9s9 959 13
3,028 3,028 't4
1,142 1,142 15
40,824 40,824 16
1,201 't,20'l 17
43,735 43,735 18
28,465 28,465 19
17,384 17,384 20
1,305 't,305 21
9,925 9,925 22
204,121 204,12'l 23
5,625 5,625 24
2,610 2,610 25
4,535 4,535 26
21,743 21,743 27
1,044 1,044 28
249,376 249,376 29
326 326 30
881 881 3'l
22,539 22,539 32
812 8't2 33
1,866 1,866 34
9,367,923 34,539,811 0 '03,907,73,f
FERC FORM NO.1 (ED.12-90)Page 330.9
ldaho Power Company (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)
o4l'141202'l
Year/Period of Report
End of 20201Q4
9. ln column (k) through (n), report the revenue amounts as shown on bills or vouchers. ln column (k), provide revenues from demand
charges related to the billing demand reported in column (h). ln column (l), provide revenues from energy charges related to the
amount of energy transferred. ln column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). lf no monetary settlement was made, enter zero (1 101 1) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and 0) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401 , Lines 16 and 17 , respectively.
11 . Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(t)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Ltne
No.
4,992 4,992 1
2
3
4
5
6
7
8
I
10
11
12
13
14
15
16
17
18
19
20
2'l
22
23
24
25
26
27
28
29
30
31
32
33
34
9,367,923 34,539,81 1 0 43,907,734
FERC FORM NO.1 (ED.12-90)Page 330.10
Name of Respondent
ldaho Power Comoany
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
041't412021
Year/Period of Report
2020to,4
FOOTNOTE DATA
328 Line No.: I Column: a
The network se ce agreement between Idaho Powerfor the Ore Trail Electric erative ]-res ember 30, 2028.
t e Power
ss
stra on
Access Transmission Tariff, Schedule 9 Network In
11 ng demand for network se
t on on Se ce
The
Power
ce s the customer's demand at the t me
328 Line No.: 1 Column: e
328 Line No.: 1 Column: h
transmission s tem ak and varies
serv ce agreement tlileen Power Bonnev e Power Administration
month
net
328 Line No.: 2 Column: a
for the USBR res December 31 , 2023.
The network serv ce agreement between ldaho Power and the Bonnev lle Power strat328Line No; 3 Column: a
328 Line No.:4 Column: a
for the Priorit Firm Customers
contract ween I Power
2022.
contracL or to Lhe
reement ween I
res S ember 30 2028.
r Irr t
Access ss Tar
D s res Decemlcer 31,
en Access Tran ss on Tar
contract tween I
The agreement tween
Po!'rer t
Power Pac
Power and
o Seatt
e4Ene
ted States Depart.ment o
3l_2022
Serw ce
s on March 3]-, 202]-
Inter or, Bureau
328 Line No.: 5 Column: a
328 Line No;4 Column: e
328 Line No.: 5 Column: e
328 Line No; 6 a
328 Line No.:7 Column: a
of Indian Affairs is sub ect to termination 90 written noti-ce the Bureau
The agreement between Idaho Power and Cycle Horseshoe Bend LLC has no exp a ondate and can be terminated either at time.
328 Line No.: I Column: e
Access ssion Ta e5 6 E Reserves
Open Access Transmission Tariff, Schedule 7
Service
8Pi mPo -Eo-Po Transm SS on
328 Line No.:8 Column: a
328 Line No.: 11 Column: e
328 Line No.: 18 Column: e
Open Access SS ,s e 11 Unreserve Use PenalLy
FERC FORM NO.1 (ED. 12.871 Pase 450.1
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5]nn Orisinat(2) l--1A Resubmission
Date of Report(Mo, Da, Yr)
o4t't4t202'l
Year/Period of Report
End of 20201Q4
I RANSMISSION Ul- E.LEC IRICII Y BY OTHERS (Account 565)
(lncluding transactions refened 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 Affi liations)
(a)
Statistical
Classification
(b)
TRANSFER OF ENERGY EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERI
Maoawau-h-oursReceived
(c)
rvragawa[[-
hoursDelivered
(d)
Enerov
CharoEs($r
(f)
umerCharoes($I
(o)
Total Cost of
Tranffission
1 Avista Corp-WWP Div NF 8,647 8,647 57,469 57,469
2 Avista Corp-WWP Div SFP 252,1 03 252,103 1,316,763 1,316,763
3 Avista Corp-WWP Div 0s -592 -592
4 Bonneville Power Admin LFP 210,625 210,625 1,1 98,056 1,198,056
5 Bonneville Power Admin SFP 4,031 4,031 28,819 28,819
6 Bonneville Power Admin NF 950 950 4,480 4,480
7 Bonneville Power Admin OS 235,111 23s,111
Bonneville Power Admin os 6,802 6,802
Bonneville Power Admin os 19,402 19,402
'10 Bonneville Power Admin os 7,169 7,169
11 Bonneville Power Admin OS 800 800
12 Bonneville Power Admin os 6,061 6,061
13 Bonneville Power Admin OS 2,735 2,735
14 Nor$Western Energy SFP 21,833 21,833 191,060 191,060
15 NorthWestem Energy NF 199 '199 1.180 1,180
16 NorhWestem Energy os 2,903 2,903
TOTAL 554,561 554,56'l 3,794,666 232p20 4,027,586
FERC FORM NO. 1/3.Q (REV. 02-04)Page 332
ldaho Power Company (1)
(2)
An Original
A Resubmission
(Mo, Da,
0411412021
Year/Period of Report
End of 20201Q4
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
( I ncluding transactions refened to as'wheeling' )
1. Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public
authorities, qualifying facilities, and others for the quarter.
2. ln column (a) report each @mpany 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 megawaft 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 voucherc rendered to the respondent. ln column (e) report the
demand charges and in column (0 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 OTHER
Magawan-hoursReceived
(c)
Magawarl.-hoursDelivered
(d)
ch,lYes
(e)
Enerov
ctr,a6gEs
(0
cnlyes
(q)
Total Gost ol
Tranffission
I NV Energy NF 1,012 't,012 5,574 5,574
2 NV Energy 798 798
3 PacifiCop lnc.400 400 703,037 703,037
4 PacifiCorp lnc.SFP 15,787 15,787 159,417 159,417
5 PacifCorp lnc.NF 2,807 2,807 20,805 20,805
6 PacifiCory lnc.36,725 36,725
7 PacifCorp lnc.-966 -966
8 PacifCop lnc.48,449 48,449
I PacifCorp lnc.588 588
10 Puget Sound Energy, lnc 31,954 31,954
11 Seatde Clty Light 12,416 12,416
12 Shell Energy Norfi Ame.3,200 3,200
13 Snohomish County PUD s3,538 53,53E
14 Tacoma Power 6,898 6,898
15
16
TOTAL 554,56',554,561 3,794,666 232,920 4,027,586
FERC FORM NO. 1r3-Q (REV. 02-04)Page 332.1
This Page lntentionally Left Blank
Name of Respondent
ldaho Power Company
This Report is:
(1) X An OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
04t't4t2021
Year/Period of Report
20201o,4
FOOTNOTE DATA
332.1 Line No.:2 Column: b
332 Line No.: 13 Column: br for reasst332 Line No.:16 Column: b
332.1 Line No.:3 Column: bratDate 05
332.1 Line No.: 6 b
332.1 Line No.:7 Column: b
332 Line No.:9 Column: b
332 Line No.: 10 Column: b t set th Seatted C t L332 Line No.:11 Column: b
332 Line No.: 12 Column: b
332 Line No.:4 Column: b
332 Line No.:7 Column: b
Schedule Paoe:332 Line No.: 3 Column: bCredit of Imbalance Penalt
Contract at Date 12 3 2021,
lemental reserves332 Line No.:8 Column: b
Anc Se
BPAT
BPAT
BPAT is
r or t reass
rovider for ca ir reass
rovider for ca c t reass
Se ces
t settled
t set Ene
t settl t Sound
t settled th Tacoma Power
or t reass
2024
Count PUD
BPAT is
BPAT
Anc 1
Anc se ces
Contract
Anc 11 Se ces
2019 Unrese USe Re
332.1 Line No.: I Column: b
2019 LFP Re
Schedule Paqe:332.1 Line No.:9 Column: b
2018 PTP True-
reass t, BPAT is rovider
t reass BPAT
reass BPAT
t reass BPAT
Capac ty reassignment, BPAT is p
332.1 Line No.: 10 Column: b
332.1 Line No.: 11 Column: b
332.1 Line No.: 12 Column: b
332.1 Line No.: 13 Column: b
332.1 Line No.: 14 Column: b
FERC FORM NO.1 (ED. 12-871 Page 450.1
Name of Respondent
ldaho Power Company
r nis BeDon rs:
(1) lx_l An Original
(2) n A Resubmission
Date of Reoort(Mo, Da, Yi)
04114t202'.1
Year/Period of Report
End of 20201Q4
MISGELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Line
No.
Descriotion(a)Amount
(b)
1 lndustry Association Dues 560,663
2 Nuclear Power Research Expenses
3 Other Experimental and General Research Expenses
4 Pub & Dist lnfu 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
8 Odette Bolano 30,360
I Thomas Carlile 85,140
10 Richard Dahl 197,0't0
11 Darrel Anderson 46,200
12 Annette Elg 91,080
13 Ronald Jibson 89,633
't4 Judith Johansen 93,1 14
15 Dennis Johnson 97,020
16 Christine King 102,765
17 Richard Navano 123,839
18 Travel & Lodging 7,393
19
20 Corporate Memberships and Subscriptions
21 Associated Taxpayers of ldaho 24,000
22 Bannock Development Corp 8,000
23 Boise Valley Economic Partners 20,000
24 Business Plus lnc.5,000
25 CEATI lntemational lnc 70,000
26 Chartwell lnc 43,988
27 E Source 19,735
28 lBlSWorld INC 8,500
29 ldaho Technology Council 10,000
30 National Association of Corporate Directors 9,310
31 National Hydropower Association 42,397
32 North American Energy Standard 't6,000
33 Oregon State University 15,000
34 Pacific NW Utilities 6s,401
35 Southem ldaho Economic Development s,000
36 Sun Valley Economic Development 6,000
37 Misc. Memberships of Subscriptions under $5000 16,864
38
39 Chamber of Commerce and Other Civic Organizations 35,274
40
41
42
43
44
45
46 TOTAL 3,692,278
FERC FORM NO.1 (ED.12.94)Page 335
Name of Respondent
ldaho Power Company
This Report is:
(1) ! An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
04l't412021
Year/Period of Report
20201Q4
FOOTNOTE DATA
Schedule Paoe:335 Line No.:4 Column: b
Reciplcnt
BLOOMBERG FINANCE TP
BROADRIDGE FINANCIAL SOLUTIONS
D F KING &COMPANY INC
DEUTSCHE BANKTRUSTCO
EQSHAREOWNER SERVICES
MODERN NETWORKS IR, LLC
NASDAQ CORPORATE SOLUTIONS TIC
NEIA'YORK STOCK B(CHANGE I
OKAPI PARTNERS TIC
PAYROI.I- REI.ATED
PR NEWSWRE
RIVEL RESEARCH GROUP INC
STOCK BASED COMPENSATION
TRAVEL EXPENSE - STOCK REIATED
Purposc
MISC EXPENSE
MISC B(PENSE
MISC EXPENSE
BROKER FEES
MGMT EXPENSE
MISC E(PENSE
MGMTEXPENSE
USTING SERVICE
MGMTEXPENSE
MISC EXPENSE
MISCB(PENSE
MGMT EXPENSE
MISCB(PENSE
MISC EXPENSE
Amount
25,18[}
7L,4L2
8,87O
10,000
1)2,86
11,821
8:i,267
8,785
19,800
182,190
19,150
t5,W
97O,78
23,307
\ffi,@7
Schedule Pase:335 Line No.: 5 Column: b
R:ciphnt
BANK OF NEWYORK
tNvEsTts, tNc.
MOODY,SANALYNCS INC
uNtoN BAN|(, N.A.
MTSCEUANEOUS UNDER $5O0O
Purpose
REVENUE BONDS
WEBSITE DESIGN
FINANCIALSOFTWARE
MISC D(PENSE
MISC EXPENSE
Amount
7,267
11,645
38,601
2e680
EI
80,S5
FERC FORM NO.1 (ED. 12-871 Page 450.1
This Page lntentionally Left Blank
Name of Respondent
ldaho Power Company
This Reoort ls:(1) finn Originat(2) l--1A Resubmission
Date of
(Mo, Da
Report
, Yr)
04t14t2021
Year/Period of Report
End of 20201Q4
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Account 403, 404, 405)
(Except amortization of aquisition adjustments)
'l . Report in section A for the year the amounts for : (b) Depreciation Expense (Account +03; (c) Depreciation Expense for Asset
Retirement Costs (Account 403.1; (d) Amortization of Limited-Term Electric Plant (Account 404); and (e) Amortization of Other Electric
Plant (Account 405).
2. Report in Section 8 the rates used to compute amortization charges for electric plant (Accounts 404 and 405). State the basis used to
compute charges and whether any changes have been made in the basis or rates used from the preceding report year.
3. Report all available information called for in Section C every fifth year beginning with report year 1971, reporting annually only changes
to columns (c) through (g) from the complete report of the preceding year.
Unless composite depreciation accounting for total depreciable plant is followed, list numerically in column (a) each plant subaccount,
account or functional classification, as appropriate, to which a rate is applied. 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 orfunctional classification Listed in column
(a). lf plant mortality studies are prepared to assist in estimating average service Lives, show in column (f) the type mortality curve
selected as most appropriate for the account and in column (g), if available, the weighted average remaining life of surviving plant. lf
composite depreciation accounting is used, report available information called for in columns (b) through (g) on this basis.
4. lf provisions for depreciation were made during the year in addition to depreciation provided by application of reported rates, state at
the bottom of section C the amounts and nature of the provisions and the plant items to which related.
A. Summary of Depreciation and Amortization Charges
Line
No.Functional Classifi cation
(a)
Dgpreciation
Expense(Accourt 403)
Depreciation
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 7,981,848 7,981,848
z Steam Production Plant 46,097,778 -431,877 45,66s,901
Nuclear Production Plant
4 Hydraulic Production Plant-Conventional 17,944,253 17,944,253
c Hydraulic Production Plant-Pumped Storage
6 Other Production Plant 16,034,889 16,034,889
7 Transmission Plant 23,418,366 23,418,366
I Diskibution Plant 43,291,49',!43,291,491
c Regional Transmission and Market Operation 15,963,840 15,963,840
1C General Plant
11
12
Common Plant-Electric
TOTAL 162,750,617 -431,877 7,981,848 170,300,588
B. Basis forAmortization Charges
See Footnote
FERC FORM NO. I (REV. 12-03)Page 336
ldaho Power Company
(1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
o4l't412021
Year/Period of Report
End of 20201Q4
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Lrne
No.Account No.
{a)
ueprecraore
Plant Base
(ln Thousands)
trsI|mateo
Avg. Service
Life(c)
Salvage
(P-.rcent)
Appileo
Depr. rates
(P_.rc€nt)
Monarly
Curve
Tvoetfl
Average
Remaining
Life(o)
't2 310.20 64S 75.00 4.40 R4.0 17.90
13 31 1.00 120,329 100.00 -9.00 3.40 s0.5 17.90
14 312.10 194,788,70.00 -5.00 3.47 s1.0 18.10
15 312.20 443,502 53.00 -8.00 5.14 R1.5 17.00
16 312.30 2,5U 35.00 10.00 5.12 R3.0 13.50
17 314.00 138,532 45.00 -7.00 5.38 s0.5 16.50
18 315.00 53,353 60.00 -3.00 3.92 s1.5 16.80
19 3't6.00 10,86C 35.00 2.00 7.76 s0.0 14.60
20 316.10 409 '13.00 15.00 8.70 L2.0 5.40
21 316.40 24C 13.00 1s.00 2.23 L2.O
22 316.50 1,122 13.00 15.00 5.81 L2.0 1 1.80
23 316.60 45 13.75
24 316.70 40'l 21.00 15.00 0.35 s1.0 12.24
25 316.80 4,70C 20.00 25.00 4.31 o1.0 17.84
26 316.90 14 35.00 15.00 2.43 s1.0 30.60
27 317.00 15,447
28 986,895
29 331.00 227,499 120.00 -25.00 2.08 R2.5 35.80
30 332.10 19,461 120.00 -20.00 0.98 s1.5 46.24
31 332.20 263,776 120.00 -20.00 1.80 s1.5 31.2A
32 332.30 5,472 1.15 Square 55.'t0
33 333.00 331,23C 100.00 -10.00 1.92 R2.5 30.60
34 334.00 66,63C 65.00 -10.00 2.82 R1.5 27.80
35 335,00 28,131 90.00 -5.00 2.18 R2.0 31.20
36 335.'t0 121 15.00 7.92 Square 7.90
37 335.20 42 20.00 0.80 Square 9.20
38 335.30 26S 5.00 14.42 Square 2.s0
39 336.00 13,963 100.00 2.58 R3.0 22.70
40 Subtotal Hydro 956,594
41 341.00 154,238 2.72 Square 32.80
42 341.1 0 25.00 4.00
43 u2.00 't0,438 50.00 2.81 s2.5 28.70
44 343.00 220,475 40.00 3.18 R2.0 26.00
45 344.00 66,599 50.00 2.45 s2.0 28.40
46 79 25.00 4.00
47 345.00 92,003 55.00 2.91 R2.0 29.30
48 346.00 6,655 35.00 3.24 R2.5 24.04
49 346.1 13 25.00 4.00
50 Subtotal Other 550,503
FERC FORtrl NO.1 (REV. 12-03)Page 337
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5]An orisinat(2) 1A Resubmission
Date of Reoort(Mo, Da, Yi)
o4t14t2021
Year/Period of Report
End of 2O2O|Q4
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line
No.Account No.
(a)
ueprecEore
Plant Base
(ln Thousands)Ih)
trslrmateo
Avg. Service
Lifelc'l
Salvage
(P-TdTnt)
Depr. rates
(P_.rcent)Curver),f"
AVerage
Remaining
(o'l
12 3s0.20 35,050 100.00 0.89 R4.0 85.20
13 350.22 254 30.0c 3.33
14 352.00 85,528 65.0C -33.00 1.88 R3.0 53.20
15 353.00 462,307 52.0C -10.00 1.97 s0.5 42.00
16 354.00 222,851 80.0c -10.00 1.07 R4.0 71.10
't7 355.00 214,345 65.0C -80.00 2.64 R1.5 s3.90
18 355.10 3,026 10.0c 10.00
19 356.00 244,761 74.Ot -50.0c 1.87 R1.5 62.30
2A 359.00 390 65.0C 0.91 R2.5 33.30
21 Subtotal Transmission 1,268,512
22 fio.22 874 30.0c 3.33
23 361.00 50,87S 70.0c -50.0c 2.17 R3.0 54.40
24 362.00 287,263 55.00 -6.0c 1.85 R1.5 42.94
25 364.00 281,088 58.00 -50.0c 2.17 R1.5 44.14
26 364.10 12,055 't2.00 8.34
27 365.00 147,321 49.00 -30.0c 2.65 R1.0 34.40
28 366.00 53,566 6s.00 -25.0C 't.8s R2.5 49.10
29 367.00 302,976 50.00 -1 't.0c 1.90 Rl.5 39.40
30 368.00 647,633 42.00 -7.0(2.17 R0.5 34.80
3'l 369.00 64,812 55.00 -40.0c 1.s8 R1.5 43.40
32 370.00 1 9,1 94 30.00 -s.0c 2.05 o1.0 25.74
33 370.10 85,682 18.00 -5.0c 5.39 R1.5 14.00
34 371.20 4,005 21.00 -5,0c 2.88 R1.0 A.7A
35 373.20 4,849 40.00 -30.0c 't.73 R1.0 29.00
36 374.00
37 Subtotal Distribution 1.962,'t97
38 390.11 34,678 90.00 -3.0c 2.08 s't.0 33.20
39 390.12 101,639 55.00 -3.0(2.11 R2.0 38.80
40 391.'t0 't3,471 20.00 4.00 Square 12.34
41 391.20 26,95€5.00 20.00 Square 2.74
42 391.21 3,287 8.00 12.54 Square 3.50
43 392.10 922 13.00 15.0(7.07 L2.0 9.30
44 392.30 4,563 15.00 40.0(4.'t3 s2.5 9.70
45 392.40 29,24C 13.00 15.00 6.20 L2.0 8.5C
46 392.s0 2,021 13.00 15.00 6.34 12.0 8.9C
47 392.60 58,022 21.O0 15.00 3.95 s1.0 14.0C
48 392.70 10,99€21.00 15.00 4.16 s't.0 12.3C
49 392.90 7,528 35.00 15.00 2.24 s1.0 24.3C
50 393.00 4,383 25.00 4.00 Square 17.4C
FERC FORM NO.1 (REV.12.03)Page 337.1
Name of Respondent
ldaho Power Company
This Reoort ls:(1) fiAn Originat(2) ;-1A Resubmission
Date of Reoort(Mo, Da, Yi)
04114t2021
Year/Period of Report
End of 202OlQ4
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Llne
No.Account No.
(a)
LreprecEole
Plant Base
(ln Thousands)
ESMaIeO
Avg. Service
Life
{c)
Salvaoe
(Perce-n0
Appl|eo
Depr. rates(Pr:.fnt)
MOfiailry
Curverlf"
Average
Remaining
Life(o)
12 394.00 12,276 20.00 5.00 Square 12.4C
13 395.00 14,859 20.00 5.00 Square 10.6C
'14 396.00 23,707 20.00 25.00 2.97 o1.0 16.7C
15 397.10 2,252 15.00 6.67 Square 4.7C
16 397.20 24,801 15.00 6.67 Square 8.10
17 397.30 13,202 15.00 6.67 Square 9.7t
18 397.40 20,264 15.00 6.02 Square 13.1C
1S 398.00 8,147 15.00 6.67 Square 8.60
20 Subtotal General 417,2'.16
21 Total Plant 6,141,917
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
FERC FORM NO. r (REV.12.03)Page 337.2
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) -A Resubmission
Date of Report
(Mo, Da, Yr)
0411412021
YeariPeriod of Report
202U44
FOOTNOTE DATA
336 Line No.: I Column:
Account 404 - Basis used to compute charges:
Balance to be Balance to beAmortized 2020 Amortized
1l'112020 Amortization 1213112020
Remaining
months of
Amort 12t31l2}l
(1) Shoshone Bannock Agreement
(2) Mid Snake Relicensing
(3) Swan Falls Relicensing
(4) Software
(5) Shoshone Bannock ROW
(6) Boardman Retrofit Analysis
(7) FERC Compliance Costs
(8) Radio Frequency - Spectrum
36,000
7,691,855
4,304,580
19,363,826
2,308,501
56,559
5,192,628
3,530,819
12,000
523,123
189,908
6,707,263
287,899
56,559
116,003
89,093
24,000
7,168,732
4,114,672
20,888,500
2,020,602
0
6,175,005
3,424,089
24
260
Y
462
Total 42,484,768 7,981,848 43,815,600
(1) Shoshone-Bannock Tribe License & Use Agreement. New five year advance payment starting January
201 8, with a December 31 , 2022 term ination date.
(2) Middle Snake Relicensing Costs (Amoritzed over a 30 year license period; licenses expire July 31 ,2034
and February 28, 2035).
(3) Swan Falls Relicensing Costs (Amortized over a 30 year license period, license expires August 31,2042)
(4) Computer Software packages (Amortized over a 62 month period).
(5) Shoshone-Bannock Right of Way (Termination date December 31,2027).
(6) Boardman Retrofit Tech Analysis (plant decommissed in 2020).
[6]
FERC License Compliance Costs (amortized over the term of the applicable FERG Licenses)
Radio Frequency Spectrum (Amorized over a 40 oeriod beoinnino Julv 2019)
Schedule Paoe: 336 Line No.: 28 Column: a
Line: 12 to 110 Column: c, d, e, g
Steam, hydro, and other production depreciation and amortization of certain electric plant is maintained by plant
location. Effective April 1,1993 the forecast life span method of life analysis using an interim retirement rate was
utilized to develop all production plant rates. Rates, service lives, net salvage and remaining lives indicated are on a
composite basis. Effective April 1, 1993 all depreciable plant is being depreciated using the straight-line remaining life
method.
Line: 12 to 26 Column: c, d,f, g
Plant accounts 31020 through 31550 and 31670 through 31690 are presented for Jim Bridger facility only. This data is
provided by the most recent depreciation study; Jim Bridger was the only thermal production facility included in the
depreciation study. Plant account 31660 is associated with Valmy facility only. Valmy was not part of the 2015
depreciation study, as Valmy has been reviewed for decommissioning within regulatory order 33771. There is no data
for estimated service life, net salvage percentage, or mortality curve.
Line: 12 to 26 Column: e
An average plant balance was used in computing these rates by plant account.
Schedule Paoe:336 Line No.:46 Column: a
Line: 49 Column: c, d, t, g
FERC FORM NO.1 (ED. 12-871 Page 450.1
This Page lntentionally Left Blank
Name of Respondent
ldaho Pmter @mpany
This Report is:
(1) XAn OriginalQ) A Resubmission
Date of Report
(Mo, Da, Yr)
0/,n412021
Year/Feriod of Report
2olUo/.
FOOTNOTE DATA
Plant accounts 3/t410, 3UL0, and 34610 were not in the last depreciation study and have not been subiectto
depreciatlon study review.
1 450.2
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5]nn orisinat(2) nA Resubmission
Date of Reoort(Mo, Da, Yi)
04t1412021
Year/Period of Report
End of 20201Q4
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 yearrs expenses that are not defened and the current yea/s amortization of amounts
deferred in previous years.
Line
No.
Description
(Fumish name of reoulatorv commission or bodv the
dbcket or case numb-er and'a description of the case)
(a)
Assessed bv
Regulatory
Commission
(b)
Expenses
of
Utility
(c)
TotalExoense for
Cuirent Year(b) + (c)(d)
uelerredin Account
182.3 atBeginning of Year
(e)
1 Federal Energy Regulatory Commission:
2 Annual admin charges assessed by FERC 3,807,06C 3,807,060
3
4 General Regulatory Erpenses and
5 Various other Dockets 161,05i 161 ,057
6
7 Oregon Hydro - Fees Amortization 158,501 158,501
8
I Regulatory Commission Expenses - ldaho
10 Rate Case - Misc expenses 43,855 43,85s 22,622
11
12 Regulatory Commission Expenses - Oregon
13 Rate Case - Misc expenses 173,374 173,374
14 General Regulatory 1,584,234 1,584,230
15 Other OPUC expenses 2,204 2,204
16
17
18
19
20
2',1
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46 TOTAL 3,965,561 1,964,716 5,930,277 22,622
FERC FORM NO.1 (ED. 12-96)Page 350
ldaho Power Company (21 A Resubmission
Date of Report(Mo, Da, Y0
0411412021
Year/Period of Report
End of 202OlQ4
REGULATORY COMMISSION EXPENSES (Continued)
3. Show in column (k) any expenses incuned in prior years which are being amortized. List in column (a) the period of amortization.
4. List in column (f), (g), and (h) expenses incurred during year which were charged currently to income, plant, or other accounts.
5. Minor items (less than $25,000) may be grouped.
EXPENSES INCURRED DURING YEAR AMORTIZED DURING YEAR
CURRENTLY CHARGEO TO Deferred to
Account 182.3
(i)
Gontra
Account
(i)
Amount
(k)
Defened inAccount 182.3
End of Yearfl)
Line
Nouepanment
(fl
lrcftuuilr
(o)
Amounr
(h)
1
Electric 928 3,807,06C 2
3
4
Electric 928 161,057 5
6
Electric 928 158,501 7
8
I
Electric 928 282 36,958 928203 43,574 16,006 10
11
12
Electric 928 't73,374 't3
Electric 928 1,584,230 14
Electric 928 2,200 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'.!
42
43
44
45
5,886,704 36,958 43,574 16,006 46
FERC FORM NO.1 (ED. 12-96)Page 351
Name of Respondent
ldaho Power Company
This Reoort ls:(1) EiRn Originat(2) l--1A Resubmission
Date of ReDort(Mo, Da, Yi)
04114t202'.1
Year/Period of Report
End of 20201Q,4
RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES
1 . Describe and show below costs incuned and accounts charged during the year for technological research, development, and demonstration (R, D &
D) project initiated, continued or concluded during the year. Report also support given to others during the year for jointly-sponsored projects.(ldenti&
recipient regardless 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 mlumn (a) the applicable classification, as shown below:
Classifications:
A. Elechic 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 (Classiff and include items in excess of $50,000.)
(7) Total Cost lncurred
B. Electric, R, D & D Performed Externally:
(1) Research Support to the electrical Research Council or the Electric
Power Research lnstitute
Line
No.
Classification
(a)
Description
(b)
1 ldaho Power did not incur any Research and
2 Development expenditures in 2020.
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
FERC FORM NO. r (ED. 12-87)Page 352
Name of Respondent
ldaho Power Company (2)A Resubmission 041't412021
Year/Period of Report
End of 2O20lQ4
RESEARCH, DEVELOPMENT, AND DEMONSTRATION AGTIVITIES (CONUNUEd)
(2) Research Support to Edison Electric lnstitute
(3) Research Support to Nuclear Power Groups
(4) Research Support to Others (Classiff)
(5) Total Cost lncuned
3. lnclude in column (c) all R, D & D items performed intemally 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)) classif, 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, Outstranding 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 lncuned lnternally
cune6lYear Costs lncurred Extemally
Cunent Year
(d)
AMOUNTS CHARGED IN CURRENT YEAR Unamortized
Accumulation
(s)
Line
No.Account(e)Amount(f)
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
FERC FORM NO. I (ED.12-87)Page 353
Name of Respondent
ldaho Power Company
This Reoort ls:(1) E]An orisinal(2) nA Resubmission
Date of Report
(Mo, Da, Yr)
o4t1412021
Year/Period of Report
End of 20201Q4
DISTRIEUTION 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 PavrollDistributlon
(b)
Total
(d)
,|Electric
2 Operation
3 Production 22,130,601
4 Transmission 6,855,762
5 Regional Market
6 Distribution '18.060,853
7 Customer Accounts 9,236,084
8 Customer Service and lnformational 5,027,620
I Sales
10 Administrative and General 76,5',12,272
't1 TOTAL Operation (Enter Total of lines 3 thru 10)'137,823,192
12 Maintenance
13 Production 4,622,',tffi
14 Transmission 3,264,225
15 Regional Market
16 Distribution 7,393,557
17 Administrative and General 958,440
18 TOTAL Maintenance (Total of lines 13 thru 17)16,238,378
19 Total Operation and Maintenance
20 Production (Enter Total of lines 3 and 13)26,752,757
21 Transmission (Enter Total of lines 4 and 14)10,1 19,987
22 Regional Market (Enter Total of Lines 5 and 15)
23 Distribution (Enter Total of lines 6 and 16)25,454,410
24 Customer Accounts (Transcribe from line 7)9,236,084
25 Customer Service and lnformational (Transcribe hom line 8)5,027,620
26 Sales (Transcribe from line 9)
27 Administrative and General (Enter Total of lines 10 and 17)77,470.712
28 TOTAL Oper. and Maint. (Total of lines 20 lhru 27)154,061 ,570 154,061,570
29 Gas
30 Operation
31 Production-Manufactured Gas
32 Production-Nat. Gas (lncluding Expl. and Dev.)
33 Other Gas Supply
34 Storage, LNG TerminalinE 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 Exploration and Development)
45 Other Gas Supply
46 Storage, LNG Terminaling and Processing
47 Transmission
FERC FORM NO.1 (ED.12.88)Page 354
1 An (Mo, Da,ldaho Power Company (2)A Resubmission 04t14t2021
Year/Period of Report
End of 20201Q,4
DISTRIBUTION OF SALARIES AND WAGES (Continued)
Line
No.
Classification
(a)
Direct PavrollDistribution
(b)
fur Total
(d)
48 Distribution
49 Administrative and General
50 TOTAL Maint. (Enter Total of lines 43 thru 49)
51 Total Operation and Maintenance
52 Production-Manufactured Gas (Enter Total of lines 31 and 43)
53 Production-Natural Gas (lncluding Expl. and Dev.) (Total lines 32,
54 Other Gas Supply (Enter Total of lines 33 and 45)
55 Storage, LNG Terminalins and Pocessins fiotal of lines 31 thru
56 Transmission (Lines 35 and 471
57 Distribution (Lines 36 and 48)
58 Customer Accounts (Line 37)
59 Customer Service and lnformational (Line 38)
60 Sales Gine 39)
61 Administrative and General (Lines 40 and 49)
62 TOTAL Operation and Maint. (Iotal of lines 52 thru 61)
63 Other Utility Departments
64 Operation and Maintenance
65 TOTAL All Utility Dept. (fohl of lines 28, 62, and 64)154,06't,570 154,061,570
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 (provlde details in footnote):
76 TOTAL Plant Removal (Total of lines 73 thru 75)
77 Other Accounts (Specify, provide details in foohote):
78 Store Expense 5,314,713 5,314,713
79 Other Clearing Accounts 3,949,606 3,949,606
80 Construc{ion Work in Progress 68,097,458 68,097,458
81 Other Work in Progress 4,059,708 4,059,708
82 Other Accounts 5,118,151 5,118,'151
83 lndirect Loading 48,048,179
84
85
86
87
88
89
90
91
92
93
94
95 TOTAL Other Accounts 86,539,636 48,048,179 134,587,815
96 TOTAL SALARIES AND WAGES 240.601.206 48,048,179 288,649,385
FERC FORM NO. r (ED. r2-E8)Page 355
This Page lntentionally Left Blank
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t14t2021
Year/Period of Report
20201Q4
FOOTNOTE DATA
No.:c
Amount amount
departments based on labor charges.
recE The ng s allocated to
FERC FORM NO.1 450.1
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5]An orisinat(2) 1A Resubmission
Date of
(Mo, Da:fB*
0411412021
Year/Period of Report
End of 20201Q4
PURCHASES AND SALES OF ANCILLARY SERVICES
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), (d), (e), (f), and (g) report the amount of reactive supply and voltage control services purchased and sold
during the year.
(3) On line 3 columns (b) (c), (d), (e), (f), and (g) report the amount of regulation and frequency response services purchased and sold
during the year.
(4) On line 4 columns (b), (c), (d), (e), (f), and (g) report the amount of energy imbalance services purchased and sold during the year
(5) On lines 5 and 6, columns (b), (c), (d), (e), (f), and (g) report the amount of operating reserve spinning and supplement services
purchased and sold during the period.
(6) On line 7 columns (b), (c), (d), (e), (f), and (g) report the total amount of all other types ancillary services purchased or sold during
the year. lnclude in a footnote and specify 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 Units
(e)
Unit of
Measure
(f)
Dollars
(s)
,|Scteduling, System Conhol and Dispatch 259,826
I Reactive Supply and Voltage 15,711
'1 Regulation and Frequency Response 698,0'12 68,370
4 Energy lmbalance
E Operating Reserve - Spinning 3,632 1,169,201 114,523
6 Operating Reserve - Supplement 3,170 1,169,201 114,523
7 Other
8 Total (Lines t hru 7)282,339 3,036,414 297,416
FERC FORM NO. I (New 2-04)Page 398
Name of Respondent
ldaho Porer Comoanv
This Report is:
(1)XAn OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
un1tm21
Year/Period of Report
20?0/44
FOOTNOTE DATA
398 HneNo.:1 @lumn: bIdaho Power does not systemat,caI
serviceg purchased.
y record the number of ts related to anc I
FERC FORilI 1 1 Paoe 450.1
Name of Respondent
ldaho Power Company
(1)
(2)
An Original
A Resubmission
Date of Report
(Mo, Da, Yr)
0411412021
Year/Period of Report
End of 202UQ4
MON THLY I RANSMISSION SYSI EM PEAK LOAI]
(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, fumish the required inbrmation for each non-integrated system.
(2) Report on Column (b) by month the tansmission system's peak load.
(3) Report on Columns (c ) and (d) the specified information for each monthly transmission - system peak load reported on Column (b).
(4) Report on Columns (e) through 0) by month the system'monthly maximum megawatt load by statistical classifications. See General lnstruction for the
definition of each statistical classification.
NAMEOFSYSTEM: ldaho PowerCompany
Line
No.Month
(a)
Monthly Peak
MW - Total
(b)
Day of
Mortttly
Peak
(c)
Hour of
lvlon$ly
Peak
(d)
Firm Network
SeMceforSelf
(e)
Firm Networt
Service br
Ohers
(0
Long-Term Fim
Pcint-tepoint
Reseryations
(s)
Other Long-
Term Firm
Soryice
(h)
Short-Term Firm
Point-topoint
Reservation
(i)
Oher
Seryice
0)
1 January 3,18t 1t 80c 1,919 n3 973 70
I Fobruary 3,39t 4 90c 1,96i 257 973 199
1 March 3,09(1:80c 1,776 21i 973 125
4 Totd lor Quarter 'l 5,662 69€2,91S 394
q AFil 3,27t 2l 't70c 1,6s8 274 973 373
6 May 4,214 2l 180C 2,693 u4 973 204
7 June 4,404 2i 180C 2,902 37[973 't59
8 Total for Quarter 2 7,253 988 2,919 736
s July 4,671 3(1 80C 3,268 37!973 50
1C August 4,69r 1t 170C 3,064 341 973 317
11 Septembor 4,27',4 170C 2,599 u2 973 363
12 Tolal lor Ouater 3 8,931 1,06'2,919 730
't3 Oc-tober 3,25r 2t 90c 1,620 235 973 430
14 November 3,1 1r 3(90c 1,844 234 973 62
15 December 3,4'il I 90c 2,136 241 973 62
t6 Total for Ouarter 4 5,600 714 2,9'lS 554
17 Total Ysar to
Dateffear 27,446 3,46C 1 1,676 2,414
FERC FORM NO. tr3-O (NEW. 07-04)Page ,100
ldaho Power Company (1)
(2)
An Original
A Resubmission
(Mo, Da,
o4114t2021
Year/Period of Report
End of 2O2O|Q4
ELECTRIG 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)
,|SOURCES OF ENERGY 21 DISPOSITION OF ENERGY
2 Generation (Excluding Station Use):22 Sales to Ultimate Consumers (lncluding
I nterdepartmental Sales)
14,828,260
3 Steam 3,719,721
4 Nuclear 23 Requirements Sales for Resale (See
instruction 4, page 31 1.)E Hydro-Conventional 6,966,84r
6 HydroPumped Storage 24 Non-Requirements Sales for Resale (See
instruction 4, page 31 1.)
1,887,139
7 Other 2,109,19t
I Less Energy for Pumping 25 Energy Furnished Without Charge
o Net Generation (Ent6r Total of lines 3
though 8)
12,795,761 26 Energy Used by the Company (Electric
Dept Only, Excluding Station Use)
10 Purchases 5,057,57i 27 Total Energy Losses 1,059,618
11 Power Exchanges:28 TOTAL (Enter Total of Lines 22 Through
27) (MUST EQUAL LINE 20)
17,775,017
12 Received 67,Ui
13 Delivered 144,671
14 Net Exchanges (Line 12 minus line 13)-77,321
15 Transmission For Other (Wheeling)
16 Received 8,248,90(
17 Delivered 8,249,90(
18 Net Transmission for Other (Line 16 minus
line 17)
'tg Transmission By Others Losses
20 TOTAL (EnterTotal of lines 9, 10, 14, 18
and 19)
17,775,01i
FERC FORM NO. 1 (ED. 12.90)Page 401a
Name of Respondent
ldaho Power Comoanv
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
04114t2021
Year/Period of Report
20201Q4
FOOTNOTE DATA
$1 Line
Page 329 Column f ers page 401 L, 000 MWH, report or
and BPA Energy imbalance schedules on page 401-. The numbers that are shown on pages
328-330 are for account 456 wheeling only, the numbers on page 401 have to be adjusted for
account 447 transmission.
FERC FORM NO.1 (ED. 12.871 Page 450.1
Name of
ldaho Power Company (1)
(21
An Original
A Resubmission
Date of
(Mo, Da
ReDort
, Yr)
o411412021
Year/Period of Report
End of 20201Q4
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 Megawatt 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
Line
No.Month
(a)
Total Monthly Energy
(b)
Monthly Non-Requirments
Sales for Resale &
Associated Losses
(c)
MONTHLY PEAK
Megawatts (Seelnstr.4)
(d)
Day of Month
(e)
Hour
(0
29 January 1,371,450 109,280 2,2U 15 0900
3C February 1,295,537 106,694 2,223 4 0900
31 March 1,240,729 128,544 1,979 2 0800
3t April 1,374,98',1 268,670 2,096 29 0800
5J May '1,444,756 163,070 2,912 29 1 900
34 June 1,643,900 167,428 3,1 11 26 1900
2E July 1,929,010 169,017 3,324 30 1900
36 August 1,853,794 124,142 3,392 18 2000
37 September 1,569,918 279,487 3,027 4 1800
38 October 1,241,588 't't2,343 2,050 26 't900
3S November 1,282,490 103,496 2,140 30 0900
4C December 1,526,864 154,968 2,212 29 1900
41 TOTAL 17,775,0',t7 1,887,139
FERC FORM NO. 1 (ED. 12.90)Page 401b
Name of Respondent
ldaho Power Company
This Reoort ls:(1) finn Originat
(2)trA Resubmission
Date of Report(Mo, Da, Yr)
04t14t2021
Year/Period of Report
End of 20201Q4
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 burned (Line 38) and average cost
per unit of fuel burned (Line 4 1 ) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20. 8. lf more than one
fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
Line
No.
Item
(a)
Plant
Name: Jim Bridger
(b)
Plant
Name: Boardman
(c)
1 Kind of Plant (lnternal Comb, Gas Turb, Nuclear Steam Steam
2 Type of Constr (Conventional, Outdoor, Boiler, etc)Semi-Outdoor Boiler Conventional
3 Year Originally Constructed 1974 1980
4 Year Last Unit was lnstalled 1979 1980
5 Total lnstalled Cap (Max Gen Name Plate Ratings-Mw)770.50 64.20
6 Net Peak Demand on Plant - MW (60 minutes)705 58
7 Plant Hours Connected to Load 8784 3081
8 Net Continuous Plant Capability (Megawatts)0 0
I When Not Limited by Condenser Water 0 0
't0 When Limited by Condenser Water 0 0
11 Averaqe Number of Employees 0 0
't2 Net Generation, Exclusive of Plant Use - KWh 3451 594000 138604000
13 Cost of Plant: Land and Land Rights 509671 1 0661 0
14 Structures and lmprovements 73050081 0
15 Equipment Costs 649952755 131
16 Asset Retirement Costs 1 I 840675 3767793
17 Total Cost 735353182 3874534
18 Cost per KW of lnstalled Capacity (line 17l5) lncluding 954.3844 60.3510
19 Production Expenses: Oper, Supv, & Engr 173482 400238
20 Fuel 1081 16321 3665972
2',!Coolants and Water (Nuclear Plants Only)0 0
22 Steam Expenses 5425827 955028
23 Steam From Other Sources 0 0
24 Steam Transferred (Cr)0 0
25 Electric Expenses 0 0
26 Misc Steam (or Nuclear) Power Expenses 7414256 680364
27 Rents 220267 0
28 Allowances 0 0
29 Maintenance Supervision and Engineering 58520 -49170
30 Maintenance of Structures 0 31047
31 Maintenance of Boiler (or reactoO Plant 6437395 60s26
32 Maintenance of Electric Plant 2022279 61 1846
33 Maintenance of Misc Steam (or Nuclear) Plant 3524956 28054
34 Total Production Expenses 1 33393303 6384345
35 Expenses per Net KWh 0.0386 0.0461
36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)Coal oir Coal oit
37 Unit (Coal-tons/Oil-barrel/Gas-m cflNuclear-indicate)Tons Barrels Tons Barrels
38 Quantity (Units) of Fuel Burned 1 99901 2 4447 0 94023 393 0
39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)9486 1 40000 0 8604 1 38800 0
40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 54.468 1.425 0.000 26.145 0.000 0.000
41 Average Cost of Fuel per Unit Burned 53.906 36.579 0.000 38.475 87.604 0.000
42 Average Cost of Fuel Burned per Million BTU 2.851 6.221 0.000 2.516 15.028 0.000
43 Average Cost of Fuel Burned per KWh Net Gen 0.031 0.000 0.000 0.026 0.000 0.000
44 Average BTU per KWh Net Generation 1 0957.000 0.000 0.000 10390.000 0.000 0.000
FERC FORM NO.1 (REV. 12-03)Page 402
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5]An orisinat(2) aA Resubmission
Date of Reoort(Mo, Da, Yi)
04t1412021
Year/Period of Report
End of 2O20lQ4
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Planlsl(Continued)
9. ltems under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For lC and GT plants, report Operating Erpenses, Account Nos.
547 and 549 on Line 25 "Electric Expenses,' and Maintenance Account Nos. 553 and 554 on Line 32, 'Maintenance of Electric Plant.' lndicate plants
designed for peak load service. Designate automatically operated plants. 1 1. For a plant equipped with combinations of fossil fuel steam, nuclear
steam, hydro, 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 conceming plant type fuel used, fuel enrichment type and quantity for the
report period and other physical and operating characteristics of plant.
Plant
Name: Valmy
(d)
Plant
Name: Danskin
(e)
Plant
Name: Eenneff Mountain
(0
Line
No.
Steam Gas Turbine Gas Turbine ,|
Outdoor Conventional Conventional 2
2001 2005 3
1985 2008 2005 4
270.90 172.80 5
140 285 179 6
't912 1933 22sO 7
0 252 199 I
0 0 9
0 0 0 10
0 6 4 11
129s23000 274624000 310086000 12
1 106140 402745 0 13
47278558 6031 1 53 1913162 14
20051 7800 104066302 s3674007 't5
-161874 0 0 16
248740624 1 10s00200 55587'169 't7
1715.4526 407.9003 321.6850 18
849287 1s4563 1134',1 19
7895561 10834285 9954665 20
0 0 0 21
3409252 0 0 22
0 0 0 23
0 0 0 24
1754144 762859 4'.t1882 25
1684064 211870 95290 26
0 0 0 27
0 0 0 28
0 0 0 29
352198 54526 19862 30
1992933 8254 10976 31
513877 389871 466336 32
44357 0 0 33
18495673 124',t6228 't0970352 34
0.'1428 0.0452 0.03s4 35
Coal oil Gas Gas 36
Tons Barrels MCF MCF 37
65347 2866 0 3058042 0 0 3242914 0 0 38
10936 1 38778 0 1027 0 0 1027 0 0 39
71.139 0.000 0.000 3.543 0.000 0.000 3.070 0.000 0.000 40
117.09s 77.435 0.000 3.543 0.000 0.000 3.070 0.000 0.000 41
5.265 13.2U 0.000 3.140 0.000 0.000 2.730 0.000 0.000 42
0.061 0.000 0.000 0.039 0.000 0.000 0.032 0.000 0.000 43
1 1349000.000 0.000 0.000 11436.000 0.000 0.000 1 0740.000 0.000 0.000 44
FERG FORM NO. 1 (REV.12-03)Page tl03
Name of Respondent
ldaho Power Company
This
(1)
(2',)
Reoort ls:
5]Rn Originat
f]A Resubmission
Date of ReDort(Mo, Da, Yi)
04t14t2021
Year/Period of Report
End of 20201Q4
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in
this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. Indicate by a footnote any plant leased or operated
as a joint hcility. 4. lf net peak demand for 60 minutes is not available, give data which is available, specifoing period. 5. lf any employees attend
more than one plant, report on line 11 the approximate average number of employees assignable to each plant, 6. lf gas is used and purchased on a
therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 7. Quantities of fuel burned (Line 38) and average cost
per unit of fuel 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 fumish 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 (lntemal 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 20't2
5 Total lnstalled Cap (Max Gen Name Plate Ratings-MW)318.4s 0.00
6 Net Peak Demand on Plant - MW (60 minutes)298 0
7 Plant Hours Connected to Load 5841 0
8 Net Continuous Plant Capability (Megawatts)329 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 't5244il004 0
13 Cost of Plant Land and Land Rights 2287261 0
14 Structures and lmprovements 14628't355 0
15 Equipment Costs 237557588 0
16 Asset Retirement Costs 0 0
17 Total Cost 3861262M 0
18 Cost per KW of lnstalled Capacity (line 17l5) lncluding 1212.5175 0
19 Production Expenses: Oper, Supv, & Engr 507945 0
20 Fuel 32267288 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 3429751 0
26 Misc Steam (or Nuclear) Power Expenses 404883 0
27 Rents 0 0
28 Allowances 0 0
29 Maintenance Supervision and Engineering 0 0
30 Maintenance of Structures 100'145 0
31 Maintenance of Boiler (or reactor) Plant 37903 0
32 Maintenance of Electric Plant 1008553 0
33 Maintenance of Misc Steam (or Nuclear) Plant 0 0
34 Total Production Expenses 37756768 0
35 Expenses per Net KWh 0.0248 0.0000
36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)GAS
37 Unit (Coal-tons/Oil-banel/Gas-m cflNuclear-indicate)MCF
38 Quantity (Units) of Fuel Bumed 10263427 0 0 0 0 0
39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)1027 0 0 0 0 0
40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 3.144 0.000 0.000 0.000 0.000 0.000
41 Average Cost of Fuel per Unit Burned 3.144 0.000 0.000 0.000 0.000 0.000
42 Average Cost of Fuel Burned per Million BTU 2.780 0.000 0.000 0.000 0.000 0.000
43 Average Cost of Fuel Bumed per KWh Net Gen 0.021 0.000 0.000 0.000 0.000 0.000
44 Average BTU per KWh Net Generation 6914.000 0.000 0.000 0.000 0.000 0.000
FERC FORM NO.1 (REV.12-03)Page 402.1
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t14t2021
Year/Period of Report
2020to,4
FOOTNOTE DATA
402 Line No.:3 Column: bThis footnote applies to li-nes 3 and 4. The ,J mBr PowerPlant consists of four equal units constructed jointly by Idaho
Power Company and Pacific Power and Light Company, with Idaho
owning 1/3 and PacifiCorp owning 2/3. lJrriL #1 was placed in
commercial operation Novernlcer 30, 1-974, UrriL #2 December 1, L975,Unit #3 1, 1976 and Unit #4 November 29 1-9'79
s footnote appl es to lines 3 and 4. The Boardman plantconsists of one unit constructed joinEly by Portland GeneralElectric Company, Idaho Power Company, and Pacific NorthwestGenerating Company, with Idaho Power Company owning 10t. Theunit was placed in commercial operation August 3, 1980 and
ceased operations in October 2020.
402 Line No.: 3 Column: c
403 Line No.:3 Column: dThis footnote app es to s3 4 Va p t cons stsof two units constructed jointly by Sierra Pacific Power Companyand Idaho Power Company, with Sierra ownj-ng l/2 arrd Idaho owningl/2. Unit #1 was ptaced in commercial operation December 1,1, 1981
and Unit #2 May 21 , 1985. Idaho Po\./er ended its participation inUnit #1 in December 20l.9.
402 Line No.: 5 Column: b
s ootnote appl estol ne5andl s l-2 through 43Information reflects Idaho Power Companyrs share as explainedin not.e for line 3 page 402 column B.
Cotumn; c lThis footnote applies to line 5 and lines 12 through 43.Information reflects Idaho Power Company's share as explainedin note on line 3 402 column C
This footnote appl es to ne5 s 1,2 43Information reflects Idaho Power Company's share as explained
403 Line No.: 5 Column: d
in note for line 3 403 column D.
Th footnote appl es to nes 9, 10,as operator of the plant will report thisinformation.
11. Pac Corp
402 Line No.:9 Column: b
402 Line No.:9 Column: c
Th s footnote appl to nes 9, l-0,11. Port GeneraElectricasator will rt this information
ootnote app es to nes 9, 10,rra Pac
Power, as operator of the plant, will report this information.l_l_. s f
403 Line No.:9 Column: d
FERC FORM NO.1 (ED. 12-871 Page 450.1
Name of Respondent
ldaho Porer Company
This Reoort ls:(1) E]An Original(2) aA Resubmission
Date of Reoort(Mo, Da, Yi)
0411412021
Year/Period of Report
End of 2O2O|Q4
HYDROELECTRIC GENERATING PLANT STATISTICS (LaTge Plants)
l. 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
r footnote. lf licensed project, give project number.
3. lf net peak demand for 60 minutes is not available, give that which is available specifuing period.
4. lf a group of employees attends more than one generating plant, report on line 'l 1 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 ProjeA No. 1975
Plant Name: Bliss
(c)
1 Kind of Plant (Run-of-River or Storage)Run-of-River Run-of-River
2 Plant Construction type (Conventional or Outdoor)Outdoor 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)92.34 75.00
6 Net Peak Demand on Plant-Megawatts (60 minutes)109 69
7 Plant Hours Connect to Load 7,630 8,783
8 Net Plant Capability (in megawatts)
9 (a) Under Most Favorable Oper Conditions 't09 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 391,243,000 362,010,000
13 Cost of Plant
't4 Land and Land Rights 875,319 768,366
15 Structures and lmprovements 12,082,664 4,089,098
16 Reservoirs, Dams, and Watemays 4,293,07s 9,089,407
17 Equipment Costs 33,222,4'.12 21,216,779
18 Roads, Railroads, and Bridges 839,276 486,477
19 Asset Retirement Costs 0 0
20 TOTAL cost (Total of 14 thru 19)51,312,745 35,650,127
21 Cost per KW of lnstalled Capacity (line 20 / 5)555.6936 475.3350
22 Production Expenses
23 Operation Supervision and Engineering 304,502 875,505
24 Water for Power 2,717,027 580,278
25 Hydraulic ExDenses 234,683 985,025
26 Electric Expenses 81,993 127,816
27 Misc Hydraulic Power Generation Expenses 366,563 41 1,335
28 Rents 195 5,001
29 Maintenance Supervision and Engineering 18,526 14,351
30 Maintenance of Structures 't02,087 29,105
31 Maintenance of Reservoirs, Dams, and WateMays 4,064 20,143
32 Maintenance of Elec{ric Plant 296,586 181,938
33 Maintenanc€ of Misc Hydraulic Plant 142,633 191,285
34 Total Production Expenses (total 23 thru 33)4,268,859 3,421,782
35 Expenses per net KWh 0.0109 0.009s
FERC FORM NO. t (REV.12.03)Page tl06
Name of Respondent
ldaho Power Company
This ReDort ls:(1) fiAn Orisinal(2) aA Resubmission
Date of ReDort(Mo, Da, Yi)
04114t2021
Year/Period of Report
Endof 202UQ4
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The ftems under Cost of Plant represent account]s or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as'Other Power Supply Expenses."
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC Licensed Project No. ,lgt,l
Plant Name: Brownlee(d)
FERC Licensed Project No. 2848
Plant Name: Cascade(e)
FERC Licensed Project No. 1971
Plant Name: Oxbow (fl
Line
No.
Storage Run-of-River Storage 1
Outdoor Outdoor Outdoor 2
1958 1983 1961 3
1980 1984 1961 4
675.00 12.42 190.00 5
634 14 210 6
8,784 8,714 8,784 7
8
747 15 221 I
220 1 202 10
8 2 6 't1
2,065,021,000 35,961,000 894,318,000 12
13
18,418,100 82,142 1,212,767 14
39,892,284 7,328,252 16,933,927 15
70,654,960 3,145,631 31,504,963 16
131,599,654 13,483,894 22,378,589 17
1,/159,263 12.,668 2,548,566 't8
0 0 0 19
262,024,261 24,162,587 74,578,812 20
388.1841 1,945.4579 392.5201 21
22
704,822 200,269 411,384 23
337,897 't22,329 179,491 24
1,096,959 362,s16 573,446 25
416,798 127,410 220,140 26
658,018 252,734 400,u7 27
123,540 77 20,2fi 28
34,794 7,652 19,713 29
41,927 8,4s8 72,518 30
25,294 72 8,790 31
443,180 107,252 122,739 32
s49,200 '117,240 374,415 33
4,432,429 1,306,009 2,403,739 34
0.0021 0.0363 0.0027 35
FERC FORM NO. I (REV.12-03)Page tl07
Name of Respondent
ldaho Power Company
This
(1)
(2')
ReDort ls:
[]An original
f]A Resubmission
Date of(Mo, Da
Report
, Yr)
0411412021
Year/Period of Report
End of 2O2O|Q4
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. lt any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in
a footnote. lf licensed project, give project number.
3. lf net peak demand for 60 minutes is not available, give that which is available speciffing 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. 1971
Plant Name: Hells Canyon
(b)
FERC Licensed Project No. 2726
Plant Name: Malad
(c)
I Kind of Plant (Run-of-River or Storage)Storage Run-of-River
2 Plant Construction type (Conventional or Outdoor)Outdool 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)418 16
7 Plant Hours Connect to Load 8,784 8,043
8 Net Plant Capability (in megawatts)
I (a) Under Most Favorable Oper Conditions 445 25
10 (b) Under the Most Adverse Oper Conditions 137 2',1
11 Average Number of Employees E 1
12 Net Generation, Exclusive of Plant Use - Kwh 1 ,798,61 't,000 153,439,000
13 Cost of Plant
14 Land and Land Rights 2,113,754 20s,376
15 Structures and lmprovements 3,810,090 3,984,726
16 Reservoirs, Dams, and WateMays 55,314,810 7,462,896
17 Equipment Costs 22,653.2%16,785,758
18 Roads, Railroads. and Bridses 968,682 1,507,442
19 Asset Retirement Costs 0 0
20 TOTAL cost (Total of 14 thru 19)84,860,s72 29,946,198
21 Cost per KW of lnstalled Capacity (line 20 / 5)216.7575 1,375.5718
22 Production Expenses
23 Operation Supervision and Engineering 462,476 192,974
24 Water for Power 234,316 752,957
25 Hydraulic Expenses 747,202 259,787
26 Electric Expenses 293,855 52,155
27 Misc Hydraulic Power Generation Expenses 572,468 147,112
28 Rents 33,693 0
29 Maintenance Supervision and Engineering 22,626 1 1,049
30 Maintenance of Structures 5,U4 9,719
31 Maintenance of Reservoirs, Dams, and Watemays 24,186 108,349
32 Maintenance of Electric Plant 217,964 57,501
33 Maintenance of Misc Hydraulic Plant ,141,058 134,467
34 Total Production Expenses (total 23 thru 33)3,0s5,688 1,726,070
35 Expenses per net KWh 0.0017 0.0112
FERG FORM NO. r (REV. 12-03)Page 406.1
Name of Respondent
ldaho Power Company
This Reoort ls:(1) fiAn Original(2) 1A Resubmission
Date of Reoort(Mo, Da, Yi)
0411412021
Year/Period of Report
End of 202010,4
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. Ptoduction Expenses
do not include Purchased Porer, System control and Load Dispatching, and OOcr Expenses classified as'Other Power Supply Expenses."
6. Report as a separate plant any plant equipped with combinations of steam, hydro, intemal combus$on engine, or gas turbino equipment.
FERC Licensed Project No. 2055
PlantNam€: 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 Runof-River Run-of-River 1
Outdoor Conventional Conventional 2
1952 1910 1935 3
1952 1994 1995 4
82.80 27.'.t7 s2.90 5
86 22 43 6
8,773 8,724 8,254 7
I
91 24 53 I
84 14 s0 10
5 4 3 11
447,516,000 119,947,000 53,183,000 12
13
5,725,987 309,958 255,499 14
9,991,310 27 '11,942,723 15
12,185,094 16,022,516 I,O25,077 16
14,754,153 32,178,0U 24,678,352 17
1,602,868 835,946 1,917,603 18
0 0 0 19
44,259,412 76,85'1,031 47,819,254 20
534.5340 2,828.5252 903.95s7 21
22
842,965 445,921 300,631 23
508,174 260,499 118,884 24
1,416,861 608,061 208,722 25
71,190 '122,434 47,968 26
6s7,821 382,2',t8 153,533 27
54,014 8,36S 4,299 28
18,594 22,M2 4,s03 29
84,549 36,146 31,765 30
68,1 15 37,173 11,276 31
233,207 363,950 50,467 32
161,496 223,387 39,0s2 33
4,116,986 2,510,600 971,100 u
0.0092 0.0209 0.0183 35
FERC FORM NO.1 (REV. 12-03)Page 407.1
Name of Respondent
ldaho Power Company
This Reoort ls:(1) [An Original(2) 5A Resubmission
Date of ReDort(Mo, Da, Yi)
o4l't412021
Year/Period of Report
End of 2O2O|Q4
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. 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 speciffing 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 Project 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 't907
4 Year Last Unit was lnstalled 1947 1921
5 Total installed cap (Gen name plate Rating in MW)34.50 't4.73
6 Net Peak Demand on Plant-Mesawatts (60 minutes)35 15
7 Plant Hours Connect to Load 8,004 5,929
8 Net Plant Capability (in megawatts)
9 (a) Under Most Favorable Oper Conditions 36 14
10 (b) Under the Most Adverse Oper Conditions 32 '11
11 Average Number of Employees 4 2
12 Net Generation, Exclusive of Plant Use - Kwh 157,397,000 52,529,000
13 Cost of Plant
14 Land and Land RighG 202,399 313,328
15 Structures and lmprovements 3,142,130 7,273,172
16 Reservoirs, Dams, and Waterways 8,941,800 14,909,006
17 Equipment Costs 9,472,784 18,353,776
18 Roads, Railroads, and Bridges 29,359 115,108
19 Asset Retirement Costs 0 0
20 TOTAL cost (Total of 14 thru 19)21,788,472 40,964,390
21 Cost per KW of lnstalled Capacity (line 20 / 5)631.549S 2,781.0177
22 Production Expenses
23 Operation Supervision and Engineering 279,948 135,757
24 Water for Power 160,929 73,973
25 Hydraulic Expenses 411,430 126,482
26 Electric Expenses 162,829 57,928
27 Misc Hydraulic Poriver Generation Expenses 236,943 1't5,901
28 Rents 0 211
2S Maintenance Supervision and Engineering 13,583 6,610
30 Maintenance of Structures 81,271 41,954
31 Maintenance of Reservoirs, Dams, and Watemays 32,148 15,960
32 Maintenance of Electric Plant 138,589 73,099
33 Maintenance of Misc Hydraulic Plant 147,U2 63,583
u Total Production Expenses (total 23 thru 33)1,665,512 7'.t1,458
35 Expenses per net KWh 0.0106 0.0135
FERC FORM NO.1 (REV. 12-03)Page 406.2
Name of Respondent
ldaho Power Company
This(1)
(2)
Reoort ls:
E]An orisinal
EA Resubmission
Date of Reoort(Mo, Da, Yi)
04t14t2021
Year/Period of Report
End of 202OlQ4
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accounts or combinations of accoun6 prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as'Other Power Supply Expenses.'
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC Licensed Project No. 1gt1
Plant Name: Common Facilities(d)
FERC Licensed Project No. 2061
Plant Name: Lower Salmon
(e)
FERC Licensed Project No. 2899
Plant Name: Milner (fl
Line
No.
Run-of-River Run-of-River 1
Outdoor Conventional 2
1949 1992 3
1949 't992 4
0.00 60.00 59.45 5
0 52 60 6
0 8,777 5,137 7
8
0 64 61 I
0 60 1 10
0 5 2 't1
0 234,128,000 127,584,000 12
13
114,368 424,428 1 38,100 14
64,749,493 3,536,806 10,664,732 15
13,556,785 7,973,770 17,779,586 16
2.672.003 27,420,989 29,308,394 17
142,581 88,693 501,877 18
0 0 0 19
8't,235,230 39,4/14,686 58,392,689 20
0.0000 657.4114 982.2151 21
22
0 398,943 196,360 23
0 197,894 630,313 24
7,192,733 507,148 117,257 25
0 19't,433 62,557 26
105 293,734 152,972 27
0 4,284 3,9sS 28
0 7,726 29
0 75,381 32,767 30
0 8,313 4J7A 31
0 65,885 u,282 32
121,60s 97,323 106,224 33
7,314,443 1,8/,8,725 1,438,575 u
0.0000 0.0079 0.0113 35
FERC FORM NO. t (REV. 12-03)Page 107.2
of
ldaho Power Company
(1)
(2)
An Original
A Resubmission
Date of ReDort(Mo, Da, Yi)
o41141202',1
Year/Period of Report
End of 20201Q4
1. Small generating plants are steam plants of, 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)
lnstalled uaDacit!
Name Plate Ratiril
(ln MW)
(c)
Net PeakDemand
MW(60,9in.)
Net GenerationExcludino
Plant UsE
(e)
Cost of Plant
(0
1 Hydro:
2 Clear Lakes 1937 2.s0 2.:1 17,443 3,576,511
3 Thousand Springs 1912 6.80 7.3 56,518 1 1,670,461
4
5
6 lntemal Combustion:
7 Salmon Diesel 1967 5.00 2.!34 88r'.,'t34
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORilt NO.1 (REV.12-03)Page 410
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Reoort(Mo, Da, Yi)
0411412021
Year/Period of Report
End of 20201Q4
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, specifoing period. 5. lf any plant is equipped with
combinations of steam, hydro intemal combustion or gas turbine equipment, report each as a separate plant. However, if the exhaust heat ftom the gas
turbine is utilized in a steam turbine regenerative feed water cycle, or for preheated combustion air in a boiler, report as one plant.
Plant Cost (lncl Asset
Retire. Costs) Per MW
(s)
Operation
Exc'|. Fuel
(h)
ProOuctron Expenses
Kind of Fuel
(k)
Fuel Costs (in cents
(per Million Btu)
fl)
Line
No.t-uet
(i)
Matntenanoe
0)
1
1,430,604 203,22'.1 '158,484 2
1,716,2U 189,430 127,118 3
4
5
6
176,827 Diesel 7
8
I
't0
11
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
43
44
45
46
FERC FORM NO.1 (REV.12.03)Page ,t11
Name of Respondent
ldaho Power Company
This Reoort ls:
5]nn Orlginat
J-lA Resubmission
(1
(2
Date of Report(Mo, Da, Yr)
04t14t2021
Year/Period of Repo(
End of 20201Q4
TRANSMISSION LINE 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 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
reportedforthelinedesignated; conversely,showincolumn(g)thepolemilesoflineonstructuresthecostofwhichisreportedforanotherline. 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.
UEl'IUNAIIUN Type of
Supporting
Structure
(e)
LENGTH (Pole miles)(ln the tase.ofunderoround lrnes
report Eircuit miles)
Number
of
Circuits
(h)
From
(a)
To
(b)
Operating
(c)
Designed
(d)
UlI JofDesi
uIt JUUCIUIeSof AnotherLine(s)
1 Borah Midpoint 345.0(500.00 S Tower 62.35
2 Boardman Slatt 500.0(500.00 S Tower 1.79
3 Summer lake Hemingway s00.0(s00.00 S Tower 0.08
4 Hemingway Midpoint 500.0(500.00 S Tower 0.15
5 Summer Lake Hemingway 500.0(500.00 S Tower 53.07
6 Hemingway MidDoint 500.0(500.00 S Tower 47.7e
7
8 Jim Bridger Goshen 345.0(345.00 S Tower 66.16
I State Line Midpoint 345.0(345.00 S Tower 76.06 I
'10 Kinport Borah 345.0(345.00 S Tower 19.8'l
11 Jim Bridger Populus 345.0(345.00 S Tower 60.93
12 Populus Kinport 345.0(345.00 S Tower 7.42
13 Jim Bridger Populus 345.0(345,00 S Tower 6'1.1C
14 Populus Borah 34s.0(345.00 S Tower 9.05
15 Goshen Kinport 345.0(345.00 S Tower 7.49
16 Midpoint Borah #'l 345.0(345.00 H Wood 51.0i
17 Midpoint Borah #2 345.0(345.00 H Wood 49.98 I
18 Adelaide Tap 345.0(345.00 H Wood 1.72 2
19
20 OuarE LaGrande 230.0(230.00 H Wood 45.9i 1
2',l Midpoint Hunt 230.0(230.00 S Tower 0.7c 2
22 Brady Antelope 230.0(230.00 H Wood 56.38 1
23 Brady Treasureton 230.0(230.00 H Wood 0.08 1
24 Brady #1 &#2 Kinport 230.0(230.00 S Tower 17 .94 2
25 Brownlee Ontario 230.0(230.00 S Tower 72.67 1
26 Mora Bowmont 138.0(230.00 S P Wood 9.99 1
27 Mora Bowmont 138.0(230.00 H Wood 8.75 1
28 Caldwell 710 Locust 230.0(230.00 SP Steel 18.50 1
29 Boise Bench Caldwell 230.0(230.00 S Tower 7.69 1
30 Boise Bench Caldwell 230.0(230.00 H Wood 33.49 I
31 Boise Bench Cloverdale 230.0(230.00 S Tower 16.08 2
32 Boardman Dalreed Sub 230.0(230.00 H Wood 1.67 1
33 Brownlee 714 Oxbow 230.0(230.00 SP Steel 10.96 2
34 Caldwell Ontario 230.0(230.00 H Wood 30.06 1
35 Caldwell Ontario 230.0(230.00 S Tower 3.14 1
36 TOTAL 4,769.22 11.02 215
FERC FORM NO, 1 (ED. 12-87)?age 422
Name of Respondent
ldaho Power Company
This(1)
(21
ReDort ls:
fiAn Originat
;1A Resubmission
Date of Report(Mo, Da, Yr)
04t1412021
Year/Period of Report
End of 2O20lQ4
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 voltrage 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 ftom 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
anangement and giving particulars (details) of such matters as per@nt ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Speciff 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 O to (l) on the book cost at end of year.
Size of
Conductor
and Material
(i)
uus r ol- LINE (lnclude In L;olumn u) Land,
Land rights, and clearing right-of-way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES
-ine
No.
Land
U)
Construction and
Other Costs(k)
Total Cost
(t)
Operation
Expenses(m)
Maintenance
Expenses
(n)
Rents
(o)
Total
Exnenses
t272 ACSR 256,38 16,047,91 I 16,304,29i 1
lx1780 ACSR 446,708 446,70t 2
t272 ACSR 3
r272 ACSR 4
tx1272 ACSR 18,865,933 18,865,93:5
}x1272 ACSR 't7,078,068 17,078,06t 6
7
1272 ACSR 483,30!5,321,732 s,805,041 8
I95 ACSR 571,97!1 1,320,88i 1 1,892,86(I
t272 ACSR 344,22{4,397,073 4,741,29i 10
t272 ACSR 9,535,579 9,s35,57(11
1272 ACSR 1?
t272 ACSR 9,259,964 9,259,96r 13
t272 ACSR 14
1x1272 ACSR 586,'144 586,1&15
f 15.5 ACSR 283,14i 17,652,637 17,935,7E(16
r15.5 ACSR 64,E51 14,905,055 14,969,90t 17
I15.5 ACSR 51,44t 224,249 275,69;18
19
/95 ACSR 62,21t 7,074,37Q 7,136,sEt 20
I15.5 ACSR 9,14r 999,238 I,008,38:21
t272 ACSR 163,32(3,827,00t 3,990,32{22
/95 ACSR 6,186 6,18(23
r15.5 ACSR 18,82(1,144,91t 1,163,74;24
2x954 ACSR 1,676,83t 20,730,37!22,407,213 25
I15.5 ACSR 413,79i 2,377,901 2,79'1,698 26
/15.5 ACSR 27
t590 ACSR 2,378,43(8,775,086 11,153,522 28
t272 ACSR 1,74E,20i 7,833,438 9,581,640 29
/15.5 ACSR 30
t272 ACSR 3,062,811 7,151,lU 10,213,946 31
/95 MC 89,08!89,089 32
)54 ACSR 34,171 16,026,47(16,060,644 33
2x954 ACSR 236,15i 9,386,76€9,622,918 34
1272 ACSR 35
35,649,6s4 685,372,706 721,02n64 8,503,434 1,591,871 4,011,44:14,106,74t 36
FERC FORM NO.1 (ED.12-87)Page 423
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5]Rn Orisinal(2) ;-1A Resubmission
Date of Report(Mo, Da, Yr)
o4t't412021
Year/Period of Report
End of 2O2O|Q4
TRANSMISSION LINE STATISTIGS
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 @sts 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-ftame wood, or steel poles; (3) tower;
or (4) underground construction lf a transmission line has more than one type of supporting sfucture, 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 ftom 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 sructures 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.
DESIGNAI ION Type of
Supporting
Structure
(e)
LENGTH (Pole miles)(ln the Case.ofunderoround linesreportEircuit miles)
Number
of
Circuits
(h)
From
(a)
To
(b)
Operating
(c)
Designed
(d)
vlt 0ofDesi
vlt ouuululgsof AnotherLrne(s)
1 Bennett Mtn PP Rattlesnake TS 230.0(230.00 SP Steel 4.39 1
2 Borah Hunt 230.0(230.00 H Steel 68.12 ,|
3 Danskin Hubbard 230.0(230.00 H Steel 36.25 1
4 Danskin Hubbard 230.0(230.00 SP Steel 1.84 1
5 Danskin Hubbard 230.0(230.00 SP Steel 1.30 2
6 Danskin Bennett Mtn 230.0(230.00 SP Steel 5.39 1
7 Hemingway Bowmont 230.0(230.00 SP Steol 12.94 1
I Langley Gulch Galloway Rd 138.0(230.00 SP Staal 14.1S 'l
o Galloway Rd Willis Tap 138.0(230.00 SP Steel 2.0s I
10 Walla Walla 230.0(230.00 H Wood 31.6i 1
11 Boise Bench Midpoint #1 230.0(230.00 S Tower 0.71 1
12 Boise Bench Midpoint #1 230.0(230.00 H Wood 108.6i 1
13 Brownlee Quartz Jct 230.0(230.00 S Tower 1.5'l 1
14 Brownlee Quartz Jct 230.0(230.00 H Wood 41.30 1
15 Brownlee Boise Bench #1 &#2 230.0(230.00 S Tower 99.78 2
16 Oxbow Brownlee 230.0(230.00 S Tower 10.32 2
17 Boise Bench Midpoint #2 230.0(230.00 S Tower 3.4S I
18 Boise Bench Midpoint #2 230.0(230.00 H Wood 102.17 1
19 Oxbow Pallette Jct 230.0(230.00 S Tower 19.9i 2
20 Pallette Jct lmnaha 230.0(230.00 H Wood 24.43 I
21 Hells Canyon Palette Jct 230.0(230.00 S Tower 9.05 2
22 Brownlee Boise Bench 230.0(230.00 S Tower 10214 I
23 Boise Bench Midpoint #3 230.0(230.00 H Wood 106.2!1
24 Palefte Jct Enterprise 230.0(230.00 H Wood 29.60 1
25 Borah Brady#2 230.0(230.00 S Tower 0.42 1
26 Borah Brady #2 230.0(230.00 H Wood 3.s2 1
27 Borah Brady #1 230.0(230.00 H Wood 3.8{1
28
29 Goshen 161.0(161.00 H Wood 40.8!1
30 Don Goshen 161.0(161.00 S Tower 2.37 2
31 Don Goshen 161.0('t61.00 H Wood 16.4!2
32 Don Goshen 138.0(161.00 H Wood 29.6{I
33 Antelope 161.0(161.00 H Wood s.68
u Goshen 161.0(161.00 H Wood 10.9C
35 Goshen 161.0(161.00 H Wood 7.84
36 TOTAL 4,769.2i 11.02 215
FERC FORM NO. 1 (ED. 12.87)Page 422.1
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5]Rn orisinat(2) ;-1A Resubmission
Date of ReDort(Mo, Da, Yi)
0411412021
Year/Period of Report
End of 2O20lQ4
IRANSMISSION LINE STATISTICS (Gontinued)
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 (0 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 thereot for
which the respondent is not the sole owner but which the respondent operates or shares in the operation ol fumish a succinct statement explaining the
anangement and giving particulars (details) of such matters as per@nt 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 affec{ed. Specifo whether lessor, co-owner, or
other party is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Speciff 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 I uF L|NE (tnctuoe rn uotumn 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
o
Operation
Expenses
(m)
Maintenance
Expenses(n)
Rents
(o)
TotalExn;;ses
t272 ACSR 81,701 1,666,354 '1,748,05{1
t590 ACSR 624,917 22,467,321 23,092,238 2
1590 ACSR 15,210,56'l 15,210,561 3
1590 ACSR 4
t590 ACSR 5
1590 ACSR 3,528,033 3,528,033 6
1590 ACSR 1,854,99(9,277,980 11,132,976 7
t590 ACSR 94E,16(9,067,60!'10,015,775 I
r272 ACSR 9
r272 ACSR 6,601,68'6,601,682 10
r15.5 ACSR 385,28i 14,882,224 15,267,511 11
r15.5 ACSR 12
I95 ACSR 53,06t 4,882,79!4,935,867 13
r95 ACSR 14
/ARIOUS 289,92:9,545,643 9,835,566 15
t272 ACSR 14,81(1,489,69i 1,504,502 16
/15.5 ACSR 227,E14 18,549,1 I 1 18,776,925 17
/ARIOUS 't8
1272 ACSR 87,46{3,933,05€4,020,526 19
1272 ACSR 't71,081 4,156,591 4,327,672 20
1272 ACSR 44,68i 1,492,66(1,537,34i 21
)54 ACSR 184,80t 6,411,7U 6,596,53S 22
r15.5 ACSR 247,Ut 8,149,83!8,397,685 23
1272 ACSR 84,01r 2,352,21t 2,436,n4 24
t272 ACSR 3,06r s36,01!539,0Ei 25
715.5 ACSR 26
t272 ACSR 7,24t 427,22t 434,476 27
28
250 COPPER 375,57(3,082,27t 3,457,854 29
715.5 ACSR 88,20r 2,638,89i 2,727,101 30
397.5 ACSR 31
397.5 ACSR 32
397.5 ACSR 797,97(797,974 33
250 COPPER 1 16,87i 1,252,441 1,369,322 34
250 COPPER 76,96(515,185 592,1s4 35
35,649,654 685,372,706 721,022,36t 8,503,434 1,591,871 4,011,443 14,106,74{36
FERC FORM NO.1 (ED.12-87)Page 423.1
ldaho Power Company (1)
(2)
An Original
A Resubmission
(Mo,
04114t2021
Year/Period of Report
End of 2O20lQ4
TRANSMISSION LINE STATISTICS
1. Report information conceming transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of 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 ftom 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-ftame 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 tom 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 VUL IAL'E IKV}(lndicate wherebther than
6O cvcle. 3 ohase)
Type of
Supporting
Structure
(e)
LENGTH (Pole miles)(ln the Case.ofunoeroround linesreportEircuit miles)
Number
of
Circuits
(h)
From
(a)
To
(b)
Operating
(c)
Designed
(d)DeoJ
rclurenetated
UN UUUCIUTESof AnotherLine(s)
1
2 American Falls Power Plant Adelaide 138.0(138.00 H Wood 14.0i 2
3 American Falls Power Plant Adelaide 13E.0(138.00 S P Wood 0.1i 2
4 Minidoka Loop Adelaide 138.0(138.00 S Tower 1.1:2
5 Nampa Caldwell 138.0(138.00 S P Wood orc 2
6 Skyway Tap 138.0('138.00 S P Steel 0.8!I
7 Upper Salmon Mountain Home Jct 138.0(138.00 H Wood 54.3t
I Upper Salmon ctiff 138.0(13E.00 H Wood 30.8'l
I Eastgate Russet 138.0(138.00 S P Wood 2.0€I
10 Brady Fremont 138.0(138.00 S Tower 1.01 I
11 Brady Fremont 13E.0(138.00 H Wood 24.38 2
12 Brady Fremont 138.0(138.00 S P Wood 24.33 2
13 Kins Lower Malad 138.0(138.00 H Wood E4.73 2
14 Emmett Jct Payette 138.0(138.00 H Wood 66.4€2
15 Mountain Home AFB Tap 138.0('t38.00 H Wood 6.2C 1
16 Ontado QuarE 138.0(138.00 H Wood 73.2C 1
17 King American Falls PP '138.0(I 38.00 S Tower 0.91 2
18 King American Falls PP 138.0('138.00 H Wood 142.05 1
19 King American Falls PP 138.0(138.00 S P Wood 3.71 1
20 Duffin Clawson 138.0(138.00 H Wood 6.1S 1
21 American Falls Brady Tie 138.0(138.00 H Wood 0.33 I
22 Upper Salmon A-B King 138.0(13E.00 H Wood 5.66 1
23 Upper Salmon B Wells 138.0(138.00 H Wood 125.47 1
24 King Wood River 1 38.0(138.00 H Wood 73.72 1
25 Toponis Pocket 138.0(138.00 S P Wood 9.80 1
26 Boise Bench Grove 138.0(138.00 S P Wood 10.3i 2
27 QuarE John Day 138.0(138.00 H Wood 67.30 ,|
28 Sinker Creek Tap 138.0(138.00 H Wood 2.79 1
29 Mora Cloverdale 138.0(136.00 H Wood 2.51 1
30 Mora Cloverdale 138.0(138.00 S P Wood 22.26 1
31 Mora Cloverdale 138.0(138.00 S P Steel 0.96 2
32 Stoddard Jct Stoddard Sub 138.0(138.00 S P Steel 3.80 1
33 Fossil Gulch Tap 138.0('138.00 H Wood 1.8't 1
34 Wood River Midpoint 138.0(I 38.00 H Wood s3.08 2
35 Wood River Midpoint 138.0(138.00 S P Wood 16.69 2
36 TOTAL 4,769.22 11.02 215
FERC FORM NO.1 (ED.12-87)Page 122.2
Name of Respondent
ldaho Power Company
This Reoort ls:(1) E]An Orisinal
(21 [lA Resubmission
Date of Report(Mo, Da, Yr)
0411412021
Year/Period of Report
End of 20201Q4
TRANSMISSION LINE SIAI IS I IUS
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 ol fumish a succinct statement explaining the
anangement 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. Speciry whether lessee is an associated company.
10. Basetheplantcostfigurescalledforincolumns(j) to(l)onthebookcostatendofyear.
Size of
Conductor
and Material
(i)
uuu r uF L|NE (rnquoe rn uorumn u) Lano,
Land rights, and clearing right-of-way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES
-ine
No.
Land
0)
Construction and
Other Costs(k)
Total Cost
(t)
Operation
Expenses(m)
Maintenance
Expenses
(n)
Rents
(o)
Total
Exlelses
I
250 COPPER 26,5o',i 385,06€4',t1,573 2
250 COPPER 3
/15.5 ACSR 21,32i 2s0,46!271,794 4
795 AAC 1,796,31'6,020,65€7,819,170 5
1272 ACSR 6
/95 ACSR 78,07t 5,041,25r 5,1 I 9,332 7
r95 ACSR 43,s6{3,336,497 3,380,065 8
795 MC 270,82i 56't,s61 832,384 I
/ARIOUS 564,93'4,749,42t 5,314,358 10
/ARIOUS 11
/ARIOUS 12
YARIOUS 76,821 4,305,E1a 4,382,638 13
YARIOUS 61,871 4,720,35!4,782,231 14
397.5 ACSR 5,08(81,843 86,92!15
/ARIOUS 34,421 9,054,821 9,089,24!'t6
r15.5 ACSR 216,91!1 1,389,146 1'1,606,065 17
'15.5 ACSR 18
r15.5 ACSR 19
1\0 4,19'475,664 479,855 20
)54 ACSR 98,179 98,17!21
I5O COPPER 2,741 E93,399 896,'14(22
/ARIOUS 2E,49(4,905,542 4,934,03'23
/ARIOUS 186,19r 24,913,821 25,100,01!24
197.5 ACSR 25
/ARIOUS 225,60i 1,646,30E 1,871,91(26
)97.5 ACSR 96,58'2,7E0,313 2,876,894 27
/ARIOUS 1't,08:137,342 148,42!28
f 15.5 ACSR 3,'t65,951 12,024,5E6 't5,190,53?29
iARIOUS 30
r9sAAC 31
t272 ACSR 32
I50 COPPER 45(190,553 '191,00:33
!97.5 ACSR 349,71i 8,s43,60!8,893,32'1 34
]97.5 ACSR 35
35,649,654 685,372,706 721,022,360 8,503,43{1,s91,871 4,011,44:14,106,74{36
FERC FORM NO.1 (ED.12.87)Page 423.2
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5]Rn Orisinat
(21 [-1A Resubmission
Date of Reoort(Mo, Da, Yi)
04t14t202',1
Year/Period of Report
End of 20201Q4
TRANSMISSION LINE STATISTICS
1 . Report information conceming transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltiages 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-ftame 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 ftom 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
Uts,s'I(,NAIIUN Type of
Supporting
Structure
(e)
LENGTH (POIE MilES}(ln the dase.ofunderoround lines
report Eircuit miles)
Number
of
Circuits
(h)
From
(a)
To
(b)
Operating
(c)
Designed
(d)
un5ofDesi
rcturenerated
un Strucruresof AnotherLlne(s)
1 Oxbow McCall 138.0(138.00 H Wood 37.05 1
2 Oxbow McCall 138.0(138.00 S P Wood 2.32 1
3 Lowell Jct Nampa 138.0(138.00 S P Wood 7.49 I
4 Hunt Milner 138.0(138.00 S P Wood 19.41 1
5 Strike Bruneau Bridge 138.0(13E.00 H Wood 13.49 1
6 American Falls Kramer Sub 138.0(13E.00 S P Wood 18.46 2
7 Pingree Haven 138.0(13E.00 S P Wood 11.72 1
8 Midpoint Twin Falls 138.0(138.00 S P Wood 25.24 2
I Twin Falls Russett 138.0(138.00 S P Wood 1.71 1
10 Blackfoot Aiken 46.0(138.00 S P Wood 6.22 I
11 Peterson Tendoy 69.0(138.00 H Wood 57.03 1
12 Eastgate Tap Eastgate 138.0(138.00 S P Wood 6.36 1
13 Kimberly Tap Kimberly 138.0(138.00 S P Steel 't.84 I
14 Boise Bench Mora 138.0(138.00 H Wood 13.10 I
15 Bowmont-Caldwell Simplot Sub r38.0(138.00 S P Wood 0.51 1
16 Gary Lane Eagle 138.0(138.00 S P Wood 6.65 1
17 Locust Grove Blackcat Sub 138.0(13E.00 S P Steel 9.26 2.98 I
18 Boise Bench Butler 138.0(138.00 S P Wood 0.1{4.02 1
19 Eagle Star 138.0(138.00 S P Wood 6.75 1
20 Star Lansing 138.0{138.00 S P Steel 5.50 I
21 Beacon Light Tap Beacon Lisht 138.0(138.00 S P Steel 4.32 1
22 Karcher Sub Zilog Tap 138.0(138.00 S P Steel 3.12 1
23 Zilog Can Ada 138.0(138.00 S P Steel 1.s0 1
24 Blackcat Can Ada r38.0(138.00 H Wood 3.42 1
25 Cloverdale - 712 712 -Wye 138.0(138.00 S P Steel 0.42 4.02 1
26 Victory Jct Mctory 138.0(138.00 S P Steel 1.8S I
27 Butler Wye 138.0(138.00 S P Steel 2.94 1
28 Horseflat Starkey 138.0(138.00 H Wood 33.9i 1
29 Starkey Mccall 138.0(r38.00 S P Steel 2.23 I
30 Sta*ey Mccall 't38.0(138.00 H Wood 3.E0 1
31 Starkey Mccall 138.0(1 38.00 S P Steel 1.50 1
32 Starkey Mccall 138.0(138.00 S P Wood 17.61 I
33 Chestnut Happy Valley 138.0(1 38.00 S P Steel 2.78 1
34 Garnet Ward 1 38.00
35 McCall Lake Fork 138.0('138.00 S P Wood 8.8!I
36 TOTAL 4,769.22 11.02 215
FERC FORM NO. r (ED. 12-87)Page 422.3
ldaho Power Company (1 Original (Mo, Da,
(2)Resubmission 0411412021
Year/Period of Report
End of 202OlQ4
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. lf two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. lf such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereol for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, 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 (i) to (l) on the book cost at end of year.
Size of
Conductor
and Material
(i)
uutt r uF LINE (lncluoe rn L;olumn 0) Land,
Land rights, and clearing right-of-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
ExFenses
,97.5 ACSR '141,53'2,74s,214 2,8E6,748 1
!97.5 ACSR 2
r15.5 ACSR 211,13'1,454,E79 1,666,010 3
r15.5 ACSR 3,32/1,544,714 1,s48,038 4
,97.5 ACSR 14,92',717,475 732,402 5
r15.5 ACSR 13,73/1,367 ,794 1,3E1,528 6
,97.5 ACSR 18,22i 1,299,173 1,317,396 7
/ARIOUS 66,28(3,275,211 3,341,49i 8
r15.5 ACSR 16,79(213,033 229,E23 I
r15.5 ACSR 13,61(580,144 593,760 10
!97.5 ACSR 395,69r 3,619,189 4,014,885 11
r15.5 ACSR 343,95r 2,195,624 2,539,579 12
I95 ACSR 13
r15.5 ACSR 14,69;736,552 751,241 14
/95 AAC s0,31s 50,31(15
I95 AAC 308,14 2,175,443 2,483,58r 16
1272 ACSR 935,E1(3,800,97s 4,736,785 17
t272 ACSR 34,6E;838,605 873,291 t8
r15.5 ACSR 621,921 8,553,915 9,175,83{19
r95 AAC 20
I95 AAC 21
r95 AAC 43,911 2,310,399 2,354,310 22
I95 AAC 23
!97.5 ACSR 24
r272 ACSR 140,41"2,602,s23 2,742,935 25
t272 ACSR 26
I95 ACSR 134,471 1,40s,436 1,539,90i 27
r15.5 ACSR 2,473,83i 19,000,082 21,473,91!2E
I15.5 ACSR 29
/15.5 ACSR 30
I15.5 ACSR 31
/15.5 ACSR 32
1272 ACSR 78,57!2,219,508 2,298,08i 33
40,58(40,580 34
r15.5 ACSR 331,53!4,682,879 5,014,41 35
35,649,654 685,372,706 721,022,360 8,503,434 1,591,87'l 4,011,44X 14,106,74r 36
FERC FORM NO.1 (ED. 12.87)Page 423.3
Name of Respondent
ldaho Power Company (1 An
(2\A Resubmission
Date of Reoort(Mo, Da, Yi)
04t1412021
Year/Period of Report
End of 20201Q4
TRANSMISSION LINE STATISTIGS
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.
DESIGNATION VULIAGE (KV)(lndicate wlierebther than60 cvcle. 3 ohase)
Type of
Supporting
Structure
(e)
LENGTH (Pole miles)(ln the Case-ofunoeroroun0 lines
report -circuit miles)
Number
of
Circuits
(h)
From
(a)
To
(b)
Operating
(c)
Designed
(d)
UII JUUGIUtCSof AnotherLine
(s)
1 McCall Lake Fork 138.0(138.00 S Steel 2.90 1
2 Caldwell Willis 't38.0(138.00 S P Steel 1.30 1
3 Caldwell Willis 't38.0(138.00 S P Steel 3.62 1
4 Caldwell Willis 138.0(138.00 S P Wood 0.8i 1
5 Willis Lansing 138.0(138.00 Verious 3.23 I
6 Valivue Tap 1 3E.0(138.00 S P Steel 0.7s 2
7 Bowmont Happy Valley 13E.0(13E.00 S P Steel 8.65 1
8 Antelope 138.0(138.00 H Wood 0.12 1
I American Falls 138.0(138.00 H Wood 1.05 1
10 Kinport Don #1 138.0(138.00 S Tower 1.27 2
11 Donn HOKU 138.0(138.00 S P Steel 2.69 1
12 HOKU Alamed 't38.0(138.00 S P Steel 0.22 2
13 HOKU Alamed 138.0(138.00 S P Steel 0.23 2
14 HOKU Alamed 138.0(138.00 S P Steel 2.E5 1
15 Eldridge tap 't38.0(138.00 S P Steel 0.85 1
16 Rockland Jct Rockland Wind Farm 138.0(138.00 S P Steel 5.1E 1
17 King Justice 138.0(138.00 S P Wood 0.0i 1
18 NorthView Tap 138.0(138.00 S P Wood 6.1i 1
19 Twin Falls PP Tap 138.0(138.00 H Wood 0.9!1
20 American Falls PP Amercian Falls Trans ST 138.0(138.00 S P Steel 0.3i 1
21 Lower Salmon King Tie 138.0(138.00 H Wood 0.11 1
22 C J Strike Strike Jct '138_0(138.00 S Tower 4.3C 2
23 Strike Jct Mountain Home Jct 138.0(138.00 H Wood 2t.42 1
24 Strike Jct Bowmont 138.00 H Wood 0.05 1
25 Strike Jct Bowmont 138.0(138.00 S Tower 0.36 I
26 Strike Jct Bowmont 138.0(138.00 H Wood 67.8!I
27 Lucky Peak Lucky Peak Jct 138.0(138.00 H Wood 4.48 2
28 Bliss King 138.0(138.00 H Wood 10.51 1
29 Milner Deadend Milner PP 138.0(138.00 S P Wood 1.3C 1
30 Swan Falls Tap 138.0('138.00 H Wood 0.95 1
31
32
33
34 Hines BPA (Harney)1 15.0(11s.00 H Wood 3.3r 1
35
36 IOIAL 4,769.2i 11.02 215
FERC FORM NO.I (ED. 12-87)Page 122.4
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5]Rn Orisinat(2) [-1A Resubmission
Date of ReDort(Mo, Da, Yi)
0411412021
Year/Period of Report
End of 20201Q4
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 fiom 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
anangement and giving particulars (details) of such matters as per@nt 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. Speciff whether lessee is an associated company.
1 0. Base the plant cost figures called for in columns fi) to (l) on the book cost at end of year.
Size of
Conductor
and Material
(i)
COST OF LINE (lnclude in Golumn (j) Land,
Land rights, and clearing right-of-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
Exlerlses
7'15.5 ACSR I
'1272 ACSR 846,52:5,852,771 6,699,29i 2
795 ACSR 3
795 ACSR 4
/95 ACSR 5
795 ACSR 351,497 351,497 6
1272 ACSR 691,72t 6,045,28(6,737,01{7
397.5 ACSR 94,004 94,004 8
250 COPPER 105,6E4 105,684 I
7't5.5 ACSR 1.171 267,313 268,487 10
'1272 ACSR 327,331 2,176,959 2,s04,293 11
1272 ACSR 12
795 ACSR 13
79s ACSR 14
79s ACSR 15
'95 ACSR -16,973 -16,973 16
t590 ACSR 60,6s9 60,65!17
,15.5 ACSR 105,93i 4,125,054 4,230,98i 18
I5() COPPER 5{64,210 64,268 19
r15.5 ACSR 176,760 '176,76(20
i97.s ACSR 4,773 4,773 21
'15.5 ACSR 1,071 636,s45 637,61!22
i97.5 ACSR 6,33'2,566,179 2,572,511 23
'15.5 ACSR 86,65 4,837,514 4,924,16a 24
I15.5 ACSR 25
715.5 ACSR 26
'15.5 ACSR 295,545 295,552 27
r15.5 ACSR 5,62(1,733,9'14 1,739,534 28
'15.5 ACSR 14,96t 183,606 198,574 29
i97.5 ACSR 17,20i 262,521 279,728 30
31
32
33
i97.5 ACSR 't,97t 68,812 70,79C 34
35
35,649,654 685,372,706 721,022,36t 8,503,434 1,591,871 4,01 '1,443 14,106,74t 36
FERC FORM NO. 1 (ED. 12.87)Page 423.1
Name of Respondent
ldaho Power Company
(1)
(2)
Original Date of Reoort(Mo, Da, Yi)
0411412021Resubmission
Year/Period of Report
End of 20201Q4
TRANSMISSION LINE STATISTICS
1. Report information conoerning 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-ftame 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.
UEs'I(,NAIIUN Type of
Supporting
Structure
(e)
LENGTH (POIC MiIES)(ln the tase.ofunderoround lines
report Eircuit miles)
Number
of
Circuits
(h)
From
(a)
To
(b)
Operating
(c)
Designed
(d)
UN J]ofDesi
rc[urenerated
un Strucruresof AnotherLlne
(s)
1
2 69 Kv Lines 69.0(69.00 H Wood 205.81 1
3 69 Kv Lines 69.0(69.00 S P Wood 875.43 1
4
5
6 46 Kv Lines 46.0(46.00 S P Wood 377.21 ,|
7
8 Total all lines 4,769.22 11.02 215
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 TOTAL 4,769.22 11.02 215
FERC FORM NO. 1 (ED. 12.E7)Page 422.5
ldaho Power Company (1)
(2)
Original
Resubmission
Date of Reoort(Mo, Da, Yi)
04t14t2021
Year/Period of Report
End of 202OlQ4
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 ftom 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 thereot 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 ownership by respondent in the line, name of coowner, 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 crmpany 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 O to (l) on the book cost at end of year.
Size of
Conductor
and Material
(i)
uos I ol- LINE (lnclude in uolumn u) Lano,
Land rights, and clearing right-of-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
Exlelses
1
/ARIOUS 1,851,321 92,393,477 94,2M,799 2
/ARIOUS 3
4
5
/ARIOUS 196,s0:25,212,02Q 25,406,52S 6
8,503,434 1,591,87't 4.011,444 14,106,74t 7
35,649,65r 685,372,70€721,02n64 8,503,434 1,591,871 4,01'.t,44i 't4,106,74C I
9
10
11
12
13
14
15
16
17
,IE
19
20
21
22
23
24
25
26
2'l
28
29
30
31
32
33
34
35
35,649,65r 685,372,706 721,022,36(8,503,434 1,s91,871 4,011,443 14,106,741 36
FERC FORM NO.1 (ED. 12.87)Page 123.5
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2) A Resubmission
Date of Report
(Mo, Da, Yr)
o4l't41202'.1
Year/Period of Report
2020to,4
FOOTNOTE DATA
n y owne Pac Corp Power owns 73.22 o 85 .4 l-eline422 Line No.:2 Column: bs1lslntly owned th Portland General Electr c and Tdaho Power owns 10.0? ofthis 17.8 mile line422 Line No.:3 Column: b
n y owned wiEh PacifiCorp Power owns 22.0 o 24]- .3 eline
422 Line No.:4 Column: bs11Sntly owned th Pac f rp and Idaho Power owns 37.0? of t.h 129.3 mileline422 Line No.: 5 Column: b
n y owne Pac Corp Power owns 22.0? o s 247.3 1eline422 Line No.: 6 Column: b s 129.3 mileline
Scneaurc page: IZZ tine tto.: g Cotumn* - ,
Th@ owned with Pacificorp ia 22G.G rnlle-line
1 Isl ntly owned th Pac f rp and Idaho Power owns 37.0? of
422 Line No.: 10 Column: b
1 is jointly owned th Pac f Corp and Idaho Power owns 73.2? of s 27-1 mileline422 Line No.: 11 Column: b
s ne t owne Pac r Power owrfs 29.2imatel193le line.
s lo t1y owned th Pac f Corp and Idaho Power owns 29.2e" of Ehis 4l-.2 mileThs1neline
422 Line No.: 12 Column: b
422 Line No.: 13 Column: b
s ne t owne hrith Pacif I Power owns 29.2matel193Ie line.
ne o t1y owne Pac and Idaho Power owns 29.21 of s 47.3 1eThs1line
422 Line No.: 14 Column: b
422 Line No.: 15 Column: bThislineneot1y owned with PacifiCorp and T Power owns 18.3?s 40.9 e
122 Line No.: 16 Column: bs1neSotIyPac Corp and Idaho Power owns 54.48 of t s 79.5 1eline
Th 1 ne 1s lo t1y owned th Pac f Corp and Idaho Power owns 54.42 of t s 77-9 1eline.
WNo:llcolumn:b--1This line is jointly owned with pacificorp and Idaho Power owns 54.42 of this 0.9 mile
1ine.
Th 1 ne s o t1y Port ect c Idaho Power owns l-0.0? ofthis 15.7 mile line
422 Line No.: 17 Column: b
122 Line No.:32 Column: b
422.1 Line No.: 10 Column: b
Thline 1 ne ].s lo t1y owned th Pac f Corp and Idaho Power owns 40.8? of s 77.5 1e
Schedule Page:422.1 Line No.: 29 Column: b
FERC FORM NO.1 (ED. 12.871 Pase 450.1
Name of Respondent
ldaho Power ComDany
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
0411412021
Year/Period of Report
20201o,4
FOOTNOTE DATA
This line is jointly owned with PacifiCorp. Idaho Power owns 37.8? of Goshen- Jefferson28.9 mile segment, 3'7.82 of the Jefferson- Big Grassy 20.8 mile segmenL and 100? of the
B Gras - State Line 40.9 mile t
S o t v Pac Corp Power owns 21.98 o s 25.8 1e
1ine.
s1 S o t1y owned th Pac fiCorp. Idaho Power owns 37.8? of Goshen- ,Jefferson
28.9 mile segment, 37.82 of the ifefferson- Big crassy 20.8 mife segment and 100t of theBiGrasState Line 40-9 mile t.
s1 e s o Iy owned th PacifiCorp. Idaho Power owns 37.8? of Goshen- Jefferson28.9 mile segment, 37.8"6 of the Jefferson- Big crassy 20.8 mil-e segment and 100? of theBiGrasState Line 40.9 mile t.
s1 s o ly owned t.h PacifiCorp and Idaho Power owns 11.5? of th 1mi e1
422.1 Line No.:33 Column: b
422.1 Line No.:34 Column: b
422.1 Line No.:35 Column: b
422.4 Line No.:8 Column: b
422.4 Line No.:9 Column: b
o v Pac Corp and Idaho Power owns 7.2* of Eh 29.1,1e
1ine.
FERC FORM NO. I (ED. 12-871 Page 450.2
Name of Respondent
ldaho Power Company
This Reoort ls:(1) fiRn Original(2) ;-1A Resubmission
Date of ReDort(Mo, Da, Yi)
04t14t202',1
Year/Period of Report
End of 2O20lO4
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.
LIIIG
LepUth
tnMiles
(c)
SUPPUK I ING 5I h(UU I UKts,UII(UUI I5 IJEK 5I KUU I UK
From
(a)
To
(b)
Type
(d)
AYeIageNumbeiper
Miles
(e)
Present
(0
Ultimate
(s)
1 Blackcat Can-ada 3.42 S P Steel I 2
I Beacon Light Tap Beacon Light 4.12 H Wood 1 8.0r 1 1
Cloverdale Locust Grove 0.18 S P Steel 16.6r 2
4 Cloverdale Boise Bench 0.18 S P Steel 16.6t I 2
c
t
7
€
C
1(
11
12
1a
14
1t
1€
17
18
19
2a
21
22
2i
24
2a
26
27
28
29
30
31
32
33
34
35
36
37
38
ao
40
41
42
43
44 TOTAL 8.10 69.75 6 7
FERC FORM NO.1 (REV.12.03)Page 421
Name of Respondent
ldaho Power Company
Thas Reoort ls:(1) fiAn Original(2) 1A Resubmission
Date of ReDort
(Mo, Da, Yi)
o4l'14t2021
Year/Period of Report
End of 2O20lA4
costs. Designate, however, if estimated amounts are reported. lnclude costs of Clearing Land and Rightsof-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.
L;UNUUU I UKlj Voltage
KV
(oe?[3tins)
LINE L;Os I Line
No.Size
(h)
Specification
(i)
Confiouration
and Spacing
fi)
Land and
Land Rights
fl)
Poles, Towers
and Fixtures(m)
Conductors
and Devices(n)
Asset
Retire. Costs(o)
Total
(o)
397.5 ACSR lbis Various 13t 1,026,E6(668,393 1
795 ACSR Tem Various 13€442,102 902,14(832,714 z
1272 ACSR Bittem 90 DCOE 23(516,741 55,0'14 1
1272 ACSR Bittem 90 DC.DE 23(4
E
6
7
8
I
10
11
12
13
14
15
16
17
18
19
2A
21
22
23
24
25
26
27
28
29
3C
31
32
33
34
35
36
37
38
39
40
41
42
43
442,102 2,44s,74t 1,s56,121 4,443,971 44
FERC FORM NO. r (REV.12.03)Page 125
This Page lntentionally Left Blank
Name of Respondent
ldaho Porryer Company
This Report is:
(1) X An OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
0/,|1412021
Year/Period of Report
2020tQ4
FOOTNOTE DATA
Schdula Paoe: 124 Line No.: 7 Column: cI Lenqth in miles and Averaqe (per mile reporte(44 Line No.: 7 e
424 Line No.:1 Column: o
For Co umn C:
For umn E:
Estimated amounts are
EsE maEed amounts are
Es mated amounts are reported
1e
n wire miles.
re 1es
424 Line No.:2 Column: o
121 Line No.:3 Column: o
FERC FORi,t NO.1 (ED. 12-871 Pase 450.1
Name
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
041't412021
YeariPeriod of Report
End of 20201Q4
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
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)
I Adelaide transmission 345.0C 138.00 13.80
2 Aiken distribution 46.0C 13.00
3 Alameda distribution 138.0C 13.00
4 Alameda distribution 138.0(13.09
5 American Falls PP - attended transmission 138.00 13.80
6 American Falls transmission 't 38.0c 46.00 12.47
7 Antelope transmission 230.00 161 .00 '13.80
8 Antelope transmission 't61.00 138.00 12.47
I Antelope transmission 16't.00 138.00 13.8C
10 Artesian distribution 46.00 13.00
11 Bannock Creek distribution 46.00 13.00
12 Beacon Light distribution 138.00 13.09
13 Bennett Mountain Power Plan! attended transmission 230.00 't8.00
't4 Bennett Mountain Power Plant- attended distribution 18.00 4.16
15 Bethel Court distribution 't 38.00 13.00
16 Big Grassy transmission 161 .00
17 Black Cat distribution 138.00 13.0S
18 Black Mesa distribution 138.00 13.00
19 Blackfoot distribution 46.00 '13.00
20 Blackfoot transmission 161 .00 46.00 12.47
21 Blackfoot distribution 16't .00 138.00 12.94
22 Bliss - attended transmission 138.00 13.80
23 Blue Gulch distribution 138.00 35.00
24 Boise Bench transmission 230.00 138.00 13.2C
25 Boise Bench distribution 't 38.00 35.00
26 Boise Bench transmission 138.00 69.00 't2.98
27 Boise Bench transmission 230.00 '138.00 13.8C
28 Boise distribution 138.00 13.00
29 Borah transmission 345.00 230.00 '13.80
30 Border distribution 138.00 13.00
3'l Border distribution 35.00
32 Bowmont distribution 138.00 35.00
33 Bowmont transmission 138.00 69.00 12.98
34 Bowmont transmission 138.00 69.00 12.47
35 Bowmont transmission 230.00 138.00 13.80
36 Brady transmission 230.00 138.00 13.80
37 Brady transmission 138.00 46.00 12.47
38 Brady distribution 46.00 13.00
39 Brady distribution 46.00 7.20
40 Brownlee - attended transmission 230.00 13.80
FERC FORM NO. 1 (ED. 12-96)Page 426
Name of Respondent
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Reoort
(Mo, Da, Yi)
04t14t2021
Year/Period of Report
Endof 202UQ4
5. Show in columns (l), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity,
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. 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 of
Spare
Transformers
ft)
CONVERSION APPARATUS AND SPECIAL EOUIPMENT Line
No.Type of Equipment
fi)
Number of Units
(i)
Total
(ln
Capacity
MVa)(k)
2 1
27 2 2
30 1 3
30 ,|4
't20 1 5
47 ,|6
224 1 7
103 1 6
92 1 9
14 1 10
't4 ,|11
45 1 12
225 ,|13
5 1 14
28 1 15
16
90 2 1t
11 ,|18
56 2 19
93 3 1 20
135 1 21
86 3 22
48 2 23
448 2 24
70 2 25
125 3 26
448 2 27
117 3 26
750 3 1 29
11 1 30
5 3 31
30 1 32
46 1 33
47 1 34
600 2 35
312 3 :ro
1 37
5 36
2 39
752 5 1 40
FERC FORM NO.1 (ED. 12.96)Page 427
Name of Respondent
ldaho Power Company
(1)
(2t
An Original
A Resubmission
Date of Reoort(Mo, Da, Yi)
041141202',1
Year/Period of Report
End of 2O20lQ4
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line
No.Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (ln MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 Bruneau Bridge distribution 138.0C 35.00
2 Bruneau Bridge distribution 138.0C 36.20
3 Buckhom distribution 69.0C 35.00
4 Buhl distribution 46.0C 13.20
5 Burley Rural distribution 69.0C 13.00
6 Burley Rural distribution 69.0C 13.09
7 Butler distribution 138.0C 13.09
I Caldwell distribution 138.0t 13.00
I Caldwell transmission 230.0c 138.00
10 Caldwell distribution 138.0C 13.09
't1 Caldwell transmission 138.0C 69.00 12.47
12 Caldwell transmission 230.0c 138.00 12.47
13 Camas distribution 35.0C
14 Camas distribution 35.0C 14.40
15 Can-Ada distribution 138.0C 13.09
16 Canyon Creek distribution 't38.0c %.20
17 Canyon Creek transmission 138.0(69.00 12.98
18 Cartwright distribution 138.0(13.00
19 Cascade Power Plant - attended transmission 69.0C 4.60
20 Cascade distribution 69.0C 13.00
2',1 Cascade distribution 69.0C 13.10
22 Cascade distribution 25.0C
23 Chestnut distribution 138.0C 13.00
24 Chestnut distribution 138.0(13.09
25 Cinder distribution 46.00 13.00
26 Clear Lake - aftended transmission 46.00 2.40
27 criff transmission 138.00 46.00 12.50
28 ctiff transmission 138.00 46.00 12.95
29 Cloverdale distribution 138.00 13.00
30 Cloverdale distribution 138.00 't3.0s
31 Cloverdale transmission 230.00 138.00 13.80
32 Council distribution 69.00 13.00
33 Crane Creek distribution 69.00 't3.00
34 Crater distribution 46.00 13.00
35 Dale distribution 46.00 4.60
36 Dale distribution 46.00 13.00
37 Dale distribution 69.00 13.00
38 Dale distribution 138.00 36.20
39 Dale transmission 138.00 46.00 12.47
40 Danskin- attended transmission 230.00 18.00
FERC FORM NO. r (ED.12-96)Page 426'1
Name of
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
0411412021
Year/Period of Report
End of 20201Q4
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
(q)
Number of
Spare
Transformers
ft)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.Type of Equipment
(i)
Number of Units
(i)
Total
(ln
Capacity
MVa)ft)
30 1 1
45 1 z
37 1 3
1 4
20 1 5
30 1 6
90 2 7
28 1 6
225 1 I
45 1 10
't40 3 't1
200 1 12
5 3 1 13
10 3 1 't4
45 1 15
45 1 16
20 1 17
11 1 18
16 1 19
7 1 20
't4 1 21
5 1 22
45 1 23
45 1 24
11 1 25
5 1 26
21 2 1 27
10 1 2E
90 2 29
45 1 30
300 1 31
't4 1 32
11 ,|33
11 1 34
1 35
7 36
1 37
45 1 3E
47 1 39
233 1 40
FERC FORM NO.1 (ED.12.96)Page 427.1
Name of Respondent
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of ReDort
(Mo, Da, Yi)
04t1412021
Year/Period of Report
End of 20201Q4
SUBSIATIONS
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)
,|Danskin- attended transmission 230.0c 138.00 13.80
2 Danskin- attended distribution 18.00 4.16
3 Danskin- attended transmission 138.00 12.OO
4 Danskin- attended distribution 35.00 13.80
5 Deen distribution 46.00 13.00
6 Dietrich distribution 46.00 't3.09
7 Don distribution 138.00 7.60
8 Don distribution 138.00 't3.20
I Don distribution 138.00 't3.00
10 DRAM distribution 138.00 13.09
11 DRAM transmission 230.00 't38.00 13.8C
12 DRAM distribution 138.00 12.47
13 DRAM distribution 138.00 13.00
14 Duffin distribution 138.00 35.00
15 Eagle distribution 138.00 13.0S
16 Eastgate distribution 138.00 13.0e
17 Eckert distribution 138.00 36.20
18 Eden distribution 138.00 36.20
19 Eden transmission 138.00 46.00 12.98
20 Eldredge distribution 138.00 13.09
21 Elkhorn distribution 138.00 12.47
22 Elkhorn distribution 138.00 13.00
23 Elmore distribution 138.00 35.00
24 Elmore transmission 138.00 69.00 12.5Q
25 Elmore transmission 138.00 69.00 12.98
26 Emmett distribution 138.00 't3.09
27 Emmett transmission 138.00 69.00 12.47
28 Falls distribution 46.00 13.00
29 Filer distribution 46.00 13.00
30 Flat Top distribution 46.00 13.00
31 Flying H distribution 69.00 2.40
32 Fort Hall distribution 46.00 13.00
33 Fossil Gulch distribution 138.00 35.00
34 Fremont transmission 138.00 46.00 12.sC
35 Gary distribution 138.00 13.09
36 Gary distribution 138.00 13.00
37 Gem diskibution 69.00 13.00
38 Gem distribution 69.00
39 Glenns Ferry distribution 138.00 13.00
40 Gooding Rural distribution 46.00 13.00
FERC FORM NO. 1 (ED. 12.96)Page 426.2
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report
(Mo, Da, Yr)
0411412021
YearlPeriod of Report
End of 20201Q4
5. Show in columns (l), O, 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 othenryise 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)
(R
Number of
Transformers
ln Service
(o)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.Type of Equipment
fi)
Number of Units
fi)
Total
(ln
Capacity
MVa)(k)
300 1 1
6 1 2
160 2 3
E 1 4
11 1 5
14 1 6
1 7
180 6 1 8
44 1 I
168 6 't0
212 2 11
28 1 12
28 1 13
60 2 14
67 2 15
75 2 16
30 1 1l
45 1 18
20 1 19
45 1 20
11 1 21
11 1 22
28 ,|23
25 1 24
20 1 25
45 1 26
47 ,|27
28 2 ZA
14 1 29
17 2 30
20 2 31
't4 1 1 32
28 1 33
67 3 1 34
37 1 35
28 1 in
14 1 2 37
't4 1 36
't1 1 39
20 2 4U
FERC FORM NO. 1 (ED. 12-96)Page 427,2
Name of
ldaho Power Company
(1)
(2t
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
0411412021
YeariPeriod of Report
End of 20201Q4
SUtsSIAIIONS
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)
,|Golden Valley distribution 69.00 13.00
2 Goshen transmission 345.0C 161 .00 13.80
3 Gowen Substation distribution 138.0C 35.00
4 Grindstone distribution 35.00
5 Grindstone distribution 35.00 2.40
6 Grove distribution 138.0C '13.09
7 Grove distribution '138.0C 13.00
I Hagerman distribution 46.00 13.00
I Hagerman distribution 69.00 13.00
10 Hailey distribution 138.0C 13.00
1'l Happy Valley distribution 138.0C 13.09
't2 Haven distribution 138.0C 3s.00
13 Haven transmission 138.0C 46.00
't4 Hemingway transmission 500.0c 230.00 34.50
15 Hewlett Packard distribution 138.0C 13.00
16 Hidden Springs distribution 138.0C 13.00
17 Highland distribution 138.0C 13.00
18 Hiil distribution 138.0C 13.00
19 Hillsdale distribution 138.0C 13.09
20 Homedale distribution 69.00 13.00
21 Horse Flat transmission 230.0c 138.00 13.80
22 Horseshoe Bend distribution 35.00 13.09
23 Horseshoe Bend distribution 69.00 36.20
24 Horseshoe Bend distribution 69.00 25.00
25 Huston distribution 69.00 13.00
26 Hulen diskibution 46.00 13.00
27 Hunt transmission 230.0c 138.00 13.80
28 Hydra distribution 138.0C 36.20
29 lsland distribution 69.00 13.00
30 Jefierson transmission 't61.0c
31 Jerome distribution 138.0C 13.00
32 Jerome distribution 138.0C 13.09
33 Julion Clawson distribution 138.0C 35.00
34 Joplin distribution 138.0C '13.00
35 Joplin distribution 138.0C 36.20
36 Justice transmission 230.0c 138.00 13.80
37 Karcher distribution '138.0c 13.00
38 Kenyon distribution 69.0C 13.00
39 Ketchum distribution 138.0C 13.00
40 Kimberly distribution 138.0C 13.09
FERC FORM NO. 1 (ED. 12-96)Page 426'3
Name of
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of
(Mo, Da:frn
0411412021
Year/Period of Report
End of 2O2O|Q4
5. Show in columns (l), (j), and (k) special equipment such as rotary converters, rectifiers, eondensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated othenrrrise 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 pafi is an associated company.
Capacity of Substation
(ln Service) (ln MVa)
(f)
Number of
Transformers
ln Service
(o)
Number of
Spare
Transformers
ft)
CONVERSION APPARATUS AND SPECIAL EOUIPMENT Line
No.Type of Equipment
(i)
Number of Units
(i)
Total
(ln
Capacity
MVa)ft)
14 1 1 1
948 5 2
45 1 3
7 1 4
7 1 5
90 2 6
45 1 7
't4 ,|8
6 1 I
37 1 10
30 1 11
20 ,|12
47 1 13
1 000 3 1 14
37 1 15
11 1 16
30 1 1t
73 2 1E
45 ,|19
34 2 20
100 1 21
7 1 22
22 1 23
7 1 24
14 1 25
14 1 '26
336 3 27
90 2 2A
20 ,|29
30
37 1 31
37 1 32
56 2 33
28 1 34
45 1 35
300 1 36
20 ,|37
25 2 38
75 2 39
45 1 40
FERC FORiI NO.1 (ED.12,96)Page 'f27.3
Name of Respondent
ldaho Power Company
(1)
(2)
An Original
A Resubmission
Date of ReDort(Mo, Da, Yi)
0411412021
Year/Period of Report
End of 20201Q4
SUBSTATIONS
1. Report below the information called for conoerning 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 funclional 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 Kinport transmission 161.0C 46.00 13.20
2 Kinport transmission 230.0c 138.00 12.47
3 Kinport transmission 230.0c 138.00 13.80
4 transmission 345.0C 230.00 13.80
5 Kramer distribution 138.0C 35.00
6 Kramer distribution 138.0C 36.20
7 Kuna distribution 138.0C 13.09
8 Lake distribution 69.0C 13.00
9 Lake Fork distribution 138.0C 36.20
10 Lake Fo*transmission 138.0C 69.00 12.50
11 Lamb distribution 138.0C 13.00
12 Langley Gulch- attended transmission 230.0c 138.00 13.80
13 Langley Gulch- attended transmission 230.0c
14 Langley Gulch- aftended transmission 230.0c 150.00
15 Lansing distribution 138.0C 13.09
16 Lincoln distribution 138.0C 13.09
17 Linden distsibution 138.00 13.00
18 Locust distribution 138.0C 36.20
19 Locust transmission 230.00 138.00 13.8C
20 Lower Malad - attended transmission 138.00 7.20
21 Lower Salmon - attended transmission 138.00 13.80
22 Map Rock distribution 69.00 13.09
23 McCall distribution 138.00 13.09
24 McCall distribution 138.00 36.20
25 Melba distribution 69.00 13.00
26 Meridian distribution 138.00 13.00
27 Micron distribution 138.00 13.09
28 Micron distribution 138.00 13.00
29 Midpoint transmission 230.00 138.00 13.8C
30 Midpoint transmission 34s.00 230.00 13.8C
31 transmission 500.00 34s.00
32 Midrose distribution 138.00 13.09
33 Milner transmission 138.00 69.00 12.47uMilnerdistribution69.00 46.00 6.9C
35 Milner distribution 138.00 35.00
36 Milner PP - attended transmission 138.00 13.80
37 Moonstone distribution 138.00 35.00
38 Mora distribution 138.00 36.20
39 Moreland distribution ,16.00 36.20
40 Mountain Home distribution 69.00 13.00
FERC FORlrl NO.l (ED. 12.96)Page 'f26.4
Name Respondent
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
o4t't4t2021
Year/Period of Report
End of 2O20lQ4
5. Show in columns (l), fi), 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 ot
Transformers
ln Service
(s)
Number ot
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
NoType of Equipment
(i)
Number of Units
(i)
Total Capacity
(ln MVa)
(k)
7 1
300 1 2
300 1 3
1000 3 1 4
20 1 5
30 1 6
45 1 I
14 1 E
30 1 I
20 1 10
30 ,|11
636 2 12
410 2 13
,|14
45 1 15
14 1 16
58 2 17
134 3 16
600 2 19
16 1 ztJ
70 4 21
14 1 22
22 ,|23
30 1 24
't1 1 25
60 2 26
40 2 27
40 2 28
300 1 1 29
1400 2 1 30
1500 3 1 31
45 1 32
125 3 1 33
8 3 1 u
50 2 35
60 1 36
20 1 3t
90 2 38
28 2 39
28 ,|40
FERC FORM NO. I (EO. 12.96)Page 427.4
ldaho Power Company (1)
(2t
An Original
A Resubmission
Date of(Mo, Da
ReDort
, Yr)
0411412021
Year/Period of Report
End of 2020144
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 Mountrain Home Air Force Base distribution 69.0C 13.00
2 Mountain Home Air Force Base distribution 138.0C 13.00
3 Nampa transmission 230.0c '138.00 13.80
4 Nampa dishibution 138.0C 13.00
5 New Meadows distribution 138.0C 36.20
6 New Plymouth distribution 69.00 13.00
7 Northview disbibution 138.0C 13.09
8 Notch Bufte distribution 138.0C 13.09
I Orchard distribution 69.00 36.20
10 Parma distribution 69.00 13.00
11 Parma distribution 69.00 35.00
12 Paul distribution 138.00 35.00
13 Paul distribution 138.0C 36.20
14 Payette distribution 138.00 't3.09
15 Pingrce transmission 138.00 46.00 12.5C
16 Pingree distribution '138.00 35.00
17 Pleasant Valley distribution 138.00 35.00
18 Pleasant Valley distribution 138.00 36.20
19 Pocatello distribution 46.00 13.00
20 Pocket distribution 138.00 36.20
21 Poleline distribution 138.00 13.09
22 hansmission 345.00
23 Portneuf distribution 138.00 35.00
24 Portneuf distribution 46.00 35.00
25 Rockford distribution 46.00 13.00
26 Russett distribution 138.00 13.00
27 Sailor Creek distribution 138.00 2.40
28 Sailor Creek distribution 138.00 35.00
29 Salmon distribution 69.00 13.09
30 Salmon distribution 69.00 36.20
3t Shoshone distribution 46.00 13.0S
32 Shoshone distribution 46.00 7.20
33 Shoshone Falls - attended transmission 46.00 4.16
u Shoshone Falls - attended transmission 46.00 6.60
35 Silver distribution 138.00 35.00
36 Simplot distribution 138.00 't3.00
37 Sinker Creek distribution 138.00 35.00
38 Siphon distribution 138.00 36.20
39 Skyway distribution 138.00 13.0S
40 South Park distribution 46.00 13.00
FERC FORM NO.1 (ED.12.96)Page 426.5
ldaho Power Company (1)
(2\
An Original
A Resubmission
Date of Reoort(Mo, Da, Yi)
o4t14t2021
Year/Period of Report
End of 2O2OIQ4
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 oompany.
Capacity of Substation
(ln Service) (ln MVa)
(fl
Number of
Transformers
ln Service
(q)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EOUIPMENT Line
No.Type of Equipment
(i)
Number of Units
fi)
Total Capacity
(ln MVa)fi)
1 1
34 1 2
300 1 3
87 a 4
22 1 5
13 1 6
45 1 7
14 1 E
4'l 2 I
14 1 10
22 1 11
30 1 1 12
45 1 13
45 1 14
67 3 15
34 2 16
30 1 17
45 1 '16
60 2 19
45 1 20
30 1 21
22
30 1 23
1 24
25 2 25
30 1 26
21 2 2t
28 1 2E
22 1 29
22 1 30
14 1 31
2 3 32
4 1 33
14 1 34
20 1 35
53 2 36
20 1 37
75 2 3E
45 ,|39
14 1 40
FERC FORM NO. 1 (ED. 12-96)Page 427'5
Name Respondent
Idaho Power Company (1)
(2)
An Original
A Resubmission
Date of Reoort
(Mo, Da, Yi)
04t1412021
Year/Period of Report
End of 2O20lQ4
I'UBSIAI IONS
1. Report below the information called for oonoeming 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
aftended 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 Spring Valley distribution 138.00 12.47
2 Star distribution 138.00 13.09
3 Starkey transmission 138.00 69.00 12.47
4 State distribution 69.00 13.00
5 Sterling distribution 46.00 13.00
6 Stoddard distribution 138.00 13.00
7 Stsike Power Plant - attended transmission 138.00 13.80
8 Sugar distribution 138.00 35.00
9 Swan Falls - attended transmission 138.00 6.90
10 Taber distribution 46.00 13.00
11 Tamarack distribution 138.00 2.40
12 Ten Mile distribution 138.00 't3.0s
13 Terry distribution 't38.0(13.0S
14 Terry distribution 138.0(13.00
15 Thousand Springs - attended transmission 46.0C 7.20
16 hansmission 345.0(
17 Toponis distribution 138.0(33.00
18 Twin Falls disfibution 138.0(13.09
19 Twin Falls transmission 138.0(46.00 12.98
20 Twin Falls PP - attended transmission 138.0(7.20
21 Twin Falls PP - attended transmission 138.0(13.20
22 Tyhee distribution 46.0C 13.00
23 Upper Malad - attended transmission 45.0C 7.20
24 Upper Salmon- aftended transmission 138.0C 7.20
25 Ustick distribution 138.0C 13.00
26 Vallivue distribution 138.0C 13.0S
27 Mctory distribution 138.0C 't3.00
28 Victory distribution 138.0C 't3.0s
29 Ware distribution 69.0C 13.00
30 Weiser distribution 69.0C 't3.00
31 Weiser transmission 138.0C 69.00 12.47
32 Wilder distribution 6S.0C 13.00
33 Willis distribution 138.0C 't3.09
34 Willow Creek distribution 138.0(13.00
35 wye distribution 138.0C 13.00
36 wye distribution 138.0C 13.0S
37 Zilog distribution 138.0C 13.0S
38
39
40 The above are all State of ldaho
FERC FORM NO.1 (ED. 12-96)Page ,t26.6
ldaho Power Company (1)
(2)
Original
A Resubmission
Date of Report
(Mo, Da, Yr)
04t14t202'l
Year/Period of Report
End of 202OlQ4
5. Show in columns (l), 0), and (k) special equipment such as rotary converterc, 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 operaled 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)
11 1 1
30 ,|2
30 1 3
58 2 4
11 2 5
28 ,|6
104 3 7
28 2 6
34 1 I
6 1 10
11 1 11
90 2 1Z
20 ,|13
50 2 14
8 1 15
16
30 1 1t
82 2 18
50 2 19
13 1 20
72 1 21
14 1 22
8 1 23
42 4 24
77 2 25
30 ,|26
45 1 27
30 1 2E
2A 1 1 29
28 2 ,|30
42 1 31
14 1 32
30 1 33
11 1 34
60 2 35
37 ,|36
45 1 37
3E
39
40
FERC FORM t{O.1 (ED. 12.96)Page 427.6
Name Date of Report(Mo, Da, Yr)
o4t14t2021ldaho Power Company (1)
(2)
Original
Resubmission
Year/Period of Report
End of 20201Q4
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
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
2 Montana:
3 Mill Creek transmission 230.00
4 Peterson transmission 230.00 69.00 13.2C
5
6 Nevada
7 Valmy - attended transmission 345.00 18.00
8 Wells transmission '138.00 69.00 13.0C
I
10 Oregon
11 Adrian distribution 69.00 13.00
12 Bums transmission 500.00
13 Cairo distribution 69.00 13.00
14 Hells Canyon - attended transmission 230.00 13.80
15 Hells Canyon - attended distribution 69.00 0.50
16 Hines transmission 138.0C 1 15.00 12.47
17 Huricane transmission 230.0c
18 Jacobson Gulch distribution 69.00 2.40
19 Malheur Butte distribution 69.00 34.50
20 Nyssa distribution 69.00 13.00
21 Ontario distribution 138.0C 13.00
22 Ontario transmission 138.0C 69.00 12.47
23 Ontario transmission 230.0c 138.00 13.80
24 Ontario transmission 138.0C 69.00 12.98
25 Ontario transmission 138.0C 69.00 13.09
26 Ontario transmission 138.0C 69.00 12.50
27 Ore-lda distribution 69.00 13.00
28 Oxbow - attended transmission 138.0C 69.00 't 3.00
29 Oxbow - aftended transmission 230.0c '13.80
30 Oxbow - attended transmission 230.0c 138.00 '13.80
31 Quartz transmission 138.0C 69.00 12.50
32 Quartz transmission 230.0c 138.00 12.98
33 Ouartz transmission 138.0C 69.00 12.98
34 Summer Lake transmission 500.0c
35 Vale distribution 69.0C 13.00
36
37 Washington:
38 WallaWalla transmission 230.0c
39
40 Wyoming:
FERC FORM NO. 1 (ED. 12-96)Page 426.7
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report
(Mo, Da, Yr)
o4t14t2021
Year/Period of Report
End of 2O20lQ4
5. Show in columns (l), O, 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 othenrise 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 of
Transformers
ln Service
(o)
Number of
Spare
Transformers
ft)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
NoType of Equipment
(i)
Number of Units
(i)
Total Capacity
(ln MVa)
&)
1
2
3
86 4 ,|4
5
6
315 1 I
25 3 1 I
I
't0
11 1 11
12
20 1 13
560 3 14
1 1 15
80 1 1 16
17
't1 1 1E
't1 3 ,|19
28 2 20
67 2 1 21
47 1 22
400 2 23
93 2 24
,|25
,|26
28 1 27
13 3 ,|za
274 2 29
100 1 30
25 ,|31
167 3 1 32
20 ,|33
u
14 1 35
36
37
38
39
40
FERC FORM NO. 1 (ED. 12.96)Page 127.7
ldaho Power Company (1)
(2)
Original
Resubmission
Date of(Mo, Da
ReDort
, Yr)
0414t2021
Year/Period of Report
End of 2O20lQ4
1. Report below the information called for conceming substations of the respondent as of the end of the year.
2. Substations wtrich 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 charac'ter 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 repo(ed for the individual stations in
column (f).
Line
No.Name and Location of Substation
(a)
Character of Substration
(b)
VOLTAGE (ln MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 transmission 345.0C 22.00 34.50
2
3
4
5
6
7 Transformersdistribution substations under 1 0,000
8 KVA61 unattended.
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
FERC FORIi NO. t (ED. 12.96)Page t126.8
Name of
ldaho Power Company (1)
(2\
An Original
A Resubmission
Date of Report
(Mo, Da, Yr)
0411412021
Year/Period of Report
End of 202OlQa
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 @-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and a@ounts
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 of
Transformers
ln Service
(q)
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)
2244 4 1
2
3
4
5
6
7
214 8
9
10
11
12
13
't4
15
16
1l
1E
19
20
21
22
23
24
25
26
27
2A
29
30
31
32
33
34
35
3tt
37
3U
39
40
FERC FORM NO.1 (ED. 12.96)Page 427.8
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
04114t2021
Year/Period of Report
2020tQ4
FOOTNOTE DATA
426 Line No.: 1 Column: a
Pac fiCorp has an ownersh p nterest ce gh-voltage Eransmission rel-ated andinterconnection eguipment located at Idaho Power's Adelaide station. Ownership interest
varl-es terminal. 100? of the capac]-ty is reported426 Line No.: 1 Column: cFor all of Column c: Pr mary voltages reported KV unless otherwi-se noted.
426 Line No.: 1 Column: d
For a of Column tages report KV ess o se not
426 Line No.: 1 Column: eFor all of Column e ary voltages reported KV unl-ess othe se noted.
426 Line No.: 1 Column: fFor a orat umn F:c
c
Power has an
unless otherwise noted
p nterest certa -vo tage tr SS related andinterconnection equipment located at PacifiCorp's Antelope station. Ownership interest
varr_es terminal". 100? of the c rted
I
.I
1
t1y owned w rh
capacity is reported
c Corp, I Power s 66.72 re of owner l-00? of the
426 Line No.:7 Column: a
426 Line No.:8 Column: a
426 Line No.:9 Column: a
'fo owne w c Corp, I Power s 55.7 reo owne 100? o
capacity is reported
Idaho Power an owners p terest certain high-voltage tran re
interconnection eguipment located at PacifiCorpts Big Grassy station. Ownership interestvarlesterminal
Pac an owners p interest in certa -vo tage tran ss reinterconnection eguipment located at Idaho Powerts Borah station. Ownership interest
Idaho Power has an ownership interest in certain high-volEage Lransmi-ssion related andinterconnection equipment located at PacifiCorp's Goshen station. Ownership interest
var.l-es terminal. 1004 of the cit ted
PacifiCorp has an owners p terest certa h h-voltage transmission related andinterconnection eguipment located at Idaho Power's Hemingway station. Ownership interest
varles terminal. 100? of the cit 1S
Idaho Power has an owners p terest certa h h-voltage transmission related andinterconnection equipment located at PacifiCorp's 'Jefferson station. Ownership interest
var].es terminal
426.4 Line No.:4 Column: a
Pac Corp has an owners hip interest in ceitain high-oltEge transmission re lated and
FERC FORM NO.1 (ED. 12.871 Page 450.1
f
426 Line No.: 16 Column: a
426 Line No.:29 Column: a
426.3 Line No.: 14 Column: a
426.3 Line No.:30 Column: a
interconnection equipment located at ldaho Power's Kinport station. Ownership interest
Name of Respondent
ldaho Power Company
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
0411412021
Year/Period of Report
2020tQ4
FOOTNOTE DATA
426.4 Line No.: 31 Column: a
var].es terminal . 100? of t.he
Pac Corp an owners certa gh-voltage
cit t-s
on related andinterconnection eguipment located at Idaho Power's Midpoint station. Ownership interestvar]-es terminal. L00? of the ca cit 1S
I Power an owners rest certain high-voltage transmission re atinterconnection eguipment located at PacifiCorpts Populus station. ownership interestvarlesterminal
I Power an owners rest certa h h-voltage transmiss re atinterconnection eguipment located at PacifiCorpts Three Mile Kno1l stati on
on Ownership
rest h
426.5 Line No.:22 Column: a
426.6 Line No.:16 Column: a
interest varies terminal
I Pov,rer 32t owners rest certain transmission related e pment ca
426.7 Line No.:3 Column: a
at Northwestern Ene 's Mifl Creek Station
ntly owned w th Sierra Pacific Power Company,a NV Energy. I Power has a 50?
426.7 Line No.:7 Column: a
426.7 Line No.: 12 Column: a
share of ownershi 100? of the ca cit
I Power a 22? owne rest certaj-n high-voltage transmiss on reinterconnectiont l-ocated at Pacif ts Burns station
Idaho Power has an ownership interest certa -vo tage SS on relaEed andinterconnection equipment located at PacifiCorpts Hurricane station. Ownership interestvar]-es terminal
I Power an owne p terest certain high-voltage transmiss on reinterconnection equipment located at PacifiCorpts Summer Lake station. Ownership interestvar]-es terminal
r Power an owne terest certain high-voltage transmiss on reinterconnection eguipment located at PacifiCorpts wal1a Wa11a station. Ownership interestvar].es terminal
J nt I w t Pac cCorp. Idaho Power has a 33.3? share of ownership. 1capacity is reported
426.7 Line No.: 17 Column: a
426.7 Line No.: 34 Column: a
426.7 Line No.: 38 Column: a
426.8 Line No.:1 Column: a
FERC FORM NO.1 (ED. 12-871 Pase 450.2
This Page lntentionally Left Blank
ldaho Power Company (1)
(2t
An Original
A Resubmission
Date(Mo,
0411412021
Year/Period of Report
End of 2O20lQ4
WITH ASSOCIATED
1. Repott below the information called for conceming all non-power goods or services received from or provided to associated (affliated) companies.
2. The repofting 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 servi@ must be specific in natur6. 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 byAffiliated
2
3
4
5
6
7
8
I
10
11
12
13
14
15
16
17
18
19
20 Non.powor Goods or Services Provided for Affiliate
21 Managerial Expenses IDACORP,INC.417420 446,210
22 922000 29,242
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
FERC FORM NO.1 (New)
FERC FORM NO.l-F (New)
Page 429
Page
December 3't, 2020
't. Report amounts for accounts 412 and 413, Revenue and Erpenses from Utility Plant Leased to Others, in another utility
column (i,k,m,o) in a similar manner to a utility department. Spread the amount(s) over lines 01 thru 24 as appropriate.
lnclude these amounts in columns (c) and (d) totals.
2. Report amounts in account 4'14, Other Utility Operating lncome, in th6 same manner as accounts 412 and 413 above.
3. Report data for lines 7, 9, and 10 for Natural Gas companies using accounts 404.1, 404.2, 404.3, 407 .1 , and 407 .2.
4. Use page 1 22 for important notes regarding the state ment of income or any account thereof.
5. Give concise erglanations concerning unsettled rate proceedings where a contingency exists such that refunds of a
material amount may need to be made to the utility's customers or which may result in a material refund to lhe utility
with respect to power or gas purchases. State for each year affect€d the gross revenues or costs to which the contingency
relates and the tax effects together with an explanation of retain such revenues or recover amounts paid with respect
to power and gas purchases.
6. Give concise €)glanations conc€rning significant amounts of any refunds made or received during the year.
STATEMENT OF INCOME FOR THE YEAR
TOTALLine
No.
(a)
Account
(Ref.)
Page
No.
(b)
Cunent Year
(c)
Previous Year
(d)
$ 1,284,238,508 $ 1,277,673,079
733,790,307
56,215,07 4
155,941,941
7,428,416
1,075,354
30,879,247
25,454,806
6,109,267
(5,973,440)
2,7 10 ,641
1,013,800,677
169,064
737 ,901,151
62,334,775
153,985,423
6,613,793
1,075,354
31,69'1,492
17.886,243
(4,475,172)
9,974,618
1,932,172
1,019,',t42,810
222,961
$ 270,437,830 $ 258,530,269
1
2
3
4
5
6
7
I
I
10
11
't2
13
14
't5
16
17
18
19
20
21
22
23
24
25
26
27
Maintenance Elpenses (402).................
Depreciation Elpense (403).................
Amort. & Depl. of Utility Plant (404-405)....
Amort. of Utility Plant Acq. Adj. (406).....
Amort. of Property Losses, Unrecowred Plant and
Accretion Erpense (41 I )..
Amort. of Conversion Epenses (407).
Regulatory Debits/Credits (407 3 A 407 .4)..
Taxes Other Than lncome Taxes (408.1 ).
lncome Taxes - Federal (409.1)..............
Provision for Deferred lncome Ta<es (410.1 & 411.1) Net.........
ln\€stment Tax Credit Adj. - Net (411.4)...
(Less) Gains from Disp. of Utility Plant (411.6).....
Losses from Disp. of Utility Plant (411.7)..
(Less) Gains from Disposition of Allolrances (41 1.8)..............
Losses from Disposition of Allowances (41 1.9)..
TOTAL Utility Operating E:penses (Enter Total of lines 4 thru 22)........
Net Utility Operating lncome (Enter Total of line 2 less 24).
UTILITY OPERATING INCOME
Regulatory Study Costs (407)
- Other (409.'1)..
Operating Revenues (400)....
Operating Epenses
Operation Epenses (401 )...
11
2
2
2
2
2
15
15
IOAHO SUPPLEMENT IDAHO POWER COMPANY
TA)(ES ALLOCATED TO IDAHO
Kind of Tax
Taxes Charged
Durino Year
Taxes OtherThan lncome Taxes:
Labor Related:
FtcA.............
FUTA............
State Unemployment........
Payroll Deduction & Loading.....
Total Labor Related........
Property Taxes...................
Kilowatt-hour Tax...............
$ 15,755,338
42,869
212,044
(16,010,2s1)
Licenses.
0
26,229.280
1,312,631
4,180
3,083,918
249,238
0
Regulatory Commission Fees.............
lnigation P|C...............
Canada Sales Tax....
Total Taxes Other Than lncome Taxes............30,879,247
Federal lncome Taxes...........
State lrrcome Taxes...........
Defened lncome Taxes...........
lnvestment Tax Credit Adjustment - Net..........,
25,454,806
6,109,267
(s,e73,440)
2,710,641
Total Taxes Allocated to 1daho........ $ 59,180,521
December 31, 2020
IDAHO SUPPLEMEiIT IDAHO POWER COMPANY
December 31, 2020
NOTES AND ACCOUNTS RECEIVABLE
Summary for Balance Sheet
Show separately by footnote the total amount of notes and accounts receivable
from directors, officers, and employees included in Notes Receivable (Account
'141 ) and Other Accounts Receivable (Account 143)
Line
No.
Accounts
(a)
Balance
Beginning of
Year
(b)
Balance
End of
Year
(c)
1
2
3
4
5
6
7
8
9
10
11
't2
13
14
't5
16
17
18
19
20
Notes Receiwble (Account 141)....
Customer Accounts Receivable (Account 142)....
Other Accounts Receivable (Account 1 43)...
(Disclose any capital stock subscription received)
Total
Less: Accumulated Provision for Uncollectible
Accounts-Cr. (Account'l 44)..........
Total, Less Accumulated Provision for
Uncollectible Accounts...............
(81,730)
74,131,805
13,107,045
$ 87,157,12'.1
1,744,071
$ 85,413,049
q
i / ir(r:l .'" I
1:. !r. :t I
$ 87,823,308
5,263,704
$ 82,559,604
ACCUMULATED PROVISION FOR UNCOLLECTIBLE ACCOUNTS - CR. (Account'144)
'1. Report below the information called for conceming this accumulated provision.
2. Erylain any important adjustments of subaccounts.
3. Entries with respect to officers and employees shall not include items for utility services.
Line
No.
Item
(a)
Utility
Customers
(b)
Mdse,
Jobbing &
Contract
Work
(c)
Officers
and
Employees
(d)
Other
(e)
Total
(f)
21
22
23
24
25
26
27
28
29
30
3'l
32
33
Balance Beg of Year:
Uncollectible Retail Electric Sales
Uncollectible Damage Claims
Uncollectibe Other Rerenues
Balance end of year...............
$ 1,744,071
r .ri 1 .,7-i
I ir I i.r,(1
$$
$
$
$
$
$
1,744,O71
3,364,974
154,659
$ 5,263,704 $$$$ 5,263,704
IDAHO SUPPLEiTEITIT
Page 3
IDAHO POWER COMPANY
RECEIVABLES FROM ASSOCIATED COMPANIES (Accounts 145, 146)
1. Report particulars of notes and accounts receivable from associated companies al end of year.
2. Provide soparate h€adings and totals for accounts 145, Notes Receivable from Associated Companies, and 146,
Accounts Receivable from Associated Companies, in addition to a total for tho combined accounts.
3. For notes receivable list each noto separately and state purpose for which received. Show also in column
(a) dat€ of note, date of maturity and interest rate.
4. lf any note was receivod in satisfaction of an open account, state the period covered by such open account.
5. lnclude in column (0 interest recorded as income during the year, including interest on accounts and notes
h€ld at any time during the par.
6. Give particulars of any notes pledged or discountod, also of any collateral held as guarantee of payment
of any noto or account.
Totals for Year
No.
Line
(a)
Particulars
Balance
Boginning
of Year
(b)
Debits
(c)
Credits
(d)
Balanc6
End of Year
(e)
lnterest
For Year
(f)
$ 20,021,988 $ 33,601,'r22 $ 43,534,388 $ 10,088,722
20,021,988 33,601J22 43,534,388 10,088,722
$$ 6,327,031 $ 6,327,03'l $
$ 6,327,031 $ 6,327,031 $
1
2
3
4
5
6
7
I
I
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
3'l
32
Total Account 145........
Account 146:
IDACORP, lnc...
Total Account 1 4,6...............-.-
Account'145:
IERCO...
4
Decembor 3'1, 2020
IDAHO SUPPLEIIENT IDAHO POWER COMPANY
STATE OF IDAHO - TOTAL SYSTEM DATA
GAIN OR LOSS ON DISPOSITION OF PROPERW (Account 42'1.'1 and 421 .2)
1. Give a brief descriflion of property creating the gain or loss. lnclude name of party acquiring the property (when
rcquired by another utility or associaled company) and the date transaction was comdeted. ldentify prop€rty
by tlpe; Leased, Held for Future Use, or Nonutility.
2. lndividual gains or lossos relating to proporty 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 approwl of joumal entriss in column (b), when approval is required. Where approral
is requir€d but has not b€en receirred, gi\iB oplanation follorying the item in column (a). (See account 102, LJtility
Plant Purchased or Sold.)
(b)
Original Cost
of Related
Date Joumal
Entry Approred
(When Required)
(c)(d)
Acr,l421.1
(e)
t&c142'1.2Line
No.(a)
Description of Prop€rty
$$$
703.55$
$663
$ (7,775.70)
$(623)
$ 1,366.93 $ (8,398.82)$
$ 26,488.38 9t29t2020 $ 26,488.38
$26,488 $0 $26,488
1
2
3
4
5
6
7
8
I
't0
11
12
13
14
15
16
17
't8
19
20
21
22
23
24
25
26
27
28
29
30
31
Gain on disposition of property
property:
Victory Substation
partial land disposalto highway district
Ten Mile Substation
partial land disposalto highway district
Hemingnnay Substation
partial land disposal to the county
IPUC Order 34793
Total loss..
5
December 31, 2020
IDAHO SUPPLEMENT IDAHO POWER COMPANY
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
33u
35
36
37
38
39
40
41
42
43
44
ADAMS COUNTY SHERIFF'S OFFICE
AGREE TECHNOLOGIES AND SOLUTIO
ALLPHIN, RANDY C
ANDERSEN SCHWARTZMAN WOODARD D
AUTOSORT
BAKER BOTTS LLP
BARKER, ROSHOLT & SIMPSON LLP
BULLARD SMITH JERNSTEDT WILSON
CLEAREDGE PARTNERS
COMPUNET PRO SERICES
DAVIS WRIGHT TREMAINE LLP
DELOITTE TAX LLP
DNV GL ENERGY SERVICES USA, IN
DONNELLEY FINANCIAL SOLUTIONS
EQ SHAREOWNER SERVICES
EVERGREEN CONSULTING GROUP, LL
EXPRESS MANAGED SERVICES
GIVENS PURSLEY LLP
HAWLEY TROXELL ENNIS & HAWLEY
HOLLAND & HART LLP
ICEBERG NETWORKS CORPORATION
IDAHO EMPLOYMENT LAWYERS, PLLC
JENSEN HUGHES
KEANE
KIRTON MCCONKIE
KW ENGINEERING INC
LEONARD PETROLEUM EQUIPMENT
MCDOWELL RACKNER & GIBSON PC
MEDIANT COMMUNICATIONS INC
MORROW & FISCHER PLLC
NAVIGANT CONSULTING INC
NIELSEN GROUP INC, THE
PARSONS BEHLE & LATIMER
PERKINS COIE LLP
QUALITY COMMUNICATIONS INC
OUINTEL-MC INC
REED HARRIS ENVIRONMENTAL LTD
RESOURCE DATA, INC
RM ENERGY CONSULTING
STOEL RIVES LLP
SULLIVAN & CROi\TVVELL
TOWERS WATSON DELAWARE INC
TUCKER, JAMES C
UNIVERSITY OF IDAHO
Management Services 15,000.00
15,195.00
27,500.00
707,248.90
34,032.10
13,326.64
306,659.69
43,427.75
75,000.00
157,334.30
209,233.98
16,121.00
318,189.84
12,358.00
122,256.43
361,181.69
13,920.00
20,796.00
34,066.84
27,533.35
13,44.2.il
13,680.00
40,189.72
16,020.00
126,430.20
87,093.03
1'1,869.64
836,568.55
35,822.96
29,531.05
50,327,90
161.,1L2.O3
11,378.00
386,180.91
48,467.2O
125,394.00
67,145.00
L,@1,753,75
t,L,774.2O
328,L67.77
183,(R3.11
10,500.00
68,735.96
199,151.08
lT Services
Manaoement Services
Legal Services
Manaqement Services
Leoal Services
Leqal Services
Leqal Services
Training Consultants
lT Services
Legal Services
Tax Services
inergy Consulting
Managernent Services
Management Services
Management Services
Managernent Services
Legal Services
Legal Services
Legal Sewices
lT Services
Legal Services
Consulting Services
Legal Services
Legal Services
Engineering Consultants
Construction Services
Legal Services
Managernent Services
Legal Services
Consulting Services
lT Services
Legal Services
Legal Services
lT Services
lT Services
Environmental Services
lT Services
Energy Consulting
Legal Services
Legal Services
Human Resources Consulting Services
Consulting Services
Management Services
December 31,2020
IDAHO SUPPLEiIENT
Page 6
IDAHO POWER COMPANY
STATE OF IDAHO - TOTAL SYSTEM DATA
PROFESSIONAL OR CONSULTATIVE SERVICES - ITEMS $1O,OOO AND OVER
Line
No.
PAYEE
(a)
SERVICE TYPE
(b)
Amount
(c)
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
M
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
81
82
83
VAN NESS FELDMAN
WINNER MANAGEMENT INC
WITHERSPOON KELLEY
WOODARD, WADE
YTURRI& ROSE& BURNHAM& BENTZ
Legal Services
Managernent Seryices
Legal Services
Legal Services
Legal Services
356,563.00
11,971.00
219,015.37
12,530.00
59,324.65
TOTAL $7.259.614
Page 6A
December 31,2020
IDAHO SUPPLEMENT IDAHO POWER COMPANY
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
8
I
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33u
35
36
37
38
39
40
41
42
43
ABBOTT, STRINGHAM, & LYNCH
AVTEC INC
CCRCORP
EVANS KEANE
EXPONENT,INC
INDUSTRIAL HYGIENE RESOURCES,
J M ROCHE AND ASSOCIATES
KUBRA DATATRANSFER LTD
MCNIVEN STRATEGIES INC
RIGHT SYSTEMS, INC
SORENSON ENGINEERING INC
TOTAL
LegalServices
lT Services
LegalServices
LegalSeMces
Ergineering Services
Health and Safety Consulting
LegalServices
Management Services
Consultirg SeMces
lT Services
Engineering Services
8,900
8,788
5,840
7,492
6,671
8,433
8,603
7,871
7,000
9,050
6,750
8s,397
December 31, 2020
IDAHO SUPFLEMEiIT
Page 68
IDAHO POWER COMPANY
ELECTRIC PI-ANT lN SERVICE (Accounts 101,'102, 103 and 106)
1 . Report belo,v the original cost of electric plant in service according to the prescribed accounts.
2. lnadditiontoAccountl0l,ElectricPlantinService(Classified),thispageandthenextincludeAccountl02,ElectricPlant
Purchased or Sold; Account 103, Experimental Electric Plant Unclassified; and Account 106, Completed Construction
Not Classified - Electric.
3. lnclude in colum n (c) or (d), as appropriate, conections of additions and retirements for the cunent or preceding year.
4. Enclose in parBntheses credit adjustments of plant accounts to indicate the negati\re effect of such accounts.
5. Clcsi! 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 re\Ersals of tentati\e distributions of prior year reported in
column (b). Likarvise, if the respondent has a significant amount of plant retirements the end of the year, include in
column (d) a tentative distribution of such r€tirements, on an estimated basis, with appropriate contra entry to the account
for accumulated deprecidion provision. lnclude also in column (d) reversals of tentative distributions of prior year of un-
classified retirements. Attach supplemental statement showing the account distributions of these tentative classifications in
cdumns (c) and (d), including the ret/ersals cf the prior years tentati\e account distributions of these amounts. Careful oF
s€rvance of the above instructions and the texts of Accounts 101 and '106 will avoid serious omissions of the reported amount
of respondent's plant actually in service at end of year.
Line
No.(a)
Account B€ginning of year
(b)(c)
Additions
1
2
3
4
5
6
7
I
I
10
't1
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
43
1. INTANGIBLE PLANT
(30'l ) Organization..............
(302) Franchises and Consents.
(303) Miscellaneous lntangible Plant......
TOTAL lntangible Plant (Enter Total of lines 2, 3, and 4)............
2. PRODUCTION PLANT
A. Steam Production Plant
(310) Land and Land Rights................
(3'l 1 ) Structures and |mprovements......................
(3,l2) Boiler Plant Equipment.
(313) Engines and Engine Driven Generators....
(314) Turbogenerator Units.
(31 5) Accessory Electric Equipment..
(316) Misc. Power Plant Equipment.........
(317) Assd Retirement Costs br Steam Production... . ....
TOTAL Steam Production Plant (Enter Total of lines 8 thru 15)........................
B. Nuclear Production Plant
(320) Land and Land Rights.
(321 ) Structures and |mprovements......................
(322) Reactor Plant Equipment..
(323) Turbogenerator Units..........
(324) Accessory El€ctric Equipment...
(325) Misc. Porvor Plant Equipment....
(326) Assd Retirement Ccts br Nuclear Production......
TOTAL Nuclear Production Plant (Enter Total of lines "17 thru 241...................
C. Hydraulic Production Plant
(330) Land and Land Rights................
(332) Reservdrs, Dams, and Waterwa)6.
(333) Water Wheels, Turbines, and Generators....
(334) Accessory Electric Equipment......................
(335) Misc. Po^/er Plant Equipment....
(336) Roads, Railroads, and Bridges.
(337) Asset Retirement Gosts for Hydraulic Production... ... . .
TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34)................
D. Other Production Plant
(340) Land and Land Rights................
(341 ) Structures and lmprovements...........
(342) Fuel Holders, Prcducts and Accessories...
(343) Prime Mowrs...............
(344) Generators
(345) Accessory Electric Equipment...
(3,16) Misc Poi/€r Plant Equipment.........
$5,2166
32,864,090
34,543,054
67,412,610
14,131,1M
1,017,046,825
882,852,660
Decombor 3'1, 2020
IDAHO SUPPLEMENT
Page 7
IDAHO POWER COMPANY
ELECTRIC PLANT lN SERVICE (Accounts 10'1,102, 103 and 106) (Continued)
Show in column (0 reclassifications or transfers within utility plant accounts. lnclud€ also in column
(f) the additions or reductions of primary account classifications arising from distribution of amounts
initially record€d in Account 102. ln shorving the clearance of Account 102, include in column (e) the
amounts with respect to accumulated provision for depreciation, acquisition adjustments, etc., and shcnv
in column (0 only the offset to the debits or crcdits distributed in column (0 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 shoiving subaccount classification of such plant conforming to the
requirements of these pag€s.
For each amount comprising the reported balance and changes in Account 102, stato the property purchased
or sold, name of vendor or purchaser, and date d transaction. lf proposed joumal entries have been filed
with the Commission as requircd by th6 Uniform System of Accounts, gi\e also date of such filing.
Retirements
(d)
Adjustm€nts
(e)
Transfers
(fl
End of Year
(q)
Line
No.
$5,480
33,796,1 92
39,393,526
(301 )
(302)
(303)
73,195,19E
14,856,097
(310)
(311 )
(312)
(313)
(314)
(315)
(316)
(317)
950,1 99,978
(320)
(321',)
(322)
(323)
(324)
(325)
(326)
(330)
(331 )
(332)
(333)
(334)
(335)
(336)
(337)
950,747,3?1
(340)
(341)
(u2)
(343)
(3441
(345)
(345)
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
December 31, 2020
IDAHO SUPPLEMENT
Page
IDAHO POWER COMPANY
ELECTRIC PLANT lN SERVICE (Accounts 101,102, 103 and 106) (Continued)
Line
No.
Account
(a)
Balance at
Beginning of year
(b)
Additions
(c)
44
.t5
6
47
48
49
50
51
52
53
54
EE
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
88
89
90
91
92
#REF!
#REF!
(346) Misc. Po,er Plant Equipment.
TOTAL Other Production Plant (EnterTotal of lines 37 thru 44)......................
TOTAL Production Plant (Enter Total of lines 16, 25, 35, and zl5)...................
3. TRANSMISSION PLANT
(350) Land and Land Rights.
(352) Structures and 1mprovements......................
(353) Station Equipment.........
(354) To /ers 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) Assd Retirement Costs icr Transrnission Plant.......
TOTAL Transmission Plant (Enter Total of lines 48 thru 57).............
4. DISTRIBUTION PLANT
(360) Land and Land Rights................
(361 ) Structures and I m provem ents.......................
(362) Station Equipment..
(363) Storage Battery Equipment....
(364) Poles, Towers, and Fixtures...
(365) Overhead Conductoc and DeMces.............
(366) Underground Conduit...................
(367) Underground Conductors and Devices.
(368) Line Transformers.................
(369) SeMces....
(370) [reters...........
(37'l ) lnstallations on Customer Pr€mises...........
(372) Leased Property on Customer Premiss....................
(373) Str€et Lighting and Signal Slstems.
(374) ess"t Retirement Costs br Distribution P|ant........
TOTAL Distribution Plant (Enter Total of lines 60 thru 74).
5. GENERAL PLANT
(389) Land and Land Rights.
(390) Structures and 1mprovements.......................
(391) Ofiice Fumiture and Equipment..
(392) Transportation Equipment...
(393) Stores Equipment.........
(394) Tools, Shop, and Garage Equipment.................,....
(395) Laboratory Equipment.........
(396) Porer Operated Equipment
(397) Communication Equipment
(398) Miscellaneous Equipment....
SUBTOTAL (Enter Total of lines 77 thru 86)...
(399) Other Tangible Property
(399. 1) Assd Retirement Costs br General Plant. .. ... ... .. . ..
TOTAL General Plant (Enter Total of lines 87, 88 and 89).........
TOTAL (Accounts 1 01 and I 06)...................
(102) Electric Plant Purchased
TOTAL Electric Plant in Service.
$ 531,140,477
2,431.039,962
37,396,62
78,254,550
418,978,969
206,209,260
198,395,,133
230,510,900
374,123
1,170,1 19,697
7,213,966
6,002,032
259,152,912
261,29',t,924
1U,884,220
53,497,506
287,588,108
591,034,192
60,342,790
94,651,442
2,957,380
4,444,825
1,803,061,296
1 7,065,533
127,458,3il
43,185,7U
92,998,812
3,W,277
1 't,'184,796
14,276,6%
21,024,722
49,013,820
7,319,401
386,916,085
386,916,085
5,858,549,650
$ 5,858,549,650
December 31,2020
IDA}IO SUPPLET'ENT
Page I
IDAHO POWER COMPANY
ELECTRIC PLANT lN SERVICE (Accounts 101,102,103 and 106) (Continued)
Retirements
(d)
Adjustments
(e)
Transfers
0
Balance d
End of Year
(s)No.
Line
(346)
$ 532,054,400
2,433,001,698
37,655,709
82,257,848
4M,601,459
214,331,374
209,028,945
235,379,556
375.347
(350)
(352)
(353)
(354)
(355)
(356)
(357)
(358)
(35e)
(359.1)
1,223.630.237
7,238,993
49,083,482
276,661,985
270,080,950
1 37,873,958
52,771 ,795
298,363,31 7
624,839,833
61,940,066
101,393.772
3,760,088
4,6U,074
(360)
(361)
(362)
(363)
(3s)
(365)
(366)
(367)
(368)
(36s)
(370)
(371)
(372)
(373)
B74l
1,888,642,313
1 8, 1 25,089
1 30,988,159
42,004,990
1 08,866,067
4,211,969
11,796,142
14.278,331
22,779.950
58,153,549
7,828,949
(s8s)
(3e0)
(3sl )
(3s2)
(3e3)
(3e4)
(3e5)
(3e6)
(3s7)
(398)
419,033,194
(3ee)
(399.1)
419,033,194
6,037,502,6210
('t02)
$ 6,037,502,640
44
45I
47q
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
81
82
83
84
85
86
87
88
89
90
9'1
92
#REF!
#REF!
D€cember 31, 2020
DAHO SUPPLEMENT IDAHO POWER COMPANY
December 31,2020
1 ,188,546,236
ELECTRIC OPERATING REVENUES (Account 400)
1 . Report b€lo,v operating relenues for each prescribed account, and manufactured gas revenues in total.
2. Report number of customers, columns (f) and (g), on the basis of meters, in addition to the number of flat rate
accounts; oa6pt that where separate meter readings are added for billing purposes, one customer should b€ counted
for each group of meters added. The average number of customers means the average of twelve figures at the close
of each month.
3. lf previous )€ar (columns (c), (e) and (g), are not deriwd from previously reported figures, e)plain any
inconsistencies in a footnote.
No.
(a)
OPERATING REVENUES
Amount for
Current Year
(b)
Amount for
Previous Year
(c)
1
2
3
4
5
6
7
I
I
10
11
12
13
14
15
16
't7
18
't9
20
21
22
23
24
25
26
Sales of Electricity
(440) Residential Sales.
(442) Commercial and lndustrial Sales
Small (or Commercial)(See lnstr. 4) (1)........
Large (or lndustrialXSee lnstr. 4) (2)
(444) Public Skeet and Highway Lighting
(445) Other Sales to Public Authorities
(446) Sales to Railroads and Railways.
[448) lnterdepartmental Sa|es........
TOTAL Sales to Ultimate Consumers.
(447) Sales for Resale - Opportunity....Non-Firm On|y.........
TOTAL Sales of Electricity...
(449) Provision for Rate Refunds..
TOTAL R€\Enue Net of Provision for Refunds.................
Other Operating Rerenues
(450) Forfeited Discounts.........
(451 ) Miscellaneous Service Revenues...
(453) Sales of Water and Water Power........
(454) Rent from Electric Property
(455) lnterdepartmental Rents
(456) Other Electric Revenues.
TOTAL Other Operating Revenues
TOTAL Electric Operating Revenues..
$532,085,463
427,454,427
165,501 ,1 03
3,669,473
$511,489,768
410,364,703
165,699,649
3,702.758
1,128,710,466 -
63,1 35,738
1 ,091,256,878
97,289,358
'1,'191,846,204
(12,151,500)
1 ,'t 79,694,705 I ,175,909,362
4,308,346
16,71 9,368
83,516,089
4,578,839
16,151,572
81,033,308
104,543,803 1 01 ,763,719
$1,284,238,508 $1,277 ,673,080
(1 ) Commercial and lndustrial sales - Small - under 1,000 J(Vl/ and includes all irrigation customers
(2) Commercial and lndustrial sales - Large - 1,000 KW and over.
IDAHO SUPPLEMENT
Page I 1
IDAHO POWER COMPANY
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. Eplain
5. See page 108, lmportant Changes During Year, for important new territory added and important rate increases or
decreases.
6. For lines 2,4,5, and 6, see page 304 for amounts relating to unbilled rewnue by accounts.
7. lnclude unmetered sales. Provide details of such sales in a footnots.
KILOWATT HOURS SOLD AVERAGE NUMBER OF CUSTOMERS PER MONTH
Line
No.
Amount for
Current Year
(d)
Amount for
Previous Year
(e)
Amount for
Current Year
(f)
Number for
Previous Y€ar
(s)
5,280,429,207
5,751,179,676
3,099,273,213
29,292,943
5,092,539,820
5,604,964,779
3,143,690,011
30,748,296
470,804
85,737
120
3,733
457,755
84,490
120
3,454
1
2
3
4
5
6
7
8
I
10
11
12
13
14,160,175,039 '*
't.802.764.476
13,871,942,906
2.72',t.703.090
560,394
N/A
545,819
NI/A
15,962,939,515 16,593,645,996 560,394 545,819
'lncludes <$8,298,103> in unbilled revenues
-'lncludes <56,802,260> KWH relating to unbilled revenues.
Lines 'l l through 21 are on an "allocated" basis
December 31,2020
IOAHO SUPPLEMENT
Page'l1a
IDAHO POWER COMPANY
ELECTRIC OPERATION AND l\jilAlNTEI.IANCE EXPENSES
lf the amount for previous year is not derived from previously reportod figures, explain in footnotes.
une
No.Account
(a)
Amounl Tor
Cun€nt Year
(b)
Amount ror
Previous Year
(c)
1 1. POWER PRODUCTION EXPENSES
2
3
4
5
6
7
8
I
10
11
12
13
14
15
16
't7
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33u
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
A. St€am Po/r/er G€nerailon
Operation
(500) Operation SupeMsion and Engin€ering.
(501) Fue|..........
(502) Steam Exp€nses...........
(503) Steam ftom Other Sources......................
(Less) (504) Steam Transfened-Cr
(505) Electric Epenses...........
(506) Miscellaneous St€am Power Expenses..
(509) Alloutances.....
TOTAL Oporation (Enter Total of lines 4 thru 12).
Maintenance
(510) lvhintenance SupeNisim and Engineering
(51 1) Maintenance of Structures...
(5'12) Maintenance of Boiler Plant....
(513) lvlaintenance of Electric Plant..
(51 4) Miscellaneous Steam Plant.....
TOTAL i/hintenance (Enter Total of Lines 15 thru 19).
TOTAL Poler Production Epenses-Steam Porer (Enter Total of lines 1 3 and 20)..
B. Nuclear Pourer Generation
Operation
(517) Op€ration Supervision and Engineering
(518) Fuel
(519) Coolants and
(520) Steam Expenses...........
(521 ) Steam ftom Other Sources......................
(Less) (522) Steam Transfened-Cr,
(523) Electric Expenses...........
(524) Miscellaneous Nuclear Po /er Expenses
(525) Rents.................
TOTAL Operation (Enter Total of lines 24 thru 32)....................
lvlaintenance
(528) [lhintenance SupeMsion and Engineering
(529) lvlaintenance of Structures...
(530) tllaintenance of Reactor Plant Equipment
(53't ) ttilaintenance of Electric P|ant..................
(532) tvlaintenance of Miscellaneous Nuclear Plant.
TOTAL Poiver Prcduction Expenses-Nuclear Pourer (Enter Total of lines 33 and 40)
C. Hydraulic Porer Generation
Operation
(535) Operation Supervision and Engineering.
(536) Water for Poiver
(537) Hydraulic Exp€nses.....
(539) Miscellaneous Hydraulic Po/ver Generation Expenses....
(Szm) Rents.......
TOTAL Operation (Enter Total of lines 44 thru 49)....................
1 ,368,608
114,327,024
9.352.388
1.675,716
9,404,861
211 .847
$1,69,722
't00,486,170
10,n4,477
1,808,419
8,814,693
215,356
136,340,443 123,088,838
8,992
368,594
8,1 1 1 ,607
3,007,255
3,459,884
133,410
282,990
10,054,792
3,893,605
5,775,653
't4,956,332 20,140,452
151,296,775 143,229,m0
5,614.761
6,651,789
1 4,383,902
2,021 ,101
4,742.157
248,038
5,5v,512
6,352,'t63
'14,089,238
1,962,780
5,558,598
242,272
33,661,747 33,739,564
December 31, 2020
IDA}IO SUPPLEMENT
Page 12
IDAHO POWER COMPANY
Docember 31, 2020
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
lf the amount for previous year is not derived from previously reported figures, a<plain in footnotes.
Lrne
No.Account
(a)
Amount tor
Cunent Year
(b)
Arount ror
PreMous 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
91
92
93
94
95
96
97
98
99
99
100
10"1
102
103
C. Hydraulic Poiver Generation (Continued)
lvlaintenance
(541) lvhintenance SupeMsion and Engineering
(542) lritlaintenance of Structures...
(543) Maintenance of Reseruoirs, Dams, and WateMays.....
(544) lvbintenance of El€ctric P|ant.................
(545) ltlaintenance of Miscellaneous Hydraulic Plant.
TOTAL ltrhintenance (Enter Total of lines 53 thru 57)...
TOTAL Power Production Expenses-Hydraulic Poiver (Enter Total of lines 50 and 58)
D. Other Porer Generation
Operation
(546) Operation SupeMsion and Engineeri n9....
(547) Fuel...
(SzE) Generation Erpenses...
(549) Miscellaneous Other Porver Generation Expenses...
(550) Rents....
TOTAL Operation (Enter Total of lines 62 thru 66)..............
Ivlaint€nance
(55 1 ) Maintenance S upervision and Engin€ering
(552) [rhintenance of Structures....
(553) lvlaintenance of Generating and Electric Plant...
(554) [rhintenance of Miscellaneous Other Poarer Generation Plant.....
TOTAL t\raintenance (Enter Total of lin€s 69 thru 72).
TOTAL Porver Production Expenses-Other Poiler (Enter Total of lines 67 and 73)..,...
E. Other Porer Supply Expenses
(555) Purchased Porer................
(556) System Control and Load Dispatching
(557) Other Expenses....
TOTAL Other Porver Supply Expenses (Enter Total of lines 76 thru 78).........
TOTAL Power Production Erpenses (Enter Total of lines 21, 41, 59,74, and 79).......,
2. TRANSMISSION EXPENSES
Operation
(560) Operation Supervision and Engineering..
(561) Load Dispatching.
(562) Station Exp€nses.
(563) Overhead Line Expenses...
(564) Underground Line Expenses
(565) Transmission ol Electricity by O(hers.
(566) Miscellaneos Transm ission Expenses...........
(567) Rents...
TOTAL Operation (Enter Total of lines 83 thru 90)....
lVlaintenance
(568) lvlaintenance S uperuision and Engi neering
(569) Maintenance of Structures...
(570) tvlaintenance of Station Equi pment.........
(571 ) [raintenance of Overhead Lines.................
(572) Maintenance of Und€rground Lines.
(573) lvlaintenance of Miscellaneous Transmission Plant.
(575) Transm ission lt/larket Adm inistration - E I M.................
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.......
$203.821
674,572
410.847
2,406,896
2,901,479
$'t28,903
619,420
607,377
2,268,3U
2,688,310
6,597,6't6 6,312,U4
40,259,363 ,10,051,908
6la,089
50,690,020
4,430,1 13
807,689
0
643,579
49,275,671
4,206,744
607,412
0
56,575,912 54,733,q2
0
'168,150
'130,051
1.794,460
0
199,395
249,236
2,723,242
2,O92,661 3,'t71,873
58,668.573 57,905,276
279,813,774
6,072
(28,409,031 )
267,616,944
4,743
6,684,096
251,410,815 274,305,783
501,635,526 515,492,256
2,751,762
4,671,622
2,676,133
850,414
3,847,512
961,701
3,857,810
0
3,032,864
5,269,49'l
2,699,617
859,091
2,715,899
0
3,771,65',1
0
19,616,954 18,348,613
147,932
1,307 ,782
1 ,791 ,613
1,382,487
467
495,840
5,126,120 4,222,663
24,743,074 22,571,276
3,904,433 4,201,504
(39,294)
1,176,432
1,549,168
949,982
585,925
451
IDAHO SUPPLETENT
Page'13
IDAHO POWER COMPANY
ELECTRIC OPERATION AND [,IAINTENANCE EXPENSES
lf the amount for previous year is not deriv€d from previously reported figures, explain in footnotes.
Lrne
No.Account
(a)
Amount lor
Cunent Year
(b)
Amounl lor
Previous Year
(c)
104
105
106
107
108
109
1t0
111
1't2
113
114
1',t5
1't6
117
118
119
120
121
122
123
124
125
126
127
128
129
130
131
132
133
1U
135
136
137
138
139
1q
't41
't42
143
144
145
14
147
148
149
150
'151
'152
153
3. DISTRIBUTION EXPENSES (Continued)
(581) Load Dispatching.
(582) Station Expenses.
(583) Overhead Line Expenses....
(584) Underground Line Erpenses........................
(585) Street Lighting and Signal System Erpenses.
(586) l{eter Expenses..........................
(587) Customer lns{allations Expenses.
(588) Miscdlaneous Distribution E&enses.....
(589) Rents........
TOTAL Operation (Enter Total of lines 103 thru 113)..........,........
Itlaintenance
(590) Maintenance Supervision and Engineering..
(591 ) lvtaintenance of Structures......
(592) tvlaintenance of Station Equipment.
(593) [ilaintenance of Overhead Lines.....
(594) Maintenance of Underground Lines.......,.........
(595) lvlaintenance of Line Transform€rs..........
(596) lvhintenance of Street Lighting and Signal Systems....
(597) lvlaintenance of [rhters...
(598) [raintenance of Miscellaneous Distribution Plant.
TOTAL iilaintenance (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) lileter Reading Expenses.....
(903) Customer Records and Collection Expons€s..
(904) Uncollectible Accounts........
(905) Miscellaneous Customer Accounts Exp€nses.
TOTAL Customer Accounts Expenses (Enter Total of lines 129 thru 133)...............
5. CUSTOMER SERVICE AND INFORivIATIONAL EXPENSES
Operation
(907) Supervision...............................
(908) Customer Assistance Expenses.
(909) lnformational and lnstructional Expenses.
(910) Miscellaneous Customer SeMce and lnformational Exp€nses.
TOTAL Cust. SeMce and Informational Exp€nses (Ent€r Total of lines 137 thru 1zl0)..,
6. SALES EXPENSES
Operation
(911) Supervision...
(912) Demonstrating and Selling Expens€s..
(9'13) Ad\€rtising Epenses...........
(916) Miscellaneous Sales Expenses..
TOTAL Sales Expenses (Enter Total of lines 144[hru '|47).....
7. ADMINISTRATIVE AND GENERAL EXPENSES
Operation
(920) Adm inistrative and General Salaries.............
(921 ) Otrce Supplies and Epenses...........
(Less) (922) Adm inistrative Ereenses Transbned-Credit.........
4.788,755
1,609,593
3,923,758
4,227.912
8,074
4,455,601
9s9,834
3,967,022
315,764
$4.354.129
1,539,772
3,791,972
3,577,702
58,877
4,256,662
1,'t 39,857
4,303,992
318,784
28,160,745 27,543,252
14,131
0
3,686.674
14,808,059
525,085
46,985
258,117
811,334
131 ,300
(262,%0"
66,315
3,984,755
15,683,063
716,M7
49,1 19
249,015
880,355
184,083
20,281,685 21,550,'t93
8,442,4n 49,093,,145
677,412
1,479,985
14,233,374
4.971,142
123
885,823
1,344,40
12,785,zil
2,076,567
107
21,%2,0fi 17,092,23'.1
693,641
47.135.250
286,906
703,675
748,596
44,900,655
160,245
589,921
4,819,471 4,399,4'.t7
83. 1 32,875
13,029,732
(28,448,941.,
85,662,794
13,973,650
(31,61 1,874)
December 31, 2020
IDAHO SUPPLETENT
Page 14
IDAHO POWER COMPANY
ELECTRIC OPERATION AND IV|AINTENANCE EXPENSES
lf the amount for previous year is not derived from previously report€d figures, explain in footnotes.
Ltne
No.Account
(a)
Amount tor
Cunent Year
(b)
Amount tor
Previous Year
(c)
154
155
156
157
158
159
160
161
't62
163
164
't65
166
167
168
169
7. ADMINISTRATIVE AND GENERAL EXPENSES (Continued)
(923) Outside Services Employed
(924) Property lnsurance....
(925) lnjuries and Damages...........
(926) Em ployee Pensions and Benef ts.............
(927) Franchise Requirements....
(928) Regulatory Comm ission Expenses....
(929) Duplicate Charges-Cr
(930.'l ) General Adrrcrtising Erpenses.
(930.2) Miscellaneous General Expenses....
(931) Rents........
TOTAL Operdion (Enter Total of lines 151 thru '164)............
iiaintenance
(935) Maintenance of General P|ant.................,
TOTAL Admin and General Erpenses (Enter Total of lines 16$167)
TOTAL El€c Op and Maint E)o Crotal of 80, 100, 126, 1U, 141, 148, 168)....... .. ..
$6,502,270
3,949,016
5,762,351
46.225,459
0
4,000,063
1 60,764
3,528,596
0
$8,992,210
3,2%,424
5,101,000
49,263,675
0
4,4f.1,927
44,586
3,465,659
0
137,842,186 142,650,051
7,1 60,659 6,937,249
145,002,845 149,587,300
$790,005,381 $800,235,926
IDAHO ONLY
Decombor 31, 2020
NUMBER OF ELECTRIC DEPARTMENT EMPLOYEES
1. The data on number of employees should be reported for the payroll period ending nearesi to October 31
or any payroll period ending 60 days b€fore or ater October 31.
2. lf the respondent's payroll for the reporting period includes any special construction personnel, include
such employees on line 3, and sho/v the number of such special construction employees in a footnote.
3. The number of employees assignable to the electric department from joint functions of combination utilities
may be determined by estimato, on the basis of employee equi\alents. Shofl the estimated number of equiv-
alent employees attributed to the electric department from joint functions.
1 Payrotl Period Ended (Date)..December 31 , 201 I
1,976
6
1,982
December 31, 2020
1.932
5
1,937
2 Total Regular Full-Time Employees.........
3 Total Part-Time and Temporary Employees.........
4 Total Employees
IDAIIO SUPPLEiIENT
Page l5
IDAHO POWER COMPANY