2018Annual Report.pdf

3Effi*
An TDACORP Company
LISA D. NORDSTROM
Lead Counsel
I [e-mail]
April24,2019
Ms. Diane Hanian, Secretary
ldaho Public Utilities Commission
PO Box 83720
Boise, lD 83720-0074
Re: ldaho Power Company's 2018 Annual FERC Form 1 Report
Dear Ms. Hanian
Enclosed forfiling are two copies of ldaho Power Company's FERC Form 1 report and
ldaho supplement for the year ending December 31,2018. One bound and one unbound
copy are being provided as requested by the ldaho Public Utilities Commission. Also
included is the !DACORP 2018 Annual Report.
lf you have any questions, please contact Regulatory Analyst Kelley Noe at 208-
388-5736 or [e-mail].
Very truly yours,
lzt-,e.(-,^lrt'r',,*
ordstromLisa D. N
LDN:kkt
Enclosures
THIS FILING IS Form 1 Approved
OMB No.1902-0021
(Expires 1213112019)
Form 1-F Approved
OMB No.1902-0029
(Expires 1213112019)
Form 3-Q Approved
OMB No.1902-0205
(Expires 1213112419)
(J
FERC FINANCIAL REPORT
FERC FORM No. 1: Annual Report of
Major Electric Utilities, Licensees
and Others and Supplemental
Form 3-Q: Quarterly Financia! Report
These reports are mandatory under the Federal PowerAct, Seclions 3, 4(a), 304 and 309, and
18 CFR 141.1 and 141.400. Failure to report may result in criminal fin€s, civil penalties and
other sanctions as provided by law. The Federal Energy Regulatory Commission does not
consider these reports to be of confidential nature
Item 1: [] An lnitial (Original)
Submission
OR ! Resubmission No. _
Exact Legal Name of Respondent (Gompany)
ldaho Power Company
Year/Period of Report
End of 20',81Q4
FERC FORM No.ll3-Q (REv. 02-o4l
THIS FILING IS
Item 1: E An lnitial (Original)
Submission
OR tr Resubmission No. _
Form 1 Approved
OMB No.1902-0021
(Expires 1213112019)
Form 1-F Approved
OMB No.1902-0029
(Expires 1213112019)
Form 3-Q Approved
OMB No.1902-0205
(Expires 1213112019)
FERC FINANCIAL REPORT
FERC FORM No. 1: Annual Report of
Major Electric Utilities, Licensees
and Others and Supplemental
Form 3-Q: Quarterly Financial Report
These reports are mandatory under the Federal PowerAct, Sections 3, a(a), 304 and 309, and
18 CFR 141 .1 and 141 .400. Failure to report may result in criminal fines, civil penalties and
other sanctions as provided by law. The Federal Energy Regulatory Commission does not
consider these reports to be of confidential nature
Exact Legal Name of Respondent (Company)
ldaho Power Company
Year/Period of Report
End of 2018/Q4
FERC FORM No.1/3-Q (REV. 02-041
Deloitte,,Deloittc & Touche LLP
800 West Main Street
Suite 1400
Bolse, ID a37O2-7734
USA
Tel: [phone]
www, deloitte.com
INDEPENDENT AU DITORS' REPORT
Idaho Power Company
Boise, Idaho
We have audited the accompanying financial statements of Idaho Power Company (the "Company"),
which comprise the balance sheet - regulatory basis as of December 31,2018, 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 723 of the accompanying Federal Energy
Regulatory Commission Form 1, and the related notes to the flnancial statements.
Management's Responsibility for the Financia! 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 interna! control relevant to the preparation and fair presentation
of financial statements that are free from material misstatement, whether due to fraud or error.
Audators' Responsibility
Our responsibility is to express an opinion on these financia! 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. [n making those risk assessments, the auditor considers internal control relevant to the
Company's preparation and fair presentation of the financial statements in order to design audit
procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion
on the effectiveness of the Company's internal control. Accordingly, we express no such opinion. An
audit also includes evaluating the appropriateness of accounting policies used and the reasonableness
of significant accounting estimates made by management, as well as evaluating the overall presentation
of the financial statements.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for
our audit opinion.
Opinion
In our opinion, the regulatory-basis financial statements referred to above present fairly, in all material
respects, the assets, liabilities, and proprietary capital of Idaho Power Company as of December 31,
2018, and the results of its operations and its cash flows forthe yearthen 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 I to the financial statements, these financial statements were prepared in
accordance with the accounting requirements of the Federal Energy Regulatory Commission as set forth
in its applicable Uniform System of Accounts and published accounting releases, which is a basis of
accounting other than accounting principles generally accepted in the United States of America. Our
opinion is not modified with respect to this matter.
Restricted Use
This report is intended solely for the information and use of the board of directors and management of
the Company and for filing with the Federal Energy Regulatory Commlssion and is not intended to be
and should not be used by anyone other than these specified parties.
fr"1,W, t{ruc&tt4
April 16, 2019
FERC FORM NO. 1/3.Q:
IDENTIFICATION
01 Exact Legal Name of Respondent
ldaho Power Company
02 Y ear lP eriod of Report
End of 2018/Q4
03 Previous Name and Date of Change (if name changed during year)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 and CAO
07 Address of Contact Person (Street, City, State, Zip Code)
1221W ldaho St, P.O. Box 70 Boise, ld 83707-0070
08 Telephone of Contact Person,lncluding
Area Code
[phone]
09 This Report ls
(1) ffi An Original (2) ! A Resubmission
10 Date of Report
(Mo, Da, Yr)
0411612019
ANNUAL CORPORATE OFFICER CERTIF!CATION
The undersigned officer certifies that;
I have examined this report and to the best of my knowledge, information, and belief all statements of fact contained in this report are correct statements
of the business affairs of the respondent and the financial statements, and other financial information contained in this report, conform in all material
respects to the Uniform System of Accounts.
01 Name
Ken Petersen
02 Title
Vice President, Controller & CAO Ken Petersen
03 04 Date Signed
(Mo, Da, Yr)
04t1612019
Title 18, U.S.C. 1001 makes it a crime for any person to knowingly and willingly to make to any Agency or Department of the United States any
false, fictitious or fraudulent stiatements as to any matter within its jurisdiction.
FERC FORM No.1/3-Q (REV. 02-04)Page 1
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5.1en Orisinat
(21 fiA Resubmission
Date of Report(Mo, Da, Yr)
0411612019
Year/Period of Report
2018tQ4End of
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
?Corporations Controlled by Respondent 103
4 Officers 104
5 Directors 105
6 lnformation on Formula Rates 106(aXb)
7 lmportiant Changes During the Year 108-109
8 Comparative Balance Sheet 110-113
I Statement of lncome for the Year 114-117
10 Statement of Retained Earnings for the Year 1 18-1 'l 9
11 Statement ol Cash Flows 120-121
12 Notes to Financial Statements 122-123
13 Statement of Accum Comp lncome, Comp lncome, and Hedging Activities 122(a){b)
14 Summary of Utility Plant & Accumulated Provisions for Dep, Amort & Dep 200-201
15 Nuclear Fuel Materials 202-203 N/A
16 Eleckic Plant in Service 204-207
17 Electric Plant Leased to Others 213 NIA
18 Electric Plant Held for Future Use 2',t4
19 Construction Work in Progress-Electric 216
20 Accumulated Provision for Depreciation of Electric Utility Plant 219
21 lnvestment of Subsidiary Companies 224-225
22 Materials and Supplies 227
23 Allowances 228(ab)-229(ab)N/A
24 Extraordinary Property Losses 234 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 Deferred Debits 233
29 Accumulated Deferred lncome Taxes 234
30 Capital Stock 250-251
Other Paid-in Capital 253
cz Capital Stock Expense 254
33 Long-Term Debt 25&257
34 Reconciliation of Reported Net lncome with Taxable lnc for Fed lnc Tax 261
35 Taxes Accrued, Prepaid and Charged During the Year 262-263
36 Accumulated Deferred lnvestment Tax Credits 266-267
FERC FORM NO.1 (ED.12-96)Page 2
ldaho Power Company
Date of Reporl
(Mo. Da, Yr)
04t16t2019
Year/Period of Report
End of 20181Q4
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
Line
No.
Title of Schedule
(a)
Reference
Page No.
(b)
Remarks
(c)
37 Other Deferred Credits 269
38 Acormulated Deferred lncome Taxes-Accelerated Amortization Property 272-273 N/A
39 Accr.rmulated Deferred lncome Taxes-Other Property 274-275
40 Accumulated Deferred lncome Taxes-Other 276-277
41 Other Regulatory Liabilities 278
42 Eleckic Operating Revenues 300-301
43 Regional Transmission Service Revenues (Acmunt 457.1)302 N/A
44 Sales of Eleckicity by Rate Schedules 304
45 Sales for Resale 310-3 1 1
46 Electric Operation and Maintenance Expenses 324-323
47 Purchased Power 326-327
48 Transmission of Electricity for Others 328-330
49 Transmission of Eleckicity by ISO/RTOs 331 N/A
50 Transmission of Electricity by Others 332
51 Miscellaneous General Expenses-Electric 335
52 Depreciation and Amortization of Electric Plant 336-337
53 Regulatory Commission Expenses 350-351
54 Research, Development and Demonstration Activities 352-353
55 Distribution of Salaries and Wages 354-355
56 Common Utility Plant and Expenses 356 NiA
57 Amounts included in ISO/RTO Settlement Statements 397 N/A
58 Purchase and Sale of Ancillary Services 398
59 Monthly Transmission $ystem Peak Load 400
60 Monthly ISO/RTO Transmission System Peak Load 400a N/A
61 Electric Energy Account 401
62 Monthly Peaks and Output 401
63 Steam Electric Generating Plant Statistics 402-403
64 Hydroelectric Generating Plant Statistics 406-407
65 Pumped Storage Generating Plant Statistics 408-409 N/A
66 Generating Plant Statistics Pages 410-411
FERC FORM NO. 1 (ED.12-96)Page 3
This Reoort ls:(1) 5_1An orisinal
(2) [lA Resubmission
ldaho Power Company (1)
(2)
An Original
A Resubmission
(Mo, Da,
04t16t2019
Year/Period of Report
End of 20181Q4
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 Stratistics Pages 422-423
68 Transmission Lines Added During the Year 424-425
69 Substations 426-427
70 Transactions with Associated (Affi liated) Companies 429
71 Footnote Data 450
Stockholders' Reports Check appropriate box:
! Two copies will be submitted
E ruo annual reportto stockholders is prepared
FERC FORM NO. ' (ED.12.96)Page 4
Name of Respondent
ldaho Power Company
This Report ls:
(1) E AnOriginal
(2) tr A Resubmission
Date of Report
(Mo, Da, Yr)
04t1612019
Year/Period of Report
End of 2o18ta4
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.
Kelr Peteraen vice President, Controller and CAO/ Idaho Pogte! CoEpany
t22L w. Idaho street, P.o. Box 70, Boise, Idaho 83707-00?0
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.
Idatro, .Iune 30, 1989
3. lf at any time during the year the property of respondent was held by a receiver or trustee, give (a) name of
receiver or trustee, (b) date such receiver or trustee took possession, (c) the authority by which the receivership or
trusteeship was created, and (d) date when possession by receiver or trustee ceased.
lilot Applicab].e
4. State the classes or utility and other services furnished by respondent during the year in each State in which
the respondent operated.
Class of Utility Service State
Electric Idaho
El€ctric 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
(2) Dg No
Enter the date when such independent accountant was initially engaged:
FERC FORM No.1 (ED. 12-87)PAGE 101
Name of Respondent
ldaho Power Company
This Report ls:
(1) E An Original
(2) tr A Resubmission
Date of Report
(Mo, Da, Yr)
0411612019
Year/Period of Report
End of 2olg91
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 100o/o of ldaho Power Company's Common Stock.
IDACORP is a public utility Holding Company incorporated effective 10-1-1998
FERC FORM NO. I (ED, 12-96)Page 102
Name of Respondent
ldaho Power Company
This
(1)
(2)
Reoort ls:
5]An orisinal
1A Resubmission
Date of Report(Mo, Da, Yr)
04t16t2019
Year/Period of Report
End of 2018tQ4
CORPORATIONS CONTROLLED BY RESPONDENT
1. Report below the names of all corporations, business trusts, and similar organizations, controlled directly or indirectly by respondent
at any time during the year. lf control ceased prior to end of year, give paffculars (details) in a footnote.
2. lf control was by other means than a direct holding of voting rights, state in a footnote the manner in which control was held, naming
any intermediaries involved.
3. lf control was held jointly with one or more other interests, state the fact in a footnote and name the other interests.
Definitions
1 . See the Uniform System of Accounts for a definition of control.
2. Direct control is that which is exercised without interposition of an intermediary.
3. lndirect control is that which is exercised by the interposition of an intermediary which exercises direct control.
4. Joint control is that in which neither interest can effectively control or direct action without the consent of the other, as where the
voting control is equally divided between two holders, or each party holds a veto power over the other. Joint control may exist by
mutual agreement or understanding between two or more parties who together have control within the meaning of the definition of
control in the Uniform System of Accounts, regardless of the relative voting rights of each party.
Line
No.
Name of Company Controlled
(a)
Kind of Business
(b)
Percent Voting
Stock Owned
(c)
Footnote
Ref.
(d)
1 Direct Control
2 ldaho Energy Resources Company Coal mining and mineral 100%
a development
4
5
6
7
B
I
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
FERC FORM NO. ,l (ED.12-96)Page 103
Name of Respondent
ldaho Power Company
This Reoort ls:(1) E:]An Original(2) 1-1A Resubmission
Date of Report(Mo, Da, Yr)
04t1612019
YeariPeriod of Report
End of 2O18lA4
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.
Llne
No.
Title
(a)
Name of Otficer
(b)
Salarvfor Yeiir(c)
1
2 President & Chief Executive Oflicer Darrel T. Anderson 860,000
3
4 Senior Vice President, CFO & Treasurer Steven Keen 445,000
5
6 Senior Mce President, COO Lisa Grow 445,000
7
8 Senior Mce President, Public Affairs Jeffrey Malmen 305,000
I
10 Senior Vice President, Admin Services & Chief HR Officer Lonnie Krawl (1)187,000
11
12 Senior Mce President & General Counsel Brian Buckham 340,000
13
14 Vice President, T&D Engineering & Construction, and CSO Vem Porter 305,000
15
16 Mce President, Power Supply Tessia Park 285,000
17
18 Vice President, Customer Operations & Bus. Development Adam Richins 260,000
19
20 Mce President, Corporate Controller & CAO 265,000
21
22 Vice President of Corporate Services & CIO Jeff Glenn 262,000
ZJ
24 Mce President of Regulatory Affairs Tim Tatum 200,000
25
20 Corporate Secretary Pakick Harrington 210,000
27
28 (1) Retirement effective 8/31/18, Salary shows YTD wages
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
FERC FORM NO.1 (ED.12-96)Page ,04
Ken Petersen
Name of Respondent
ldaho Power Company
(1)
(21
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
0411612019
Year/Period of Report
End of 20181Q4
DIRECTORS
1, Reportbelowtheinformationcalledforconcerningeachdirectoroftherespondenlwhoheldofiicealanytimeduringtheyear. lncludeincolumn(a),abbrevialed
titles of the directors who are officers of the respondent.
2. Designate members of the Executive Committee by a triple asterisk and the Chairman of the Executive Committee by a double asterisk.
LItgNo.Name (and i lue) ot urrector ness Address
)
1
2 Judith A. Johansen 10446 E. Palo Brea Dr., Scottsdale, Arizona85262
3
4 Christine King, Comp. Committee Chair,.-.8527 East Old Field Rd
5 Scottsdale, Arizona 85266
6
7 Thomas E. Carlile 2719 North Woodview place, Boise ldaho 83702
B
9 Darrel T. Anderson President & CEO, ".*ldaho Power Company, 1221 W.ldaho Street,
10 P.O. Box 70, Boise, ldaho 83707-0070
11
12 J. LaMont Keen (1)481 North Strata Via Way, Boise ldaho 83712
13
't4 Robert A. Tinstman, Board Chair & Corp Gov Chair, "*4433 W. Quail Point Court, Boise, ldaho 83703
15
16 Richard Dahl, Audit Chair "-60 Laiki Pl,
17 Kailua, Hawaii 96734-1 905
18
19 Dennis L. Johnson 926 W Oakhampton Dr, Eagle, ldaho 83616
20
21 Ronald W. Jibson 417 Aerie Circle, North Salt Lake City, Utah 84054
22
23 Richard J. Navano 1256 E. Candleridge Ct., Boise, ldaho 83712
24
25 Annette G. Elg 3475 E. Rivernest Lane, Boise, ldaho 83706-6928
26
27 (1) Retired on May 16, 2018
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
4B
FERC FORM NO.1 (ED.12.9s)Page 105
Pfinqpal ul
ldaho Power Company An Original
A Resubmission(2)
Date of Report
(Mo, Da, Yr)
04t16t2019
Year/Period of Report
gn6 61 2018/Q4
INFORMATION ON FORMULA RATES
FERC Rate Schedule/Tariff Number FERC Proceeding
Does lhe respondent have formula rates?I ves
ENo
1. Please list the Commission accepted formula rates including FERC Rate Schedule or Tariff Number and FERC proceeding (i.e. Docket No)
accepting the rate(s) or changes in the accepted rate.
Line
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
27
28
29
30
31
32
33
34
1R
36
37
38
39
40
41
FERC FORM NO.1 (NEW.12-08)Page 106
Name of Respondent
ldaho Power Company
This Reoort ls:
(1) E An original
(2) - A Resubmission
Date of Report(Mo, Da, Yr)
04t16t2019
Year/Period of Report
En6 o1 2018/Q4
INFORMATION ON FORMULA RATES
FERC Rate Schedule/Tariff Number FERC Proceeding
Does the respondent file with the Commission annual (or more frequent)
filings mntaining the inputs to the formula rate(s)?I ves
Eruo
2. lf yes, provide a listing of such filings as mntained 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
I 201 80829-51 66 0812912018 ER09-1 641 -000 ldaho Power Companl FERC Electric Tariff
2 2018 Annua
3 lnformational Fillinl
4 under ER09-1641-00(
5
6
7
B
I
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
I I I I
FERC FORM NO.1 (NEW.12-08)Page 106a
Name of Respondent
ldaho Power Company
This Reoort ls:(1)E An original
(2) l-l A Resubmission
Date of Report(Mo, Da, Yr)
04t16t2019
Year/Period of Repo(
En6 61 2018/Q4
INFORMATION ON FORMULA RATES
Formula Rate Variances
1. lf a respondent does not submit such filings then indicate in a footnote to the applicable Form 1 schedule where formula rate inputs differ from
amounts reported in the Form 1.
2. The footnote should provide a narrative description explaining how the "rate" (or billing) was derived if different from the reported amount in the
Form 1.
3. The footnote should explain amounts excluded from the ratebase or where labor or other allocation factors, operating expenses, or other items
impacting formula rate inputs differ from amounts reported in Form 1 schedule amounts.
4. Where the Commission has provided guidance on formula rate inputs, the specific proceeding should be noted in the footnote.
Line
No.Page No(s).Schedule Column Line No
1
2
3
4
5
6
7
8
I
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
FERC FORM NO. 1 (NEW. 12-0E)Page 106b
Name of Respondent
ldaho Power Company
Ihas Report ls;
(1)
(2)En
An Original
A Resubmission
Date of Report
04t16t2019
Year/Period of Report
End of 20181Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR
Give particulars (details) concerning the matters indicated below. Make the statements explicit and precise, and number them in
accordance with the inquiries. Each inquiry should be answered, Enter "none," "not applicable," or "NA" where applicable. lf
information which answers an inquiry is given elsewhere in the report, make a reference to the schedule in which it appears,
1. Changes in and important additions lo 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 conceming the transactions, name of the Commission authorizing the transaction, and reference to
Commission authorization.
3. Purchase or sale of an operating unit or system: Give a brief description of the property, and of the transactions relating thereto,
and reference to Commission authorization, if any was required. Give date journal entries called for by the Uniform System of Accounts
were submitted to the Commission.
4. lmportant leaseholds (other than leaseholds for natural gas lands) that have been acquired or given, assigned or 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. I , 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.
'l 1. (Reserved.)
12. lf the important changes during the year relating to the respondent company appearing in the annual report to stockholders are
applicable in every respect and furnish the data required by lnstructions 1 to 1'l 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)Pago 10E
Name of Respondent
ldaho Power Companv
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
0411612019
Year/Period of Report
2018tQ4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
3.
4.
L. None
2. None
None
None
5. None
6. ln March 2018, ldaho Power issued 5220 million in principal amount of 4.2OYo first mortgage bonds, secured medium-term
notes, Series K, maturing on March 7,2048.|n April and May 2015, ldaho Power received orders from the IPUC, OPUC, and
Wyoming Public Service Commission (WPSC) authorizing ldaho Power to issue and sell from time to time up to 5500 million in
aggregate principal amount of debt securities and first mortgage bonds, subject to conditions specified in the orders. The order
from the IPUC approved the issuance ofthe securities through May 31, 2019, subject to extensions upon request to the IPUC.
The OPUC's and WPSC's orders do not impose a time limitation for issuances, but the OPUC order does impose a number of
other conditions, including a requirement that the interest rates for the debt securities or first mortgage bonds fall within
either (a) designated spreads over comparable U.S. Treasury rates or (b) a maximum all-in interest rate limit of 7.0 percent.
7. None
8. Effective L2128/20L8 a 3.O% general wage adjustment was implemented
9. None
10. None
11. Reserved
12. None
13. Officer Changes in 2018
Jeff S. Glenn's title changed from "Vice President of lnformation Technology and Chief lnformation Officer" to "Vice
President of Corporate Services and Chief lnformation Officer" effective June 2, 2018.
Lonnie G. Krawl retired as Senior Vice President of Administrative Services and Chief Human Resources Officer on
August 3L,2OL8.
L4. ldaho Power and its unregulated parent, IDACORP have separate cash management programs (separate bank accounts,
liquidity facilities, short-term debt and investment programs). No money has been loaned or advanced from ldaho Power to
IDACORP through a cash management program.
FERC FORM NO. 1 (ED.12-96)Page 109,1
a
a
Name of Respondent
ldaho Power Company
This Report ls:
(1) I An Original
(2) tr A Resubmission
Date of Report
(Mo, Da, Yr)
0411612019
Year/Period of Report
End of 2o18lQ4
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Line
No.Title of Account
(a)
Ref.
Page No.
(b)
Current Year
End of QuarterfYear
Balance
(c)
Prior Year
End Balance
12131
(d)
1 UTILITY PLANT
2 Utility Plant (101-106, 114)200-201 6,108,607,184 5,914,236,887
J Construction Work in Progress (107)200-201 480,258,675 452,424,340
4 TOTAL Utility Plant (Enter Total of lines 2 and 3)6,588,865,859 6,366.661,227
5 (Less) Accum. Prov. for Depr. Amort. Depl. (108, 1 't0, 1 1 1 , 1 15)2AO-201 2,394,578,621 2,283,266,546
6 Net Utility Plant (Enter Total of line 4 less 5)4,194,287,232 4,083,394,681
7 Nuclear Fuel in Process of Ref., Conv.,Enrich., and Fab. (120.1)202-203 0 0
I Nuclear Fuel Materials and Assemblies-Stock Account (120.2)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 7-1 1 less 12)C 0
14 Net Utility Plant (Enter Total of lines 6 and 13)4,194,287,232 4,083,394,681
15 Utility Plant Adjustments (1 16)c 0
16 Gas Stored Underground - Noncunenl (117)c 0
17 OTHER PROPERTY AND INVESTMENTS
18 Nonutility Property (121 )3,653,10C 1,071,638
19 (Less) Accum. Prov. for Depr. and Amon (22)c 0
20 lnvestments in Associated Companies (123)0 0
21 lnvestment in Subsidiary Companies (123.1)224-225 57,026,771 72,212,978
22 (For Cost of Account 123.'t, See Footnole Page 224, line 421
23 Noncunent Portion of Allowances 228-229 c 0
24 Other lnvestTents (1 24)0
25 Sinking Funds (125)0
26 Depreciation Fund (126)c 0
27 Amortization Fund - Federal (127)C 0
28 Other Special Funds (128)36,487,611 30,265,777
29 Special Funds (Non Major Only) (129)0 0
30 Long-Term Portion of Derivative Assets (175)0 4,074
31 Long-Term Portion of Derivative Assets - Hedges (176)0 0
32 TOTAL Other Property and lnvestments (Lines 18-21 and 23-31)97,167,482 103,554,467
33 CURRENT AND ACCRUED ASSETS
34 Cash and Working Funds (Non-maior Only) (130)c 0
35 Cash (131)86,225,12A 34,375,147
36 Special Deposits (1 32-1 34)1,167,693 2,364,499
37 Working Fund (135)7,000 '10,500
38 Temporary Cash lnvestments (136)79,228,007 10,260,000
39 Notes Receivable (141)-84,743 -86,399
40 Customer Accounts Receivable (142)79,182,448 77,764,379
41 Other Accounts Receivable (143)6,330,066 28,1 69,330
42 (Less) Accum. Prov. for Uncollectible Acct.-Credit ('144)1,989,13'l 2,192,252
43 Notes Receivable from Associated Companies (145)0 0
44 Accounts Receivable from Assoc. Companies (146)0 0
45 Fuel Stock (151)227 47,979J22 56,638,459
46 Fuel Stock Expenses Undistributed (152)227 0 5
47 Residuals (Elec) and Extracted Products (153)227 0 0
48 Plant Materials and Operating Supplies (154)227 53,553.674 53,856,630
49 Merchandise (155)227 0 0
50 Other Materials and Supplies (156)227 0 0
51 Nuclear Materials Held for Sale (157)202-2A31227 0 0
52 Allowances (158.1 and 158.2)228-229 0 0
FERC FORM NO. 1 (REV.12-03)Page 110
Name of Respondent
ldaho Power Company
This Report ls:
(1) I An Orisinal
(2) Z A Resubmission
Date of Report
(Mo, Da, Yr)
o4t't6t2019
Year/Period of Report
End of 2018tQ4
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEB|TS(pontinued)
Line
No.Title of Account
(a)
Ref.
Page No.
(b)
Current Year
End of Quarterl/ear
Balance
(c)
Prior Year
End Balance
12131
(d)
53 (Less) Noncurrent Portion of Allowances 0 0
54 Stores Expense Undistributed (163)227 1,433,652 1,888,307
55 Gas Stored Underground - Cunent (164.1)0 0
56 Liquefied Natural Gas Stored and Held for Processing (164.2-164.3)0 0
57 Prepayments (165)16,373,874 16,865,877
58 Advances for Gas (166-167)0 0
59 lnterest and Dividends Receivable (171)56,822 6,500
60 Rents Receivable (172)0 0
61 Accrued Utility Revenues (173)69,318,1 68 75,119,761
62 Miscellaneous Current and Accrued Assets ('174)0 U
63 Derivative lnstrument Assets (175)3,655,138 22,228
64 (Less) Long-Term Portion of Derivative lnstrument Assets (175)0 4,074
65 Derivative lnstrument Assets - Hedges (176)n 0
66 (Less) Long-Term Portion of Derivative Instrument Assets - Hedges ( 176 0 0
67 Total Current and Accrued Assets (Lines 34 through 66)442,436,870 355,058,897
6B DEFERRED DEBITS
69 Unamortized Debt Expenses (181)15,958,660 15,097,172
70 Extraordinary Property Losses (182.1 )23Oa 0 0
71 Unrecovered Plant and Regulatory Study Costs (182.2)230b c 0
72 Other Regulatory Assets (182.3)232 1,214,174,417 '1 ,1 32,096,1 94
73 Prelim. Survey and lnvestigation Charges (Electric) (183)c 0
74 Preliminary Natural Gas Survey and lnvestigation Charges 183.1)c 0
75 Other Preliminary Survey and lnvestigation Charges (183.2)c 0
76 Clearing Accounts (184)2,005,924 535,559
77 Temporary Facilities (1 85)C 0
78 Miscellaneous Deferred Debits (1 86)233 73,405,043 73,132,688
79 Def. Losses from Disposition of Utility Plt. (187)c 0
80 Research, Devel. and Demonstration Expend. (188)352-353 c 0
81 Unamortized Loss on Reaquired Debt (189)42,445,54C 39,822,616
82 Accumulated Deferred lncome Taxes ('190)234 293,383,262 289,813,919
83 Unrecovered Purchased Gas Costs (191)c 0
84 Total Deferred Debits (lines 69 through 83)1,641 ,372,846 1,550,498,148
85 TOTAL ASSETS (lines '14-16, 32,67, and 84)6,375,264,430 6.092.506,193
FERC FORM NO. 1 (REV. 12-03)Page 111
Name of Respondent
ldaho Power Company
This Report is:
(1) tr AnOriginal
(2) tr A Resubmission
Date of Report
(mo, da, y)
04t16t2019
Year/Period of Report
end of 20181Q4
CoMPARATTVE BALANCE SHEET (LtABtLtTrES AND OTHER CREDTTS)
Line
No.Title of Account
(a)
Ref.
Page No.
(b)
Current Year
End of Quarter/Year
Balance
(c)
Prior Year
End Balance
12t31
(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, 2OS)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 (208-211)253 0 0
8 lnstallments Received on Capital Stock (2'12)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 Earnings (215, 21 5.1, 216)118-119 1,354,681,706 1,234,859,727
12 Unappropriated Undistributed Subsidiary Eamings (216.1)1 '1 8-1 19 54,563,677 69,74S,884
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(al(b)-22,843,785 -26,872,209
16 Total Proprietary Capital (lines 2 through 15)2,1 94,439,1 38 2,085,774,942
17 LONG-TERM DEBT
18 Bonds (22'l)256-257 1,835,460,000 1,745,460,000
't9 (Less) Reaquired Bonds (222)256-257 0 0
20 Advances from Associated Companies (223)256-257 0 0
21 Other Long-Term Debt (224)256-257 19,885,000 19,885,000
22 Unamortized Premium on Long-Term Debt (225)0 0
23 (Less) Unamortized Discount on Long-Term DebtDebit (226)4,598,059 4,124,868
24 Total Long-Term Debt (lines '18 through 23)1,850,746,941 1,761,220,132
25 OTHER NONCURRENT LIABI LITIES
Obligations Under Capital Leases - Noncunent (227)0 0
Accumulated Provision for Property lnsurance (228.1)0 0
28 Accumulated Provision for lnjuries and Damages (228.2)1 ,81 1,302 '1,468,935
29 Accumulated Provision for Pensions and Benefits (228.3)431 ,492,131 438,886,02s
30 Accumulated Miscellaneous Operating Provisions (228.4)0 0
31 Accumulated Provision for Rate Refunds (229)136,s05,890 119,666,875
32 Long-Term Portion of Derivative lnstrument Liabilities 63,744 0
33 Long-Term Portion of Derivative lnstrument Liabilities - Hedges 0 0
34 Asset Retirement Obligations (230)26,791,608 26,415,381
35 Total Other Noncurrent Liabilities (lines 26 through 34)596,664,675 586,437,216
36 CURRENT AND ACCRUED LIABILITIES
37 Notes Payable (231)0 0
38 Accounts Payable (232)134,836,251 107,891 ,859
39 Notes Payable to Associated Companies (233)4,5s2,447 4,083,304
40 Accounts Payable to Associated Companies (234)2,088,345 57,561 ,953
41 Customer Deposits (235)1,342,50e 2,037,068
42 Taxes Accrued (236)262-263 1,306,621 -15,1 s6,342
43 lnterest Accrued (237)23,857,084 22,620,139
44 Dividends Declared (238)C 0
45 Matured Long-Term Debt (239)c 0
FERC FORM NO. 1 (rev. 12-03)Page 112
26
27
Name of Respondent
ldaho Power Company
This Report is:
(1) tr An Original
(2) n A Resubmission
Date of Report
(mo, da, yr)
04116t2019
Year/Period of Report
end of 20'tBtQ4
COMPARATIVE BALANCE SHEET (LlABlLlTlES AND OTHER CREDlTShtinueo)
Line
No Title of Account
(a)
Ref.
Page No.
(b)
Current Year
End of QuarterfYear
Balance
(c)
Prior Year
End Balance
12t31
(d)
46 Matured lnterest (240)0 0
47 Tax Collections Payable (241)2,224,148 2,751,894
48 Miscellaneous Current and Accrued Liabilities (242)56,428,043 50,874,603
49 Obligations Under Capital Leases-Current (243)0 0
50 Derivative Instrument Liabilities (244)974.268 1,224,571
51 (Less) Long-Term Portion of Derivative lnstrument Liabilities 63,744 0
52 Derivative lnstrument Liabilities - Hedges (245)0 0
53 (Less) Long-Term Portion of Derivative lnstrument Liabilities-Hedges U 0
54 Total Current and Accrued Liabilities (lines 37 through 53)227,545,969 233,889,049
55 DEFERRED CREDITS
56 Customer Advances for Construction (252)5,156,242 6,762,256
57 Accumulated Deferred lnvestment Tax Credits (255)266-267 92,789,836 87,384,738
58 Defened Gains from Disposition of Utility Plant (256)U 0
59 Other Defered Credits (253)26S 8,306,007 8,746,270
60 Other Regulatory Liabilities (254)278 351,782,980 307,404,206
61 Unamortized Gain on Reaquired Debt (257)0 0
62 Accum. Defened I ncome Taxes-Accel. Amort.(281 )272-277 0 0
63 Accum. Defened lncome Taxes-Other Progefty (282)908,615,099 890,330,923
64 Accum. Deferred lncome Taxes-Other (283)139,217,543 124,556,461
65 Total Deferred Credits (lines 56 through 64)1,505,867,707 1,425,184,854
66 TOTAL LIABILITIES AND STOCKHOLOER EQUITY (lines 16, 24,35,54 and 65)6,375,264,430 6,092,506,193
FERC FORM NO. 1 (rev. 12-O3l Page 113
ldaho Power Company )An Original
A Resubmission
Da,
(2)04t16t2019
Year/Period of Report
End of 2018/Q4
STATEMENT OF INCOME
Quarterly
1. Repod in column (c) the cunent year to date balance. Column (c) equals the total of adding the data in column (g) plus the data in column (i) plus the
data in column (k). Report in column (d) similar data for the previous year. This information is reported in the annual filing only.
2. Enter in column (e) the balance for the reporting quarter and in column (f) the balance for the same three month period for the prior year.
3. Report in column (g) the quaftr to date amounts for electric utility function; in column (i) the quarter to date amounts for gas utility, and in column (k)
the quarter to date amounts for other utility function for the current year quarter.
4. Report in column (h) the quarter to date amounts for electric utility function; in column (j) the quarter to date amounts for gas utility, and in column (l)
the quarter to date amounts for other utility function for the prior year quarter.
5. lf additional columns are needed, place them in a footnote.
Annual or Quarterly if applicable
5. Do not report fourth qua(er 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 lhru 26 as appropriate. lnclude these amounts in columns (c) and (d) totals.
7. Report amounts in account 414, Other Utllity Operating lncome, in the same manner as a@ounts 412 and 413 above.
Line
No.
Title of Account
(a)
(Ref.)
Page No.
(b)
Tolal
Cunent Year to
Date Balance for
Quarterffear
(c)
Total
Prior Y6ar to
Date Balance for
Quarterffear
(d)
Cunent 3 Months
Ended
Quarterly 0nly
No 4th Quarter
(e)
Prior 3 Months
Ended
Quarterly 0nly
No 4th Quarter
(0
1 UTILITY OPERATING INCOME
2 Operating Revenues (400)300-301 '1,361,957,4s0 1,340,860,404
3 0perating Expenses
4 Operation Expenses (401 )320-323 800,135,259 769,799,625
5 Maintenance Expenses (402)320-323 69,035,321 60,983,589
6 Depreciation Expense (403)336-337 156,332,587 153,S58,586
7 Depreciation Expense forAsset Retirement Costs (403.1)336-337 566,665 566,665
8 Amort. & Depl. of Utility Plant (404405)336-337 6,98'1,078 6,243,722
9 Amort. of Utility Plant Acq. Adj. (406)336-337 15,018 32,539
10 Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407)
11 Amort. of Conversion Expenses (407)
12 Regulatory Debih (407.3)6,802,055 1,289,770
13 (Less) Regulatory Credils (407.4)2,167,344 .788,738
14 Taxes Other Than lncome Taxes (408.1)262-263 u,792,143 34,089,536
't5 lncome Taxes - Fedenal (409.1)262-263 20,035,445 44,701,50'r
16 - Other (409.1)262-263 -2,242,797 I 0,557,960
17 Provision for Defened lncome Taxes (410.1)234,272-277 37,060,319 s4,908,265
18 (Less) Provision for Defened lncome Taxes-Cr. (41 1.1)234,272-277 44,43s,246 80,542,460
19 lnvestment Tax Credit Ad.l. - Net (41 1.4)266 5,405,098 7,424,853
20 (Less) Gains from Disp. of Utility Plant (41 1.6)
21 Losses from Disp. of Ulility Plant (411.7)
22 (Less) Gains from Disposition of Allowances (41 1 .8)154,940 1 30,740
23 Losses from Disposition of Allowances (41 1.9)
24 Accretion Expense (41 1,10)227,740 221s29
25 TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24)1,088,388,401 1,064,894,118
26 Net Util Oper lnc (Enler Tot line 2 less 25) Carry to Pg1 17 ,line27 273,569,049 275,966,286
FERC FORM NO.1/3-Q (REV. 02-04)Page 114
Name of Respondent
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5]An original
Q\ r--'lA Resubmissiontt
Date of Report
(Mo. Da, Yr)
04t1612019
Year/Period of Repo(
End of 2O18lQ4
STATEMENT OF INCOME FQR THE YEAR
9. Use page 122lor imporlant notes regarding the statement of income for any account thereof.
10. Give concise explanations concerning unsettled rate proceedings where a contingency exists such that refunds of a material amount may need to be
made to the utility's cuslomers or which may result in material refund to the utility with respect to power or gas purchases. State for each year effected
the gross revenues or costs to which the contingency relates and th6 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.
1 1 Give concise explanations concerning significant amounts of any refunds made or received during the year resulting from settlement of any rate
proceeding affecting revenues received or @sts incurred for power or gas purches, and a summary of the adjustments made to balance sheet, income,
and expense accounts.
12. ll any notes appearing in the report to stokholders are applicable to the Statement of lncome, such notes may be included alpage 122.
13. Enter on page 122 a concise explanation of only those changes in accounting methods made during the year which had an effect on net in@me,
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'slquarter's figures are different from that reported in prior reports.
15. lf the columns are insufficient for reporting additional utility departrnents, supply the appropriate account titles report the information in a footnote to
this schedule.
ELECTRIC UTILITY GAS UTILITY OTHER UTILITY
Line
No.
Current Year to Date
(in dollars)
(s)
Previous Year to Date
(in dollars)
(h)
Cunent Year to Date
(in dollars)
(i)
Previous Year to Date
(in dollars)
fi)
Current Year to Date
(in dollars)
(k)
Previous Year to Date
(in dollam)
o
1
1,361,957,450 1,340,860,404 2
3
800,1 35,2sS 769,799,625 4
69,035,321 60,983,589 5
156,332,587 153,958,586 6
566,665 566,665 7
6,981,078 6,243,722 B
15,018 32,539 I
10
11
6,802,055 1,289,770 12
2,167,344 -788,738 13
34,792,143 34,089,536 14
20,035,445 44,701 ,501 15
-2,242,797 10,557.960 16
37,060,319 54,908,265 17
44,435,246 80,542,460 18
5,405,098 7,424,893 19
20
21
1s4,940 130,740 22
ZJ
227,740 221,929 24
1,088,388,401 1,064,894,118 25
273,569,049 275,966,286 26
FERC FORM NO.1 (ED. 12-96)Page 115
ls:
Original
Date
(Mo,ldaho Power Company A Resubmission 04t16t2019
e
1
(2)
Year/Period of Report
End of 20181Q4
TOTALLine
No.
Title of Account
(a)
(Ref.)
Page No.
(b)
Cunent Year
(c)
Previous Year
(d)
Cunent 3 Monlhs
Ended
Quarterly 0nly
No 4th Quarter
(e)
Prior 3 Months
Ended
Quarterly 0nly
No 4th Quarter
0
27 Net Utility Operating lncome (Canied fonruard lrom page 114)273,569,049 275,966,286
28 Other lncome and Deductions
29 Other lncome
30 Nonutilty Operating lncome
31 Revenues From Merchandising, Jobbing and ContractWork (415)3,971,967 4,032,474
32 (Less) Costs and Exp. of Merchandising, Job. & Contract Work (416)4,003,151 4,'104,918
33 Revenues From Nonutility Operations (417)25,046 29,462
34 (Less) Expenses oi Nonulility Operations (417.1 )12,425 61,905
35 Nonoperating Rental lncome (418)-3,351 -7,437
36 Equity in Eamings of Subsidiary Companies (4'18,1)119 8,813,793 7,082,051
37 lnterestand Dividend lncome (419)8,923,003 6,043,906
3B Allowance for Other Funds Used During Construction (419.1)24352523 24,784,392
39 Miscellaneous Nonoperaling lncome (421)79,416 253,942
40 264,632Gain on Disposition of Property (421.1)450,000
41 TOTAL Other lncome (Enter Total of lines 31 thru 40)42,411,453 34,500,96i
4Z Olher lncome Deductions
43 Loss on Disposition of Property (421.2)48,950
44 Miscellaneous Amortization (425)
45 Donations (426.1)811,136 881,377
46 Life lnsurance (426.2)-2]79 387 -2,089,82s
47 Penalties (426.3)40,155 14,381
48 Exp. for Cetuin Civic, Political & Related Activities (426.4)1,203,610 1,U2]03
49 Other Deductions (426.5)7,820,081 8,164,084
50 TOTAL Other lncome Deductions (Total of lines 43 lhru 49)7,144,545 8,412,720
51 Taxes Applic. to Other lncome and Deductions
262-26352Taxes Other Than lncome Taxes (408,2)'19,680 20,222
53 lncome Taxes-Federal (409.2)262-263 627,071 20,849
54 lncome Taxes-Other (409,2)262-263 193,942 3,721
<E Provision for Deferred lnc. Taxes (4'10.2)234,272-277 261,601 13,168,748
234,272-277 770,831 1,248,72256(Less) Provision for Defened lncome Taxes-Cr. (411,2)
57 lnvestrnent Tax Credit Adj.-Net (4 1 1 .5)
58 (Less) lnvestment Tax Credils (420)
EO 331,463 1 1,964,818TOTAL Taxes on Other lncome and Deductions (Total of lines 52-58)
60 Net Other lncome and Deductions (Total of lines 41, 50, 59)34,935,445 14,123,429
61 lnteresl Charges
62 lnterest on Long-Term Debt (427)84,407,634 81,1 98,430
63 1,606,787 1,508,990Amort. of Debt Disc. and Expense (428)
64 Amortization of Loss on Reaquired Debt (428.1)2,152,952 2,152,952
65 (Less)Amort. of Premium on Oebt-Credit (429)
66 (Less) Amodzation of Gain on Reaquired DeblCredit (429.1)
67 lnterest on Debl to Assoc. Companies (430)279,757 81,933
7,874,38668Other lnterest Expense {431 )7,494,378
69 (Less) Allowance lor Bonowed Funds Used During Construction-Cr. (432)10,'151,313 8,694,285
70 Net lnterest Charges {Total of lines 62 thru 69)86,1 70,203 83,742,398
71 lncome Before Exlraordinary ltems (Total of lines 27, 60 and 70)222,334,291 206,347,317
72 Extraordinary ltems
73 Exhaordinary lncome (434)
74 (Less) Extraordinary Deductions (435)
75 Net Extraordinary ltems (Total of line 73 less line 74)
76 262-263lncome Taxes-Federal and Other (409.3)
77 Extraordinary ltems After Taxes (line 75 less line 76)
78 Net lncome (Total of line 71 and 77)222,334,291 206,347,317
I
FERC NO. 1/3-Q (REV. 02-04)Page 117
Name of Respondent
ldaho Power Company
This ReDort ls:(1) 5]Rn orislnat(2) EA Resubmission
Date of Report(Mo, Da, Yr)
04t1612019
Year/Period of Report
2018tQ4End of
STATEMENT OF RETAINED EARNINGS
1. Do not report Lines 49-53 on the quarterly version.
2. Report all changes in appropriated retained eamings, unappropriated retained eamings, year to date, and unappropriated
undistributed subsidiary eamings for the year.
3. Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436
- 439 inclusive). Show the contra primary account affected in column (b)
4. State the purpose and amount of each reservation or appropriation of retained earnings.
5. List first account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow
by credit, then debit items in that order.
6. Show dividends for each class and series of capital stock.
7. Show separately the State and Federal income tax effect of items shown in account 439, Adjustments to Retained Eamings.
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)
Current
QuarterlYear
Year to Date
Balance
(c)
Previous
Quarterffear
Year to Date
Balance
(d)
UNAPPROPRIATED RETAINED EARNINGS (Account 2'tG)
1 Balance-Beginning of Period 1,22',t,586.621 '1,123,606,367
2 Changes
2 Acljustments to Retained Eamings (Account 439)
4 Benefit Plan Tax Reform Adjustment 4,092,208
E
6
7
I
I TOTAL Credits to Retained Earnings (Acct. 439)I
10
11
12
13
14
15 TOTAL Debits to Retained Earnings (Acct. 439)
16 Balance Transferred ftom lncome (Account 433 less Account 418.1)213,520,498 199,202,985
17 Appopriations of Retained Eamings (Acct. 436)
18
19
20
21
22 TOTAL Appropriations of Retained Earnings (Acct. 436)
23 Dividends Declared-Preferred Stock (Account 437)
24
25
26
27
28
29 TOTAL Dividends Declared-Preferred Stock (Acct. 437)
30 Dividends Declared-Common Stock (Account 438)
31 -121,790,727 ( 113,285,012)
32
33
34
35
36 TOTAL Dividends Declared-Common Stock (Acct. 438)-121,790,727 { 113,285,012]}
37 Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Eamings 24,000,000 12,062,281
3B Balance - End of Period (Total 1,9,'15,16,22,29,36,37)1,34't ,408,600 1,221,586,621
APPROPRIATED RETAINED EARNINGS (Account 215)
FERC FORM NO. 1l3-Q (REV. 02.04)Page rlE
Name of Respondont
ldaho Power Company
This Reoort ls:(1) fiAn Originat(2) l-l A Resubmission
Date of Report(Mo. Da, Yr)
04t16t2019
Year/Period of Report
End of 201AQ4
STATEMENT OF RETAINED EARNINGS
1. Do not report Lines 49-53 on the qua(erly version.
2. Report all changes in appropriated retained earnings, 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 approprialion of retained earnings.
5. List first account 439, Adjustments to Retained Eamings, reflecting adjustments to the opening balance of retained eamings. Follow
by credit, then debit items in that order.
6. Show dividends for each class and series of capital stock.
7. Show separately the State and Federal income tax effect of items shown in account 439, Adjustments to Retained Earnings.
8. Explain in a footnote the basis for determining the amount reserved or appropriated. lf such reservation or appropriation is to be
recurrent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated.
9. lf any notes appearing in the report to stockholders are applicable to this statement, include them on pages 122-123.
Line
No.
Item
(a)
Contra Primary
Account Affected
(b)
Current
QuarterlYear
Year to Date
Balance
(c)
Previous
QuarterlYear
Year to Date
Balance
(d)
39
40
41
42
43
44
45 TOTAL Appropriated Retained Earnings (Account 215)
APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Account 215.'l)
46 TOTAL Approp. Retained Eamings-Amort. Reserve, Federal (Acct. 215.1)13,273,106 13,273,106
47 TOTAL Approp. Retiained Eamings (Acct. 215, 215.1) (Total 45,46)13,273,106 13,273j06
48 TOTAL Retained Earnings (Acct. 215, 215.1 ,216) (Total 38, 47) (216.1)1,354,681,706 1,2U,859,727
UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account
Report only on an Annual Basis, no Quarterly
49 Balance-Beginning of Year (Debit or Credit)69,749,884 74,667,833
50 Equity in Earnings for Year (Credit) (Account 418.1)8,813,793 7,082,051
51 (Less) Dividends Received (Debit)24,000,000 '12,000,000
52
53 Balance-End of Year (Total lines 49 thru 52)54,563,677 69,749,884
*r
FERC FORM NO. 1/3.Q (REV. 02-04)Page 119
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
04t16t2019
Year/Period of Report
2018tQ4
FOOTNOTE DATA
Schedule Page:118 Line No.:9 Column: c
In November 2018, the FERC issued a fi-na1 accounting order
entities, including Idaho Power, to make a policy election
stranded tax effeets resulting from income tax reform from
in accordance wlth ASU 2018-02, Incone Statement*Reporting
(Topic 220). In 2018, Idaho Power transferred $4.1 million
earnings.
allowing certain
to recl-assify the
AOCf to retained earnings
Comprehensive Income
from AOCI to retained
FERC FORM NO. 1 (ED. 12-871 Page 450.1
Name of Respondent
ldaho Power Company
This Reoort ls:(1) []An Orislnat
12) nA Resubmission
Date of Report(Mo, Da, Yr)
04t16t2019
Year/Period of Report
End of 20181Q4
STATEMENT OF CASH FLOWS
(1 ) Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (o) lnclude commercial paper; and (d) ldentify separately such items as
investments, fixed assets, intangibles, etc.
Equivalents at End of Period" with related amounts on th€ Balance Sheet.
in those activities. Show in lhe Notes to the Financials the amounts o{ interest paid (net of amount cap;talized) and income taxes paid.
dollar amount of leases caprtalized with the plant cost.
Line
No.
Description (See lnstruction No. 1 for Explanation of Codes)
(a)
Current Year to Date
Quarterf/ear
(b)
Previous Year to Date
Quarter/Year
(c)
1 Net Cash Flow from Operating Activities:
2 Net lncome (Line 78(c) on page 1 17)222,334,291 206,347,3',17
a Noncash Charges (Credits) to lncome:
4 Depreciation and Depletion 156,332,587 153,958,586
E Amortization of 4 1 1,378,099
b
7
Deferred lncome Taxes (Net)-1,689,885 14,370,999
I lnvestment Tax Credit Adjustment (Net)1,456,7s7 -20,660,275
'10 Net (lncrease) Decrease in Receivables 633,606 -2,496,038
11 Net (lncrease) Decrease in lnventory 9,463,201 -809,418
12 Net (lncrease) Decrease in Allowances lnventory
13 Net lncrease (Decrease) in Payables and Accrued Expenses 36,135,459
14 Net (lncrease) Decrease in Other Regulatory Assets 30,090,539 39,149,025
15 Net lncrease (Decrease) in Other Regulatory Liabilities 18,301 ,367 17,982,095
16 (Less) Allowance for Other Funds Used During Construction 24,352,523 20,784,392
17 (Less) Undistributed Earnings from Subsidiary Companies -15,186,207 -4,917,949
18 Other (provide details in footnote):-12,7U,285 -22,985,607
19
20
21
22 Net Cash Provided by (Used in) Operating Activities (Total 2 thru 21)418,006,106 416,503,799
23
24 Cash Flows from Investrnent Activities:
25 Construction and Acquisition of Plant (including land)
26 Gross Additions to Utility Plant (less nuclear fuel)-302,'r75,811 -306,254,955
27 Gross Additions to Nuclear Fuel
28 Gross Additions to Common Utility Plant
29 Gross Addltions to Nonutility Plant
30 (Less) Allowance for Other Funds Used During Construction -24,352,523 -20,784,392
31 Other (provide details in footnote)25,112,774 8,397,326
32
33
34 Cash Outflows for Plant (Total of lines 26 thru 33)-252,710,514 -277.073,237
35
36 Acquisition of Other Noncurrent Assets (d)
37 Proceeds from Disposal of Noncurrent Assets (d)
3B
39 lnvestments in and Advances to Assoc. and Subsidiary Companies -1,655 3,362
40 Contributions and Advances from Assoc. and Subsidiary Companies 469,1 43 3,838,869
41 Disposition of Investments in (and Advances to)
42 Associated and Subsidiary Companies
43
44 Purchase of Investment Securities (a)-11,390,307 -1 1,356,339
45 Proceeds ftom Sales of lnvestment Securities (a)5,007,519 4,989,363
FERC FORM NO.1 (ED. 12-96)Page 120
-s,272,216
Name of Respondent
ldaho Power Company
ls:
(1)
(2)
An Original
A Resubmission
Date of Report
(Mo, Da, Yr)
04t16t2019
Year/Period of Report
End of 20181Q4
STATEMENT OF CASH FLOWS
(1) Codes to be used:(a) Net Proceeds or Payments(b)Bonds, debentures and other long-term debt: (c) lnclude commercial papor; and (d) ldantify separately such items as
investments, fix€d ass€ts, intangiblos, etc.
Equivalents at End of Period'with related amounts on the Balance Sheet.
in those activities. Show in lhe Notes to tho Financials the amounts of interest paid (net of amount capitalized) and income taxes paid.
the Financial Statements. Do not include on this statement tho dollar amount of leases capitalized per the USofA General lnstrction 20; instead provide a reconciliation of the
dollar amount of leases capilalized with the plant cost.
Line
No.
Description (See lnstruction No. 1 for Explanation of Codes)
(a)
Current Year to Date
Quarterl/ear
(b)
Previous Year to Date
QuarterfYear
(c)
46 Loans Made or Purchased
47 Collections on Loans
48
49 Net (lncrease) Decrease in Receivables
50 Net (tncreaso ) Deoease in lnventory
51 Net (lncrease) Decrease in Allowances Held for Speculation
ct Net lncrease (Decrease) in Payables and Accrued Expenses
53 Other (provide details in footnote):755,N 6 -1 1,959
54
55
56 Net Cash Provided by (Used in) lnvesting Activities
57 Total of lines 34 thru 55)-257,830,358 -279,609,941
58
59 Cash Flows ftom Financing Activities:
60 Proceeds from lssuance of:
61 Long-Term Debt (b)220,000,000
62 Preferred Stock
63 Common Stock
64 Other (provide details in footnote):
65
66 Net lncrease in Short-Term Debt (c)
67 Other (provide details in footnote):
68
69
70 Cash Provided by Outside Sources (Total 61 thru 69)220,000,000
71
72 Payments for Retirement of:
73 LongFterm Debt (b)-130,000,000 -1,063,634
74 Preferred Stock
75 Common Stock
76 Other (provide details in footnote):-240,000
77
78 Net Decrease in Short-Term Debt (c)-21,800,000
79
80 Dividends on Preferred Stock
81 Dividends on Common Stock -121,790,727 -113,285,012
82 Net Cash Provided by (Used in) Financing Activities
83 (Total of lines 70 thru 81)-39,361 ,268 -136,388,646
84
85 Net lncrease (Decrease) in Cash and Cash Equivalents
86 (Total of lines 22,57 and 83)120,814,480 505,212
87
88 Cash and Cash Equivalents at Beginning of Period 44,645,647 44,140,435
8S
90 Cash and Cash Equivalents at End of period 165,460,127 44,645,647
FERC FORM NO.1 (ED.12-96)Page 121
-7,570,54',l,
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
04t16t2019
Year/Period of Report
20181o,4
FOOTNOTE DATA
Schedule Page:
Amortization
120 Line No.: 5 Column: b
Plant
Unamortized debt expense
Unamr:rtized discount
Water rights
Other
6,996,096
3,785.635
297.955
1.042.009
63 768
12,186.464
Schedule Page: 120 Line No; 13 Column: b
Cash (received) paid during the period for:
lncome taxes
lnterest (net of anrount capitalized)
Schedule Page: 120 Line No.: 18 Column: b
Cash Flow from Operating Activities (Other!
58,703.841
80.893.762
Pension and postretirement benefit plan expense
Contributions to pension and postretirement benefit plans
Unbilled revenues
Accrued payroll
Prepayments
Deposits fiom third parties
Other
32,239.953
[45,883,362]
6,157.496,
2.1 37.367
{2.e13.828}
(2,300.576i
(2,141.339)
(12.704.28e)
Schedulg Pqge: 120 Line No.: 26 Column: b
ilon-cash investing activities:
Addltions to PP&E in accounts payable
Schedute Page: 120 Line No.:31 Column: b
0ther Cash Florrs from Plant
29.526.490
Payments received fiom joint funding partners
Sale of renewable energy certificates and emission allowances
Sale of utility property
21.585,687
3.052.681
473.406
25,L72,77 4
Scfiedule Page: 120 Line No.: 53 Column: b
Other lnvesting Cash Flor,ris
Life lnsurance Proceeds- net of prenriums 795..{56
70f 456
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Schedule Page: 120 Line No.:76 Column: b
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) _A Resubmission
Date of Report
(Mo, Da, Yr)
04t1612019
Year/Period of Report
20181Q4
FOOTNOTE DATA
Other Financing Cash Florrs
Make-whole prernium on retirement of longternr debt
Debt issuance costs
Discount on debt issuance
(4,606,943)
(2,14e.5eB)
00
FERC FORM NO.1 (ED. 12-871 Page 450.2
Name of Respondent
ldaho Power Company
This Reoort ls:(1) E]An Original(2) l-lA Resubmission
Date of Report(Mo, Da, Yr)
04t16t2019
Year/Period of Report
End of 2O18lQ4
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
1. Report in columns (b),(c),(d) and (e) the amounts of accumulated other comprehensive income items, on a net-of-tax basis, where appropriate.
2. Report in columns (f) and (g) the amounts of other categories of other cash flow hedges.
3. For each category of hedges that have been accounted for as "fair value hedges", report the accounts affected and the related amounts in a footnote.
4. Report data on a year-to-date basis.
Line
No.
Item Unrealized Gains and
Losses on Available-
for-Sale Securities
(b)
Minimum Pension
Liability adjustment
(net amount)
(c)
Foreign Currency
Hedges
(d)
Other
Acljustments
(e)
1 Balance of Account 219 at Beginning of
Preceding Year ( 20,881,620)
2 Preceding QtrA/r to Date Reclassifications
from Acct 219 to Net lncome '1,882,086
3 Preceding QuarterfYear to Date Changes in
Fair Value ( 7,872,675',)
4 Total (lines 2 and 3)( 5,990,589)
5 Balance of Account 21 9 at End of
Preceding QuarterfYear ( 26,872,2091
6 Balance of Accounl 21 9 at Beginning of
Current Year ( 26,872,209)
7 Current Qtrf/r to Date Reclassifications
from Acct 219 to Net lncome 2,88s,872
8 Current Quarter^fear to Date Changes in
Fair Value 1.142552
I Total (lines 7 and 8)4,028,424
10 Balance of Acmunt 219 at End of Current
QuarterA'ear ( 22,843,785)
FERC FORM NO.1 (NEW06-02)Page 122a
(a)
Name of Respondent
ldaho Power Company
This Reoort ls:(1) E]An orisinal(2\ n A Resubmission
Date of Report(Mo, Da, Yr)
0411612019
Year/Period of Report
End of 20181Q4
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
Line
No.
Other Cash Flow
Hedges
lnterest Rate Swaps
(0
Other Cash Flow
Hedges
flnsert Footnote at Line 1
to specifyl
(s)
Totals for each
category of items
recorded in
Acmunt 219
(h)
Net lncome (Canied
Forward from
Page 1 17, Line 78)
(i)
Total
Comprehensive
lncome
(i)
1 ( 20,881,620)
2 1.882,086
3 ( 7,872,675)
4 ( 5,es0,58e)206,347,317 200,3s6,728
5 ( 26,872,209)
6 ( 26,872,209)
7 2,885,872
8 't,142,552
I 4,O28,424 222,334,291 226,362,715
10 ( 22,843,785)
FERC FORM NO. 1 (NEW 06.02)Page'122b
Name of Respondent
ldaho Power Company
This Report ls:
(1)
(2)ED
An Original
A Resubmission
Date of Report
o4t1612019
Year/Period of Report
End of 2O18lQ4
NOTES TO FINANCIAL STATEMENTS
1. Use the space below for important notes regarding the Balance Sheet, Statement of lncome for the year, Statement of Retained
Earnings for the year, and Statement of Cash Flows, or any account thereof, Classiff the notes according to each basic statement,
providing a subheading for each statement except where a note is applicable to more than one statement.
2. Fumish 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 anears
on cumulative prefened stock.
3. For Account 116, Utility Plant Adjustments, explain the origin of such amount, debits and credits during the year, and plan of
disposition contemplated, giving references to Cormmission orders or other authorizations respecting classification of amounts as plant
adjustments and requirements as to disposition thereof.
4. Where Accounts 189, Unamortized Loss on Reacquired Debt, and 257 , Unamortized Gain on Reacquired Debt, are not used, give
an explanation, providing the rete treatment given these items. See General lnstruction 17 of the Uniform System of Accounts.
5. Give a concise explanation of any retained earnings restrictions and state the amount of retained earnings affected by such
restrictions.
6. lf the notes to financial statements relating to the respondent company appearing in the annual report to the stockholders are
applicable and furnish the data required by instructions above and on pages 1 14-121 , 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. Forthe 3Q disclosures, the disclosures shall be provided where events subsequent to the end ofthe most recent year have occuned
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 npw borrowings or modifications of existing financing agreements; and
changes resulting from business combinations or dispositions. However were material contingencies exist, the disclosure of such
matters shall be provided even though a significant change since year end may not have occurred.
9. Finally, if the notes to the financial statements relating to the respondent appearing in the annual report to the stockholders are
applicable and furnish the data required by the above instructions, such notes may be included herein.
PAGE l22INTENTIONALLY LEFT BLANK
SEE PAGE 123 FOR REQUIRED INFORMATION
FERC FORM NO. 1 (ED.12-96)Page '|22
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
0411612019
Year/Period of Report
2018/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
IDAHO POWER COMPANY
NOTES TO CONSOLIDATED F'INANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICAI{T ACCOUNTING POLICIES
Idaho Power Company (Idaho Power) is the principal operating subsidiary of IDACORP, Ino. (IDACORP), a holding company formed
in I 998. Idaho Power is an electric utility engaged in the generation, transmission, distribution, sales, and purchase of electric 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 owned in part by Idaho Power.
Basis of Reporting
The financial statements include the assets, liabilities, revenues and expenses of ldaho 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 utilify 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) deferred income taxes, (5) income tax expense, (6) non-utility r€venues, (7) accrued taxes, and (8) debt issue costs.
Management Estimates
Management makes estimates and assumptions when preparing hnancial 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 of contingent assets and liabilities at the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period. These estimates involve judgments with respect to, among other things, future
economic faotors 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 Powels results ofoperations and financial condition.
Idaho Power's financial statements reflect the effects of the different ratemaking principles followed by the jurisdictions regulating
Idaho Power. The application of accounting principles related to regulated operations sometimes results in Idaho Power recording
expenses and revenues in a different period than when an unregulated enterprise would record such expenses and revenues. In these
instances, the amounts are deferred or accrued as regulatory assets or regulatory liabilities on the balance sheet. Regulatory assets
FERC FORM NO. 1 ED.1 123.1
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t1612019
Year/Period of Report
201UQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
represent incuned costs that have been deferred because it is probable they will be recovered from customers through fufire rates.
Regulatory liabilities represent obligations to make refunds to customers for previous collections, or represent amounts collected in
advance ofincurring an expense. The eflects 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 allowance is
reviewed periodically and adjusted based upon a combination ofhistorical write-offexperience, aging ofaccounts receivable, and an
analysis of specihc customer accounts. Adjustments are charged to income. Customer acoounts receivable balances that remain
outstanding after reasonable collection efforts are wrinen off.
Other receivables are also reviewed for impairment periodically, based upon transaction-specific facts. When it is probable ttrat 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, 2018 and201'l , Once a receivable is determined to be
impaired, any fruther interest income recogrized is fully reserved.
Derivative Financial Instruments
Financial instruments such as commodity futures, forwards, options, and swaps are used to manage exposure to commodify price risk
in the electricity and natural gas markets. All derivative instnrments are recognized as either assets or liabilities at fair value on the
balance sheet unless they are desig:rated as normal purchases and normal sales. With the exception of forward contracts for the
purchase of nafural gas for use at Idaho Power's natural gas generation facilities and a nominal number of power transactions, Idaho
Power's physical forward contracts are designated as normal purchases and normal saies. Because of Idaho Power's regulatory
accounting mechanisms, Idaho Power records the changes in fair value of derivative instruments related to power supply as regulatory
assets or liabilities.
Revenues
On January l, 2018, IDACORP and Idaho Power adopted Accounting Standards Update (ASU) 2014-09, Revenue from Contracts
with Customers (Topic 606).The adoption did not change the timing or amounts of revenue recognized by IDACORP or Idaho Power.
FERC FORM NO. 1 (ED.12-88)Page 123.2
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t16t2019
Year/Period of Report
2018/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
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 onginal 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
properly and replacements and renewals of items determined to be less than units of property. For utiliry properry replaced or renewed,
the original cost plus reuroval cost lsss salvage is charged to accumulated provision for depreciation, while the cost of related
replacements and renewals is added to properry, plant and equipment.
All utilify plant in service is depreciated using the straight-line method at rates approved by regulatory authorities. Annual depreciation
provisions as a percent of average depreciable utility plant in service approximated 2.8 percent in 2018 and 2.9 percent h2017 .
During the period of construction, costs expected to be included in the final value of the constructed asset, and depreciated once the
asset is complete and placed in service, are classified as construction work in progress on the consolidated balance sheets. If the project
becomes probable of being abandoned, such costs are expensed in the period such determination is made. Idaho Power may seek
recovery ofsuch costs in customer rates, although there can be no guarantee such recovery would be granted.
Long-lived assets are periodically reviewed for impairment when events or changes in circumstances indicate that the carrying amount
of an asset may not be recoverable. If the sum of the undiscounted expected future cash flows from an asset is less than the carrying
value of the asset, impairment is recogrized in the financial statements. There were no material impairments of long-lived assets in
2018 or 2017.
Allowance for Funds 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 of the related properfy through increased revenues resulting from a higher rate base and higher
depreciation expenss. The component of AFUDC attributable to borrowed funds is included as a reduction to total interest
expense. Idaho Power's weighted-average monthly AFUDC rate was 7.6 percent for 201 8 and 2017 .
Income Taxes
Idaho Power account for income taxes under the asset and liabilify method, which requires the recognition of deferred tax assets and
liabilities for the expected future tax consequences of events that have been included in the financial statements. Under this method
(commonly referred to as normalized accounting), deferred tax assets and liabilities are determined based on the differences between
the financial statements and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are
expected to reverse. In general, deferred income tax expense or benefit for a reporting period is recognized as the change in deferred
tax assets and liabilities from the beginning to the end ofthe period. The effect ofa change in tax rates on deferred tax assets and
FERC FORM NO. 1 ED.1 123.3
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
04!16t2019
Year/Period of Report
20181Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
liabilities is recognized in income in the period that includes the enactment date unless Idaho Power's primary regulator, the Idaho
Public Utilities Commission (IPUC), orders direct deferral of the effect of the change in tax rates over a longer period of time.
Consistent with orders and directives of the IPUC, unless contrary to applicable income tax guidance, Idaho Power does not record
deferred income taxes for certain income tax temporary differences and instead recogrizes the tax impact currently (commonly
referred to as flow-tfuough accounting) for rate making and financial reporting. Therefore, Idaho Power's effective income tax rate is
impacted as these differences arise and reverse. Regulated enterprises are required to recogrize 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.
IDACORP and Idaho Power use judgment, estimation, and historical data in developing the provision for income taxes and the
reporting oftax-related assets and liabilities, including development ofcurrent 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 income, cash flows, and tax-related assets and
liabilities.
In compliance with the federal income tax requirements for the use of accelerated tax depreciation, Idaho Power records deferred
income taxes related to if,s plant assets for the difference between income tax depreciation and book depreciation used for financial
statement purposes. Deferred income taxes are recorded for other tomporary differences unless accounted for using flow-through.
The state of Idaho allows a three percent investment tax credit on qualifoing plant addifions. Investment tax credits eamed on regulated
assets are deferred and amortized to income over the estimated service lives of the related properties. Credits earned on non-regulated
assets or investments are recognized in the year earned.
Income taxes are discussed in more detail in Note 2 - "Income Taxes."
Other Accounting Policies
Debt discount, expense, and premium are deferred and amortized over the terms of the respective debt issues. Losses on reacquired
debt and associated costs are amortized over the life ofthe associated replacement debt, as allowed under regulatory accounting.
Reclassifications
In these consolidated financial statements, certain amounts in prior periods' consolidated financial statements have been reclassified to
conform with current period presentation. On Idaho Power's December 31 ,2017 , consolidated balance sheet, the "Long-term
receivables" balance of $0.5 million which had previously been reported separately, was reclassified to "Deferred Debits."
New and Recently Adopted Accounting Pronouncements
Rece ntly Adopted Accounting Pronouncements
In May 2014, the Financial Accounting Standards Board (FASB) issued ASU 2014-09 , Revenue from Contracts with Customers
(Topic 606). ASU 2014-09 is intended to enable users of financial statements to betterunderstand and consistently analyze an entiry's
revenue across industries, transactions, and geographies. Under the ASU, recognition of revenue occurs when a customer obtains
FERC FORM NO. 1 (ED. 12-88)Page 123.4
Name of Respondent
ldaho Power Company
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
04116t2019
Year/Period of Report
20181Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
control of promised goods or services. In addition, the ASU requires disclosure of the nature, amount, timing, and unceriainty of
revenue and cash flows arising from contracts with customers. The FASB amended certain aspects of ASU 2014-A9 to clarifo the
implementation guidance, including clarilications related to principal versus agent considerations, licensing and identifuing
performance obligations, narrow scope improvements, and practical expedients. Idaho Power adopted ASU 2014-09 on January l,
2018, using the modified-retrospective approach as provided for in the standard. The adoption did not change the timing or amounts of
revenue currently recognized by the companies, so no cumulative-effect adjustment was required. The adoption did change
presentation of revenues on the consolidated statements of income and also added disclosures. To conform with current period
presentation, "Electric utility revenuos" and "Operating Revenues" on Idaho Power's consolidated statcments of income for the years
ended December 31, 2018 ar,Ld2017, which had previously been reported separately as "General business," "Off-system sales," and
"Other revenues," are no longer reported separately. See Note 4 - "Revenues" for additional information on the disaggregation of
revenue and additional disclosures.
In January 2016, the FASB issued ASU 2016-01 , Financial Instruments-Overall (Subnpic 825-10): Recognition and Measurement
of Financial Assets and Financiol Liabiliries, which revises the accounting related to the classification and measurement of
investments in equity securities and the presentation of certain fair value changes for financial liabilities measured at fair value. It also
amends certain disclosure requirements associated with the fair value of financial instruments. The new standard is effective for fiscal
years beginning after December 15,2017 , including interim periods. Idaho Power adopted ASU 201 6-0 I on January I , 2018. The
adoption did not have a material impact on the companies' financial statements as the companies previously elected the fair value
option and reported available-for-sale securities at fair value.
In August 2016, the FASB issued ASU 2016-15 , Statement of Cash Flows (Topic 230) Classification of Certain Cash Receipts and
Cash Paymenls, to reduce diversiry in practice in how certain cash receipts and cash payments are classified in the statement of cash
flows. The companies'classification of proceeds from the settlement of corporate-owned life insurance policies and related costs will
be classified as investing activities under the new guidance. The new guidance did not affect the companies'presentation ofdebt
prepa)ment and extinguishment costs, proceeds from the settlement of insurance claims (other than corporate-owned life insurance),
and distributions received from equity-method investments. Idaho Power adopted ASU 2016-15 on January l, 2018, using the
retrospective approach as provided for in the standard. To conform with current period presentation, the companies reclassified $3.0
million and $3.6 million of company-owned life insurance proceeds received, for the year ended December 31, 2017 and2016,
respectively, from "Change in accounts receivable" and $0.1 million and $0.1 million of prepaid insurance premiums paid, for the year
ended December 31,2017 and2016, respectively, from "Change in other assets" (net reclassification of $2.9 million and $3.5 rnillion,
respectively) within "Operating Activities" to "Other" within "Investing Activities" on the consolidated statement of cash flows,
In March 20L7 , the FASB issued ASU 201 7-07 , Compensation -- Retirement Benefits (Topic 7 I 5) : Improving the Presentation of Net
Periodic Pension Cost and Net Periodic Poslretirement Benefit Cosr, which requires employers to disaggregate the service cost
component from other components of net periodic beneht costs and to disclose the amounts of net periodic benefit costs that are
included in each income statement line item. The standard requires employers to present the service cost component in the same line
item as other compensation costs and to present the other components ofnet periodic beneht cost (which include interest costs,
expected retum on plan assets, amortization ofprior service cost or credits and actuarial gains and losses) separately and outside a
subtotal of operating income. In addition, only the service cost component is eligible for capitalization. Idaho Power capitalizes
amounts of pension or postretirement costs that are insigniticant to the consolidated financial statements. The amendments in ASU
201'7-07 are effective for interim and annual reporting periods beginning after December 15.2017. Entities must use (1) a retrospective
transition method to adopt the requirement for separate presentation in the income statement of service costs and otler components and
(2) a prospective transition method to adopt the requirement to limit the capitalization of benefit costs to the service cost component.
Idaho Power adopted ASU 20 I 7-07 on January 1 , 20 I 8, and accordingly, have retrospectively adjusted prior periods to reflect the
FERC FORM NO. 1 (ED. 12-88)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)
0411612019
Year/Period of Report
201BtQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
disaggregation ofservice cost from other components ofnet periodic benefit costs. The adoption did not have a material impact on the
company's financial statements nor did it affect net income for the year ended December 31, 2018. For the years ended December 31,
2017 and 2016, $3.0 million and $2.6 million, respectively, was reclassified from "Other operations and maintenance" to "Other
expense, net" to conform to current period presentation.
Recenl Accounting Pronouncements Not Yet Adopted
In August 2018, the FASB issued ASU 2018-l5,Intangibles-Goodwill and Other-Internal-Use Sofnuare (Subtopic 350-40):
Customer's Accountingfor Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract, to provide
guidance on implementation costs incurred in a cloud computing arrangement that is a service contract. ASU 2018-15 aligns the
accounting for such costs with the guidance on capitalizing costs associated with developing or obtaining intemal-use software. The
new standard is effective for interim and annual reporting periods beginning after December 15,2019, with early adoption permitted.
Idaho Power are evaluating the impact of ASU 2018-15 on their respective financial statements.
In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), intended to improve financial reporting about leasing
transactions. The ASU requires lessees to recognize a right-of-use asset and lease liability on the balance sheet for most leases. In
addition, the ASU revises the definition of a lease in regards to when an arrangement conveys ttre right to control the use of the
identified asset under the arrangement, which may result in changes to the classification of an arrangement as a lease. ASU 2016-02
was effective on January I , 2019 , and Idaho Power will record any effects of the adoption in the first quarter of 20 19. While Idaho
Power is finalizing the assessment of the financial impacts of the adoption, the adoption of ASU 2016-02 will not have a material
impact on their respective financial statemetrts.
Subsequent Events
Management has evaluated the impact of events occurring after December 31,2018, up to February 21,2019, the date that Idaho
Power Company's U.S. GAAP financial statements were issued and has updated such evaluation for disclosure purposcs through April
15,2019. These financial statements include all necessary adjustments and disclosures resulting from these evaluations.
FERC FORM NO. I {ED. 12-88)Page 123.6
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t16t2019
Year/Period of Report
20't8tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
2. INCOME TAXES
A reconciliation befween the statutory federal income tax rate and the effective tax rate is as follows (dollars in thousands);
Federalincome ttsn enpense Et 212 statutory rate
Dhange in tarer resulting lrom:
Equily earnings of subsidiary companies
AFUOD
Capitalized interest
lnuestmpnt lEtr credits
Bond redemption costs
Bemoval cost=
Capitalized ouerhead costs
I apitalired repair crrsts
State income taHes. net of federalbenefit
Eepre'=ietion
Excess defened income teH reuersal
9tock-baEed compensation
Bemeesurement ol delered taxes
lncome tex relurn adiuslments
Other, net
?n1P 7n1,1
50.074 $ 83.370
Total ineome ta* exppnse $ 18.'135 ;} 48.335
Effectiue tax rate 6.Bz 19.22
The items comprising income tax expense are as follows (dollars in thousands):
2018 ?t17
lncome ta$es cu.rently payable:
Federal
State
Total
lncome tanes delerred:
Federal
Total
lnueitment talr credit5:
Oeferred
Pestored
Total
Total income tarr e.tpenre $ 18.155 $ 48.535
$
{1.651 001
IT.24E r:101
328.00
{2.313 D0l
n.023 D0l
(3 471 001
t8.720.001
[1l.B5l nr]l
8.532.00
13 11n nn
(7,?83.001
(EB3.r-r0l
t5.620 00)
$.842.ff)t
3.257.00
t2.4?9.00)
t'1!.31A. D0l
1.513.00
t:r.081.00)
0.00
t6.?81'l.iJ0l
n1.200.00)
t3B.l0tl.0Lll
8.108.00
1e 9E1 nn
0.00
t1.483.001
2.623.00
t3.s75.00)
t4.158.00)
20.683 44"722rz.o4sl 1D.5EZ18.614 s5.284
t13.30st t8.41815.425 ts.Z5Bl
t7.884) t13.7141
8,334 10.508
t2.3z3t t3.081)5.405 7.4?5
FERC FORM NO. 1 (ED. 12-881 Page 123.7
Name of Respondent
ldaho Power Company
This Report is:
(1)X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
04116t2019
Year/Period of Report
2018tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
'fhe components of the net deferred tax liability are as follows (dollars in thousands):
2014 2,J17
Delerred tan assets:
Feguletory liabilities $ 98.042 $ 38,744
Oeferred oompensation 21.826 21.fr?5
Eeferred reuenue 35.13? 3'l.0BE
Tax ':redits 44.4fl8 4:1.995
Retirement benelits 31,867 34.433
Orher 5.12?
Total 300.402 297.778
Deferred ta$ liabalaties:
Property. plant errd equipment
Regulatory assets
Fised cost adlustmenr
Relirement benefits
llther
234,411
E'14.144
fl.S40
108.440
2E,855
306.002
584.329
8,016
103.407
21.05?
Total 1.054.850 1_1122.851
Het deferred tax liabilities .t 754.448 $ ?25.D7:J
IDACORP's tax allocation agreement provides that each member of its consolidated group compute its income taxes on a separate
company basis. Amounts payable or refimdable are settled through IDACORP and are reported as trxes accrued or income taxes
receivable, respectively, on the consolidated 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 201 8 and prior tax years. The Company recognizes interest
accrued related to unrecogtized tax benefits as interest expense and penalties as other expense.
ldaho Power is subject to examination by its major tax jurisdictions - U.S, federal and the State of Idaho. The open tax years for
examination are 2018 for federal and 2014-2018 for ldaho. In May 2009, IDACORP formally entered the U.S. Internal Revenue
Service (IRS) Compliance Assurance Process (CAP) program for its 2A09 tax year and has remained in the CAP program for all
subsequent years. The CAP program provides for IRS examination and issue resolufion throughout the current year with the objective
of return filings containing no contested items. In 2018, the IRS completed its examination of IDACORP's 201'? tax year with no
unresolved income tax issucs.
Income Tax Reform
In December 2017 , the Tax Cuts and Jobs Act was signed into law, which significantly reforms the Internal Revenue Code of 1986, as
amended. Effective January l, 2018, the Tax Cuts and Jobs Act pemanently lowers the corporate tax rate to 2l percent from the
existing maximum rate of 35 percent, provides for expanded bonus depreciation, limits the deductibility of interest expense, eliminates
the alternative minimum tax, repeals the manufacturing deduction, and imposes additional limitations on the deductibility of executive
compensation. Public utility companies, such as Idaho Power, retain the deductibility of interest expense and are excluded from the
bonus depreciation provisions; however, traditional accelerated tax depreciation methods are still available.
Due to the enactment of the Tax Cuts and Jobs Act and foilowing generally accepted accounting principles, at December 31,2017,
FERC FORM NO.1 12-88 123.8
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2)_ A Resubmission
Date of Report
(Mo, Da, Yr)
0411612019
Year/Period of Report
2A18!Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Idaho Power remeasured all deferred income tax assets and liabilities. The effects of these adjustments resulted in a net tax expense for
201'7 , as shown in the rate reconciliation table above. Also, as shown above, in 2018, a net tax benefit was recognized for the
remeasurement of deferred taxes for the adjustment of temporary differences as a result of IDACORP's 201 7 consolidated income tax
retum filings.
Additionally, in2017, the net deferred tax liabilities decreased by approximately $672 million. Idaho Power's regulatory asset deferred
income tax liability item decreased as the related regulatory asset was reduced in lwo primary ways: (l) the decrease in the fbderal
income tax rate decreased the future cost to customers for funding the net deferred income tax liabilities resulting &om the cumulative
impacts of using the flow-through income tax accounting method fbr regulatory purposes and (2) the decrease in the federal income tax
rate also reduced the net-to-gross multiplier that increases the regulatory asset to a revenue requirement carrying value. The change in
income tax law also reduced the deferred income tax liability for depreciation-related timing differences under the normalized tax
accounting method. As this reduction will flow back to customers in the future under the statutorily prescribed average rate assumption
method, it was recorded as a regulatory liabiliry on the consolidated balance sheets of the companies.
On March ).2,z\l\,Idaho House Bill 463 was enacted which lowered the Idaho state corporate incorne tax rate from7 .4 percent to
6.925 percent effective January 1, 2018. The Idaho tax rate reduction did not have a material impact on Idaho Power's 2018 income tax
expense or detbrred tax asset and liability balances.
Policy Statement PLf9-2-000 Disclosures
Idaho Power's accumulated deferred income tax (ADIT) accounts (190,282,283) and income tax-related regulatory asset and liability
accounts (182.3 and 254) were adjusted for the impacts from the income tax reform described above. ADIT accounts were remeasured
by first recalculating de ferred income tax balances by appllng the new 2 l7o statutory corporate tax rate to existing temporary
differences. The remeasured balances were then compared to the deferred income tax balances on Idaho Power's books prior to
income tax reform. The difference in the balances resulted in excess ADIT (254 account), no deficient ADIT, and a reduction to Idaho
Power's regulatory asset ( I 82.3 account) for flow-through income tax accounting differences and regulatory liability for investment tax
credits (254 account).
The excess ADIT balance as of December 31,2017 was $194.0 million. A.2017 tax return adjustment of $3.4 million was recorded in
the current year which increased the balance of excess ADIT to $197.4 million. All of Idaho Power's excess ADIT is protected.
Unprotected temporary differences were either subject to Idaho Power's flow-through regulatory income tax accounting method or the
remeasured amounts were immaterial. The remeasurement of unprotected items resulted in a $2.6 million net income tax expense in
2017 and a $5.6 million net income tax benefit in 2018 for items adjusted due to the filing of 2017 income tax returns.
Idaho Power's protected excess ADIT will be retumed through rates as the underlying temporary differences reverse using the
statutorily prescribed Average Rate Assumption Method (ARAM). For the year ended December 3 I , 201 8, a $7.3 million tax benefit
was recorded in account 4t l.l for the reversal of excess ADIT. The excess ADIT will be included in rates for both rate base (254
account balance) and cost of service (arurual amortization pursuant to ARAM) when fufure general rate cases are filed for state
regulatory jurisdictions and beginning with Idaho Power's 2019 formula rate filing for FERC purposes.
3. REG['LATORY MATTERS
FERC FORM NO. I (ED. 12-88)Page 123.9
Idaho Power's financial statements reflect the effects of the different ratemaking pnnciples followed by the jurisdictions regulating
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
04t1612019
Year/Period of Report
20181Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
ldaho Power. Included below is a summary of Idaho Powels regulatory assets and liabilities, as well as a discussion of notable
regulatory matters.
Regulatory Assets and Liabilities
The application of accounting principles related to regulated operations sometimes results in Idaho Power recording some expense$
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):
FERC FORM NO. 1 (ED. 12-88)Pase'123.10
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
04t16t2019
Year/Period of Report
2018tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
As of Dcccmbcr 31, 2018
Dcscriptioa
*'"-#T:" Earainsr ,"Iil, . rotel rs orDc*mbcr 31,
pcriod Returt tr) Rcruri lolg ZOLT
Reguhtolv .{ssctg:
locooc tsrc3 e)
Uafuoded postrctircrueot 6-.66 {l)
Persioa cxpco3r dcfarals
Eoergl'efficieacy progran colt (4)
Po*cr supply costr (5)
Fixcd coct adjustmeot (5)
YgtrJBtPlEnt $ttl€ocnE (,
-A.ss.t rctrcagtrt obhgarioos (O
Loog-tcrm scn'ice agrecaeot
Other
Totel
Re guhtor.t Liebilitics :
Iacoue taxes 0
Dcprcciatron-related cxccsr dcfercd iacooe
taxcs o
Eaergy cfEcicocy Fogrerr co3s ({)
Pos'er ruppl-v costs {t)
Scttlcacat agrecocat rhadq 66ghrnim {5)
I![ark-to -aarkct asscts (9)
Other
3 -S 614,114t 614.1,143 584,329
278,67.1 279,674 280.166
t26,8ll 2t,025 t47,836 t27,72t
1,398 t,399 6,213
3'137
34,502 8,001 ,12,503 30,S56
1?,5t2 ?7.5t2 U,633
I l,5tJ I 1.65J I 5.76?
t6,095 10,6J3 26,148 21,90'l
770 6,98{ 7,104 11,3073 257,038 i e57,r36 u3llgl 3 r,132,0e6
5 98,0.12 I 98,012 $ 9S,7,14
190"062 190,062 193,991
5,259 5.259 408
3i,815 6,507 12,322 5,d.13
5,025 5,025
3,700 3,100 22
. , 6,314 8,796
=ig*gg-
!--llug. $ 353'r4i. I--10u91-
2019-20:0
2019-2028
20t9-2043
2019-2055
t
20 l 9-2020
20 I 9-2020
Total
(l) Errarqrrrtr.nairludarcithrirtarelorerGlurloq$.sn'arltad:ircourgourdofrlrbrs.dtLrllor$dntrofrctLEE
(1) R.?EatEt lhw-&ragh racoo: ux *counnreg diFrrl*cr n'hrcf, Llr : cmrryooding drllrrcd bx li:brlit5' dirlorcl il liotc I - "kec,ror T:xre.'
(3) Rrgmr@! t[. u!fisdcd oblUno of ldebo Poru'r p:Bron rod ponrcruarrt bror6t das, n'trctr ro dircil$cd ra Nar I I - 'Bdtt PlIIrs.'
(r) TLr rar6' cfrcicl' r!!t{ ,rF...atr tbr OrEoo lurildiction belacr rlld thr lubrlit-t rcpcoarr er ld:[o ju'isecion brLrxr.
(J) TLir itro ir dinlrd in ron drarl s tiir Notr 3 - 'Rqulror)'Illtar."
(6) rLrrt retrratl obl;lrda6 ya dircrtld ra \ote 13 . ",\sra Rrtnrra Obligetou. '
(D Rrfcacro the tu grou-rry nhtcd to 6a depccirtlo-r:htrd sar dcfcrd imoan trxs rad iglesaat o:< scdis irc.lud.d iB tLir abh aJ }l :
conopoadug &fznd tan ure &rdord aliotr I - 'Incorar Tru."
(8) Thr Tu. Crr ad ]obr Ac,t, coxtrd oo Dccrabs 22, 201 r, rcdrxd &e de&rred urnom trcr r.*tl ad Iubilitic!. Fc drgrcrrticra-r:had tiDrna
drifi:reacrs uds tk aoruuliad tex rcflrtrtry n tlod, tl;. raductm ndl0ow b-l to cutmc radrr th. rrrutonb' p(unb.d rrga;. r.t
r$u!1Pt6lr Erthod.
(9) t\'Ld(-teorybt usro od liebrliticr rc dircuucd rn Note 16 - Tu \rlue lr{ersuranou.'
Idaho Power's regulatory assets and liabilities are typically amortized over tle 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 sffanded investments. If not allowed full recovery
FERC FORM NO. I (ED. 12-881 Page 123.11
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
a4n612019
Year/Period of Report
2018/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
of these items, Idaho Power would be required to write off the applicable portion, which could have a materially adverse financial
impact.
Power Cost Adjustment Mechanisms and Deferred Power Supply Costs
In both its Idaho and Oregon jurisdictions, Idaho Power's power cost adjustment mechanisms address the volatility of power supply
costs and provide for annual adjustments to the rates charged lo its retail customers. The power cost adjushnent mechanisrns compare
Idaho Power's actual net power supply costs (prirnarily fuel and purchased power less wholesale energy sales) against net power supply
oosts being recovered in Idaho Power's retail rates. Under the power cost adjustment mechanisms, certain differences between actual
net power supply costs incurred 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 deferral period or ldaho-jurisdiction power cost adjustment (PCA) year mns from April 1 through March
31 . Amounts deferred during the PCA year are primarily recovered or refunded during the subsequent June I through May 31 period.
Idaho furisdiction Power Cost Adjustment Mechsnisra.' ln the Idaho jurisdiction, the annual PCA adjustment consists of (a) a
forecast component, based on a forecast of net power supply costs in the coming year as compared with net power supply costs
included in base rates; and (b) a true-up component, based on the difference between the previous year's actual net power supply costs
and the previous year's forecast. The latter component also includes a balancing mechanism so that, over time, the actual collection or
refund of authorized true-up dollars matches the amounts authorized. The PCA mechanism also includes:
a cost or benefit sharing ratio that allocates the deviations in net power supply expenses between customers (95 percent) and
shareholders (5 percent), with the exceptions of expenses associated with PLIRPA power purchases and demand response
incentive payments, which are allocated 100 percent to customers; and
a sales-based adjustment intended to €nsure that power supply expense recovery resulting solely from sales changes does not
distort the results of the mechanism.
The table below summarizes the three most recent PCA rate adjustments, all of which also include non-PCA-related rate adjustments
as ordered by the IPUC:
Effccth'e S CfugcDetc (rnillioas) Notcs
Jucc t,2018 I (30.1) Thc 330.4 oitliou total dccrcase io PCA ratcs iacludcs a 37.8 oiUioo oae-time bcocfit for
igcoac trx b.q.Ets accrucd tom Januarl' I to May 31, 2018, aad tie iacooe trxes rclatcd to
Idsho Pove/r.oglg.!S.c.c.ll taasoirsioo tarif (OAfD ratc. Scc 'lacooe Trx Refono -
Rcgulatorl Trcatneat' bclow for orotc infr,rmatioo-
a
a
Junc 1,2017 $ 10.6 The nct iucrease ra PCA rater hclu&d an offscniag S l3 .0 oitlion reducton for the refi.rod of
previously collectcd lda.bo eaerg-r-, efricieacl' rrder fuods.
Oregon Jurisdicrton 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 pow€r 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 exp€nses recovered through the APCU for
the same period. Under the PCAM, Idaho Power is subject to a portion of the business risk or benefit associated with this deviation
FERC FORM NO.1 (ED. 12-88)Page 123.12
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
04116t2019
Year/Period of Report
2018tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
through application of an asymmetrical deadband (or range of deviations) within which Idaho Power absorbs cost increases or
decreases. For deviations in actual power supply costs outside ofthe deadband, the PCAM provides for 90/10 sharing ofcosts and
benefits between customers and Idaho Power. However, collection by Idaho Power will occur only to the extent that Idaho Power's
actual Oregon-jurisdictional retum on equity (Oregon ROE) for the year is at least 100 basis points below ldaho Power's last
authorized Oregon ROE. A refund to customers will occur only to the extent that Idaho Power's actual Oregon ROE for that year is at
least 100 basis points above Idaho Power's last authorized Oregon ROE. Oregon jurisdiction power supply cost changes under the
APCU and PCAM during 2018 and 2017 did not have a material impact on the companies' financial statements.
Notable Idaho Regulatory Matters
Idaho Bqse Rate Changes.' Idaho base rates were most recently established rr:.2012, and adjusted in2014,2017, ard 2018. Effective
January l,2ll2,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 in a 4.0'7 percent, or $34.0 million, overall increase in Idaho Power's annual ldaho-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. In June 2072, the IPUC issued an order approving a $58.1 million increase in annual ldaho-jurisdiction base rates,
effective July l, 20l2.The order also provided for a $335.9 million increase in Idaho rate base. Neither the settlement stipulation nor
the IPUC orders adjusting base rates specified an authorized rate of return on equity or imposed a moratorium on Idaho Power filing a
general rate case at a future date.
As notcd above in this Note 3, 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 of the PCA rate that became
effective June l, 2014.In June 2018, the IPUC issued an order adjusting base rates for the impacts of income tax reform, as discussed
below in "Income Tax Reform - Regulatory Treatment."
October 2014 Idaho Earnings Support and Sharing Settlement Stipulation: ln October 2014, the IPUC issued an order approving an
extension, with modifications, of the terms of a December 201 1 Idaho settlement stipulation for the period from 2015 tkough 2019, or
until the terms are otherwise modified or terminated by order of the IPUC or the full $45 million of additional accumulated deferred
investrnent tax credits (ADITC) contemplated by the settlement stipulation has been amortized (October 2014 ldaho Earnings Support
and Sharing Settlement Stipulation). The provisions of the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation
are described in the table included under "Income Tax Reform - Regulatory Treatment" below.
In 2018, Idaho Power recorded a $5.0 million provision against current revenue for sharing with customers, as its fuIl-year retum on
year-end equity in the Idaho jurisdiction (Idaho ROE) for 20 I 8 was above 10.0 percent. ln 2017 , Idaho Power did not record any
additional ADITC amortization or any provision for sharing with customers, as its Idaho ROE in both years was between 9.5 percent
and 10.0 percent. Accordingly, at December 31, 2018, the full $45 million of additional ADITC remains available for future use under
the terms of the October 2014Idaho Earnings Support and Sharing Settlement Stipulation. The October 2014 Idaho Eaming Support
and Sharing Settlement Stipulation was modified and indefinitely extended, as described in "Income Tax Reform - Regulatory
Treatment" below.
Income Tax Reform - Regulatory Treatment: 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.
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)
04116t2019
Year/Period of Report
20't8tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
In January 2018, the IPUC issued an order requiring utilities within its jurisdiction, including Idaho Power, to file a report with the
IPUC, identifuing and quantifying the financial impact of the income tax reform changes on the utility, along with proposed tariff
schedule changes that would adjust the utilify's rates and corresponding revenues to reflect the utility's modified federal tax obligations
under the Tax Cuts and Jobs Act. The IPUC order required Idaho Power to estimate the income tax reform changes by comparing
aclnnl2017 federal income tax components with what those federal income tax components would have been if the Tax Cuts and Jobs
Act had been effective for the full-year 2017.
In March 2018, Idaho Power made a filing with the IPUC providing the results of its pro forma analysis indicating pro forma annual
income tax reform expense reductions, composed ofa current income tax expense reduction and a deferred income tax expense
reduction. In May 20 I 8, the IPUC issued an order approving a settlement stipulation (May 201 8 Idaho Tax Reform Settlement
Stipulation) related to income tax reform. Beginning June 1, 2018, *re settlement stipulation provides an annual (a) $18.7 million
reduction to Idaho customer base rates and (b) $7.4 million amortization of existing regulatory defenals for specified items or future
amortization of other existing or future unspecified regulatory deferrals that would otherwise be a future liabiliry recoverable from
Idaho customers. Additionally, a one-time benefit of a $7.8 million rate reduction is being provided to Idaho customers through the
Idaho-jurisdiction power cost adjustment (PCA) mechanism for the period from June 1 , 201 8 through May 3 I , 201 9, for the income
tax reform benefits accrued from January I , 201 I to May 3 1 , 2018, and the income tax reform benefits related to Idaho Power's OATT
rate. The amount provided via the PCA mechanism will decrease to $2.7 million on June 1,2019, for income tax reform benefits
related to Idaho Power's OATT rate and will cease on June 1,2020, to reflect the impact of a full year of reduced OATT third-parry
transmission revenues.
The May 2018 Idaho Tax Reform Settlement Stipulation also provides 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.
FERC FORM NO. I (ED. 12-88)Page 123.14
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
04t1612019
Year/Period of Report
2018tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
The table below summarizes and compares the terms of the October 2014 Idaho Eamings Support and Sharing Seftlement Stipulation
with the terms in the May 2018 Idaho Tax Reform Settlement Stipulation that will be applicable commencing on January 1,2020.
Octobcr t0l4 ldaf,o Earaiags Support rnd Shariag
Sctttcocar Stipulation - ]1"y 20lE ldilo Tar Rcforr Scnlcmcot Stipolrtion
Gfiertive throueh Blc;tsber ]1. 20lg) @ftctivc begimug Jaruary l, 2020, u:& no dcGred cnd datc)
If I&ho Potrdr actr.ral ralual ldabo ROE ia aay yec ! !s3s rhn
9.5 p€rocat, thlo tdlho Porrtr ary ncord.dditifisl ADITC
@odizrtioo np to 32J oilioo to hcb rchieve a 9.5 p.rccd
Idabo ROE frr tbd 1,car, ad any record ldditiooal ADITC
uortizrrioo up b a total of t4J raillioq oru tt 20lJ ltroush
2019 Fiod. If e. t4, oillioo ofADITC rru co,oplctely
aoroai.a4 thc rrtrfir rhaflng povirionr bcloc, uurtd ao lagcr
be appticabhl
If Idaho Poqrds amual Idabo ROE m aay lcar cxcccds 10.0
pcm€ot thc amouat of ctrnmg* xceediog a 10.0 pcrccat ldabo
ROE aad up to ,od iocludi{g a 10^5 perceat ldaho ROE udl be
allocaed 75 pcrccat to ldabo Powcdr ldabo customcc as a ratc
rcductoo to bc cEectiTe at thc ri-e of thc vubccqucot _vca/r
PCA rnd 25 pcrceat to Idaho Pou's.
If t&ho Portds aaoual ldlno ROE io ry ycar crcccds 10.5
p.tc d, tbc anouat of carangs escdiog a 10.5 pcrcaf l&to
ROE wi[ bc dlocatcd 50 pcrccat to l&ho Pon'eds Idrho
orstomcrs I a rzE rrdrctsm to be e&ctirr u tic tnae of ttc
rubrcqucdyca/r pCA 2J pcrcartto ldatoPorcds Idaho
eustoorcrs b thc form of r rr&xtion to tbe pca:ion rcgufao,rt'
aset balaocrag mcorrot (to r.&rcc 6c aoouot to bc collecud io
&. finurc &om Idrho curtoocrs), ad 25 pcrccat b ldaho Poltr.
In ltc cvcot tb IPUC app.rorcs a claoge to ldaho Porw/r
dloscd aoaual ldaho ROE as part of a geaeral ratr casr
procccdra* before Decernber 31, 2019, tic Idabo ROE tbresbol&
nrll bc adjustd oo a prorpec!{e basir as follorw: (a) thc Idaho
ROE uodcr nfuch ldaho Porver u^ill be pcmittcdto zmoltizedt
additiooal aaounr of.{DITC srll be set at 9J pcrccot of the
ncn'$ authorized ldaho ROE, (b) ib.rlng rvith custoorcrs oa a
75 pcrccot basis ar a curtod., rat rcductiod ildl bcgilr at thc
nan'ly auttorucd l&ho ROE, aad (c) shanag u,it[ custoaacrs oa
a 75 pcrccat basis brI allocated 50 perccot to a rate rcdr:ctioo,
aad 25 pcrceat to e pcosioa esparsc deferral rcguliloe'.siet,
sill bcgia at 105 pcrceat of thc neuly arlhorued l&ho ROE.
If l&to Po\,!dr actrul aamal ldrho ROE io ery 1'cer is lcss
tlra 9.a pcrced, t&a ld*o Pons o:1. ooortizc ug to 325oillio of additioo.l ADIIC to hclp *lisuc a 9.4 pcrccut ldalo
ROE for that year, rc log ar tt: ctoulative amonot of ADITC
usd docs oot rnmcd t4J millim 0&ho Portr will har,r
avaiLablc rod oay comiauc b rrsc aoy lrou!.d poruoo ofthc 9J
aillioa of additimd ADITC fro rtc Octobcr 20t4 l&ho
Earotag! $rgport ad SbuioC Scttl.orcar Stifnrlstoo); honetu,
Idrho Po*rr oay seclc agprord &m thc IPUC to rcpl-i.h tLc
tdl amouor ofADITC il ir pcroltcd to aoonize. Iftlcre ur oo
niosiorag aosrroti ofADITC alrhorizcrl to bc aoortzt4 ttc
rcrrarc shair* ?ror,rrioas bclow nmrld aor bc applicable until
.ADITC is rrpl-ittd.
If Idato Po*t/s aaaual Idaho ROE rn al'ye.!r cxcocds !0.0
pcrc.oq thc arnouat of aararngs cxccedi.ng a 10.0 pfccot Idabo
ROE aad up to ad io.luditrg a t0.5 pcrcem Idaho ROE u.ill bc
allocared 80 pcrccd to Idaho Pou,edr ldaho custoarers as a rate
rcdrctioa io be efactiru at thc timc of thc sub,!.qucat l..ads
PCA and 20 parccnt to ldalo Power.
If ldalo Ponrdr aauurl Idrto ROE b uy ytar excccd! 10.5
pcrccr! lLe aoout ofcroiop cxcc*diry a 10.5 pcrccor l&bo
ROE utitl bc .ltocatld 5, pGtccot to Idabo Ponrds Idaho
curbe:r! dr a tat rr&rtio to bc eftctirr at ttc troc of hc
$bt.qu.at l€rdr PCA 25 pcrccd to ldaho Pou.tdr Idato
cuioocrs io lb fola of e rdEtioa to tn! pcosioa Gguldori'
arsd ba!8rci[E eccouot (to rcdrc! ltc rsouat to tc collectctl il
tb. imrc frora ldrho crstoocn), .ad 20 pcrc.ot to l&to Postr.
la thc ev-r the IFUC rpprotcs a chaugc to l&ho Posr/r
dlontd aranal Idalo ROE as prt of a garal ratc casc
proccediac c$cctrte oa or a0cr Juuarv l, 2020, thc Idaho ROE
tireshold: uitl bc adjustcd on l prolpcctrve basb a.r follow'u (a)
thc Idaho ROE uadcr wtich ldaho Porvcr rrll be pcrmittcd to
aoortize ao additooal amouat of ADITC u,ill bc se{ rt 95 pcrceat
of thc neu,ly arlbrized Idaho ROE, (b) sharirry sith curto!063
oo ao $0 perccd basls as a curtom;r ratc rcdrctioo *r1I begin at
&c oetly authorrzcd Idaho ROE, aod (c) rhann-e uitt curtoolcrs
m ar 80 pcrccd basu h.[ dlocrcd !5 pcrccot to a ratc
redrctioc ad 25 gerceot to a pcanim cxprore d.&rral
re$rlatoo. assc( uill bcgir at 105 pcrcanr ofttc ocrvly
authorizd Idaho ROE.
Neither the October 20 14 Idaho Earnings Suppott and Sharing Settlement Stipulation nor the May 2018 Idaho Tax Reform Settlement
Stipulation impose a moratorium on Idaho Power filing a general rate case or other form of rate proceeding in Idaho during their
respective terms.
FERC FORM NO. ,l (ED. 12-88)Page 123.'15
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t16t2019
Year/Period of Report
2018/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
AIso in May 2018, the Public Utility Commission of Oregon (OPUC) issued an order approving a settlement stipulation that provides
for an annual $ I .5 million reduction to Oregon customer base rates beginning June I , 2018, through May 31, 2020, related to income
tax reform. Unless earlier resolved in a regulatory proceeding, the settlement stipulation requires Idaho Power to file a deferral request
with the OPUC by December 3l , 2019, to begin tracking income tax reform benefits beginning January l, 2020, at which time Idaho
Power, the OPUC staft and other interested parties will discuss the methodoiogy to quantifu potential future income tax relbrm
benefits.
Fixed Cost Adjustment: The Idaho jurisdiction fixed cost adjustrnent (FCA) mechanism, applicable to Idaho residential and small
commercial customers, is desigrred to remove a portion of Idaho Power's hnancial disincentive to invest in energy efficiency programs
by separating (or decoupling) the recovery of fixed costs from the variable kilowatt-hour charge and linking it instead to a set amount
per customer. Under Idaho Power's current rate design, recovery of a portion of fxed costs is included in the variable kilowatt-hour
charge, which may result in over-collection or under-collection of f,xed costs. To retum 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. Any
annual increase in the FCA recovery is capped 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
FCAyerr period Retcs ia Effecr AnnualA'utourt
(in millions)
2011
l0l6
Juae 1, 2018-May 31, 2019
Jure 1. -?017-lvta1'I1. 201I
$15.6
$li.0
Hells Canyon Complex Relicensing Costs Settlement Stipulation.' [n December 2016, Idaho Power filed an application with the
IPUC requesting a determination that Idaho Power's expenditures of $220.8 million through year-end 2015 on relicensing of the HCC
were prudently incurred, and thus eligible for inclusion in retail rates in a future regulatory proceeding. In December 2Afi,Idaho
Power filed with the IPUC a settlement stipulation signed by Idaho Power, the IPUC staff, and a third-parry intervenor, recognizing
that a total of $2 I 6.5 million in HCC relicensing expenditures and other related costs were reasonably incurred, and therefore should
be eligible for inclusion in customer rates at a later date. As a result of filing the settlement stipulation, Idaho Power recorded a $5.0
million pre-tax charge in the fourth quarter of 2017, which included $4.3 million for costs incurred through 2015, as well as $0.7
million related to associated costs incurred in 201 6 and 2017 . Of the $5.0 million pre-tax charge in 201'1 , $2.5 million was recorded as
other operations and maintenance (O&M) expense and $2.5 million was recorded as a reduction to AFUDC. In April 2018, the IPUC
issued an order approving the settlement stipulation as filed with the IPUC and determined the $216.5 million of associated costs to be
reasonably and prudently incurred.
Western Energt Imbalance Market Cosfs.' Idaho Power's participation in the energy imbalance market implemented in the westem
United States (Westem EIM) commenced on Apnl 4,2018. The Western EIM aims to reduce the power supply costs to serve
customers through more efficient dispatch within the hour of a larger and more diverse pool of resources, to integrate intermittent
power from renewable generation sources more effectively, and to enhance reliability.
In January 2017 , tn r€sponse to Idaho Power's request to match costs with benefits of Western EIM participation, the IPUC issued an
order authorizing defenal accounting treahnent for costs associated with joining the Western EIM. In November 2017, Idaho Power
filed an application with the IPUC requesting authorization to establish an interim method of recovery for costs associated with
participation in the Westem EIM. Through March 201 8, Idaho Power had de ferred $ I .0 million of incremental other O&M costs. In
FERC FORM NO. 1 (ED. 12-88)Page 123.16
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
0411612019
Year/Period of Report
2018tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
the second quarter of 2018, Idaho Power amortized those costs in accordance with the provisions of the May 201 8 Idaho Tax Reform
Settlement Stipulation discussed above. In July 2018, the IPUC issued an order approving a settlement stipulation that provides for
recovery of ongoing Western ElM-related costs through Idaho Power's PCA mechanism, beginning April 20 I 8. The recovery
mechanism provides for monthly incremental rcvenue, which includes a retum on and return of Western ElM-related capital costs and
recovery of ongoing Western EIM operating costs. As of April l, 2018, Idaho Power ceased deferring incremental Western EIM
participation O&M start-up costs, and began recognizing the monthly incremental revenue associated with Westem EIM participation.
From April through December 2018, Idaho Power recorded$2.2 rnillion as a regulatory asset within the PCA balance per the
stipulation in order to match the costs with the benefits of the Western EIM.
Valmy Base Rate Adjustment Settlement Stipulations
In May 2017, the IPUC approved a settlement stipulation allowing accelerated depreciation and cost recovery for Idaho Power's
jointly-owned North Valmy coal-hred power plant (Valmy Plant), The settlement stipulation provides for an increase in Idaho
jurisdictional revenues of$13.3 million per year, and (1) levelized collections and associated cost recovery through December 2028,
(2) accelerated depreciation on unit I through 201 9 and unit 2 through 2025, (3) Idaho Power to use prudent and commercially
reasonable efforts to end its participation in the operation ofunit I by the end of2019 and unit 2 by the end of2025, and (4) a filing no
later than December 31, 2019 that would include actual and planned incremental investments in unit 2, including updated financial
analysis regarding the lowest costs options for unit 2. The costs intended to be recovered by the increasedjurisdictional revenues
include current investments as of May 31,2077, 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 I through 2A19 and unit 2 through 2025) compared with costs permitted to be recovered during the cost recovery
penod specified ur thc settlement stipulation (including depreciation expense through 2028). Ifactual costs incurred differ from
forecasted amounts included in the settlement stipulation, collection or refund of any differences would be subject to regulatory
approval.
In June 2017, the OPUC also approved a settlement stipulation allowing for accelerated depreciation of units I and 2 through
December 31,2025, cost recovery of incremental Valmy Plant investments through May 31, 2017, and lbrecasted decommissioning
costs. The settlement stipulation provides for an increase in the Oregon jurisdictional revenue requirement of $ l. I million, effective
lily I , 2017 , with yearly adjustments, if warranted. As part of the May 20 I 8 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
ofunit I by the end of2019 and approved Idaho Power's request to recover annual incremental accelerated depreciation relating to unit
l, begiruring June l, 2018, and ending December 31,2019, resulting in a $2.5 million annualized revenue requirement.
Notable Oregon Regulatory Matters
Orcgon Base Rate Changes: Oregon base rates were most recently established in a general rate case i,r:,2012.In February 2012, rhe
OPUC issued an order approving a settlement stipulation that provided for a $1.8 million base rate increase, a return on equity of 9.9
percent, and an overall rate of return of 7.757 percent in the Oregon jurisdiction. New rates in conformity with the settlement
stipulation were effective March I , 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 I , 2012. for inclusion of the Langley Gulch power
plant in Idaho Power's Oregon rate base. In June 201 8, the OPUC also issued an order adjusting base rates for the impacts of income
tax reform, as discussed above in "Income Tax Reform - Regulatory Treatment.'l
FERC FORM NO. 1 (ED. 12.88)Page 123.17
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t16t2419
Year/Period of Report
2018tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Federal Regulatory Nlatters - Open Access Transmission Tariff Rates
Idaho Power uses a formula rate for transmission service provided under its OATT, which allows transmission rates to be updated
annually based primarily on financial and operational data Idaho Power files with the FERC. Idaho Power's OATT rates submitted to
the FERC in Idaho Power's four most recent annual OATT Final Informational Filings were as follows:
Applicrblc Period OATT Rrtc (pcr
Octobcr l, 2018 to Scpteobcr 30, 2019
Octobcr l, 2017 to Scptcabcr 30,2018
Octobcr 1,2016 to Scptcobcr 30,2017
$
$
3
31.25
3,1.90
25.52
ldaho Power's current OATT rate is based on a net annual transmission revenue requirement of $123.1 million, which represents the
OATT formulaic determination of Idaho Power's net cost of providing OATT-based transmission service.
4. REVENUES
On January I , 201 8, Idaho Power adopted ASU 20 14-09 , Revenue from Contracts with Customers, using the modified retrospective
method. The adoption did not change the timing or amounts of revenue recognized by Idaho Power and, therefore, the companies
recorded no cumulative-effect adjustrnent. The following table provides a sunrmary of elecftic utility operating revenues for Idaho
Power (in thousands):
?018 xOt 7
EIecEic utilit5r operetiug rcvenuec:
Revenue from contrscts rvittr customers
Alteraative reveoue progratrs md other reveaues
$ l.rr:,11? $ 1.320,004
54,470 2,r,889
Total electric utiht', operat"inp re1'euues $ 1.366.582 $ 1.344.893
Revenues from Contracts with Customers
Revenues from contracts with customers are primarily related to Idaho Pewer's regulated tariff-based sales of energy or related
services. Generally, tariff-based sales do not involve a written contract, but are classified as revenues from contracts with customers
under ASU 2014-09, Revenue from Contracts with Customers. Idaho Power assesses revenues on a contract-by-contract basis to
determiae the nature. amount, timing, and uncertainty, if any, of revenues being recognized. The following table presents revenues
from contracts with customers disaggregated by revenue source (in thousands):
FERC FORM NO. 1 (ED. 12.88)Page 123.18
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2\ - A Resubmission
Date of Report
(Mo, Da, Yr)
o4J16t2019
YearlPeriod of Report
2018/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
20t8 2017
Rsr'€oncs &om contmcts rrilh cus(omcrs:
8-etarl rer,euues:
Residtutal (i:rcludes 114.6L5, $17.3?0 aad $.19,110, respectitely, related to tte
FCAG})
Comorercral (ircludes t1,299, $876 arrd $l=087, resp€ctn'ely, relaed to the
Fce[tt;
Iadustrial
hrigarlon
Pror.isioa for sharing
Defeced reveaue related to HCC rclicmsiagAlUDQG)
Total retail reveaues
Less: FCA o.ecladse ermuciJl)
Wholesale energy sales
Tralsoilsioa whee lilg rer.eaues
Eaergy efficieocy progri[tr r€vetru€s
Otler rglequea &oo cootractc with custooers
Total reveaues from cootfacG *'ittr customers
$ 530,527 $ 5i2,33i
3 19, l9J
195,124
150,030
(10.706) )
1,20i,916
(18,re6) )
?4,790
43,9?0
39,14t
24,213 _
!_!:1gr9r =
1) l}e FCA o*bailu is ar alla-rB'.r rs,.etroe preeraai in the idaho jlm.rdlctiou rud does uot rerrernl ,fltuue iolr contraE nd& custoareri.
l.l ,\spertofifsl:nurr-r'30, 1009.gaerelntecasaords,theIPUCisrllon'irgld:boPomtorocm'erapsdionofttre-4.FUDConcoetnrctiolwmkin
prnges: rehled to &e HCC rdicelrug lrocesc, eru thrug[ th* relicrumg pcce:s ir rot r'* pl-nn!4! ad tle cogts have uot bxr uored to elccrrc pbt*
iarm.ice-Id:hoPorryeris$[rctias$8.8miltioomullf iafie],t-hojui:dicticabulisdekrugrei'ear.HoEarbosoftheuwurbcoUrtedutrltheIicre ic L$ed rnd lhe rccuantrlcd liceose *sts :ptrrtrcd fc re*e1v repleccd m wice himto tie ]v121 1018 lchlo Ta Refctar Sqnllaut
Stpulooa desibed ir Noite 3 - ''Rrgdatow h{rttu,'' Ida}o Ponrr s- collectag $ I0 ) milLoa urJiy-
Retail Revennes.. 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 seryices 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 ldaho 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
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 flucfuations 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 15 days of billing. Idaho Power accrues estimated unbilled revenues 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.
FERC FORM NO.1 123.19
310,299
t90,130
lJ8,00l
(5,0?5)
(8,780)
l,l 75,152
(35,eU)
51. s45
59,094
35,743
25,242
I_lJ_r3J.!r
Credit losses recorded on receivables arising from ldaho Power's contracts with customers were $3.6 million and $4.7 million for 2018
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
a4t1612019
Year/Period of Report
20,t8tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
and 2017 , respectively"
&cs,dgl1ltglgU$q$g!$: tdaho 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 eamings. 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 efhciency initiatives.
Commercial Customers: Most businesses are included in Idaho Power's commercial customer class, as well as small industrial
companies, and public street and highway lighting accounts. Idaho Power's commercial austomers are less influenced by weather
conditions than residential customers, although weather does affect commercial customer energy use. Economic conditions, including
manufacturing activity levels, and energy efhciency initiatives also affect energy use of commercial custorners.
IryIq-st{l.gl.eu-Sjqmers: Industrial customers consist of large industriai companies, inctuding special contract customers. Energy use of
industrial customers is primarily driven by economic conditions, with weather having iittle impact on this customer class.
Irrigation Customers: Irrigation customers use electricity to operate irrigation pumps, primarily during the agricultural growing season.
The amount and timing of precipitation as weil as temperature levels can affect the timing and amounts of sales to irrigation customers,
with increased precipitation generally resulting in decreased sales.
Provision for Sharing: Idaho Power's sharing mechanism is associated with the October 2014 Idaho Earnings Support and Sharing
Settlement Stipulation that provides for the sharing with customers of a portion of ldaho-jurisdiction eamings exceeding a 10.0 percent
Idaho ROE. Based on fuI1-year 2018 Idaho ROE, Idaho Power recorded a $5.0 million provision against current revenues for sharing
of eamings with customers for 2018. During 2017,Idaho Power recorded no sharing of earnings with customers. The October 2014
Idaho Earnings Support and Sharing Settlement Stipulation is described further in Note 3 - "Regulatory Matters."
Vl/holesale 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 '*,holesale electricity sales are primarily to utilities
and power marketers and are predominantly short-term and consist of a single performance obligation satisfied as energy is transferred
to the counterparry. Idaho Power's wholesale energy sales depend largely on the availability of generation resources in excess of the
amount necessary to serve customer loads as well as adequate market power prices at the time when those resources are available. A
reduction in either factor may lead to lorver wholesale energy sales.
Trqnsmission lYheeling 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 opportunily to access the transmission system. Idaho Power's transmission revenue is primarily
related to third parties reserving capacify on Idaho Power's transmission system to transmit electricity through Idaho Power's service
area. The reservations are predominantly short-term but may be part ofa long-term capacity contract, short-term contract, or
on-demand when available. Transmission wheeling revenues consist of a single performance obligation satisfied as capacity on Idaho
Power's transmission system is provided to the third parfy. Transmission wheeling revenues are affected by changes in Idaho Pou,er's
OATT rate and customer demand. Demand for transmission services can be affected by regional market factors, such as loads and
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)
0411612A19
Year/Period of Report
201BlQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
generation of utilities in ldaho Power's region.
Energt Elficiency Program Revenues: Idaho Power collects most of its energy efficiency program costs tkough an en€rgy efhciency
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 recorded in revenues, resulting in no net irnpact on
earnings. Energy effrciency program revenues are recognized in the period when the related costs ofthe energy efficiency program are
incurred by ldaho Power. The cumulative variance between expenditures and amounts collected through the rider is recorded as a
regulatory asset or liabiliry. 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,2018,Idaho Powels energy efFrciency rider balances
were a $5.3 million regulatory liability in the Idaho jurisdiction and a $ 1 .4 million regulatory asset in the Oregon jurisdiction.
Alternative Revenue Programs and Other Revenues
While revenues from contracts with customers make up most of Idaho Power's revenues, the IPUC has authorized the use of 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 of the 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 of utility service and billed to customers, such amounts are recorded as recovery of the
associated regulatory asset or liability and not as revenues.
The table below presents the FCA mechanism revenues and other revenues (in thousands):
Aftcmetive nevcruc Drogrrrrs aad other rErernca:
FCA mechaaisr[ reveaues
Derivative ret'eouet
$
!018
I5,9t.1
18,546
2017
18,196
6,693
Total alteraative rerenue progfitrns and olher revesues $ t.r,{?o $ 14,889
5. LONG-TERM DEBT
The following table summarizes Idaho Power's long-term debt at December 3l (in thousands of dollars)
FERC FORM NO. 1 (ED. 12-88)Page 123.21
Name of Respondent
ldaho Power Company
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t16t2019
Year/Period of Report
2A18lo4
NOTES TO FINANCIAL STATEMENTS (Continued)
20lE t0l7
Fint mortgage bouds:
4.50% Scries Are 2020
3.{0ozo Serics due 2020
2.9J7o Saics 6E 2022
2.507o Scriq due2023
6.007c Scrics drlc 2032
5-50olo Scries duc 2033
5.J00lo Scrics duc 2034
t.875% Scrier due 203.1
5.307o Scrics dur 2035
6.30% Series duc 2037
6.25% Scries duc 2037
.1.$57o Seocs due 2040
4.307o Scrics dtt 2042
,1.0096 Serier duc 20.13
3.650lo Scrics dtt 2045
.l.0jo,'o Scties duc 2046
4-20olo Series duc 2048
3 $r30,000
100,000
7J,000
7J,000
r00,000
70,000
50,000
J5,000
60,000
140,000
r00,000
100,000
75,000
75,000
250,000
120,000
100,000
7r,000
i5,000
t00,000
70,000
J0,000
55.000
60,000
140.000
100,000
100,000
7r,000
75,000
250,000
120,000
22A,000
Total firsr arortgage boads r.665,000 1,575,000
Pollutioo coatrol revcouc boads:
i.1J7o Series dur 2024 {})
5.2Jo6 Scriec duc 2026 (l)
Variable Rate Scries 2000 duc 2027
{9,800
I 16,300
4,360
19,800
t t6,300
.r,360
Total pollutioa coatrol rcr,cauc boadr 170,460 L70,4@
.{mcricas Falls boad tuaraotcr
Uoanodiz*d diccoudr
19,8 8 5
{4,5e8}
19.885
(4,125)
Tota.l Idaho Power outrtxrdiag debt Ci 1,8J0,?d7 1,761,220
(l) Hubol,& Cou4'rud Srrtrrr*r Ca,4'Pol}*ioa Coacl fi.rn'{rru. Bordr ur rcured \'th 6rrr mort34r, brugu3 tb. totrl 6r$ &Entryr bmdr
ourt&drq a Dccaber 31, 1018, o tl.9ll brllroo-
G) fu Dccrarbcr 31, 2018 rld :01l, tbr otrrdl effectir'. coai rde of Idrho Pouers outrtuding &bt wes J.S3 prrccat rd '{.91 percoa, rup*ttdy'.
At December 31,2018, the maturities for the aggregate amount of Idaho Power long-term debt outstanding were as follows (in
thousands ofdollars):
FERC FORM NO.1 (ED. 12-88)Page 123.22
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) _A Resubmission
Date of Report
(Mo, Da, Yr)
04116t2019
Year/Period of Report
2018tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
!019 20x0 |,o21 20?,7 20x3 Thereafter
$$ 100,000 $$ 75,000 $ t5,000 $ 1,605,t45
Long-Term Debt Issuances, Maturities, and Availability
In March 201 8, Idaho Power issued $220 million in principal amount of 4.20oh first mortgage bonds, secured medium-term notes,
Series K, maturing on March l, 2048. In April 201 8, Idaho Power redeemed, prior to maturity, $ 130 million in principal amount of
4.50% first mortgage bonds, medium-term notes, Series H, due March 2020. In accordance with the redemption provisions of the
notes, the redemption included Idaho Power's payment of a make-whole premium of $4.6 million. Idaho Power used a pofiion of the
net proceeds of the March 20 I 8 sale of hrst mortgage bonds, medium-term note s to effect the redemption.
Idaho Power First 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 2016, Idaho Power received orders from the IPUC, OPUC, and
WPSC authorizing Idaho Power to issue and sell from time to time up to $500 million in aggregate principal amount of debt securities
and first mortgage bonds, subject to conditions specified in the orders. Authority from the IPUC is effective through May 31,2019,
subject to extensions upon request to the IPUC. The OPUC's and WPSC's orders do not impose a time limitation for issuances, but the
OPUC order does impose a number of other conditions, including a requirement that the interest rates for the debt securities or first
mortgage bonds fall within either (a) designated spreads over comparable U.S. Treasury rates or (b) a maximum all-in interest rate
Iimit of 7.0 percent.
On September 27 ,20l6,Idaho Power entered into a selling agency agreement with seven banks in connection with the potential
issuance and sale from time to time of up to $500 million aggregate principal amount of hrst mortgage bonds, secured medium term
notes, Series K (Series K Notes), under ldaho Power's Indenture of Mortgage and Deed of Trust, dated as of October 1, 1937, as
amended and supplemented (lndenture). At the same time, Idaho Power entered into the Forfy-eighth Supplemental Indenture, dated as
of September 1,2016, to the Indenture. The Forfy-eighth Supplemental Indenture provides for, among other items, the issuance of up
to $500 million in aggregate principal amount of Series K Notes pursuant to the Indenture. As of December 31, 2018, $280 million in
principal amount of Series K Notes remained available for issuance under the lndenture.
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, workmen's compensation awards, and similar encumbrances and minor defects and clouds common to properties.
The mortgage of the Indenture does not create a lien on revenues or profltts, or notes or accounts receivable, contracts or choses in
action, except as permitted by law during a completed default, securities, or cash, except when pledged, or merchandise or equipment
manufactured or acquired for resale. The mortgage of the Indenture creates a lien on the interest of Idaho Power in property
subsequently acquired, other than excepted property, subject to limitations in the case ofconsolidation, merger, or sale ofall or
substantially all of the assets of Idaho Power. The Indenture requires Idaho Power to spend or appropriate I 5 percent of its annual
gross operating revenues for maintenance, retirement, or amortization of its properties. Idaho Power may, however, anticipate or make
up these expenditures or appropriations within the five years that immediately follow or precede a particular year.
The Forfy-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
FERC FORM NO. 1 (ED. 12-881 Page 123.23
Name of Respondent
ldaho Power Company
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
0411612019
Year/Period of Report
2018/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
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 fwice the annual
interest requirements on all outstanding debt of equal or prior rank, including the bonds that Idaho Power may propose to issue. Under
certain circumstances, the net eamings test does not apply, including the issuance of refunding bonds to retire outstanding bonds that
mature in less than two years or that are of an equal or higher interest rate, or prior lien bonds.
As of December 31, 2018, Idaho Power could issue under its Indenture approximately $1.9 billion of additional first mortgage bonds
based on retired first mortgage bonds and total unfunded properly additions. These amounts are further limited by the maximum
amount of first mortgage bonds set forth in the Forry-eighth Supplemental Indenture. As a result, the maximum amount of first
mortgage bonds Idaho Power could issue as of December 3 1 , 20 I 8 was limited to approximately $669 million under the lndenture.
6. NOTES PAYABLf,
Credit Facilities
On November 6,2015,Idaho Power entered into Credit Agreements replacing the existing Second Amended and Restated Credit
Agreements, dated October 26,2011,0o 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 of loans and standby letters of credit,
not to exceed the aggregate principal amount at any one time outstanding of $300 million, including swingline loans in an aggregate
principal amount at any time outstanding not to exceed $30 million, and letters of credit in an aggregate principal amount at any time
outstanding not to exceed $100 million. Idaho Power has the right to request an increase in the aggregate principal amount of the
facilities to $450 million, subject to certain conditions.
The interest rates for any borrowings under the facilities are based on either (1) a floating rate that is equal to the highest of the prime
rate, federal funds rate plus 0.5 percent, or LIBOR rate plus 1.0 percent, or (2) the LIBOR rate, plus, in each case, an applicable
margin, provided that the federal funds rate and LIBOR rate will not be less than zero percent. The margin is based on Idaho Power's
senior unsecured long-term indebtedness credit rating by Moody's Investors Service, Inc., Standard and Poor's Ratings Services, and
Fitch Rating Services, Inc., as set fbrth on a schedule to the credit agreements. Under the credit facility, Idaho Power pays a facility fee
on the commitment based on the company's credit rating for senior unsecured long-term debt securities. While the credit facilities
provide for an original manrrity date of November 6,2020, the credit agreements grant Idaho Power the right to request up to two
one-year extensions, subject to certain conditions. On November 7 ,2017 Idaho Power executed the second extension agreement with
the consent of all the lenders, extending the mahrrity date under both credit agreements to November 4, 2022. No other terms of the
credit facilities, included the amount of permitted borrowing under the credit agreements, were affected by the extensions.
At December 31, 2018, no loans were outstanding under Idaho Power's facilities. At December 31, 2018, Idaho Power had regulatory
authority to incur up to $450 million in principal amount of short-term indebtedness at any one time outstanding. Balances (in
thousands of dollars) and interest rates of Idaho Power's short-term borrowings were as follows at December 3 I , 20 I 8 and 201'll'
FERC FORM NO, 1 (ED. 12-881 Page 123.24
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
04t16t2019
YearlPeriod of Report
2018to.4
NOTES TO FINANCIAL STATEMENTS (Continued)
2018 20t7
Com uercial peper balances :
At the eud of year
Aterage during the year
Weightcd-arrra gc inlcrest rate
At the eod of the year
$
$
$
$
_ort
7. COMMON STOCK
Idaho Power Common Stock
No contributions were made to Idaho Power in 2018 or 20L7 and no additional shares of Idaho Power common stock were issued.
Restrictions on Dividends
Idaho Power's ability to pay dividends on its common stock held by IDACORP is limited to the extent payment of such dividends
would violate the covenants in its credit facility or Idaho Power's Revised Code of Conduct. A covenant under Idaho Power's credit
facility requires Idaho Power to maintain leverage ratios of consolidated indebtedness to consolidated total capitalization, as defined
therein, of no more than 65 percent at the end of each fiscal quarter. At December 31, 2018, the leverage ratio for Idaho Power was 46
percent. Based on these restrictions, Idaho Power's dividends were limited to $1.2 billion at December 31, 2018. 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, 2018, Idaho Power was in compliance
with those covenants.
Idaho Power's Revised Policy and Code of Conduct relating to ffansactions between and among Idaho Power, IDACORP, and other
affiliates, which was approved by the IPUC in April 2008, provides that Idaho Power will not pay any dividends to IDACORP that will
reduce Idaho Power's common equity capital below 35 percert of its total adjusted capital without IPUC approval. At December 31,
2018, Idaho Power's coutmon 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 coilrmon stock if preferred stock
dividends are in arrears. As of the date of this report, Idaho Power has no prefered stock outstanding.
In addition to contractual restrictions on the amount and payment of dividends, the FPA prohibits the payment of dividends from
"capital accounts." The term "capital account" is undehned 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 earnings or retained earnings.
ln accordance with Section l0(d) of the Federal Power Act, Idaho Power has $13.3 million of amortization reserves established for
certain of its licensed hydroelectric facilities.
FERC FORM NO. 1(ED. 12-88)Page 123.25
-9,ir
839
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
o411612019
Year/Period of Report
2018tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
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, resfiicted
stock and restricted stock units (together, Restricted Stock), performance shares and performance-based units (together,
Performance-Based Shares), and several other tlpes of share-based awards. At December 31, 2018, the maximum number of shares
available under the LTICP was 720,408.
Restricted Stock and Performunce-Bqsed Shares Awards
Reshicted Stock awards have three-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 settled 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 of common 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 tkee-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 ofspecific performance conditions over the
three-year vesting period. The performance conditions are two equally-weighted metrics, cumulative earnings per share (CEPS) and
total shareholder retum (TSR) relative to a peer group. Depending on the level of attainment of the performance conditions and the
year issued, the final number ofshares awarded can range from zero to 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 of shares awarded.
The grant-date fair value of the CEPS portion is based on the closing market value at the date of grant, reduced by the loss in
time-value of the estimated future dividend payments. The fair value of this portion of the awards is charged to compensation expense
over the requisite service period based on the estimated achievement of performance 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 expense over the requisite service period, provided the requisite service
period is rendered, regardless of the level of TSR metric attained.
A summary of Restricted Stock and Performance-Based Shares award activity is presented below. Sharc amounts represent the shares
of IDACORP common stock:
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)
04t16t2019
Year/Period of Report
2018tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Nurrber of
Shares/Unis
Wcighted-
Ar-crage
Grant Dete
Feir lhlue
Nngln;tfdsharesr\xrits at January l, 2018
Sharesruuits graoted
SLares/units forfeited
Sharesruuit$ vested
199,65? $
106,40?
(5, l7e)
(96,016)
12.39
't9.29
85.07
60.31
Nonvested sharesrunjts *Deceaber 3l- 2018 104.859 $ 81.31
The total fair value of shares vested was $8.3 million in 2018 and $7.5 million in20l7. At December 31, 2018, Idaho Power had $7.9
million oftotal unrecognized compensation cost related to nonvested share-based compensation. These costs are expected to be
recognized over a weighted-average period of 1.7 years. Original issue and/or treasury shares of IDACORP are used for these awards.
In 2018, a total of 12,950 shares of IDACORP common stock were awarded to directors of IDACORP and Idaho Power at a grant date
fair value of $8 I .05 per share. Directors elected to defer receipt of 3 ,237 of these shares, which are being held as deferred stock units
with dividend equivalents reinvested in additional stock units.
Compensation Expense: The following table shows ldaho Power's compersation cost recognized in income and the tax benefits
resulting from the LTICP (in thousands of dollars):
2018 t0l7
$9,276 $
2"3S8
Coor.persalioa cost
Iacome ta,r beaefi.t {1']
7,304
j,8)6
(1| DuetotfieTaxCutsandJobsA{t,flieeffectiveincornetaxrat€wasredwedin20lSforbothl0ACORPandldahoPur.rer.rvhichisoes(ribed
in Note 2 - "lncorne lus.''
No equity compensation costs have been capitalized. These costs are primarily reported within "Other operations and maintenance"
expense on the consolidated statements of income.
9. COMMITMENTS
Purchase Obligations
At December 31,2018, ldaho Power had the following long-term commitments relating to purchases of energy, capaciry, transmission
rights, and fuel (in thousands of dollars):
2019 2020 2011 2022 2013 lhcrceftcr
Cogcacratioa and powcr productioa
Fuel
s ,3s,,,18 S
'1rJO6
S X3*Lr8 t 'JrJl6 !
'56J03
S r3O5J5'
.r3, 163 29,t2r :8,010. 8,389 I,j79. S.r.18:
FERC FORM NO. 1 (ED. 12-88)?age 123.27
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
0411612019
Year/Period of Report
2018tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
As of December 31, 2018, Idaho Power had 1,119 MW nameplate capacity of PURPA-related prqects on-line, wi& an additional 29
MW nameplate capacity of projects projected to be on-line in 2019. The power purchase contracts fcr these projects have original
contract terms ranging from one to 35 years. Idaho Power's expenses associated with PliRPA-related projects were approximately
$ 190 million in 20 I 8 and $ I 70 million in 2017 .
Idaho Power also has the following long-term commitments (in thousands of dollars):
2019 t0l0 l0ll 2022 2423 Thercrftrr
Joiot-operating rgrGm.nt pa].,oeotr G)
Easefietrts and other paymetrts
Maratcaaoce and senice agracaeds (l)
FERC *ad urther industry-related fees (I)
{I) tpfnsxirl{v $)9 ni|lioo, t2-0 ril]ion- and tTl uillio sfthe obligatioos ixlnd:d iajouc-openti4g rg€"-d pa].ll6b, mir*race and m,iceageryB, aod FERC ad oiher iodustr.r.relaed &u, rspetiudS hrve cmtrct: that do mt speifr &ru nlded to eryintiou- As tha:e cmtrasts ue
Frruned to coilia{. irdrfairell'. tea 1'us of i!&ra{ioq ertimzted bued car cunerd.oltract t@s, },'r bea rrlded iu the hble fcr prreratrtiun
FqPols-
Idaho Power's expense for operating leases was not material for the years ended 20 I 8 and 2017 .
Guarantees
Through a self-bonding mechanism, ldaho 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 $58.4 million at December 31, 2018, representing IERCo's one-third share of BCC's total reclamation obligation of
$175.2 million. BCC has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs. At December
31, 2018, the value of the reclamation trust fund was $101.9 million. Dururg 2018, the reclamation trust fund made distributions of
$6.7 million for reclamation activity costs associated with the BCC surface mine. BCC periodically assesses the adequacy of the
reclamation trust fund and its estimate of future reclamation costs. To ensure that the reclamation trust fund maintains adequate
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.
Idaho Power enters into financial agreements and power purchase and sale agre€ments that include indemnification provisions relating
to various forms of claims or liabilities that may arise from the transactions contemplated by these agreements. Generally, a maximum
obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under
such indemnification provisions cannot be reasonably estimated. Idaho Power periodically evaluates the likelihood of incurring costs
under such indemnities based on its historical experience and the evaluation of the specific indemnities. As of December 3 I , 2018,
management believes the likelihood is remote that ldaho 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 liabiliry on
its consolidated balance sheets with respect to these indemnification obligations.
FERC FORM NO. 1 (ED. 12-88)Page 123.28
$ 2,901 s 2,902 $ Z,gOl $ 2,902 $ 2,902 $ 1,t.512
2,r0 1.311 r.32r 1.331 t,328 16,831
34,089 15.694 10,739 11.713 4.140 54,92'7
14.27 ,1 13.11.1 t2*714 12,71{ t2.714 63.J68
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
04116t2019
Year/Period of Report
201BtQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
10. CONTINGENCIf,S
Idaho Power has in the past and expect in the future to become involved in various claims, controversies, disputcs, 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 of parties. 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, [daho 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 uncertainfy. For matters that affect Idaho Power's
operations, Idaho Power intends to seek, to the extent permissible and appropriate, recovery through the ratemaking process of costs
incurred, although there is no assurance that such recovery would be granted.
Idaho Power is party to legal claims and legal and regulatory actions and proceedings in the ordinary course ofbusiness and, as noted
above, records 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 govemmental agencies for damages for alleged
personal injury, properry damage, and economic losses, relating to the company's provision of electric service and the operation of its
generation, transmission, and distribution facilitie s. Some of those claims relate to electrical contacts, service quality, property damage,
and wildflres. In recent years, utilities in the western United States have been subject to significant liabiliry 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 both governmental agencies and private landowners for damages for fires allegedly originating from ldaho
Power's transmission and distribution system. As of the date of this report, the companies believe that resolution of existing claims will
not have a material adverse effect on their respective consolidated financial statements. Idaho Power is also actively monitoring
various pending environmental regulations and executive orders related to environmental matters that may have a significant impact on
its future operations. Given uncertainties regarding the outcome, timing, and compliance plans for these environmental matters, Idaho
Por.ver is unable to estimate the financial impact of these regulations.
11. 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
FERC FORM NO. I (ED. 12-881 Page 123.29
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t16t2019
Year/Period of Report
2018iQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Idaho Power has two pension plans-a noncontributory dehned benefit pension plan (pension plan) and two nonqualified defined
benefit pension plans for certain senior management employees called the Security Plan for Senior Management Employees I and
Securiry 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 benehts under these plans are based on years ofservice and the employee's final average earnings.
Idaho Power's funding policy for the pension plan is to contribute at least the minimum required under the Employee Retirement
Income Security Act of 1974 (ERISA) but not more than the maximum amount deductible for income tax purposes. In 2018 and 2017,
Idaho Power elected to contribute more than the minirnum required amounts in order to bring the pension plan to a more funded
position, to reduce future required contributions, and to reduce Pension Benefit Guaranty Corporation premiums.
The following table summarizes the changes in benefit obligations and plan assets of these plans (in thousands of dollars):
FERC FORM NO. 1 (ED. 12-881 Page 123.30
Name of Respondent
ldaho Power Company
This Report is:
(1)X An Original(21 A Resubmission
Date of Report
(Mo, Da, Yr)
0411612019
Year/Period of Report
20181Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Pcnsion PIa-n S[TSP
2018 2011 !0I8 :01?
Chrnge in projccted benelit obligation:
Beac& otligatiou at Jaouary I
Scrr;ice cost
Iaterst cost
Achrrial (gara) loss
Bearfrtts pard
$ 999,344 $ 89J,060 $ [0,303 $ 99.570
37,836 13,142 (316) 7J9
38,833 38,95"1 4,248 4,315
(84,158) 6t,75s (7,050) 10,635
(3e,3e8) (36,173) (4,867) (4,e76>
951,857 999,344 102,318 110,30_?
69r,683 60r,i68
(47,681) 86,288
40,000 40,000
(16,173) -. ..:-.
lrlllJr I_Ggt 0!D t_ll9a11u !l!!JE)
Projected benefrt obligatron at Derember J 1
Ch-hgr il phn $retr:
Fair r.aluc at Jaouary I
Achtsl (loss) retum oo plerr assets
Eoployer cortibutioas
Beacfi& paid
Fat r,ahc at December 3l
FUaded status at eod ofyer
Anorats necogrized in tLe str(emelt of fneaciel position consist
of:
Othercurreatlrabrhties $ - $ - $ (J,lrB)$ (5,010)
Noacurreat Iabilities (301,253) (101,66r) (97,160) (105,293)
Net aleouat recoeaizcd S (301.253) $ (301.66t) 3 (102.318) t (110.303)
.{mornts rccoglLcd il accumulrtcd other conprthcusivc
inconc consist ofl
Ner lgs ! 278,12A $ 177,052 $ 30,496 $ 41333
Pris,r seri'ice cost 62 68 399 498
Subtoaal
Less lnoouat recorded ag regulatorl, asset
Nr( amo ,nt recognrzed h accumulded oth:l "94p*h*.ry!:q99.1 $ - S - $ 30,895 $ 41.831
.{,ccurnuhted benefit obhEation $ 814.549 $ 8i0,763 $ 94,6t0 $ 100,222
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 $92.5 million and $85.7 million at December 31, 2018 and2017, respectively, and is reflected
in Investments and in Company-owned life insurance on the consolidated balance sheets.
FERC FORM NO. 1(ED. 12-881 Page 123.3'l
nEJ,r. Xl.lro 30Jr5 4ls3t
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) _A Resubmission
Date of Report
(Mo, Da, Yr)
0411612019
Year/Period of Report
2018tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
The following table shows the components of net periodic benefit cost for these plans (in thousands of dollars). For purposes of
calculating the expected return on plan assets, the market-related value ofassets is equal to the fair value ofthe assets.
Peasion Plan SIiSP
Senrice cort
Itrterest cost
F.xFected return oo asstt
A-arortizatioa of net loss
Aaortizatioa of prior sef,rrlce cost
rolE 20t1
$ (316) S 75e
4,248 ,{.315
3,?8S
98
7,963
127
Net periodrc pmsim cost
Regutatory deferrat ofnet periodic beaefit cost 0)
Prer-iously deferred pension cost recoEnized (l)
Netpeuodic bcrcfrt cost reeognrzed frr fnaactd m,porung (l)i2t
3 7,93 I ,10.i79
(36,153) (38,6ee)
li.li+ l?,1i4
$ 18,932 $ r9J34
?,81s 8,164
10tE 20L7
$ 7.04e $ (10.635i
$ ?,818 $ 8,164
(I) Nst p$odrc b€nefit ceE ftr the pcnson piar re reogized for Errniel reportirg based upoa tbe lutlonzatioo of exi regr]dr]'prudiction ia sLich
Lbho Pow oper-le:- Uqds t.l,u-'C wda &a l&tro portioG of rat periodi. bacit cct i rrcud:d u a ngulamry asei ud L ropiad iu ee incolri€:trturd u tb* mse N r*cotsd *[ou3h ntes-
O) Of tstal Et periodic bror6t cst recoguized fw fi-'mirl ,EpofiaE tli.2 uillion md t16,) millical e:pectr,ell', szs re*ogEizsd ia 'Othr ogctircas aad
'ui*-rr.'atrd tll-6 nril$m and $11.1 oillion" rapccrtcf'. w rrcogni:cd in "Otbs erF.{5c, uEt" outtre colsoli&ted stfugt of irc of tf,e
co4aicr frtLe tw&emoathg EdEd DK@I6ll.2018 and 1011.
The following table shows the components of other comprehensive income for the plans (in thousands of dollars):
Pension Plar SIIS?
Acnurrisl (los*) gair duriag the yeu
Plan "mendme$t service cost
Reclassificatic,n adjustmeots for:
Amortizatios of net loss
Aaortkatioa of prior rervice eost
Adjusbrrd for deferred ta.x effects
AdjusEred due to lte eEects of regulatioa
!0tE !017
$ (15J16) $ (26,60Si
13,5i8
6
428
t,234
1i.190
28
l.?44
11,646
3.?88
98
(2.8 15j
2.961
lz7
1,5i5
Other c oupreheosiv e inconre reco garzed related
to peosion beaefit plans
In 2019, Idaho Power expects to recognize as components of net periodic benefit cost $16.5 million from amortizing amounts recorded
in accumulated other comprehensive income (or as a regulatory asset for the pension plan) as of Decernber 31, 2018, relating to the
pension plan and SMSP. This amount consists of $13.9 million of amortization of net loss for the pension plan and $2.5 million of
amortization of net loss and $0. 1 million of amortization of prior service cost for the SMSP.
The following table summarizes the expected future benefit payments of these plans (in thousands of dollars)
2019 2020 t0!t 202s 2014-!,928
Peosica Plan $ 3S,r7? $ 40,287 $ 42,403 $ 44,489 $ 4$,611 $ 264,707
S]\{SP 5,166 5,716 _ 5,901 6,011 6*431 I 1,86r
As of Decembcr 3 I , 2018, Idaho Power's minimum required contributions to the pension plan are estimated to be zero in 2019.
Depending on market conditions and cash flow considerations in 201 9, Idaho Power could contribute up to $40 million to the pension
FERC FORM NO. 1 (ED.12-88)?age 123.32
!$
10lE t0t7
$ 37,836 t 33,74?
38,833 38,95?
(52J02) (d5,1381
li,s58 13,190
628
$ 8,n0 $ (5,990)
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
04t16t2019
Year/Period of Report
20't8tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
plan during 2019 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,
Postretirement Benefits
Idaho Power maintains a defined benefit posffetirement benefit plan (consisting of health care and death benefits) that covers all
employees who were enrolled in the active-employee group plan at the time of retirement as well as their spouses and qualifying
dependents. Retirees hired on or after January 1, 1999, have access to the standard medical option at full cost, with no contribution by
Idaho Power. Benefits for employees who retire after 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):
t0t8 t0L7
Ch:nge in accumolated beneEt obligetiou:
Beoe6t obligetioa et Jaauary I
Service cost
Itrterest cost
Actririal (gain) toss
Beaefits paid (U
Plaa'*eudareats
$70,051 $
1,05 I
2",613
(2,688)
(4,604)
63,876
973
2,781
5,769
s,562)
)t2
Beaefit obligatioa at Deceaber 3l 66,453 ?0,051
Chrngc in plan rsscts:
Fair value of plan assets at Jarury I
Actual (loss) retum oo pla:r assets
Eaptoyer cootributroas O)
Beoefits paid (.1)
38,294
( r,330)
1,031
(+.60-1)
34,999
5,1 l2
1,?,t5
(3.562)
Fair rialoe of plao assets at DeccErbef, 3l 33,391 38.294
Funded status at end of year (mcluded i" "qS",l-"ot ]14!ihq"*)$ (3i.062) $(_1 l,? 5 7)
(i) C,*rributiou aad beo*3ts pard aru "'"h tr€t of$].l nillion ad $3.4 ullon ofplaup:ruop:n! coatnhrtoor Ss! 2018 ed i0tl, ruger:tiel-v.
Amounts recognized in accurnulated other comprehensive income consist of the following (in thousands of dollars);
2018 20t7
Net (loss) gaia
Frior renrce cost
${330) $2,171
269
(l0s)
l0s
3.046
(].046)
Subtotal
Less amormt recogri.zed ia. regulatorl'asseb
Nc( r,nouat recogaized ir accumulded otter compreheasive racome $$-
FERC FORM NO. 1 (ED. 12-88)Page 123.33
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t16t20'19
Year/Period of Report
2018tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
The net periodic postretirement benefit cost \ias as follows (in thousands of dollars)
20lE 2011
Sefi,'ice coct
htErest cost
Expected retrrn oo plen assets
Irn*ediate recognitios of loss frosr tenporsry deviatioo (I)
Asoraeatron of prim service cost
$1,051 $
3,643
(2,467)
4,2t6
+l
973
2,783
(2,307\
47
Net periodic postrelireoeat bene.fit cost $5J90 $ r.4e6
(lJ ln 2018, e lois assoEiat€d Lyith a tempore.y der/istion from the cost-sharing provisions ofthe subsErfitive plan rrlas recognized in "Odrer
exlense. net" on ttE ctrrsol;daled staterpnts of inEorre of the companies.
The following table shows the components of other comprehensive income for the plan (in thousands of dollars):
20tE 70t7
Actuarial l,oss during the yea
Prior sen-ice cost arising duriag the year
Reclassifrcdic,a adjur&caS for:
lmn"ediate recognition of loss froor teaporar]'derriatio,a {li
Reclassificilim adjuseeats for amortrzatioa ofprior senrce cost
Adjustarem for deferred tax effects
Adjustmert due to fte e&cts of regulatior
$ (1,!0e) $(2,964)
(il2)
4,216
4:7
210
(3,824)
47
807
2,122
Othec coangreheosir,e iflcoorre relat€d to po*t etifemeot beoefit plarls I $
[1] ln 2018, a lots arsociated vvith s temporary dwiation from the cost-iharing provisions of th€ sub,sEntive p]an wac recogrrized in "Other
elF€r]se, net" on th ionsoladatEd rtatements of income of the companies-
The following table summarizes the expected future benefit payments of the postretirement benefit plan (in thousands of dollars):
2019 ,010 2021 2022 7923 t0t+:0:E
Erpected beaefi t paymeuts $ 5,438 $ 5,05r $ 4.894 $ 4,112 $ C,r*S $ 20,080
FERC FORM NO. 1 (ED.12-88)Page 123.34
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Odginal
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
0411612019
Year/Period of Report
201'8tA4
NOTES TO FINANCIAL STATEMENTS (Continued)
Plan Assumptions
The following table sets forth the wcighted-average assumptions used at the end of each year to determine benefit obligations for all
Idaho Power-sponsored pension and postretirement benefits plans:
Pcrsiou Pler sltsP ?ostrctircurcut
Bocfit:
Di:couu rat
Rate of compeasaion ircrcasc 'r r
lvlcdical read nte
Deotai trcnd rate
Itlcanrcrcal dae
20lE 2017 20lE z0t7 tolE 20t7
4.55% 3.95% 4.64% 3.95% {.60% 3.95%4.25i1 4.t1% 4.75% 4.75%
I2,3lr0l8 l2ftlt20l7 123lr20l8 12.3Lt?xl'l
6.3%
t"0%
12,3U20t8
6.t',/o
{.0%
l?;31r201?
(l)Tt l0l8rr.otcoqrarsciaerurcstspoootuOrparcahilci:nruuf^rto<crrgooraof2.J0%p&lrrl.l5'tconpolrttuiirectrcqr@' thi ir brtad orarylqr*'1urof srtr. llsit rrlr]'o<r*t.t Ir ainErd to ba 8-0!6 fu rflo}tre in tdr 6m yrr of rn'i<r od xde
do$a to Oil fu qlolur u 6rir hetn[ ]r of {rtica sd bt}ud.
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:
Persiou Phn ST$P Portnctinncnt
f,2arfir.
Diloorltd rdr
EJpect"d long-tcno ratc of rctum ol
asset!
R.dc of coupcasatiotr rmrcar?
Ilcdicai Ecud ratc
DatdttndrAc
2018 ,017
3.95% 4.45%
,150y, ?.J09,;
4.25% l.|'.t%
2018 20t7
1.95% 4.45%
4.75% 4.15%
20lE !017
3.95% 4.45%
6.'15% 6.75%
-%63% 6.5%
4.4% 4_0%
The assumed health care cost trend rate used to measure the expected cost of health benefits covered by the postretirement plan was
6.3 percent in 2018 and is assumed to decrease to 5.7 percent tn2019,5.1 percent in2020,5.1 percent in2A2l and to gradually
decrease to 4.1 percentby2076. The assumed dental cost trend rate used to measure the expected cost ofdental benefits covered by
the plan was 4.0 percent, or equal to the medical trend rate if lower, for all years. A one percentage point change in the assumed health
care cost trend rate would have the following effects at December 3l, 2018 (in &ousands of dollars):
Oan-Ptrctrt*gc-Pdrr
Ircrsm Drcrcrpe
EfEct co'bal of cngt coulroreds $()A7)
(?.d83)Effect sa accumulated mrtretiremeut oblieahon 3.212
$339
Plan Assets
FERC FORM NO. 1 (ED. 12-88)Page 123.35
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
04t1612019
YearlPeriod of Report
2018tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Pension Asset Allocation Policy: The target allocation and actual allocations at December 31, 2018, for the pension asset portfolio by
asset class is set forth below:
Assct C}ss .{llotrti<ln
Actrrl
.{lhcrtior
Dcctabcr 31,rnlt
Trryct
Dtbt $cuincs
Equrn'sccurdcs
Rlal *lrtc
CIhcr ulaa asd:
u%
56%
'l l./a/e
t3%
16%
56%
60/,
r 10,l- o
T"4.1 --------J0g
-JPYIAssets are rebalanced as necessary to keep the portfolio close to target allocations.
The plan's principal investment objective is to maximize total return (defined as the sum of realized interest and dividend income and
realized and unrealized gain or loss in market price) consistent with prudent parameters of risk and the liability profile of the portfolio.
Emphasis is placed on preservation and growth of capital along with adequacy of cash flow sufficient to fund current and future
payments to plan participants.
The three major goals in Idaho Power's asset allocation process are to:
r 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 of the plan. Idaho Power sets bond allocations sufficient to cover approximately five years of
benefit pa)4rents and cash allocations sufiicient to cover the current year benefit payments. Idaho Power then utilizes growth
instruments (equities, real estate, venture capital) to fund the longer-term liabilities of the plan; and
r maintain a prudent risk profile consistent with ERISA fiduciary standards.
Allowable plan investlents include stocks and stock funds, investment-grade bonds and bond funds, real estate fi.rnds, 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/refurn 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 refums, as well as worst-case and best-case scenarios. Based on the current low interest rate environment, current
rate-of-return expectations are lower than the nominal retums generated over the past 20 years when interest rates were generally much
higher.
Idaho Power's asset modeling process also utilizes historical market returns to measure the portfolio's exposure to a "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 invesfinent style, provides the
basis for managing the risk associated with investing portfolio assets.
FEEC FORM !lO. 1 (ED. 12-88)Page '123.36
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
04t1612019
Year/Period of Report
2018tQ4
NOTES TO FINANCIAL STATEMENIS (Continued)
Fair Yalue 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'
investrnents by asset category (in thousands ofdollars).
Lcvcl I Levcl2 Lcvcl 3 Totrl
Asscr! rt Dcccurbcr 31,2018
Crh rnd crsLcquirdal.r
Sbort-tcrn bouds
Intmcdiatc bodr
Loug-tcrm bonds
Ecuin' S€firitics: Largc'Cap
Eryrq' Secrritiet: Iv[id-Crp
Equitl' Seqriticu Srall;Cry
E+iti, Srcuritict: Ir'[icruCap
Equity Sccuntics: lnrcmaaonel
Equi$' Sffrriticr: Euaglrg lvlarkee
Pbr r:sttr ucesurd rt I{AV (aot srbjcc,t to lictrrcly disclo'sulr)
Equrg' Secuntics: Globd end tltsnaioaal
Equity Securitics: Emcrginr lvfa*cB
RcaI estntc
Prir:tr arrhe inl.cs&.rb
Coroodiacs fi.ud
t 9,717 t
20,61.1
20,595
3 3 9,717
20,641
108241
40,857
7t,176
? l,4l g
53,401
30,38'
7,101
6,519
87,645
40,85j
7l,l?6
71.419
53,401
30,387
7,104
6.5t9
95,6J3
29,'t51
39,846
35,041
30.842
Totd t 290962 I 128,503 t - t 650,604
Poctctircad plla asscts, i I's lJs s 12.633 t s 33.391
FERC FORM NO.I (ED. 12.s81 Page 123.37
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(21 A Resubmission
Date of Report
(Mo, Da, Yr)
0411612019
Year/Period of Report
20181Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Lcrncll Lsrcl 2 Level 3 Totel
.{srcts rt l}cccubcr 31,2017
Carh ard casb cqunnleats
Short-tcrmbfid!
Intcrmcdiatc bonds
Log-trmbmdr
Equts Sccuriticr: Large-Cap
Equrt'Sccunticr: M&Ce
E4uiq' Scctrrsi6; $m'll -Q6p
Eqdty Sccrriticr: MforuCrp
E+ritl' Sccruitier: Iateraauooal
E{uil1' Secuntict: Encrcing ilLdflils
Phr rssets ncesurtd rr N.lV (aot subjrt to Licnrcly disclosun)
Equity Snctriti6; l6661im.l
Equrty Secuitics: Emergilg \larkcts
Rcd crm
hirate Elk t invesEeats
Cooaloditrcg fud
s 20,s52 s
20,475
20,699
t s 20,851
20A15
103,672
40,?07
95, l 79
81,127
62,502
3\153
6,114
8,?85
82,923
44.747
95,r?9
st,r2'1
62,542
32,153
6,1)1
8,?t5
83J8e
36255
38'43J
3l,6tg
3J,010
Toul s 349,146 S 123,630 S - S 697,683
Postrearmsrt phn assttr t"I 56? t 3?,?27 $$ 38J94
(l) fL poiE.srDr.lt b.i.ft! r!.!E lr Finrgib'li& rsrruc. cfirrrc!.
For the years ended December 31, 2018 and 2017 " there were no material transfers into or out of Levels 1,2, or 3
FERC FORM NO. 1 (ED.12-88)Pase 123.38
Name of Respondent
ldaho Power Company
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
0411612019
Year/Period of Report
2018tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Fair Value Measurement o.f Level 2 Plsn asse* and PIan assets ,neasured at NAV:
Level 2 Bonds: These investments represent U.S. government, agency bonds, and corporate bonds. The U.S. government 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 Postretirernent Asset: This asset represents an investment in a life insurance contract and is recorded at fair value, which is the
cash surrender va1ue, less any unpaid expenses. The cash surrender value ofthis irsurance contract is contractually equal to the
insurance conffact's proportionate share of the market value of an associated investrnent 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.
Comminsted Funds: These funds, made up of the global, international, emerging markets equity securities, and commodities fund
measured at NAV, are 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 hnds have redemption limitations that permit monthly redemption following notice requirements of 5 to 7
days.
Real Estatc: Real estate holdings represent investments in commingled real estate funds. As the property interests held in these real
estate funds are not frequently traded, establishing the market value of the property interests held by the fund, and the resulting unit
value of fund shareholders, is based on unobservable inputs including properly 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 properly values, and comparisons with sale prices of similar properties ur sirrular markets. These real estate funds also
furnish annual audited hnancial statements that are also used to further validate the information provided. Redemptions are generally
available on a quarterly basis, with l0 to 35 days written notice, depending on the individual fund. If the fund has sufltcient liquidity,
thc 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.
Private Markct 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 underlying fund holdings divided by the fund shares
outstanding or multiplied by the ownership percentages of the holder. Some hedge fund strategies utilize securities with readily
available market prices, while others utilize less liquid investment vehicles that are valued based on unobservable inputs including
cost, operating results, recent 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 fulI redemption, a reserye amount of 5Yo to I 0% 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 inveshnents are valued based on unobservable
inputs including cost, operating results, discounted cash flows, the price of recent funding events, or pending offers from other viable
entities. These private market investrnents furnish amual audited financial statements that are also used to further validate the
FERC FORM NO. I (ED. 12-881 Page 123.39
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2\ _ A Resubmission
Date of Report
(Mo, Da, Yr)
04t16t2019
Year/Period of Report
201BtQ4
NOTES TO FINANCIAL STATEMENTS {Continued)
information provided. These funds are formed for a stated life of 10 to 15 years. The general partner can extend the fund life for 2 or 3
ono-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.
Employee Savings PIan
Idaho Power has a defined contribution plan designed to comply with Section 401(k) of the Internal Revenue Code and that covers
substantially all employees. Idaho Power matches specified percentages of employee contributions to the plan. Matching annual
contributions were approximately $7.7 million and $7.4 million in 2018 and 2017, respectively.
FERC FORM NO. 1 (ED.12-88)Page 123.40
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
04116t2015
Year/Period of Report
20181Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
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 Idaho Power's consolidated balance sheets at December 31, 2018, and
2017, were approximately $2 million.
12. PROPERTY, PLAI\T AtrD EQUTPMENT AND JOTNTLY-OWNED PROJECTS
The following table presents the major classiircations of Idaho Power's utility plant in service, annual depreciation provisions as a
percent of average depreciable balance, and accumulated provision for depreciation for the years ended December 31, 2018 and.2}fi
(in thousands of dollars):
:0lE 20t7
Ar:-Bete Erlerec Atc.Rrtc
Productoq
Trancml$rou
Disrrbution
Gcacral axd Otb.r
3 2.6J4.20r
l:01.092
1,792294
2.598,940
1,t63:,40
1,710,126
433.356
3.t0% t
1.8970
22A%
6.40%
3.07%
t.9t%
2.U%
6.0t%
2.81%
Jnrrsi f--lt$.0ll t f30?-888
At December 31, 2018, Idaho Power's construction work in progress balance of S480.3 million included relicensing costs of $297.0
million for the HCC, Idaho Power's largest hydroelectric complex. In 2018, 2017 , and 201 6, the IPUC authorized Idaho Power to
include in its ldaho jurisdiction rates $6.5 million annually ($8.8 million when grossed-up for the effect of income taxes in 2018 and
$10.7 million when grossed-up for the effect of income taxes in 2017 and 2016 prior to income tax reform described in Note 2 -
"Income Taxes") of AFUDC relating to the HCC relicensing project. Collecting these amounts will reduce the amor,rnt collected in the
future once the HCC relicensing costs are approved for recovery in base rates. At December 31, 2018, Idaho Power's accumulated
provision for rate refunds for collection of AFLIDC relating to the HCC was $135.1 million.
Idaho Power's ownership interest in three jointly-owned generating facilities is included in the table above. Under the joint operating
agreements for these facilities, each participating utility is responsible for financing its share of construction, operating, and leasing
costs. Idaho Power's proportionate share of operating expenses for each facility is included in the Consolidated Statements of Income.
These jointly-owned facilities, including balance sheet amounts and the extent of Idaho Power's participation, were as follows at
December 31, 2018 (in thousands of dollars):
FERC FORM NO. 1 (ED. 12-88)Page 123.41
6.103-856
e,210,781)
2.U% 5.906.162
(2,09SJ74)
Brlrncc
Total ia scn{cc
.{ccwrulatd prorisiou fs dcprecratiou
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
o4t16t2019
Year/Period of Report
2018!Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Neme of Plalt Locrtinn
l'tilii'
Plart ir
Service
Constrrt{ior\ffo*ir
Prcgress
Acsumulated
Prcvisiol for
Doprechtion
s 334.131
1,1,148
2',?9.6$
Olotrship
gb l}flltl)
JirBn&erunits l4
Boardman
Valrnvuniu I and2
R.och Spriner. W'l'
Bmrdman, OR
\tiuremucca, t.IV
I ?33.451 S
81.4i9
410,947
J.141 31
t0
50
't7t
64
u4
4
2.18
(I) Id:ho Pouu's slse of oauplne capaoir
IERCo, Idaho Power's wholly-owned subsidiary, is a joint venturer in BCC. Idaho Power's coal purchases from the joint venture were
$8 1 .8 million in 2018 and $86.4 million in 2011 .
Idaho Power has contracts to purchase the energy fiom four PURPA qualifying facilities that are 50 percent owned by Ida-West. Idaho
Power's power purchases from these facilities were $9.7 million in 2018 and $9.8 million n2A17.
13. ASSET Rf,TIREMENT 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 entify 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. lf, 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 facilify are
exempted from such regulatory treatment as Idaho Power is now collecting amounts related to the decommissioning of Boardman in
rates.
Idaho Power's recorded AROs relate to the removal of polychlorinated biphenyl-contaminated equipment at its distribution facilities
and the reclamation and removal costs at its jointly-owned coal-fired generation facilities.
Idaho Power also has additional AROs associated with its transmission system, hydroelectric facilities, natural gas-fired generation
facilities, and jointly owned coal-fired generation facilities; however, due to the indeterminate removal date, the fair value of the
associated liabilities curently cannot be estimated and no amounts are recognized in the consolidated financial statements,
The following table presents the changes in the carrying amount of AROs (in thousands of dollars):
FERC FORM NO. I (ED. 12-881 Page 123.42
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2\ _ A Resubmission
Date of Report
(Mo, Da, Yr)
04t16t2019
Year/Period of Report
2018/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
2018 2AL7
Balancc 6l !3grrnins ofrcar
.{csetion rxpcnse
Rcruisios in estirutcd cash lour
Liabilit'r&crurcd
Liability rcnlcd
3 26-415 3
1,0_s5
05l)
r29
(56)
26257
I,01-\
o9l)
(66)
Balance at end ofvear S 26.1n S 26J15
14.INVESTMENTS
The table below summarizes Idaho Power's inve stments as of December 3 I (in thousands of dollars):
20tE 2Al7
s 5?,026 3
36,41t
17
122t3
30,2{9
l7
Tml Idaho Pon'er mves@ents 93.51{102.4?9
Investments in Equity Securities
Investments in securities classified as available-for-sale securities are reported at fair value. Any unrealized gains or losses on
available-for-sale securities are included in income, as the fair value option has been elected for these instruments. Unrealized gains
and losses on available-for-sale securities were immaterial at December 3 I , 201 8 and December 31 , 2017 . The following table
summarizes sales of available-for-sale securities (in thousands of dollars):
!018 2017 !016
hocreds from oles
Gross rerlized gaing fr6m salss
$5.00? t ,+.989 i 15.693
54
15. DERIVATIVI FINAI{CIAL INSTRUMENTS
Commodify 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 intluenced 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
FERC FORM NO. 1 (ED. 12-88)Page 123.43
Idabo Pouu inrufiaent:
IERCO
Excbange ts'aded rhort-tsm boud filrdt alrd cash equivaleutr
Exccntiw dcfrrrcd co@paldrou ptre im'ctulpts
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
04t1612019
Year/Period of Report
20181Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
exposures. The primary objectives of Idaho Power's energy purchase and sale activiry are to meet the demand of retail electric
customers, maintain appropriate physical reseryes to ensure reliability, and rnake economic use of temporary surpluses that may
develop.
All of idaho Power's derivative instruments have been entered into for lhe purpose of economically hedging forecasted purchases and
sales, though none of these instruments have been designated as cash flow hedges. Idaho Power offsets fair value amounts recognized
on its balance sheet and applies collateral related to derivative instruments executed wrth the same counterparty under the same master
netting agreement. Idaho Power does not offset a counterparty's current derivative contracts with the counterparfy'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
transacfions executed under the master netting arrangement. These fypes of transactions may include non-derivative instruments,
derivatives qualifuing for scope exceptions, receivables and payables arising from settled positions, and other forms of non-cash
collateral (such as letters of credit). These types of transactions are excluded &om the offsetting presented in the derivative fair value
and offsetting table below.
The tablc below presents the gains and losses on derivatives not designated as hedging instruments for the years ended December 3 l,
2018 and 2017 (in thousands of dollars):
Locrtioa of Rrrlized Geiil(!"ors) oa Grir(Loss) or Dcrireth'* Rccopiztd ir hcorc 0l
Ihrh,rth'ct Rccognizcd in hconc !0lS 201?
Finaacirl $r"p!
Firuncral srrzps
Firarciel sn'apc
Firaacial nraps
Fonrrrd coatrart!
Fonrzrd co[Eects
Fonrzrd contracB
1,316 t
?.gtg
22,563
lrg
4t
(54)
(186)
Opcratiu relralrsr
hrchascd porrcr
Ftrloqcar
Otbcr opcrabonr and mautenarce
Opraing rctraues
h.rchased por.-erFqlry
s 902
166
701
(s4)
J5
(6e)
4
(t) Exrfudrr rsr:lnrd frar fi lotra. G drrlr:lrru, Irhi(! sr rrcadrd r &r bdc.r rbrc a ratulSa,\'i!.r! c rtgul*e1'bbrlrt.r.
Settlement gains and losses on electricify 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 l6 - "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 ofderivatives recognized as assets and as liabilities to the net amounts presented in the
balance sheets at December 31, 2018 and2017 (in thousands ofdollars);
FERC FORM NO. I (ED. 12-88)Page 123.44
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
0411612019
Year/Period of Report
2018/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Asset Dcrh'rtivcs Lie Dcri.-:th'cs
.{oouots I\.-.tOfBct LirbiliticsBrleace Shcet Location
Gr.oss
Frir .{.uoulrtr
Off,rct
Nct
Asscts
Gnost
Frirl|rhr
Dcccabcr 31, 2018
Curreot:
Fiuacirl runps
Fioeacial ra'epr
Fonrrrrd cootracts
Loag-trm:
Fitucirl rwrpl
Othcr crrmed rcsaG
Othcr curcat liabi[ticr
Ottcr curreat liabiliticc
Othcr liabilitics
3 .1,639 t (98{) 0} 3 3,6ri S 938 3
806
104
64
(e38) 3
8;
104
64
Total I .r.639 S (93J) S 1.6-it S t.9ll S (gis)$
$
974
Deccnbcr 31, 2017
Currrat:
Firaacral sr*'aps
Fiaeocid rrr'rpr
Fonrrard coatracts
Loog-rcra:
Fiaeocial swapr
Othcr currcat ascctJ
Oticr curreat liabiliticc
Other currcat liabiliticr
Otler asrcts
t8$
553
$ r83
.l
o48) CI
$E
(553)1,971
2
t,221
2
J
-s!-- t-:JJ. I-gIi) !-:3- !-Jelr !-gg)
I) C\rrautdcnrril'.rEoutoofEaiuchrdr95thorgzadofcollrtrrdp:,yzblc&rtbrpcrrodcoii.gDcccurbrr3l,:01S.
2) Currrar lubrhg' drmzorr emor.ruts ofBa irludr J I 95 Aousrd of colL*"el rrcrirzbh ftr thr prnod sdrnr Drcooba 3 I , 20 I I
The table below presents the volume s of derivative commodity forward contracts and swaps outstanding at December 3 I , 201 8 and
2011 (in thousands of units):
Dcccmber 31,
Conmoditv Unitc 20rE 7
Elcctricity purchascs
Electricity sder
Naturd gupurelacr
Natural ras tales
s t225G
MWb
N{\\,'h
MMBtU
I\'IhlBnr
52
39
7,514
.r46
3t2
224
7,028
l{0
FERC FORM NO. I (ED. 12-88)Page 123.45
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t16t2019
Year/Period of Report
2018/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Credit Risk
At December 3l,2078,Idaho Power did not have material credit risk exposure from financial instruments, including derivatives. Idaho
Power monitors credit risk exposure through reviews ofcountelparty credit quality, corporate-wide counterparty credit exposure, and
corporate-wide counterparty concentration levels. Idaho Power manages these risks by establishing credit and concentration limits on
transactions with counterparties and requiring contracfual guarantees, cash deposits, or letters ofcredit from counterparties or their
affiliates, as deemed necessary. Idaho Power's physical power conffacts are comrnonly under WSPP, Inc. agreements, physical gas
contracts are usually under North American Energy Standards Board contracts, and financial transactions are usually under
Intemational Swaps and Derivatives Association, Inc. contracts. These contracts contain adequate assurance clauses requiring
collateralization ifa counterparly has debt that is downgraded below investment grade by at least one rating agency.
Credit-Contingent Features
Certain of Idaho Power's derivative instruments contain provisions that require Idaho Power's unsecured debt to maintain an
investment grade credit rating from Moody's Investors Service and Standard & Poor's Ratings Services. If Idaho Power's unsecured
debt were to fall below investment grade, it would be in violation of these provisions, and the counterparties to the derivative
instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative
instruments in net liability positions. The aggregate fair value of all derivative instruments with credit-risk-related contingent features
that were in a liability position at December 3l , 20 I 8, was $ I .9 million. Idaho Power posted no cash collateral related to this amount.
If the credit-risk-related contingent features underlying these agreements were triggered on December 31, 2018, Idaho Power would
have been required to pay or post collateral to its counterparties up to an additional $7.8 million to cover open liability positions as
well as completed transactions that have not yet been paid.
16. FAIR VALUE MEASUREMENTS
Idaho Power has categorized its financial instruments into a tbree-level fair value hierarchy, based on ths priority of the inputs to the
valuation technique. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or
liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). If the inputs used to measure the financial instruments fall
within different levels of the hierarchy, the categorization is based on the lowest level input that is significant to the fair value
measurement of the instrument.
Financial assets and liabilities recorded on the consolidated balance sheets are categorized based on the inputs to the valuation
techniques as follows:
Level l: Financial assets and liabilities whose values are based on unadjusted quoted prices for identical assets or liabilities in
an active market that Idaho Power have the abiliw to access.
Level2: Financial assets and liabilities whose values are based on the foilowing:
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 fuIl term of the asset or liability: and
d) pricing models whose inputs are derived principally from or corroborated by observable market data through
FERC FORM NO.1 1 123.468t
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
0411612019
Year/Period of Report
20181Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
correlation or other means for substantially the full term of the asset or liability
Idaho Power Level2 inputs are based on quoted market prices adjusted fbr 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 unobsenable and signihcant to the overall fair value measurement. These inputs reflect management's own assumptions
about the assumptions a market participant would use in pricing the asset or liability.
Idaho Power's assessment of a particular input's significance to the fair value measurement requires judgment and may affect the
valuation of fair value assets and liabilities and their placement within the fair value hierarchy. An item recorded at fair value is
reclassified among levels when changes in the nature of valuation inputs cause the item to no longer meet the criteria for the level in
which it was previously categorized. There were no transfers between levels or material changes in valuation techniques or inputs
during the years ended December 31, 2018 and2017.
The following table presents information about Idaho Power's assets and liabililies measured at fair value on a recurring basis as of
December 31, 2018 and2017 (in thousands of dollars):
I)'cctmbrr 31, !,OlE Darmbtr 3tn:017
Lctcl I La'd I L€r'cts Totel Lclcl I Lcrlll I Lrtrl J Terrl
Ass.tr:
Itloocryna*a filo& rod comnarnl prpcr
Denrmrxa
Eqrr$ rcoritcr
Lhbilitict:
Denrsr,tc
$?9,118
;,6J5
36,488
*t- t?9J28 t1€,2d0
3,61J t:
36.4t8 vr.2f6
t- 310.260
11
1o,256
$-
r 970-r 104r -r e74t 1*, ! -s lr{1
iU tlo1diDg co!Bpa.u]'or!,r Does nst irclude aaouatg held Q'- Id:ho Posser.
Idaho Power's derivatives are contracts entered into as part ofits management ofloads and resources. Electriciry 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 investrnents 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 hnancial instruments that are not reported at fair value, as of
December3l.20l8 arrd20lT,usingavailablemarketinformationandappropriatevaluationmethodologies(inthousands).
FERC FORM NO. 1 (ED. 12-8el Page 123.47
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(21 A Resubmission
Date of Report
(Mo, Da, Yr)
o411612019
Year/Period of Report
2018tO4
NOTES TO FINANCIAL STATEMENTS (Continued)
Dcccobcr 31, 2018 Dcccarbcr 3l 20t7
Cerrytug
Asoount
Estinrtcd Fdr
ljelqe
Cerryil3
Auouut
Esttnetcd Feir
lUqe
LllbiEdcc:
Loag-tcra dcbt (l)5 l.s3+.788 t
(ttousetrds ol dollarsl
1,942.1i3 S 1,7.16,13 $l.9l t,4J9
(l) Lmt-tra &h rn c:tgmlrd u Ll'C 3 erd Lcrd l, nrprttdy, of,tte Et rzlrr hirrcb., a dfu rglirr ra Air Na* 16 - "Feir Vdlr
llr.lrrr&.!b.'
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, 2018 and2017 (in thousands of
dollars). Items in parentheses indicate reductions to AOCI.
I'eer Ended December 3l
2018 2Dr7
Defired baefit pea.irru items
Balmce at begirurra.g of period $ (26.872) $ (20-8s2)
5.234 (7.872)
2,886 1,882
Otfer coarorcheosive iacome before recl,ascilications
.tmormts reclassified out ofAOCI to uet incoare
Net cureot-period ottcr coapreheasive ircooe
Cr:arulatj',,e 6ffsf,1 sf el'ante in acrounhag priaciple (t)
8.120
(4,0e1;
(5.990)
Balaace at eud ofperiod L----122.1!{} $-_-*_G!.9i2)
(1) In November 2018, the FERC issued a final accounting orderallowing certain entities" including Idaho Power, to make a policy election to reclassif, the
stranded tax effects resulting from income tax refonn frorn AOCI to retained eamings in accordance with ASU 20 1 8-02, lncome Statement^ -Reporting
Comprehensive Income (Topic 220).ln2018.ldaho Power transfercd $4.1 rnillion frorn AOCI to rctainod earnings.
The table below presents the effects on net income of amounts reclassified out of components ofAOCI and the income statement
location of those amounts reclassified during the years ended December 3 I , 201 8 and 2017 (in thousands of dollars). Items in
parentheses indicate increases to net income.
FERC FORM NO. 1 (ED. 12-88)Page 123.48
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(21 A Resubmission
Date of Report
(lrlo, Da, Yr)
04116t2A19
Year/Period of Report
2018tO4
NOTES TO FINANCIAL STATEMENTS (Continued)
Amount Rechssified from AOCI
Year f,nded Decembcr 31,
20lE 2011
Amortizatioa of defined beaeflt peersioa ilerrr(n
Prior senice eost
Net loss
$e8$
3,788
l?7
2,963
Total before tmr
Tax besefit'l)
3.886
(1.000)
3.090
( r,20 8)
Net of tfl 2.886 1.8s2
Total reclagsificalioo for the period $2-8S6 $1 -8S?
(lj .Juooruzrroo of tLese itemg ig included i.o Idrho Porvg's coasoiidaed iucoou statemerrE iu o6g ryenre, net"
CJ) TLe tc bec6f n ilcluded ilr ircrlm bx ryeare in ttt corgolidaed imoure it*eortab of Idalc Poner.
18. RELATED PARTY TRANSACTIONS
IDACORP: Idaho Power performs corporate functions such as financial, legal, and management services for IDACORP and its
subsidiaries. Idaho Power charges IDACORP for the costs of these services based on service agreements and other specifically
identified costs. For these services, ldaho Power billed IDACORP $0.7 million in both 2018 and2017.
AtDecember31,2018 and20lT,IdahoPowerhada$l.9millionand$5T.3millionpayabletoIDACORP,respectively,whichwas
included in its accounts payable to affiliates balance on its corsolidated balance sheets. In 2018, Idaho Power paid IDACORP certain
estimated income taxes that had been accrued at December 31,2017 .
Ida-West: Idaho Power purchases all of the power generated by four of Ida-West's hydroelectric projects located in Idaho. Idaho
Power paid Ida-West $9.7 million in 2018 and $9.8 million in2017 for that power.
FERC FORM NO. 1 (ED. 12-88)Page 123.49
Nam€ of Respondent
ldaho Power Company (2)A Resubmission
uate ot Hepon(Mo, Da, Yr)
0411612019
YearHenoo oI Kepon
End of 2018lor4
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), (f), and (g) report other (specify) and in
column (h) common function.
Line
No.
Classification
(a)
Total Company for the
Current YeariQuarter Ended
(b)
Electric
(c)
I Utility Plant
2 ln Service
Plant in Service (Classified)6,1 03,1 04,829 6,103,104,829
4 Property Under Capital Leases
5 Plant Purchased or Sold
6 Completed Construction not Classifi ed
7 Experimental Plant Unclassifi ed
8 Total (3 thru 7)6,103,104,829 6,1 03,1 04,829
I Leased to Others
10 Held for Future Use 4,751,462 4,751,462
11 Construction Work in Progress 480,258,675 480,258,67s
12 Acquisition Adjustments 750,893 7s0,893
13 Total Utility Plant (8 thru 12)6,588,865,859 6,588,865,859
14 Accum Prov for Depr, Amort, & Depl 2,394,578,627 2,394,578,627
15 Net Utility Plant (13 less 14)4,194,287,232 4,194,287,232
't6 Detail of Accum Prov for Depr, Amort & Depl
17 ln Service:
18 Depreciation 2,369,301,348 2,369,301,348
19 Amort & Depl of Producing Nat Gas Land/Land Right
2A Amort of Underground Storage Land/Land Rights
21 Amort of Other Utility Plant 25,229,722 25,229,722
22 Total ln Service (18 thru 21)2.394,531,070 2,394,531,070
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 47,557 47,557
33 Total Accum Prov (equals 14) (22.26,30,31 ,32)2,394.578,627 2,394,578,627
FERG FORM NO. 1 (ED. 12.89)Pag€ 200
ldaho Power Company (1)
(2)Resubmission
Date of Report
(Mo, Da, Yr)
04116t2019
Year/Period of Report
End of 2018/Q4
1. Report below the original cost of electric plant in service according to the prescribed accounts.
2. lnadditiontoAccountl0l,ElectricPlantinService(Classified),thispageandthenextincludoAccountl02,ElectricPlantPurchasedorSold;
Account 103, Experimental Electric Plant Unclassified; and Account 106, Completed Construclion Not Classified-Electric.
3. lnclude in column (c) or (d), as appropriate, conections of additions and retirements for the current or preceding year.
4. For revisions to the amount of initial asset retirement costs capitalized, included by primary plant account, increases in mlumn (c) additions and
reductions in column (e) adjustments.
5. Enclose in parentheses credit adjustments of plant accounts to indicate the negative effect of such accounts.
6. Classify Account 106 according to prescribed accounts, on an estimated basis if necessary, and include the entries in column (c). Also to be included
in column (c) are entries for reversals of tentativo 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 en €stimated basis, with appropriate contra entry to the account for accumulated depreciation provision. lnclude also in column (d)
Line
No.
Account
(a)
BalanceBeginning of Year
(b)
Aclditions
(c)
1 1. INTANGIBLE PLANT
2 (301) Organization 5,703
3 (302) Franchises and Consents 2.828.359
4 (303) Miscellaneous lntangible Plant 26,616,961 11,042,574
5 TOTAL lntanqible Plant (Enter Total of lines 2, 3, and 4)57,292,347 13.870.933
6 2. PRODUCTION PLANT
7 A. Steam Production Plant
8 (3'10) Land and Land Riqhts 1.722.42',1
I (31 1) Structures and lmprovements 154.463.765 2,107.274
10 (312) Boiler Plant Equipment 757.671J26 12,516,851
11 (313) Engines and Engine-Driven Generators
12 (314) Turboqenerator Units I 2.858,191
13 (315) Accessory Electric Equipment 73,750,009 1,064,174
14 (316) Misc. Power Plant Equipment 20,152,814 2,385.775
15 (317) Asset Retirement Costs for Steam Production 14,889,891 -733.1 46
16 TOTAL Steam Production Plant (Enter Total of lines 8 thru 15)1 ,192,509,651 20,199,1 15
't7 B. Nuclear Production Plant
18 (320) Land and Land Rights
19 (321) Structures and lmprovements
20 (322) Reactor Plant Equipment
21 (323) Turbogenerator Units
22 (324) Accessory Electric Equipment
23 (325) Misc. Power Plant Equipment
24 (326) Asset Retirement Costs for Nuclear Production
25 TOTAL Nuclear Production Plant (Enter Total of lines 18 lhru 24)
26 C. Hydraulic Production Plant
27 (330) Land and Land Rights 31,497,639 157.426
28 (33'l ) Structures and lmprovements 196,242,642 4,101,160
29 (332) Reservoirs. Dams. and Waterways 273,545.283 2,182,772
30 (333) Water Wheels, Turbines, and Generators 260,309,413 31,719,160
31 (334) Accessory Electric Equipment 2,039,620
32 (335) Misc. Power PLant Equipment 2s.991 ,708 1,090.249
33 (336) Roads, Railroads, and Bridqes 10,881 ,683 1,004,050
34 (337) Asset Retirement Costs for Hydraulic Production
35 TOTAL Hydraulic Production Plant (Enter Total of lines 27 lhru 34)860,933,235 42.294.437
36 D. Other Production Plant
37 (340) Land and Land Rishts 2,690,006 9,788
3B (341) Structures and lmprovements 143.332.756 34,376
39 (342) Fuel Holders, Producls, and Accessories 10,537,569 177.298
40 (343) Prime Movers 224.537.829 10,259,022
41 (344) Generators 182J72
42 (345) Accessory Electric Equipment 91 ,478,361 403,449
43 (346) Misc. Power Plant Equipment 6,388,713 102.375
44 (347) Asset Retirement Costs for Other Production
45 TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44)545,497,110 11,168,480
46 TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45)2,598,933,9S6 73,662,032
FERC FORM NO.1 (REV.'t2.05)Page 204
30.669.68:
I
62,464.86i
I
66.531.87(
Name
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
0411612019
Year/Period of Report
End of 20181Q4
and 1
distributions of these tentative classifications in columns (c) and (d), including the reversals of the prior years tentative account distributions of these
amounts. Careful observance of the above instructions and the texts of Accounts 101 and 106 will avoid serious omissions of the reported amount of
respondent's plant actually in service at end of year.
7. Show in column (f) reclassifications or transfers within utility plant accounts. lnclude also in column (Q the additions or reductions of primary account
classifications arising from distribution of amounts initially recorded in Account 102, include in column (e) the amounts with respect to accumulated
provision for depreciation, acquisition adjustments, etc., and show in column (f) only the offset to the debits or credits distributed in column (f) to primary
account classifications.
8. For Account 399, state the nature and use of plant included in this account and if substantial in amount submit a supplementary statement showing
subaccount classification of such plant conforming to the requirement of these pages.
9. For each amount comprising the reported balance and changes in Account 1 02, state the property purchased or sold, name of vendor or purchase,
and date of transaction. lf proposed journal entries have been liled with the Commission as required by the Uniform System of Accounts, give also date
Retirements
(d)
Adjustments
(e)
Transfers
(0
Balance at
End of Year(s)
Line
No.
1
5.703 2
33,498,042 3
8,631,209 29,028,326 4
8,631,209 62.532.071 5
o
I
1,722,421 8
501 ,81 1 156,069,228 9
6,3s1,836 763,836,1 41 10
11
328,089 172.389.727 12
155,844 74,658,335 13
507.310 22.031 .279 14
14,156,745 15
7,844,890 1,204,863,876 16
17
18
19
20
21
22
23
24
25
26
31,655,065 27
417,519 199,926,283 28
541,606 275,186.449 29
981,961 291,046,612 30
722,285 63,782,202 31
462,800 26,619,157 32
4,000 1 1,881 ,733 33
34
3,130,'171 900.097.501 35
Jb
2,699.794 37
28,341 143,338,791 38
10.714.867 39
7,352.522 227,443,929 40
66,714,048 41
44,618 91.837,192 42
6,491,088 43
44
7.425.881 549.239,709 45
18.400,942 2,654,201,086 46
FERC FORM NO.1 (REV.12-05)Page 205
I
I
S:
ldaho Power Company (1)
(2)
An Original
A Resubmission
(Mo, Da,
04116t2019
Year/Period of Report
End of 20181Q4
1
Lrne
No.
Account
(a)
Additions
(c)
47 3. TRANSMISSION PLANT
48 (350) Land and Land Riqhts 37,127.446 1.796.147
49 (352) Structures and lmprovements 80,263,617 779,590
50 (353) Station Equipment 428,949,669 14,651,950
51 (354) Towers and Fixtures 206.552.729 4,834.230
52 (355) Poles and Fixtures 1 83,335,657 14,396,763
53 (356) Overhead Conductors and Devices 226,621,106 8,673,207
54 (357) Underground Conduit
55 (358) Underqround 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 ,163,240,490 45,131.887
59 4. DISTRIBUTION PLANT
60 (360) Land and Land Riqhts 6,052,619 500,666
61 (36'1 ) Structures and lmprovements 2.929.310
62 (362) Station Equipment 237,332,109 18,934,953
63 (363) Storage Battery Equipment
M (364) Poles, Towers, and Fixtures 265,381,383 9,083.493
65 (365) Overhead Conductors and Devices 136,069,938 6,625,653
66 (366) Underqround Conduit 'l ,932,1 18
67 (367) Underoround Conductors and Devices 258,499,754 20,485,907
68 (368) Line Transformers 560,033,828 35,074,016
69 (369) Services 60.786,068 1,715,228
70 (370) Meters 90,021,168 6.730,337
71 (371) lnstallations on Customer Premises 3,057,356 120,491
72 (372) Leased Propertv on Customer Premises
73 (373) Street Lighting and Signal Systems 4,526,921 112,690
74 (374) Asset Retirement Costs for Distribution Plant 142,630
75 TOTAL Distribution Plant (Enter Total of lines 60 thru 74)1,710,126,217 104,244.862
76 5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT
77 (380) Land and Land Rights
78 (381) Structures and lmprovements
79 (382) Computer Hardware
80 (383) Computer Software
81 (384) Communication Equipment
82 (385) Miscellaneous Regional Transmission and Market Operation Plant
83 (386) Asset Retirement Costs for Reqional Transmission and Market Oper
84 TOTAL Transmission and Market Operation Plant (Totral lines 77 thru 83)
85 6, GENERAL PLANT
86 (389) Land and Land Riqhts 17 282.090
87 (390) Structures and lmprovements 120.654,120 7.025.068
88 (391) Office Furniture and Equipment 44,912,532 9,506,697
89 (392) Transportation Equipment 88,148,894 8.314.242
90 (393) Stores Equipment 2,947,647 86.112
91 (394) Tools. Shop and Garaqe Equioment 10,438,'t64 800,860
92 (395) Laboratory Equipment 13,869,062 341,551
93 (396) Power Operated Equipment 16.265.279 3.045.89S
94 (397) Communication Equipment 54,135,749 1,090,906
OA (398) Miscellaneous Equipment 6.979,1 00 707,965
96 SUBIOTAL (Enter Total of lines 86 thru 95)375.812,01 1 31.201.390
97 (399) Other Tangible Property
98 (399.1) Asset Retirement Costs for General Plant
99 TOTAL General Plant (Enter Total of lines 96, 97 and 98)375.8',12.011 31 ,201 ,390
100 TOTAL (Accounts 101 and '106)5,905,411,061 268,'t11.104
101 (102) Electric Plant Purchased (See lnstr. 8)
102 (Less) (102) Electric Plant Sold (See lnstr. 8)
103 (103) Exoerimental Plant Unclassified
104 TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103)5,905,411,061 268,111,104
FERC FORM NO.1 (REV.12.0s)Page 206
I
37.463.37i
50.759.07t
ldaho Power Company (1)
(2)
An Original
A Resubmission 04t1612019
Year/Period of Report
End of 2018/Q4
103 and Continued)
Retirements
(d)
Adjustments
(e)
Transfers
(fl
Balance at
End of.Year(s)
Line
No.
47
56 38,923,537 48
19,413 81,023,794 49
2,575,92',1 44'1,02s.698 50
29,119 211,357,840 51
2,524,737 195,207,683 52
2,131,230 233,1 63,083 53
54
55
390.266 56
57
7.280.476 1,201,091,901 58
59
6,553,285 60
148,927 40,283,756 61
1,903,678 254,363,384 62
63
2.768.978 271,695,898 64
2.210.426 140,485.165 65
453,187 52,238,001 66
3,016,630 275,969,031 67
7,515,663 587,592,181 68
581 ,568 61,919,728 69
3,424,210 93,327,295 7A
53,515 3,124.332 71
72
50.726 4,588,885 73
142,630 74
22,087,508 1,792,283,571 75
76
77
78
79
80
81
82
83
84
85
17.743.554 86
160,419 127,518,769 87
5.912.746 48,506,483 88
3,597,458 92,865.678 89
10,654 3,023,105 90
144J60 11 ,094,864 91
507,083 13.703.530 92
76,867 19,234.311 93
3,297,353 51,929,302 94
310.461 7.376.604 95
14,017,201 392,996,200 96
97
98
14,O17,201 392.996,200 99
70,417,336 6,1 03.1 04,829 100
101
102
103
70.417,336 6,1 03,1 04,829 104
FERC FORM NO.1 (REv.12.0s)Page 207
ldaho Power Company 1)An
(2)A Resubmission
Date of Report
(Mo. Da, Yr)
0411612019
Year/Period of Report
End of 2018/Q4
1. Report separately eactr 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 kansferred to Account 105.
Line
No.
Descriotion and Locationbf P6frty tn
t alance at
End of Year(d)
1 Land and Rights:
2 Boise Operations Center 12t31182 202012021 480,501
3 Production 109,961
4 Transmission Stations 423,088
5 Transmission Lines 195,489
6 Distribution Stations 1,084,696
7 Beacon Light Substation 12t30t02 2020 465,662
I Homedale Substation 2129t08 2035 109,453
I Line #854 500 Kv 3/31/09 2024 308,066
10 General Plant 62,673
'11 Distribution Line 25,581
12
13
14 Column B and C if no date listed it is various
15
16
17
18
'19
20
21 Other Property:
22 Transmission Stations 199,069
23 Distribution Stations 69,941
24 Homedale Substation 2t29t08 2035 217,797
25 Beacon Light Substation 12t30t02 2020 555,940
26 Underground Vault, Blaine County 8/30/16 2021 443,545
27
28
29
30 Column B and C if no date listed it is various
3'1
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47 Total 4,751,462
FERC FORM NO.1 (ED.12-96)Page 214
Name Respondent ls:
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo. Da, Yr)
0411612019
YealPeriod of Report
End of 20181Q4
CONSTRUCTION WORK lN PROGRESS - - ELECTRIC (Account 107
1 . Report below descriptions and balances at end of year of projects in process of construction (107)
2, Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see
Account 107 of the Uniform System of Accounts)
3. Minor projects (5% of the Balance End of the Year for Account 107 or $1,000,000, whichever is less) may be grouped.
Line
No
Description of Project
(a)
Construclion work inEleclric (Account 1
(b)
progress -
07)
1 ROLLUP RELIC COST BROWNLEE '1 13,5't 1,636
2 ROLLUP RELIC COST HELLS CANYON 77,297,487
3 GATEWAY WEST sOOKV LINE 38,052,995
4 ROLLUP RELIC COST OXBOW 35,961,8'18
5 HELLS CANYON RELICENSING OUTSI 32,424,212
6 B2H PERIVITTING 11I1i2011 & FOR 17,638,563
7 BOARDMAN - HEMINGWAY 5OO KV LI 9,317,310
8 HCC WATERSHED ENHANCEMENT PROG 8,157,383
I BROWNLEE UNIT 2 TURBINE REFURB 7,559,022
10 UPPER MALAD FISH LADDER 5,925.263
11 LEGAL DEPT. LABOR FOR RELICENS 5,464,205
12 WQ HCC4O1 CERTIFICATION OPS AN 5,192,744
13 LANGLEY GULCH WATER BETTERMENT 4,856,493
14 BAYHA ISLAND RESEARCH PROJECT 4,707,424
15 SHOSHONE FALLS UPGRADE - REPLA 4,382,017
16 REL-HCC OREGON REAUTHORIZATION 3,790,834
17 B2H TLINE CONSTRUCTION COSTS 3,162,876
18 METEOROLOGY MOOEL FOR OPERATIO 3,1 1 6,606
19 BULL TROUT PROGRAM . ADMINISTR 3,049,751
20 BTLR1 5OOO1 NEW METALCLAD 2,854,365
21 GRAND VIEW IRRIGATION UPGRADE 2,825,728
22 NEWX14OOO5 - NEW 138KV LINE FR 2,702,515
23 WDRI.KCHM NEW 138KV 2,583,099
24 WQ HCC4O1 APPLICATION, REVISIO 2,421 ,271
25 FALL CHINOOK PROGRAM - REDD SU 2,342.937
26 TOOMHZ SPECTRUM PURCHASE 2,202,592
27 HBND-041:ALT LINE ROUTE TO GAR 2,025,580
28 SFP EQUIPMENT SKIP 2,015,864
29 LOWER SALMON UNIT 2 REFURB 1,923,786
30 HCC RELICENSING WATER QUALITY 1,831,430
31 BOBN160002 REPLACE C232 SERIES 1,629,492
32 MAINSTEM FLOW AND TEMPERATURE 1,389,679
33 22OMHZ SPECTRU M PURCHASE 1,367,707
34 BUILD ELDR SUBSTATION 1,340,164
35 BYRL1TOOOI STA WORK FDR O13 FO 1,250,079
36 DONN.REPLACE METAL-CLAD E WOP 1,234,321
37 HC SEDIMENT PROGRAMS 1 ,1 88,048
38 VARIlTOOO5 - GRID MOD PLAN, SC 1,175,785
39 SHOSHONE FALLS SITE ACCESS IMP 1 ,099,814
40 VARIl60010. MOBILE VEHICLE RA 1,08s,492
41 HCC HOUSING RENOVATIONS #562,1,041,253
42 SFP INTAKE MOOI FICATION 1,040,471
43 TOTAL 480,258,675
FERC FORM NO.1 (ED.12-87)Page 216
Name of Respondent
ldaho Power Company
(1)
(2)
An
ls:
Original
A Resubmission
Date of Report
(Mo, Da, Yr)
04t16t2019
Year/Period of Report
End of 2UUA4
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 1 07 of the Uniform System of Accounts)
3. Minorprojects(5%oftheBalanceEndoftheYearforAccountl0Tor$1,000.000,whicheverisless)maybegrouped.
Line
No.
Description of Project
(a)
Conslruction work in progress
Electric (Account'1 07)
(b)
1 BOCB17OO34 - MBE 9 PURCHASE A 1,028,571
2 Other Minor Projects Under $1.000,000 55,090,353
3
4
5
6
7
8
I
10
11
12
1a
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
34
35
36
37
38
39
40
41
42
43 TOTAL 480,258.675
FERC FORM NO.1 (8D.12-87)Page 216.1
ldaho Power Company (1)
(2)
Original Da,
Resubmission 0411612019
Year/Period of Report
End of 2018/Q4
ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT (tr65sun1 1gg;
1. Explain in a footnote any important adjustments during year.
2. Explain in a footnote any difference between the amount for book cost of plant retired, Line 11, column (c), and that reported for
electric plant in service, pages 204-207, column 9d), excluding retirements of non-depreciable property.
3. The provisions of Account 108 in the Uniform System of accounts require that retirements of depreciable plant be recorded when
such plant is removed from service. lf the respondent has a significant amount of plant retired at year end which has not been recorded
and/or classified to the various reserve functional classifications, make preliminary closing entries to tentatively functionalize the book
cost of the plant retired. ln addition, include all costs included in retirement work in progress atyear end in the appropriate functional
classifications.
4. Show separately interest credits under a sinking fund or similar method of depreciation accounting.
Section A. Balances and Changes During Year
Ltne
No.
Item
(a)
- Total.(c+d+e)
(b)
Eleqlrrc rlant rnSeruce
(c)
tslecmc PlantLeased to Others(e)
1 Balance Beginning of Year 2,256,354,154 2,256,354,1s4
2 Depreciation Provisions for Year, Charged to
3 (403) Depreciation Expense 156,332,587 156,332,587
4 (403.1) Depreciation Expense for Asset
Retirement Costs
566,665 566,665
5 (413) Exp. of Elec. Plt. Leas. to Others
6 Transportation Expenses-Clearing 4,638,583 4,638,583
7 Other Clearing Accounts
I Other Accounts (Speci!, details in footnote):
I Fuel Stock 244,670 244,670
't0 TOTAL Deprec. Prov for Year (Enter Total of
lines 3 thru 9)
161 ,782,505 161,782,505
't'l Net Charges for Plant Retired
12 Book Cost of Plant Retired 61,786,072 61 ,786,072
13 Cost of Removal 16,529,633 16,529,633
14 Salvage (Credit)2,965,438 2,965,438
15 TOTAL Net Chrgs. for Plant Ret. (Enter Total
of lines 12 thru 14)
75,350,267 75,3s0,26i
16 Othar Debit or Cr. ltems (Describe, detrails in
footnote):
26,514,956
17
18 Book Cost or Asset Retirement Costs Retired
19 Balance End of Year (Enter Totals of lines 1,
10, 15, 16, and 18)
2,369,301,348 2,369,301,348
Sectlon B. Balances at End of Year According to Functional Classification
20 Steam Production 682.108,587 682.1 08,58i
21 Nuclear Production
22 Hydraulic Production-Conventional 434.817,800 434,817,800
23 Hydraulic Production-Pum ped Storage
24 Other Production 113,048,970 113,048,970
25 Transmission 376,318,187 376,318,1 87
26 Distribution 641 ,913,009 641 ,913,009
27 Regional Transmission and Market Operation
2B General 121,094,795 121,094,795
aa TOTAL (Enter Total of lines 20 thru 28)2,369,301,348 2,369,301,348
FERC FORM NO.1 (REV.12-05)Page 219
26,514,05t
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
0411612019
Year/Period of Report
20181Q4
FOOTNOTE DATA
Schedule Page: 219 Line No.: 16 Golumn: cfncludes: Vatmy deprecia:ion adjustments (ID 33771 and OR 17-235),
Retirement Obligation ac--ivity.
CIAC and Asset
FERC FORM NO.1 1 450.1
Name of Respondent
ldaho Power Company
This Reoort ls:(1) fiAn Orlginal(2) ;-iA Resubmission
Date of Reoort
(Mo, Da, Yi)
04t16t2019
Year/Period of Report
End of 20181Q4
I NVESTMENTS IN SUBSIDIARY COMPANIES Account 123.1
1. Report below investments in Accounts 123.1, investments in Subsidiary Companies.2. Provide a subheading for each company and List there under the information called for below. Sub - TOTAL by company and give a TOTAL in
columns (e),(f),(g) and (h)
(a) lnvestment in Securities - List and describe each security owned. For bonds give also principal amount, date of issue, maturity and interest rate.
(b) lnvestment Advances - Report separately the amounts of loans or investment advances which are subject to repayment, but which are not subject to
current settlement. With respect to each advance show whether the advance is a note or open account. List each note giving date of issuance, maturity
date, and specirying whether note is a renewal.
3. Report separately the equity in undisfibuted subsidiary earnings since acquisition- The TOTAL in column (e) should equal the amount entered for
Acmunt 418.1.
Lane
No.
Description of lnvestment
(a)
Date Acquired
(b)
Date Of,1,$,,,Amount ot lnvestment at
Beoinnino of Year- (d)-
1 ldaho Energy Resources Company
2 Common Stock 02t01t74 500
3 Capital contributions 2,462,594
4 Equity in earnings 69,749,884
5
6 Subtotal ldaho Energy Resources Gompany 72,212,978
7
8
9
10
11
12
'13
14
15
16
17
18
't9
20
21
22
23
24
25
26
27
28
29
30
31
J2
33
34
35
36
37
38
39
40
41
42 TOTAL 72,212,978
FERC FORM NO.1 (ED.12-89)Page 224
Name
ldaho Power Company
(1)
(2)
An Original
A Resubmission
(Mo, Da,
04t1612019
Year/Period of Report
End of 201BlQ4
4. For any securities, notes, or accounts thatwere pledged designate such securities, notes, or accounts in a footnote, and state the name of pledgee
and purpose of the pledge.
5. lf Commission approval was required for any advance made or security acquired, designate such fact in a footnote and give name of Commission,
date of authorization, and case or docket number.
6. Report column (f) interest and dividend revenues form inveslments, including such revenues form securities disposed of during the year.
7. ln column (h) report for each investment disposed of during the year, the gain or loss represented by the difference between cost of the investrnent (or
the other amount at which carried in the books of account if difference from cost) and the selling price thereof, not including interest adjustrnent includible
in column (f).
8. Report on Line 42, column (a) the TOTAL cost of Account 1 23.1
hquity in Subsidiary
Earninls,of Year
Hevenues lor Year
(f)
Amount ot lnvestment at
End flfear
Gain or Loss trom Investment
oisol.s,eo or Line
No.
1
500 2
2,462.594 3
8,813,793 24,000,000 54,563,677 4
5
8,81 3,793 24,000,000 57,026.771 6
7
I
I
10
1',!
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
2S
30
31
32
33
34
35
36
37
3B
39
40
41
8,813,793 24,000,000 57,026,771 42
FERC FORM NO. 1 (ED.12-89)Page 225
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5]Rn Orisinat(2) 3 A Resubmission
Date of Report
(Mo, Da, Yr)
0411612019
Year/Period of Report
End of 2O18lQ4
MATERIALS AND SUPPLIES
1. For Account 154, report the amount of plant materials and operating supplies under the primary functional classifications as indicated in column (a);
estimates of amounts by function are acceptable. ln column (d), designate ttre department or departments which use the class of material.
2. Give an explanation of important inventory adjustments during [re year (in a footnote) showing general classes of material and supplies and the
various ac@unts (operating expenses, clearing ac,counts, plant, etc.) affected debited or credited. Show separately debit or credits to stores expense
clearing, if applicable.
Line
No
Account
(a)
Balance
Beginning of Year
(b)
Balance
End of Year
(c)
Department or
Departments which
Use Material(d)
1 Fuel Stock (Account 1 51 )56,638,459 47,979,122 Electric
2 Fuel Stock Expenses Undistributed (Account 152)5 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 17,946,659 17,733,796
8 Transmission Plant (Estimated)10,01 1 ,948 9,422.601
I Dishibution Plant (Estimated)24,559,578 27,1 60,s00
10 Regional Transmission and Market Operation Plant
(Estimated)
11 Assigned to - Other (provide detrails in foohote)1,338,445 -7
12 TOTAL Account 1 54 (Enter Total of lines 5 thru 1 'l )s3,856,630 53,553,674 Electric
13 lVlerchandise (Account 1 55)
14 Other Materials and Supplies (Account '156)
'15 Nuclear Materials Held for Sale (Account 157) (Not
applic to Gas Util)
16 Stores Expense Undistributed (Account 163)'t,888,307 1,433,6s2
17
18
19
20 TOTAL Materials and Supplies (Per Balance Sheet)112383,401 102,966,448
FERC FORM NO. r (REV.12-0s)Page 227
Production Plant (Estimated)
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
04t1612019
Year/Period of Report
2018tQ4
FOOTNOTE DATA
Sclredule Page: 227 Line No.: 11 Column: cThis amount represents miscellaneous inventory thaE is not yet assigned to a particular
function, offset by a year-end reserve for obsolete inventory.
FERC FORM NO. 1 (ED. 12-871 Page 450.1
Name of Respondent
ldaho Power Company
This Reoort ls:(1)E An Orisinal
(2) n A Resubmission
Oate of Report(Mo, Da, Yr)
04t16120't9
Year/Period of Report
gn6 o1 2018/Q4
Transmission Service and Generation lnterconnection Study Costs
1. Report the particulars (details) called for concerning the costs incurred and the reimbursements received for performing transmission service and
generator interconneclion 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.
Line
No Description
(a)
Costs lncuned During
Period
(b)
Account Charged
(c)
Reimbursements
Received During
the Period
(d)
Account Credited
With Reimbursement
(e)
1 Transmission Studies
2
4
5
6
7
B
9
10
't1
12
13
14
15
16
17
18
'19
20
21 Generation Studies
22 BAKER CITY 1 SOLAR 269 1 86623 I 86623
aa JACKPOT ANNEX SOLAR #523 762 1 86623 ( 762)1 86623
24 CAT CREEK PUMP STORAGE#524 1 86623 ( 7,861)1 86623
.E ONTARIO SOLAR #525 8,918 1 86623 ( 362)1 86623
26 WARM SPRINGS HYDRO #526 1 86623 ( 30,000)I 86623
27 SHOSHONE FALLS HYDRO PROJECT IPCO 1 86623 ( 4,988)1 86623
28 AMALGAMATED SUGAR #531 13,276 1 86623 ( 31,000)1 86623
29 CAT CREEK PUMP STORAGE #530 8,566 1 86623 ( 60,000)I 86623
30 GEM-VALE #534 3OOMW 9,780 1 86623 ( 70,000)1 86623
31 GENT-VALE WIND #535 sOOMW 5,548 '186623 ( 70,000)1 86623
32 VERDE LIGHT POWER #532 3MW 2,465 1 86623 ( 11,000)1 86623
33 BORREGO SOLAR #533 6,067 1 86623 ( 9,750)1 86623
34 OLD CAMP SOLAR SOMW 1,721 1 86623 ( 60,000)1 86623
35 MASON DAM HYDRO #538 2MW 1 86623 ( 500)186623
Jb
37
38
39
40
FERC FORM NO.'tll-Fl3-Q (NEW. 03-07)Page 231
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
04t16t2019
Year/Period of Report
2018tQ4
FOOTNOTE DATA
Schedule Page: 231 Line No.: 22 Column: d
Amounts represent both reimburseme;rts received (credi: amounts)and refunds back to the
counterparti-es (debit amounts). Refunis are i-nitiated when the inrtial deposit exceedsthe fical expenses,
FERC FORM NO.1 (ED. 12-871 Page 450.1
Name of Respondent
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of(Mo, Da
Report
, Yr)
0411612019
Year/Period of Report
End of 2A181Q4
OTHER REGULATORY ASSETS (Account 1 82.3)
1. Report below the particulars (details) called for conceming other regulatory assets, including rate order docket number, if applicable.
2. Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $100,000 which ever is less), may be grouped
by classes.
3. For Regulatory Assets being amortized, show period of amortization.
Line
No.
Description and Purpose of
Other Regulatory Assets
(a)
Balance at Beginning
of Cunent
Quarterffear
(b)
Debits
(c)
CREDITS Balance at end ol
Cunent Quarterffear
(0
Written ofi During the
ouarter /Year Account
Charsed (d)
Written otf During
the Period Amount
(e)
1 Fixed Cost Adjustment (FCA) (1 82302)15,542J27 34,502,069 400 15,542,127 34,502,069
2 order Pending (Amorl period 06/19 thru 05/20
3
4 AOCI lmpact of Unfunded Post Retirement Liability 3,045,521 2283 3,153,456 -107,935
5 Order#30256 (182306)
6
7 FCA Calender Mo Adjustment ( 704,07s)1,585,585 881,s10
B 0rder#33295 (182308)
I
10 Prior Year FCA - Order #33527 (1 82309)16,017,844 15,606,71 'l 400 24,504,916 7,1 19,639
't1 (Amort pedod 06/18 thru 05/19) Order#34079
12
13 PCA Unbilled Amortization (1 8231 6)( 1,346,828)1,346,828
14
15 AOCI lmpact 0f Unfunded Pension Liability ?77,120,492 15,225,643 2283 1 3,564,466 278,781,669
16 Order#30256 (182320)
't7
18 Defened Pension Expense Net of Contributions 23,032,921 36,152,743 1823 38,160,690 21,024,974
19 Order#30333 (182321)
20
21 FAS 109 Unfunded (182322\322,260,285 35,942,056 3s8,202,341
22 Accum Defened lncomo Noncurrent
23
24 PCA PriorYear Defenal (182324)4,482,791 Various 4,482,791
25 (Amort period 06117 thru 05118)
26
27 ldaho Pension Cash - Order #32248 (182327\104,688,433 39,276,027 Various 17,153,713 126,810,747
28 (Amort period beginning 06/11 thru indelinite)
29
30 ASC 815 Mark to Market (182330)1 ,419,163 244 508,638 91 0,525
31 0rder #28661
32
33 Oregon Pension Expense Capilalized (182339)4,39i,606 634,828 4073 135,861 4,896,573
34 Order#'10{64
35
36 Asset Retirement Oblioations (182341)15,629,470 1,934,008 17,563,478
37 IPUC Order #29414-OPUC 0rder #04-585
38
39 2008 PCAM Unbilled Amort (182356)843 402 843
40
41 RA-Hells Canyon-Baker Co-Order #33948 (1 82360)3,085,321 4073 2,771,815 31 3,506
42
43 Lidar Surveys - Order#32426 (182361)174,418 402 43,604 1 30,814
FERC FORM NO. 1/3-Q (REv. 02-04)Page 232
Name of Respondent
ldaho Power Company
This Reoort ls:(1) fiAn Originat(2) 1-1A Resubmission
Date of Report
(Mo, Da, Yr)
04116t2019
Year/Period of Report
End of 2018tQ4
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 aI 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
Quarter/Year
(b)
Debits
(c)
CREDITS Balance at end of
Cunent Quarterffear
(0
Written otl During lhe
0uarter flear Account
Charsed (d)
Written off During
the Period Amount
(e)
1 (Amort period 01/12Ihru 121211
2
3 RA-lntervenor Funding-ldaho (1 82387)I 50,754 41,717 192,471
4
5 RA-C0NTRA-DEF rNC TAx (182389)262,069,157 Various 6,127,411 255,941,746
6
7 ldaho Boardman ARO - Order# 29414 (182393 1 30,669 Various '130,669
8
I Langley Revenue Accrual - Order#12-226 (182398)1,186,995 95,1 04 1,282,099
10
11 RA-OR Langley Rev lnt Res {182399)( 125,700)4'190 34,011 -159,71 1
12
13 Siemens Long Term Defened Rate Base (182410)10,769,931 4073 431,488 10,338,443
14 Order#33420 (Amort period 01/'16 thru 12143)
15
16 Siemens Long Term Defened Rate Base (182411l.16,070,904 4073 643,867 15,427,037
17 Order #33420 (Amort period 01/'16 thru 12143)
1B
19 Siemens Long Term Defened Rate Base (182412\426,648 32,697 Various 44,047 4 1 5,298
20 Order#15-387 (Amorl period 01/16 thru '12136)
21
22 Siemens Long Term Defered Rate Base (1824131 707,684 4073 39,316 668,368
23 Order#'15-387 (Amort period 01/16 thru 12136)
24
25 Seimens Long Term lnterest Reserve (182414)( 67 865)41 90 32,697 -1 00,562
26
27 RA-Valmy 0&M lD 33771 (182432)( 738,442)Vanous 1,969,609 -2,708,051
28
29 RA-Valmy OR Depr Adj 17-325 (182434)1,281,969 403 393,456 888,513
30 (Amort period 06/'17 lhru 12125\
31
32 RA-Valmy Acctg Adj lD 33771 (182435)44,107,596 33J42,248 77,249,844
33
34 RA-Valmy Decomm OR (182436)15,451 '1,98't ,949 1,997,400
35 OPUC Order #17-235 (Amort period 06117 thru 12125
36
37 ldaho Boardman Decomissioning (182493)Various 5,438,694 -s,438,694
38 Ofier#32549 &#32457
?o
40 RA-lD Eoardman Decomm (182495)5,292,856 5,292,856
41 IPUC 0rder #32457
42
43 RA-OR Boardman Decomm {182496)237/89 237,789
FERC FORM NO. 1/3-Q (REV. 02-04)Page 232.1
ldaho Power Company (1)
(2)
Original (Mo, Da,
Resubmission o411612019
Year/Period of Report
End of 2018tQ4
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, oramounts 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
Quarterffear
(b)
Debits
(c)
CREDITS Balance at end of
Cunent QuarteriYear
(0
Written off During the
Quailer /Year Account
Charg8d (d)
Written off During
the Period Amounl
(e)
I OPUC Order#12-235
2
3 Oregon DSM Rider (254202)6,272,529 2,257 ,714 Various 7,132,494 1,39i,749
4 Advice #05-03
5
6 Minor ltems (10)991,582 512,593 Vanous 1,282,263 221,912
7
8
I
10
11
12
'13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44 TOTAL 'r,132,096,194 225,801,1 6s 143,722,942 1,214,174,417
FERC FORM NO. 1/3-Q (REV. 02-04)Page 232.2
Name of Respondent
ldaho Power Company
(1)
(2)
(Mo,
A Resubmission 04t16t2019
Year/Period of Report
End of 20181Q4
1. Report below the pa(iculars (details) called for concerning miscellaneous deferred debits.
2. For any deferred debit being amortized, show period of amortization in column (a)
3. Minor item (1olo 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 ofYear
(0ChargedAmount
(e)
1 Prepaid Credit Facility 186025 1,008,962 431 262,302 746,660
2 Amortization period 1 1 I 1 6-1 1 120
3
4 Prepaid Services 186052 3,1 87,5't 1 3,449,778 Various 2,963,449 3,673,840
A Lonq-term portion
6
7 Workers Compensation 1 861 21 1,020,064 98,548 1,118,6',t2
8
I Prepaid ROW 186160 669,377 311,973 401 362,571 618,779
10 Lonq-term portion
11
12 CARB lnventory 186650 843,050 843,050
13
14 Coal Royalties 186709 1,007,388 151 63.770 943.618
15
16 Stable Value Life lnv 186719 43,159,437 2,310,575 4262 34,268 45,435,744
17
18 Security Plan 186720 12,274,448 222,237 4262 1 ,929,146 10,567.539
19 Net lnsurance Asset
20
21 Retiree MedicaLCOLI 186726 3,889,0s7 411.224 4262 451,1 88 3.849.0S3
22
23 American Falls Water Rts'186727 7,380,895 401 1,042,008 6,338.887
24 Amortization period 0 1 /06-02/25
25
26 American Falls Bond Refi '186770 343.994 401 47,999 295,995
27 Amortization period 1 2 I 09-021 25
28
29 Regulatory Reserves 1 86800 -2.772,230 1.649,843 -1j22.387
30
31 Minor ltems (6)'t,963,785 2.608.726 Various 4,476,898 95,613
32
33
34
35
36
37
3B
39
40
41
42
43
44
45
46
47 Misc. Work in Progress
48 Detened Regulatory Comm.
Expenses (See pages 350 - 351 )
49 TOTAL 73j32,688 73,405,043
FERC FORM NO.1 (8D.12.94)Page 233
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5.1Rn orisinat(2) nA Resubmission
Date of Report
(Mo, Da, Yr)
04t1612019
Year/Period of Report
End of 2O18lQ4
'l . Report the information called for below concerning the respondent's accounting for defened income taxos.
2. At Other (Speciff), include defenals relating to other income and deductions.
Line
No.
Description and Location
(a)
tsalance ot Beornrnoof Year -
(b)
Llalance at Endof Year
(c)
1 Electric
2
3
4
5 Other Electric (See footnote)89,557,247 s6,930,307
6
7 Other (See footnote)182,469,703 178.068,785
8 TOTAL Electric (Enter Totral of lines 2 thru 7)272,026,950 274,999,O92
o Gas
10
11
12
13
14
15 Other
16 TOTAL Gas (EnterTotal of lines 10 thru 15
17 Other Non Electric (See footnote)17,786,96S 18,384,170
18 TOTAL (Acct '190) (Total of lines 8, 16 and 17)289,81 3,91S 253,383,262
Notes
FERC FORM NO. 1 (ED. 12-E8)Page 234
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2\ _ A Resubmission
Date of Report
(Mo, Da, Yr)
0411612019
Year/Period of Report
2018tQ4
FOOTNOTE DATA
Schedule Page: 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
Retention Pay Accrual
Stock Based Cornpensation
Pension Expense-Oregon
Bridger Revenue Deferral
Asset Retirement Obligation (ARO)
I ncentive Deferral-Profit Shari ng-Not i n Rates
OR Reconnect Fees Adv
Rate Case Disallowance
Prov for Rate Refund-HC Relicensing (AFUDC)
Revenue Sharing
VEBA-Post Retirernent Benefits
Deferred ldaho ITC
Deferred GBC Federal
TotalOther Electric
Beginning Balance
1,420,074
436,208
74,148
(238,565)
28,8OB
21,449
3,209,060
2,714,789
377,040
1,230,333
3,752,926
237
1,356,867
31,085,864
0
7,854,162
29,195,228
7,038,619
Ending Balance
1,082,811
313,224
64,475
(468,289)
4,427
0
3,437,429
3,019,304
499,057
1,423,588
3,491,132
955
't,268,220
35,136,616
1,293,322
g,g76,0gg
26,408,291
10,979,656
89,557.247 96,930,307
Schedule Page: 234 Line No.:7 Column: c
Pension-FAS '158
Regulatory Liability-FAS 1 09
Minimum Pension Liability
Postretirement Plan-FAS 1 58
TotalOther
Beginning Balance
72,068,421
98,743,759
10,866,388
791,135
Ending Balance
72,101,874
98,042,z',t7
7,952,476
(27,7821
182,469,703 178,068,785
Schedule Page: 234 Line No.: 17 Column: c
Senior Management Security Plan
Total Non Electric
Beginning Balance
17,786,969
Ending Balance
18,384,170
17,7B6,969 18,384,170
FERC FORM NO. 1 (ED. 12-871 Page 450.1
Name of Respondent
ldaho Power Company 1
(2)A Resubmission
Date of Report(Mo, Da, Yr)
0411612019
Year/Period of Report
End of 20181Q4
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 prefened stock. lf information to meet the stock exchange reporting
requirement outlined in column (a) is available from the SEC 10-K Report Form filing, a specific reference to report form (i.e., year and
company title) may be reported in column (a) provided the fiscal years for both the 10-K report and this report are compatible.
2. Entries in column (b) should represent the number of shares authorized by the articles of incorporation as amended to end of year.
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
a ldaCorp, lnc. and not traded
4 Total Common Stock 50,000,000 2.50
5
b Account 204 - None
7
8
9
10
11
12
13
14
15
16
17
18
't9
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
FERC FORM NO.1 (ED.12-91)Page 250
Name of Respondent
ldaho Power Company
This
(1)
(2')
Reoort ls:
[]An orisinal
nA Resubmission
Date of Report
(Mo, Da, Yr)
04t16t2019
Year/Period of Report
End of 20181Q4
3. Give particulars (details) concerning shares of any class and series of stock authorized to be issued by a regulatory commission
which have not yet been issued.
4. The identification of each class of preferred stock should show the dividend rate and whether the dividends are cumulative or
non-cumulative.
5. State in a footnote if any capital stock which has been nominally issued is nominally outstanding at end of year.
Give particulars (details) in column (a) of any nominally issued capital stock, reacquired stock, or stock in sinking and other funds which
is pledged, stating name of pledgee and purposes of pledge.
OUTSTANDING PER BALANCE SHEET(Total amount outstanding without reduction
for amounts held by respondent)
HELD BY RESPONDENT Line
No.AS REACQUIRED STOCK (Acmunt 217)IN SINKING AND OTHER FUNDS
Shares(e)Amount(f)Sh 'es Amount
fi)
1
39,150,812 97,877,030 2
39,150,812 97,877,030 4
b
7
B
I
10
11
12
13
14
15
16
17
18
19
2A
21
22
23
24
25
26
27
28
29
30
31
32
34
35
36
37
3B
20
40
41
42
FERC FORM NO.1 (ED.12-88)Page 251
Jnares(q)
Name of
ldaho Power Company (1)
(2)
An
A Resubmission
Date of Report
(Mo, Da, Yr)
04t16t2019
Year/Period of Report
End of 2018iQ4
OTHER PAID{N CAPITAL (Accounts 2A8-21'l ,lnc.)
Report below the balance at the end of the year and the information specified below for the respective other paid-in capital accounts. Provide a
subheading for each ac@unt and show a total for the account, as well as total of all accounts for reconciliation with balance sheet, Page 1 12. Add more
columns for any account if deemed necessary. Explain changes made in any account during the year and giv6 the accounting entries effecting such
change.
(a) Donations Received from Stockholders (Account 208)-State amount and give brief explanation of the origin and purpose of each donation.
(b) Reduction in Par or Stated value of Capital Stock (Account 209): State amount and give brief explanation of the capital change which gave rise to
amounts reported under this caption including identification with the class and series of stock to which related.
(c) Gain on Resale or Cancellation of Reacquired Capital Stock (Account 210): Report balance at beginning of y6ar, 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.Item(a)Amount(b)
,|Acmunt 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
I Account 211 - Miscellaneous paid-in Capital - None
I
10
11
12
't3
14
15
16
17
18
19
20
21
22
aa
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
S:
(1)
(2)
An Original
A Resubmission
Da,
04t16t2019
Year/Period of Report
End of 20181Q4
CAPITAL STOCK EXPENSE
1 . Report the balance at end of the year of discount on capital stock for each class and series of capital stock.
2. lf any change occurred during the year in the balance in respect to any class or series of stock, attach a statement giving particulars
(details) of the change. State the reason for any charge-off of capital stock expense and specify the account charged.
Lrne
No-
Class and Series ot Stock
(a)
Balance at End ot Year
(b)
I Common Stock 2,096,925
2
J
4
5
o
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.'t (ED.12-87)Page 254b
ldaho Power Company (1)
(2)
An Original
A Resubmission
Da,
0411612019
YeariPeriod of Report
End of 20181Q4
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, Olher long-Term Debt.
2. ln column (a), for new issues, give Commission authorization numbers and dates.
3. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds.
4. For advances from Associated Companies, report separately advances on notes and advances on open accounts, Designate
demand notes as such. lnclude in column (a) names of associated companies from which advances were received.
5. For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were
issued.
6. ln column (b) show the principal amount of bonds or other long-term debt originally issued.
7. ln column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued.
8. For column (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount.
lndicate the premium or discount with a notation, such as (P) or (D). The expenses, premium or discount should not be netted.
9. Furnish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with
issues redeemed during the year. Also, give in a footnote the date of the Commission's authorization of treatment other than as
specified by the Uniform System of Accounts.
Line
No
Class and Series of Obligation, Coupon Rate
(For new issue, give commission Authorization numbers and dates)
(a)
Principal Amount
Of Debt issued
(b)
Total expense,
Premium or Discount
(c)
1 Account22l'.
2 First Mortgage Bonds:
3 4.50% Series due2020 130,000,000 1 ,'1 99,383
4 235,300 D
5
6 5.50% Series due 2033 70,000,000 728,701
7 36,400 D
8
9 3.40% Series due 2020 100,000,000 1,'159,871
10 499,000 D
11
12 5.30% Series Due 2035 60,000,000 3,849,739
13 408,600 D
't4
15 4.00% Series due2043 75,000,000 742,017
16 194,250 D
17
18 6.00% Series due 2032 100,000,000 1,191,216
't9 544,000 D
20
21 5.875o/o Series due 2034 55,000,000 585,759
22 748,000 D
23
24 5.50% Series due2034 50,000,000 524,419
25 383,500 D
26
27 4.85% Series Due 2040 '100,000,000 1,284,871
28 170,000 D
29
30 6.30% Series due 2037 140,000,000 1,500,031
31 278,600 D
32
33 TOTAL 1,985,345,000 34,005,796
FERC FORM NO.1 (ED.12-96)Page 256
Name of Respondent
ldaho Power Company (1)
(21
An
of Report
Da, Yr)
A Resubmission 04t16t2019
Year/Period of Report
End of 20181Q4
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, Amodization 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 longterm
advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid
during year. Give Commission authorization numbers and dates.
13. lf the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee
and purpose ofthe pledge.
14. lf the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end of
year, describe such securities in a footnote.
1 5. lf interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest
expense in column (i). Explain in a footnole any difference between the total of column (i) and the total of Accounl 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)
AIVIORTIZATION PERIOD uutstandrno(Totial amount oulstaniling without
reduction for amounts held byrase?flfen0
lnterest for Year
Amount
(i)
Line
No.Date From
(f)
Date To
(s)
I
2
11120109 3t01t20 11t20t09 3101120 1,722,500
4
5
5/1 3t03 4to1t33 5/1 3/03 3/31/33 70,000,000 3,850,000 6
7
8
8/30i 1 0 11tUt2A 8/30/10 11101t20 100,000,000 3,400,000 9
JO
11
8t26105 8115t35 8t26t05 8/15/35 60,000,000 3,1 80,000 12
13
14
4108t't3 4101143 4t08113 4t01t43 75,000,000 3,000,000 15
16
17
11t15102 11t15t32 11t15102 11115t32 100,000,000 6,000,000 18
19
20
8l16l04 8115t34 8t't6104 8115134 55,000,000 3,231,250 21
22
23
3126104 3t15134 3126l04 3115134 50,000,000 2,750,000 24
25
26
8/30/1 0 8t15t40 8/30/10 8t15140 100,000,00c 4,850,000 27
28
23
6l22lA7 6115137 6t22t07 6115137 140,000,000 8,820,000 30
31
32
1.855,345,000 84,407,634 33
FERC FORM NO.1 (ED.12-96)Page 257
Name of Respondent
ldaho Power Company
This
(1)
(2)
Reoort ls:
5]Rn Originat
[lA Resubmission
Date of Report(Mo. Da, Yr)
04t16t2019
Year/Period of Report
End of 20181Q4
1. Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221, Bonds,222,
Reacquired Bonds, 223, Advances from Associated Companies, and 224, Olher long-Term Debt.
2. ln column (a), for new issues, give Commission authorization numbers and dales.
3. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds.
4. For advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate
demand notes as such. lnclude in column (a) names of associated companies from which advances were received.
5. For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were
issued.
6. ln column (b) show the principal amount of bonds or other long-term debt originally issued.
7. ln column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued.
8. For column (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount.
lndicate the premium or discount with a notation, such as (P) or (D). The expenses, premium or discount should not be netted.
9. Furnish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with
issues redeemed during the year. Also, give in a footnote the date of the Commission's authorization of treatment other than as
specified by the Uniform System of Accounts.
Line
No
Class and Series of Obligation, Coupon Rate
(For new issue, give commission Authorization numbers and dates)
(a)
Principal Amount
Of Debt issued
(b)
Total expense,
Premium or Discount
(c)
1 6.257o Series due 2037 100,000,000 1,227,490
2 268,000 D
3
4 Port of Morrow Variable due 2027 4,360,000 189,597
5
6 Humboldt 5.15% due 2024 49,800,000 I ,309,010
7
8 Sweetwater 5.25% due 2026 116,300,000 3,044,152
I
10 2.50% Series due2023 75,000,000 648,267
11 374,250 D
12
13 4.30% Series Due2042 75,000,000 802,240
14 49,500 D
't5
16 2.95% Series Due2022 75,000,000 708,490
17 128,250 D
18
19 3.657o Series Due 2045 2s0,000,000 2,559,510
20 1,715,000 D
21
22 4.05% Series Due 2046 120,000,000 1,311,383
23 309,600 D
24
25 Due 2,283,400
26 ldaho Order #33513 (4127116)814,000 D
27 Oregon Order #16-151 (U21116)
28 Wyoming Docket #20005-37-ES16 (5117116)
29
30 Subtotal Account 221 't,965,460,000 34,005,796
31
32 Account 222 - Reaquired Bonds
33 TOTAL 1,985,345,000 34,005,796
FERC FORM NO.1 (ED.12-96)Page 256.1
220,000,00(
Name of Respondent
ldaho Power Company
This Report ls:(1) [lAn Orisinal(2) ;-1A Resubmission
Date of(Mo, Da
Report
r, Yr)
04t16t2019
Year/Period of Report
End of 20181Q4
L0nunueo
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 ofthe pledge.
14. lf the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end of
year, describe such securities in a footnote.
1 5. lf interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest
expense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Accounl 427 , interest on
Long-Term Debt and Account 430, lnterest on Debt to Associated Companies.
16. Give particulars (details) concerning any long{erm debt authorized by a regulatory commission but not yet issued.
Nominal Date
of lssue
(d)
Date of
Maturity
(e)
AMORTIZATION PERIOD uutst lndino(Total amount outstantlino without' reduction for amounts hlld byrese?frfent)
lnterest for Year
Amount
(i)
Line
No.Date From
(f)
Date To
(s)
10118t07 10t15137 10/18107 10t15t37 100,000,00c 6,250,000 1
2
3
5117100 2101/27 05117t00 02101t27 4,360,000 70,934 4
5
8120t09 12101t24 8120l0s 12101t24 49,800,000 2,564,700 6
7
8t20t09 7t15126 8120l09 7115126 116,300,000 6,105,750 8
I
4t08t13 4101t23 4t08t13 4101123 75,000,000 1,875,000 10
11
12
4t13t12 4101142 4t13t12 4101t42 75,000,000 3,225,000 '13
14
15
4113112 4101t22 4t13t12 4lo1l22 75,000,000 2,212,500 16
17
'18
3/05/1 5 3t01t45 3t06115 3to1t4s 250,000,000 9,125,000 19
20
21
3t10t16 310'U46 3t10t16 3t1t46 120,000,000 4,860,000 22
23
24
3116118 3lo1l48 3t16t18 3t01t48 220,000,000 7,315,000 25
zo
27
28
29
1,835,460,000 84,407,634 30
31
32
1,855,345.000 84,407,634 33
FERC FORM NO.1 (ED.12.96)Page 257.1
Name of Respondent
ldaho Power Company
This Reoort ls:(1) fiAn Original(2) 1-1A Resubmission
Date of Report(Mo, Da, Yr)
0411612019
Year/Period of Report
End of 201BlQ4
1. Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221 , Bonds,222,
Reacquired Bonds, 223, Advances from Associated Companies, and 224, Olher long-Term Debt.
2. ln column (a), for new issues, give Commission authorization numbers and dates.
3. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds.
4. For advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate
demand notes as such. lnclude in column (a) names of associated companies from which advances were received.
5. For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were
issued.
6. ln column (b) show the principal amount of bonds or other long-term debt originally issued.
7. ln column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued.
8. For column (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount.
lndicate the premium or discount with a notation, such as (P) or (D). The expenses, premium or discount should not be nefted.
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 Accnunt224'.
5 Bond Guarantee - American Falls 19,885,000
6 Subtotal Accounl224 19,88s,000
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 TOTAL 1,985,345.000 34,005,796
FERC FORM NO.1 (ED.12.96)Page 256.2
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5]An orisinat(2) l-lA Resubmission
Date of Report(Mo, Da, Yr)
o4116t2019
Year/Period of Report
End of 20181Q4
10. ldentifo separate undisposed amounts applicable to issues which were redeemed in prior years.
11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, Premium
on Debt - Credit.
12. ln a footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to longterm
advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid
during year. Give Commission authorization numbers and dates.
13. lf the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee
and purpose ofthe pledge.
14. lf the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end of
year, describe such securities in a footnote.
15. lf interest expense was incuned during the year on any obligations retired or reacquired before end of year, include such interest
expense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Accounl 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 (Jutstandino
(Total amount outstani,ing without
reduction for amounts held byresp?flfent)
lnterest for Year
Amount
(i)
Line
No.Date From
(f)
Date To
(s)
1
2
3
4
4t26t00 2101t25 19,885,000 5
19,885,000 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
1,855,345,000 84,407,634 33
FERC FORM NO.1 (ED. 12-96)Page 257.2
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(21 A Resubmission
Date of Report
(Mo, Da, Yr)
04t16t2019
Year/Period of Report
2018tQ4
FOOTNOTE DATA
Schedule Page: 256.1 Llne No.: 25 Column: aUnamortlzed debt expense at refunding is amortized by equal monthly amolin:s over the fife
of the new issue.
FERC FORM NO.1 450.1
Year/Period of Report
End of 20181C'4(1)
(2)
An Original
A Resubmissionldaho Power Company
Date of Report(Mo, Da, Yr)
o4t't6t2019
RECONCILIATION OF REPORTED NET INCOME WITH TAXABLE INCOME FOR FEDERAL INCOME TAXES
1. Report the reconciliation of reported net income for the year with taxable income used in computing Federal income tax accruals and show
computation of such tax accruals. lnclude in the reconciliation, as far as practicable, the same detail as furnished on Schedule M-1 of the tax return for
the year. Submit a reconciliation even though there is no taxable income for the year. lndicate clearly the nature of each reconciling amount.
2. lf the utility is a member of a group which files a consolidated Federal tax return, reconcile reported net income with taxable net income as if a
separate return were to be field, indicating, however, intermmpany amounts to be eliminated in such a consolidated return. State names of group
member, tax assigned to each group member, and basis of allocation, assignment, or sharing of the consolidated tax among the group members.
3. A substitute page, dasigned 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.
Amount
(b)
Line
No.
Particulars (Details)
(a)
222,334,2911Net lnmme for the Year (Page 117)
2
3
4 Taxable lncome Not Reported on Books
8,A7,'5
6
7
8
I Deductions Recorded on Books Not Deducted for Retum
10
11
12
13
14 lncome Recorded on Books Not lncluded in Return
7&820,0e15
16
17
't8
't9 Deductions on Return Not Charged Against Book lncome
20 149,211,232
21
22
23
24
25
26
27 Federal Tax Net lncome 204,692,434
28 Show Computation of Tax:
29 Tentative Federal lax @ 21o/o 42,985,411
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
202,142jffi
Name of Respondent
ldaho Power Comoany
This Rqport is:
(1)X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t16t2019
YearlPeriod of Report
2018tQ4
FOOTNOTE DATA
4OOS-AVOIDED COST 4,420,007
4OO3-CONSTRUCTION ADVANCES '1,606,014)
2,060,89640,I3-CIAC - TAXABLE. ACCT 107
143,0414021-ENGINEERING FEES . TAXABLE - ACCT 107
3,229,3674024-RENEWABLE ENERGY CERTIFICATES (REC)
SALES
Total 9,247,297
261 Line No.:b
Schedule 261 Line No.: 10 Column: b
Schedule 261 Line No.: 15 Column: b
FERC FORM NO. 1 (ED. 12-871 Page 450.1
Total Federal and State taxes deducted on books 16,134,602
(203,121)5OO1.BAD DEBT EXPENSE
5OO2-INVENTORY RESERVE ADJUSTMENT 1,654,824
5024-NON-DEDUCTIBLE M EALS 492,000
5,366,162sO7O-INCENTIVE DEFERRAL-CRI &
RELIABILITY-INCLUDED IN RATES
501 O-POSTEMPLOYMENT BENEFITS 0
5023-PENSION EXPENSE 17,153,713
5035-PCA EXPENSE DEFERRAL 0
SO4T.EXECUTIVE DEFERRED COMP 0
3,768,6905053-STOCK BASED COMPENSATION
(11,647,322\5058-FIXED COST ADJUSTMENT
5O6O-OREGON - PCAM (786,312)
5061-PENSION EXPENSE . OREGON 1,279,263
5067-ASSET RETIREMENT OBLIGATION (ARO,794,406
5071 -INCENTIVE DEFERRAL-PROFIT SHARING-NOT IN
RATES
753,926
5075-EIM DEFERRAL 772,395
5504-NON-DEDUCTIBLE POLITICAL EXPENSES 938,916
2,950,5845505-SMSP - NET
7O1O-PROV FOR RATE REFUND - HC RELICENSING
TAFUDC)
16,839,014
5,024,5627012-REVENUE SHARING
4,642,4563OO1 -VEBA . POST RETIREMENT BENEFITS
4,900,5638O2O-CONSERVATION EXPENSES
3OOg-DEPR TIMING DIFF - OPERATING - FEDERAL 129,512,939
3703-IPCO-1 62(m) THRESHHOLD 1,800,000
Iotal 202,142,',l60
5066-BOARDMAN DECOMMISSION 1,088,745
5074-VALMY SETTLEM ENT ADJUSTMENT 6,584,633
25,191 ,6015077-VALMY DEPRECIATION ADJ USTMENT
2,397,3295501.SMSP - INSURANCE COSTS
8,813,7937501-REVERSE EQUITY EARNINGS OF SUBSIDIARIES
24,352,523TsO2.ALLOWANCE FOR OFUDC
7So3-ALLOWANCE FOR BFUDC 10,151 ,31 3
- INSURANCE 240,145
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
04116t2019
Year/Period of Report
2018tQ4
FOOTNOTE DATA
Schedule 261 Line No.:20 Column: b
FERC FORM NO. 1 (ED. 12-871 Page 450.2
32,000,0005022.263A CAPITAL IZED OVE RHEADS
5538-STOCK BASED COMP - STOCK 3,539,'111
8702-STOCK BASED COMP - DIVIDENDS 667,188
8034-REMOVAL COSTS 16,529,633
2,622,9238o42-GAIN/LOSS ON REACQUIRED DEBT
8073-REPAI RS DEDUCTION 85,000,000
8077-PREPAID INSURANCE & OTHER EXPENSES (4e7,64s)
8o59-SOFTWARE - LABOR COSTS DEDUCTED . ACCT
107
4,280,000
8o72-RELICENSING. LABOR COSTS DEDUCTED - ACCT
107
2,462,000
STATE INCOME TAX DEDUCTED ON FEDERAL RETURN 2,608,022
Total 149,211,232
ldaho Power Company (1)
(2)
An Original
A Resubmission
(Mo, Da,
04t16t2019
Year/Period of Report
End of 20181Q4
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total laxes 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. lncludeonthispage,tiaxespaidduringtheyearandchargeddirecttofinalaccounts,(notchargedtoprepaidoraccruedtaxes.)
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 @lumn (d) taxes charged during the year, taxes charged to operations and other ac@unts through (a) accruals credited to taxes accrued,
(b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other
than accrued and prepaid tax accounts.
4. List the aggregate of each kind of tax in such manner that the total tax {or each State and subdivision can readily be ascertained.
Line
No.
Kind of Tax
(See instruction 5)
(a)
BALANCE AT BEGINNING OF YEAR 'i
ql
lxesald
rnngeale)
Adiust
ments
(0
Taxes Accrued(Accomt 236)Preoaid Taxes(lnclude in Account 165)
1 Federal
2 lncome -22,211,260 21,785,861 7,194,234
1 Social Security - (FOAB)431,833 15,595,269 15,649,443
4 Unemployment 37,428 94,472 92.509
A Subtotal Federal -21,741 ,999 37,475,602 22,936,1 86
b
7 State of ldaho:
I lncome -4,332,804 -2,635,249 -4,256,598
I Unemployment 22,775 199,492 208,1 94
10 Property 9,841,215 22,845,101 22,578,849
11 Non-Operating 9,044 17,648 17,868
12 kwh 105,033 2.157.522 2,175,683
13 Regulatory Commission 2,724.231 2,724,231
14 Business License - Sho Ban 150 150
15 Subtotal ldaho 5,645,263 25,308,895 23,448,377
16
't7 State of Oregon
18 lncome -357,714 525,059 489,294
19 Unemployment 2,194 48,092 47,244
20 Property 1,695,878 3,477,311 3,562,183 -513
21 Non-Operating Property 1,042 2,032 2,058
22 Regulatory Commission 255,980 255,980
23 Franchise 197,157 837,813 835,286
24 Subtotal Oregon -1 58,363 1,696,880 5,146,287 5,192,045 -513
25
26 State of Montana:
27 Property 179,456 340,253 349,735
28 Subtotal Montana 179,456 340,253 349,735
29
30 State of Nevada:
31 Property 415,074 839,533 846,710
32 Subtotal Nevada 415,074 839,633 846,710
33
34 State of Wyoming
35 Property 754,229 1,424,436 1,466,446
36 Corporate License 4,202 4,202
37 Subtotal Wyoming 754,229 1,428,638 1,470,648
38
39
40
41 TOTAL -1 5,1 56,342 2,111,954 s4,673,004 54,255,075 15,219
FERC FORM NO.1 (ED. 12-96)Page 262
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5]An orisinal(2) 1_1A Resubmission
Date of Report(Mo, Da, Yr)
04t1612019
Year/Period of Report
End of 2O18lQ4
5. lf any tax (exclude Federal and Slate income taxes)- covers more then one year, show the required information separately for each tax year,
identifying the year in column (a).
6. Enter all ad.justments of the accrued and prepaid tax accounts in column (f) and explain each adjustment in a foo! note. Designate debit adjustments
by parentheses.
7. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending
transmittal of such laxes to lhe taxing authority.
8. Report in columns (i) through (l) how the taxes were distributed. Report in column (l) only the amounts charged to Accounts 408.1 and 409.1
pertaining to electric operataons. 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 OF YEAR Line
No.(Taxes accruedAccoln! 236)
Prepaid Taxes
(lncl. in
\cryunt
16s)
Electric(Account 408.1, 409.1 )
Extraordinary ltems
(Account 409.3)
Adruslments to F(et.
Earnings (Account 439)
(k)
Other
(t)
1
-7,619,635 20,035,445 1,750,416 2
377,660 15,595,269 3
39,391 94,472 4
-7,202,584 35,725,186 't ,750,416 5
6
7
-2,711,454 -2,816,167 180,918 8
14,073 199,492 I
10,107,466 22,844,092 1.009 10
8,824 r7,648 11
86,873 2,157,522 12
2,724,231 't3
150 14
7,505,782 25,109,320 199,57s 15
't6
17
-321,948 51 5,365 s.694 18
3,042 48,092 19
1.780,237 3,354,144 20
21
255,980 22
199,684 837,813 23
-119,222 1,780,237 5,01 1,394 134,893 24
25
26
169,975 344,253 27
169,975 340,253 28
29
30
422,251 839,633 31
422,251 839,633 32
33
34
712,218 35
4,202 36
712,218 a1
38
39
40
1,306,621 2,202,488 52,584,791 2,088,213 41
FERC FORM NO.1 (ED.12-96)Page 263
't23,'t61
2.032
1,424,436
1,428,638
S:
ldaho Power Company (1)
(2)
An Original
A Resubmission 0411612019
Year/Period of Report
End of 20181Q4
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
acfual, or estimaled amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts.
2. lnclude on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.)
Enter the amounts in both columns (d) and (e). The balancing of this page is not affected by the inclusion of these taxes.
3. lnclude in column (d) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued,
(b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other
than accrued and prepaid tax accounts.
4. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained.
Ltne
No.
Kind of Tax
(See instruction 5)
(a)
BALANCE AT BEGINNING OF YEAR Adjust
ments
(f)
I axes Accrueo(Account 236)(b)
PreDard I axes(lnclude tn Account 165)
1 State of Washington
2 Property 11,000 9,687 9,687
2 Subtotal Washington 11,000 9,687 9,687
4
6 Other States lnmme 155,143 61,334 7,237
o Canada GST fax -1,071 -5,550
7 Payroll Tax Credit -15,937,325
8
o
10
11
12
13
14
15
16
17
18
1S
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41 TOTAL -15,156,342 2,111,954 54.673.004 54,15,219
FERC FORM NO. I (EO.12-96)Page 282.1
I
q
16,782
me
1ldaho Power Company (2)A Resubmission
Date of Report(Mo, Da, Yr)
04t1612019
Year/Period of Report
End of 201BlQ4
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
5. lf any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year,
identifying the year in column (a).
6. Enter all adjustments of the accrued and prepaid tax accounts in column (f) and explain each adjustment in a foot- nole. 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 othenruise pending
transmittal of such taxes to the taxing authority.
8. Report in columns (i) through (l) how the taxes were distributed. Report in column (l) only the amounts charged to Accounts 408.1 and 409.'t
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) ol apportioning such tax.
BALANCE AT :ND OF YEAR Line
No.(Taxes accruedAccolnj 236)
Prepaid Taxes
(lncl. in ffiunt 165)
Electric(Account408.1,409.1)Extraordinary ltems
(Account 409.3)
AOrustments to Het.
Earnings (Acmunt 439)
(k)
Other
(r)
1
11,000 9,687 2
1 1,000 9,687 3
4
209,241 58,00s 3.329 5
20,211 6
-15.937,325 7
8
I
10
11
12
13
14
15
16
17
18
't9
20
21
22
23
24
25
26
27
28
29
30
31
32
JJ
34
35
36
37
38
39
40
1,306,621 2,202,488 52,584,791 2,088,213 41
FERC FORM NO.1 (EO.12-96)Page 2O3.1
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
04116t2019
Year/Period of Report
2018/Q4
FOOTNOTE DATA
Schedu/eAccou:rt
Accou:rt
Page:262 LineAAO A C
409.1 $
No.:2 Column: I
621,0i2
1,723,344
rr,-,I,a- s l,r.:i,1:e
Scftedule Page: 262 Line No.: 8 Column: I
Ac r(,ui, i 4)':; .2 3 -r?i: , ' L?
Schedule Page: 262 Line No.: 10 Column: I
Accour-rt 107 $ 1, C09
Schedule Page: 262 Line No.: 11 Column: I
Account 4A8.2 $ 17,648
Schedule Page: 262 Line No.: 18 Column: I
Account 4a9.2 I 9, €94
Schedule Page: 262 Line No.: 20 Column: f
A refund for erroneous taxes paii in the
Schedule Page: 262 Line No.: 20 Column: I
Account 107 $ 123,76'/
Schedule Page: 262 Line No.: 21 Column: I
Account 4AB.2 $ 2,432
Schedule Page: 262-1 Line No.: 5 Column: I
Account 4A9 .2 S 3, 329
prior year.
Schedute Page: 262.1 Line No.:6 Column: f
Canada GST accrua.I is an adjustment because the offset account is not a 600 expense
account.
ScDedule Page: 262.1 Line No.:7 Column: i
This amount is an offset to Iines 3, 4, 9, and 19. Each month employer paid taxes flow
into various 408.1 accounts. In that- same month these amount-s are offset- with a di-fferent
408.1 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. 12-8 450.1
ldaho Power Company (1)
(2)
An
A Resubmission
Date of Report(Mo, Da, Yr)
0411612019
Year/Period of Report
End of 2O18lQ4
ED INVESTMENT TAX C
Report below information applicable to Account 255. Where appropriate, segregate the balances and transactions by utility and
nonutility operations. Explain by footnote any correction adjustments to the account balance shown in column (g).lnclude in column (i)
the average period over which the tax credits are amortized.
Lrne
No.
Account
Subdivisions(a)
tsalance,at ts€ginning
(b)
Deferred for Year Adjustments
(s)ACCOUnT NO.
(c)
Amount(d)A@OUnr NO.(e)fvTt((f unI
1 Electric Utility
2 3Yo
3 4Yo 277,580 411.401 33,82C
4 7%
5 10%15,246,',!45 41't.401 1,634,952
6 Other- Federal 8,054.933 3,941,037 22,27C
7 Other- State 63,806,080 411.402 4,393,349 411.402 1,238,24e
I TOTAL 87,384,738 8,334,386 2,929,28e
I Other (List separately
and show 3Yo, 4To,7o/o,
10% and TOTAL)
1C 1 1o/o 1 ,086,186 4'.t1.401 22,27C
11 30Yo 6,968,747 411.401 3,941,037
12 Total Line No. 6 8,054,933 3,941,037 22,27Q
'13
14
15 State of ldaho 63,806,080 4'.t1.402 4,393,349 411.402 't,238,24e
16
't7
1B
1g
2A
21
22
aa
24
.E
26
27
28
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
4e,
47
48
FERC FORM NO.1 (ED.12-89)Page 266
Cr rrrcr
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5_1en Originat(2) l-l A Resubmission
Dale of Report(Mo, Da, Yr)
04116t2019
Year/Period of Report
End of 20181Q4
Balance at Endof Year
(h)
Averaoe Period
of Allocation
to lncome(i)
ADJUSTMENT EXPLANATION Line
No.
1
2
243,760 8.21 3
4
1 3,61 1 ,1 93 9.33 5
1 1,973,700 6
66,961 ,1 83 51.53 7
92,789,836 8
I
1,063,916 48.78 '10
10,909,784 11
11,973,700 12
13
14
66,961,183 15
to
17
18
19
20
21
22
,'1.
24
25
26
27
28
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
4B
FERC FORM NO.1 (ED. 12-89)Page 267
Name of Respondent
ldaho Power Company
This Reoort Is:(1) gNAn orisinat(2) nA Resubmission
Date of Report(Mo, Da, Yr)
a4116t2419
Year/Period of Report
End of 20181Q4
nt
1. Report below the particulars (details) called for concerning other deferred credits.
2. Fot any deferred credit being amortized, show the period of amortization.
3. Minor items (5% of the Balance End of Year for Account 253 or amounts less than $100,000, whichever is greater) may be grouped by classes.
Line
No.
Description and Other
Defened Credits
(a)
Balance at
Beginning of Year
(b)
DEBITS
Credits
(e)
Balance at
End of Year
(f)
Conlra
Account(c)
Amount
(d)
1 PTP Transmission Deposits 253201 1,847,225 237 526,788 275,000 1,595,437
2
J FTV Dark Fiber Rental 253202 1,666,666 400 400,000 1,266,666
4 Amortization period 03/98-02/23
5
6 Sho-Ban Scholarships 253480 157,500 15,000 't42,500
7 Amortization period 01 105-1 2127
8
I Operations Accrual 253550 438,284 Various 59,326 117,992 496,950
10
11 Postretirement Benefi ts 253960 1,216,876 238,856 1,455,732
12
13 Directors Deferred Compensation 3,419,719 401 413,236 342,239 3,348,722
14 253970-253999
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
47 rOTAL 8,746,270 1,414,350 974,O87 8,306,007
FERC FORM NO.1 (ED.12-94)Page 269
242
Name of Respondent
ldaho Power Company
This Reoort ls:(1) []An orisinal(2) f-1A Resubmission
Date of Report(Mo, Da, Yr)
04t1612019
Year/Period of Report
End of 2O18lQ4
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 41 0.1
(c)
Amounts Credited
to Account 41 1.1
(d)
1 Account 282
2 Electric 5,256,947 20,716,527
3 Gas
4 Other
TOTAL (Enter Total of lines 2 thru 4)300,592,058 5,256,947 20,716,527
6 Non-Operating Property
7 Other - Regulatory Asset 5U,329,442
I Like Kind Exchange- Reclass No 5,409,423
I TOTAL Account 282 (Enter Total of lines 5 thru 890,330,923 5,256,947 20,716,52t
10 Classification of TOTAL
11 Federal lncome Tax 716,118,788 5,1 97,1 64 20,612,598
12 State lncome Tax 174,212,'.t35 59,783 103,929
13 Local lncome Tax
NOTES
FERC FORM NO.1 (ED. r2.96)Page 274
300,592,05€
1 An
ls:
Originalldaho Power Company (2)A Resubmission
Date of Report(Mo, Da, Yr)
04t16t2019
Year/Period of Report
End of 20181Q4
3. Use footnotes as required.
CHANGES DURING YEAR ADJUSTMENTS
Balance at
End of Year
(k)
Line
No.
Amounts Debited
to Account 410.2
(e)
Amounts Credited
to Account 41 1.2
(0
Debits Credits
Account
Credited(s)
Amount
(h)
Account
Debited
(i)
Amount
(i)
1
254 3,359,749 282t254 7,510,55€289,283,28t 2
3
4
3,359,749 7.510,55S 289,283,28t 5
6
182 29,814,U4 6',t4.144,08e 7
282 -221,698 5,187,72!8
3,359,74!37,103,505 908,615,09S I
10
254 3,359,74S 182t254 36J65,721 733,s09,32€11
182 937,785 175,105,774 12
13
NOTES (Continued)
FERC FORM NO.1 (ED.12-96)Page 275
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
04116t2019
Year/Period of Report
2A1BtQ4
FOOTNOTE DATA
No.:2 Column: b
Accou nt
Like Kind Exchange - Reclass Non-Rate Base
Excess Deferred Tax on Depreciation (Reg Liab)
CIAC-Taxable-Acct 107
Engineering Foes-Taxable-Acct 1 07
Software-Labor Costs Deducted-Acct 107
lntangible-Labor Costs D€duct€d-Acct 107
FERC FORM NO. 1 (ED. 12-87)Page 450.1
2018 ChanEes during Year Adjustments Debits Adjustments Credits 2018
EeginninB
Balance
b
DR to
410,1
c
CR to
4LL.7
d
Acct.
credited Amount
h
Acct.
debited
i
Amount
I
EndinE
Balance
k
490.499,923
(5,409,423)
(193,991 ,452)
(3,266,525)
(41 6,628)
1,975,684
11.200,479
3,689,1 00
103,284
47
861 ,1 13
603,403
20,253,7A1
432,788
30,038
254967 3,359,749
282111
254967
221,698
7,288,861
473,935,322
ls,L87,72Sl
(190,062,340)
(3,s95,029)
li446,6191
2,836,797
11,803,882
300,s92,0s8 5,2s6,947 20,716,527 3,1s9,749 7,510,559 289,283,288rfAL
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5l1An orisinat(2) f-lA Resubmission
Date of Report(Mo, Da, Yr)
04t1612019
Year/Period of Report
End of 2UAQ4
1. Report the information called for below concerning the respondent's accounting for deferred income taxes relating to amounts
recorded in Account 283.
2. For other (Speciff),include defenals relating to other income and deductions.
Line
No.
Account
(a)
Balance at
Beginning of Year
(b)
CHANGES DURING YEAR
to
Amounts Credited
to Accotilt 411.1
1 Account 283
2 Electric
3 Other Electric - See Note 51.700.1 30,518,46S 15,060,757
4
5
6
7
I Other - See Note 7r,859,6r
I TOTAL Electric (Total of lines 3 thru 8)124,559,721 30,518,469 15,060,757
10 Gas
11
12
13
14
15
16
17 TOTAL Gas (Total of lines 11 thru 16)
18 Other - See Note 1 11,350
19 TOTAL (Acct 283) (Enter Total of lines 9, 17 and 1B)124,556,461 30,s18,653 15,072,107
20 Classification of TOTAL
21 Federal lncome Tax 94,348,750 23,148,824 10,815,784
22 State lncome fax 34,207,711 7,369,829 4,256,324
23 Local lncome Tax
NOTES
FERC FORM NO.1 (ED.12-96)Page 276
I
-3,260
Name of Respondent
ldaho Power Company
(1)
(2)
An Original
A Resubmission 0411612019
YearlPeriod of Report
End of 20181Q4
ACCUMULAIED DEFERRED INCOME TAXES - OTHER (Accounl 2B3) (Continued
3. Provide in the space below explanations for Page 276 and 277. lnclude amounts relating to insignificant items listed under Other,
4. Use foolnotes as required.
CHANGFS DI,IING YFAR
Balance at
End of Year
(k)
Line
No.
Amounts Debited
to Account 410.2
(e)
Amounts Credited
to Account 41 1.2
(0
Debits Credits
crlafeo Amount
(h)
ACCTUnIDebited(i)
Amount
(i)
1
2
67,157,877 3
4
5
6
7
190 -785,464 72,074,092 8
-785,464 139,231 ,969 9
10
11
12
13
14
15
16
17
-14,426 18
-785,4U 139,217,543 19
20
190 84,111 106,765,901 21
190 -869,575 32,451,641 22
23
NOTES (Continued)
FERC FORM NO.1 (ED.
'2-96)Page 277
Name of Respondent
ldaho Power Company
This Report is:
(1)X An Original
(2) - A Resubmission
Date of Report
(Mo, Da, Yr)
04116t2019
Year/Period of Report
20181Q4
FOOTNOTE DATA
Schedule 276 Line No.:3 Column: b
Account
Renewable Energy
Royalty lncome
Pension Expense
PCA Expense
lntervenor Funding Orders
Fixed Cost Adjustment
PS & I Costs
Oregon PCAM
2011 LIDAR Surveys Deferral
Boardman Decommission
Valmy Settlement Adjustment
EIM Deferral
Valmy Depreciation Adjustment
Langley Revenue Accrual
Conservation Expenses
Siemens LTP Contract
Prepaid Credit Facility
Siemens OR DRB lnterest Reserve
Boardman Removal Costs
TOTAL
Schedule 276 Line No.: I Column: b
Account
(a)
158
Postretirement Plan-FAS 1 58
TOTAL
Schedule 276 Line No.: 18 Column: b
Account
a
EDC-Unrealized Gain/Loss From Rabbit Trust
SMSP-Unrealized Gainiloss From Rabbi Trust
FERC FORM NO. 1 (ED. 12-871 Page 450.1
2018 Changes during Year 2018
Beginning
Balance
b
DR to
4t0.L
c
CR to
47L.7
d
Ending
Balance
k
126,691
237,340
30,547,823
76,300
8,015,436
103,957
(202,380)
56,636
377,412
11,1s9,753
209,469
(444,450)
1,248,806
46,153
144,428
(8,958)
5,749
515,640
17
10,609,226
156
2,998,021
632
204,243
103
286,282
1,757,818
260
13,361,104
415,851
353,436
13,237
337
161
1,945
837,100
3,959
4,790,860
11,844
665,342
6,999,800
200,728
62,740
3,756
1,276,023
541
38,193
8,671
70
17,748
73,129
70,253
(t94,7691
233,398
36,366,190
58,708
10,940,327
34,336
1,863
44,895
(1,548)
5,977,777
9,001
73,298,354
(32,3ss)
326,279
58,849
L06,572
(17,469)
7,624
s1,700,165 30,518,469 15,060,757 67,157,877
2018 Changes
during Year
Adjustments Credits 2018
Beginning
Balance
b
DR to
4L0.1
c
CR to
47L.1
d
Acct.
debited
i
Amount
Ending
Balance
k
72,068,421
791,135
190
190
33,454
(818,918)
72,Lot,875
(27,783)
72,859,556 190 {.785,4641 72,O74,O92
2018 Changes during
Year
2018
Beginning
Balance
b
DR to
410.1
c
Ending
Balance
k
CR to
417.7
d
4,473
(7,s86)
253
1
1
B
4
35
4,577
6,771
2
(63)
{'74,6221
259
(3,250)184 11,350 (14,426].TOTAL
Tax
i
Name of Respondent
ldaho Power Company
ThiS Reoort ls:
lX lAn Original
l-lA Resubmission
(1 )
(2)
Date of Report
(Mo, Da, Y0
04t16t2019
Year/Period of Report
End of 20181Q4
OTHER REGULATORY LIABILITIES (Account 254)
1. Report below the particulars (details) called for concerning other regulatory liabilities, including rate order docket number, if
applicable.
2. Minor items (5% of the Balance in Account 254 atend of period, or amounts less than $100,000 which ever is less), may be grouped
by classes.
3. For Regulatory Liabilities being amortized, show period of amortization.
Line
No
Description and Purpose of
Other Regulatory Liabilities
(a)
Balance at Begining
of Current
Quarter/Year
(b)
DEBITS
Credits
(e)
Balance at End
of Current
Quarter^fear
(0
Account
Credited
(c)
Amount
(d)
'l Market to Market Short Term - (254001 )18,155 3,682,258 3,700,413
2 IPUC Order #28661
J
4 ldaho DSM Rider (254201)407,604 Various 33,663,001 38,514,354 5,258,957
5 IPUC 0rder #29026
6
7 BPA Credit Residential Idaho (254401 )964,483 Various 10,002,245 I 0,935,1 51 1,897,389
8 Advice #1 5-1 3
o
10 BPA Credit ResidentJal 0regon (254402)93,231 Various 389,1 90 391,64:95,684
1'l Advice #15-1 I
12
13 BPA Credit Farm ldaho (254403)( 34,946)Various 1,597,875 1,971 ,28C 338,4s9
14 Advice #1 5-1 3
15
'16 BPA Credit Farm 0regon (254404)1,734 Various 95,603 108,3sS 14,490
17 Advice #15-1 1
18
19 0rEon Green Tags (254415)108,044 Various 64,651 128,439 171,832
20 Advice #1 1-086
21
22 ldaho Tax Setuement (254451 )1,721,624 1,721,624
23 IPUC Order #34071
24
25 0regon Tax Settlement (254452)564,308 564,308
26 0PUC Advice #1 8-1 99
27
28 Bridger Depreciation (254800)1,938,839 597,68€2,536,s25
29 0PUC 0rder #12-296
30
31 RL-WAQC CRYoVR (254901 )104,602 25,782 130,384
32 IPUC Order #29505
33
34 Unfunded Accum Def lncome Tax (254966)30,666,0s4 1,496,757 32,162,811
35
36 RL-DEF rNC TAX-ARAM (254967)1 93,991,452 Various 3,929,1 11 190,062,341
37
38 RL-DEF rNC TAX-ARAM GR0SS-Up (254968)68,077,705 Various 2,1 98,300 65,879,405
39
40 ldaho Revenue Sharing (254101)5,024,562 5,024,562
41 TOTAL 307,404,206 81,642p22 126,02't ,696 351,782,980
FERC FORM NO. 1/3-Q (REV 02-04)Page 278
Name of Respondent
ldaho Power Company
This
(1)
(2)
ReDort ls:
fiAn originat
flA Resubmission
Date of Report
(Mo, Da, Y0
04t16t20't9
Year/Period of Report
End of 20181Q4
OTHER REGULATORY LIABILITIES (Account 254)
1. Report below the particulars (details) called for concerning other regulatory liabilities, including rate order docket number, if
applicable.
2. Minor items (5% of the Balance in Account 254 at end of period, or amounts less than $100,000 which ever is less), may be grouped
by classes.
3. For Regulatory Liabilities being amortized, show period of amortization.
Line
No.
Description and Purpose of
Other Regulatory Liabilities
(a)
Balance at Begining
of Current
QuarterAfear
(b)
DEBITS
Credits
(e)
Balance at End
of Current
QuarterlYear
(0
Account
Credited
(c)
Amount
(d)
1 IPUC 0rder Pending
2
3 RA-PCA Defenal-lD (254425)5,336,64'1 Various 23,059,065 59,876,231 42,153,807
4
a RA-0R BDMN Decomm 0rder #1 2-235 147,904 Various 147 ,904
6
7 Minor ltems (6)5,582,704 6,495,977 983,262 69,989
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 TOTAL 307,404,206 81,642,922 126,02'1 ,696 35'1,782,980
FERC FORM NO. 1/3-Q (REV 02-04)Page 278.1
of
ldaho Power Company (1)
(2)
An
A Resubmission
Date of Report(Mo, Da, Yr)
04116t20't9
Year/Period of Report
End of 20181Q4
1. The following inslructions generally apply to the annual version of these pages. Oo not report quarterly data in columns (c), (e), (f), and (g). Unbilled revenues and MWH
related to unbilled revenues nesd not be reported separately as required in the annual version of these pages.
2. Report below operating revenues for each prescribed account, and manufactured gas revenues in total.
3. Report number of customers, columns (f) and (g), on the basis of meters, in addition to the number of flat rate accounts: except thal wh6re separate meter readings are added
for billing purposes. one customer should be counted for each group of meters added. The -averag€ number of customers means the av€ragg of twelvs figures at the close of
each month.
4. lf increases or decreases from previous period (columns (c),(e), and (g)), are not dsrivod from previously reported figures, explain any inconsistencies in a footnote.
5. Disclose amounts of $250,000 or greater in a footnote for accounls 451 , 456, and 457.2.
Line
No.
Title of Account
(a)
Operating Revenues Year
to Date Quarterly/Annual
(b)
Operating Revenues
Previous year (no Quarterly)
(c)
I Sales of Electricity
2 (440) Residential Sales 533,062,028 552,333,276
3 (442) Commercial and lndustrial Sales
4 Small (or Comm.) (See lnstr. 4)466,201,600 465,145,591
5 Large (or lnd.) (See lnstr. 4)1 91 ,1 75,361 195,124,244
6 (444) Public Street and Highway Lighting 4,032,545 4,079,095
7 (445) Other Sales to Public Authorities
8 (446) Sales to Railroads and Railways
I (448) I nterdepartmential Sales
10 TOTAL Sales to Ultimate Consumers 1,194,471 ,534 1,216,682,206
11 (447) Sales for Resale 79,1 56,537 33,381,940
12 TOTAL Sales of Electricity 1,273,628,071 1,250,064,146
13 (Less) (449.1) Provision for Rate Refunds 19,972,541 10,706,040
14 TOTAL Revenues Net of Prov. for Refunds 't,253,655,530 1,239,358,106
15 Other Operating Revenues
16 (450) Forfeited Discounts
17 (451 ) Miscellaneous Service Revenues I 4.463,096 4,273,744
18 (453) Sales of Water and Water Power
19 (454) Rent from Electric Property 16,048,736 15,236,098
20 (455) lnterdepartmental Rents
21 (456) Other Electric Revenues 36,461.056 39,921,003
22 (456.1) Revenues from Transmission of Electricity of Others 51,329,032 42,071,453
23 (457.1) Regional Conkol Servier Revenues
24 (457.2) Miscellaneous Revenues
25
26 TOTAL Other Operating Revenues 108,301,920 101 ,502,298
27 TOTAL Electric Operating Revenues 1,361,957,450 1,340,860,404
FERC FORM NO. 1/3-Q (REV. 12-05)Page 300
Name Respondent ls:
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report
(Mo, Da, Yr)
o411612019
YearlPeriod of Report
End of 2018/Q4
ELECTRIC OPERATING REVENUES I
6. Commercial and industrial Sal6s. Account 442, may be classifled according lo the basis of classification (Small or Commercial, and Large or lndustrial) regulady used by tho
respondentifsuchbasisofclassificationisnotgenerallygreaterthanl000Kwofdemand. (SeeAccount442oftheUniformSystemofAccounts. Explainbasisofclassification
in a footnote.)
7. Seepagesl0S-l09,lmporlantChangesDuringPeriod,forimportantnewterritoryaddedandimportantratoincreaseordocreases.
8. For Lines 2,4,5,and 6, seo Page 304 for amounts r€lating to unbilled revenue by accounts.
9. lnclude unmetered sales. Provide details of such Sales in a footnote.
MEGAWATT HOURS SOLD AVG.NO. CUSTOMERS PER MONTH Line
No.Year to Date QuarterlyiAnnual
(d)
Amount Previous year (n0 Quartedy)
(e)
Current Year (no Quarterly)
(0
Previous Year (no Quarterly)
(s)
1
s,134,576 s,354,568 459,128 448,800 2
3
6,049,156 5,838,862 88,929 87,675 4
3,370,566 3,345,712 118 120 5
32,224 31,812 3,280 2,995 6
7
8
I
14,586,522 14,570,954 551,455 539,s9C 10
2,863,637 2,135,649 11
17,450,159 16,706,603 551,455 539,59C 12
13
17,450,159 16,706,603 551,455 539,59C 14
Line 12, column (b) includes $
Line 12, column (d) includes
-6,071,163
-'15,220
of unbilled revenues.
MWH relating to unbilled revenues
FERC FORM NO. 1/3.Q (REV. 12-05)Pag€ 301
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
0411612019
Year/Period of Report
2018tQ4
FOOTNOTE DATA
Schedule Page: 300 Line No.: 17 Column: bThis amount consists of:
Service Establ-lshment,/Connecti-on Charges
( Includes late and after hour charges )Misc. Under $250,000
$4 ,791,1 63
2't1
Total Account 451 s4, 463,096
Schedule Page: 300 Line No.:21 Column: b
Thi-s amount consists of:Alternate Distribution Servlce
DSM ActiviLyMisc. Under $250,000
$ 592,364
35 ,'? 02 , 948
L65",J.*!.
$36,46L,056Total Account 456
FERC FORM NO. 1 (ED. 12-871 Page 450.1
Name of Respondent
ldaho Power Company
This
(1)
(2)
Reoort ls:
fiAn ortginal
;1A Resubmission
Date of Report
(Mo. Da, Yr)
0411612019
Year/Period of Report
End of 20181Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue ac@unt 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.
Line
No
NumDer anO ltue ot Hate scheoule
(a)
MWn 50to
(b)
KCVENUE
(c)Per !
Hevenue HerKWh Sold(f)
1 440 - Residential Sales:
2 01 - Residential 5,115,376 518,023,382 455,721 11,225 0.1 01 3
I 03 - Residential Master Meter 4,609 447,826 23 200,391 0.0972
4 05-Residential -TOD 19,171 1,880,049 1 ,159 16,541 0.0981
06 - Residential On-Site Generati 14,316 1,s30,181 2,225 6,434 0.1 069
€15 - Dusk to dawn lighting 2,634 645,239 0.2450
7 Unbilled Revenues -21,530 -4,959,747 0.2304
8 Other Revenues 15,495,098
o Total 440 5,134,576 533,062,028 459,128 11,183 0.1 038
10
11 442-Commercial & lndushial Sales
12 07 - General service 149,668 18,585,424 31 ,016 4,826 0.1242
13 08 - General service On-Site Gene 226 28.289 43 5,256 0.1252
14 09P - General service s42,007 35,660,806 244 2,221,34C 0.0658
't5 09S - General service 3,366,257 249,273,645 35,547 94,699 0.0741
16 09T - General service 6,534 456,427 4 1,633,50C 0.069s
17 15 - Dusk to Dawn Light 4,312 755,243 0.1751
18 'l9P - Uniform rate contracts 2,298,361 133,757,391 111 20,705,955 0.0582
19 195 - Uniform rate contracts 6,412 388,232 1 6,012,00c 0.0646
20 19T - Uniform rate contracls 142,742 8,195,430 2 47,580,667 0.0574
21 24S - lrrigation Pumping 1,976,587 156,436,905 21,104 93,659 0.0791
22 40 - General service 10,431 906,986 971 10,743 0.0870
23 Special Contracts 910,281 46,514,4',t9 J 303,427,000 0.0511
24 Commercial & lndustrial Unbill 6,304 -'1,095,8s8 -0.1738
25 Other Revenues 7,513,622
2e Tolal M2 9,419,722 657,376,961 89,047 105,784 0.0698
27
28 444 - Public Slreet Lighting:
29 40 - General service 786 68,697 468 1,679 0.0874
30 41 - Street lighting 28,636 3,775,167 2,181 't 3,130 0.1318
31 42 -Tratfic control lighting 2.796 177,646 631 4,431 0.0635
32 Unbilled 6 15,563 -2.5938
33 Other Revenues 26,5S8
34 Total 444 32,224 4,032,545 3,280 9,824 0.1251
35
36
37
3B
39
40
41 TOTAL Billed 1,200.542,697 551,459 26.479 0.0822
42 Total Unbilled Rev.(See lnstr. 6)-15,22C -6,071,163 c (0.398S
43 TOTAL 14,586,522 1 ,194.471.534 551,455 26,451 0.081s
FERC FORM NO. I (ED.12-95)Page 304
satesitomer
14.601.74
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Reoort
(Mo, Da, Yi)
04t16t2019
Year/Period of Report
End of 20181Q4
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
powerexchangesduringtheyear. Donotreportexchangesofelectricity(i.e.,transactionsinvolvingabalancingofdebitsandcredits
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, lhe 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 intenupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.9., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
lF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. 'Long-term" means five years or Longer. The availability and reliability of
seivice, aside from transmission constraints, must match the availability and reliability of designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line
No.
Name of Company or Public Authority
(Footnote Affi liations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule orTariff Number
(c)
Averaoe
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
Averaoe
Monthly NCF Demanr
(e)
Averaoe
Monthly C{Demand
(0
1 ADM lnvestor Services, lnc.]S WSPP
2 Arizona Public Service Co.SF WSPP
3 Avangrid Renewables (IBERDROLA)OS OATT
4 AVANGRID RENEWABLES, LLC SF WSPP
5 Avista Corp.os WSPP
6 Avista Corp.SF WSPP
Avista Corp. - WWP Div.OS OATT
B Basin Eleckic Power Cooperative )S WSPP
9 Basin Electric Power Cooperative SF WSPP
10 Black Hills Power lnc.OS WSPP
11 Black Hills Power lnc.SF WSPP
12 Black Hills Power lnc.0s OATT
13 Bonneville Power os OATT
14 Bonneville Power Administration SF WSPP
Subtotal RQ 0 0 0
Subtotal non-RQ c 0 0
Total 0 0 0
FERC FORM NO.1 (ED.12-eo)Page 310
of
ldaho Power Company
(1)
(2)
An Original
A Resubmission
Date of Report
(Mo, Da, Yr)
0411612019
Year/Period of Report
End of 20181Q4
SALEi 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), identifiT 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 (0 must be in megawafts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g)through (k) must be subtotaled based on the RQiNon-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ' amount in column (g) must be reported as Requirements Sales For Resale on Page
401 , line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements 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
($)
0)
1,328,994 1,328,994 1
11,703 300,358 300,358 2
8,064 8,064 3
9,433 221,941 221,941 4
6,350 46,400 46,400 5
39s,700 5,835,801 5,835,801 6
424 42C -7
9,986 25,544 25,544 8
5,155 9,670 9,670 I
500 2,500 2,500 10
31 ,261 252,121 252,121 11
447 447 12
2,207,278 2,207,278 IJ
1 15,004 3,680,760 3,680,760 14
0 0 0 0 0
2,863,637 0 69,701 ,1 80 9,455,357 79,1 56,537
2,863,637 0 69,701,180 9,455,357 79,1 56,537
FERC FORM NO.1 (ED. r2-90)Page 31'l
Name of Respondent
ldaho Power Company (1)
(2)
An Original
A Resubmission
(Mo, Da,
0411612019
Year/Period of Report
End of 20181Q4
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 Affiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule orTariff Number
(c)
Averaoe
Monthly Bitt
Demand (M
(d)
ingw)
Actual Demand (MW)
AVeraoe
Monthly NCP Demanr
(e)
AveraoeMonthly CP-Demand
(f)
1 BP Energy Company SF WSPP
2 Brookfield Energy Marketing OATT
a Brookfield Energy Markeling LP SF WSPP
4 California lndependent System Operator SF CAISO
5 Chelan Co PUD SF WSPP
6 Citigroup Energy lnc.SF WSPP
7 Citigroup Energy lnc.ISDA
I Clatskanie PUD SF WSPP
I CWP Energy OS OATT
10 DTE Energy Trading, lnc.SF WSPP
11 EDF Trading North America (EAGL)os OATT
't2 EDF Trading North America, LLG SF WSPP
13 Energy Keepers, lnc SF WSPP
14 Energy Keepers, lnc.)s OATT
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORM NO.1 (ED.12-90)Page 310.1
|on rs:
OS
OS
Name of Respondent
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
0411612019
Year/Period of Report
End of 20181Q4
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 (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401 , line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
'10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours
Sold
(g)
REVENUE Total ($)
(h+i+j)
(k)
Line
No.Demand Charges
(h)
Energy Charges
($)
(i)
Other Charges
($)
0)
21,971 677,972 677,972 1
62,334 62,334 2
250 4,O20 4,020 3
155,921 9,593,527 9,593,527 4
263 2,996 2,996 (
7,1 85 85,561 85,561 6
-21 ,912 -21,912 7
559 10,313 1 0,313 B
3,154 3,154 s
75,42s 2,512,980 2,512,980 10
4,164 4,164 11
103,587 2,334,744 2,334,744 12
44 754 754 13
35,91S 35,919 14
0 0 0 0 0
2,863,637 U 69,701,180 9,455,357 79,156,537
2,863,637 0 69,701,180 9,455,357 79,156,537
FERC FORM NO. 1 (ED. 12-90)Page 31'1.1
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
0411612019
Year/Period of Report
End of 20181Q4
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 eleclricity ( 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 nole 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 reliabilig 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 generaling unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Shtistical
Classifi-
cation
(b)
FERC Rate
Schedule orTariff Number
(c)
Averaoe
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
AVElfloE
Monthly NCP Demanr
(e)
AveraoeMonthly CPDemand
(0
1 Eugene Water & Electric Board SF WSPP
2 Exelon Generation Company, LLC SF WSPP
3 J.Aron & Company LLC 06 ISDA
4 Los Angeles Department of Water & Power SF WSPP
5 Macquarie Energy LLC SF WSPP
6 Macquarie Energy LLC OE OATT
7 Macquarie Energy LLC OS ISDA
8 MAG Energy Solutions OS OATT
I Morgan Stanley Capital Group lnc.OS ISDA
10 Morgan Stanley Capital Group lnc.SF ISDA
11 Morgan Stanley Capital Group lnc.OS OATT
12 Municipal Energy Agency of Nebraska SF WSPP
13 Nevada Power OS OATT
14 Nevada Power Company, dba NV Energy SF WSPP
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORM NO.1 (ED.12-90)Page 310'2
Name of Respondent
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
o4t'16t2019
Year/Period of Report
End of 20181Q4
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 adlustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. ln Column (c), identifo the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawaft basis and explain.
7. Report in column (g)the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Repo( 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) rnust 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
($)
(i)
Other Charges
($)
0)
5,261 1't0,525 1 10,525 1
222,475 6,414,888 6,414,888 2
40.298 40,298 3
10,800 314,550 314,55C 4
16,148 153,249 1s3,249 5
5,669 5,66e 6
-30,892 -30,892 7
61,826 61,826 B
13,615 71 ,'t 05 7'1 ,1 05 9
186,371 2,062,064 2,062,464 10
2,070,600 2,070,600 11
857 't1,727 '11,727 12
5,391 5,391 13
19,871 1 ,1 56,888 1 ,156,888 14
0 0 0 0 0
2,863,637 0 69,701 ,180 9,4s5,357 79,1 56,537
2,863,637 0 69,701,180 9,455,357 79,1 56,537
FERC FORM NO.1 (ED.12.90)Page 311.2
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
o411612019
Year/Period of Report
End of 20181Q4
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 shortterm 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 Longterm 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 designaled generating unit. The same as LU service except that "intermediate-term" means
Longerthan 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
Dem
(e)(f)
1 NorthWestern Energy SF WSPP
,NorthWestem Energy NWDS )S OATT
3 PacifiCorp WSPP
4 PacifiCorp SF WSPP
5 PacifiCorp r-7
6 PacifiCorp lnc.os OATT
7 PacifiCorp lnc. - lmnaha OS OAIT
8 Portland General Electric Company SF WSPP
I Portland General Electric Company os OATT
10 Powerex Corp.OS WSPP
11 Powerex Corp.5t-WSPP
12 Powerex Corp.os OATT
13 Public Service Company of Colorado SF WSPP
14 Puget Sound Energy, lnc.SF WSPP
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORM NO.1 (ED.12-90)Page 3'10.3
OS
os
ldaho Power Company (1)
(2)
An
A Resubmission
Date of Report(Mo, Da, Yr)
a4h6l2a19
Year/Period of Report
End of 20181Q4
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), identifu 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) rnust be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule, The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ' amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
40'l,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours
Sold
(s)
REVENUE Total (S)
(h+i+j)
(k)
Line
No.Demand Charges
(h)
Energy Charges
($)
(i)
Other Charges
($)
(i)
9,072 't25,205 125,205 1
96 96 2
8,199 47,449 47,449 3
236,151 5,510,649 5,510,649 4
51 1,754 1,754 5
2,615,958 2,615,958 6
49 49 7
127,686 5,224,361 5,224,361 8
86,089 86,08S I
3,950 8,400 8,400 10
16,751 170,957 170,957 11
47,019 47,019 12
26 685 685 13
24,436 451,822 451,822 14
0 0 0 0 0
2,863,637 0 69,701 ,1 80 9,455,357 79,156,537
2,863,637 0 69,701,180 9,455,357 79,156,537
FERC FORM NO.1 (ED.12-90)Page 311.3
Name Respondent
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
04t16t2019
Year/Period of Report
End of 201BlQ4
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
powerexchangesduringtheyear. Donotreportexchangesofelectricity(i.e.,transactionsinvolvingabalancingofdebitsandcredits
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 servlce to its own ultimate consumers.
LF - for tong-term service. "Long-term" means flve 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 which meets the
deflnition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
lF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classifi-cation
(b)
FERC Rate
Schedule orTariff Number
(c)
Averaoe
Monthly Billing
Demand (MW)
(d)
Actual Demand
(e)(f)
1 Rainbow Energy Marketing Corporation SF WSPP
2 Rainbow Energy Marketing Corporation ]S OATT
J Salt River Project SF WSPP
4 Seattle City Light )S WSPP
4 Seattle City Light SF WSPP
b Seattle City Light OS WSPP
7 Shell Energy North America (US), L.P WSPP
8 Shell Energy North America (US), L.P SF WSPP
9 Shell Energy North America (US), L.P OS OATT
10 Sierra Pacific Power Co., dba NV Energy )S r-7
11 Snohomish County PUD SF WSPP
12 Tamma Power SF WSPP
'13 Tenaska Power Services Co.SF WSPP
14 Tenaska Power Services Co.rS OATT
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORM NO.1 (ED.12-90)Page 310.4
os
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
04t16t2019
YeariPeriod of Report
End of 20181Q4
OS - for other service. use this category only for those services which cannot be placed in the above-deflned categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-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), identifrT the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
10. Footnote enlries 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
($)
(i)
Other Charges
($)
0)
25,664 85,112 85,112 1
45,425 45,425 2
2 92 92 3
1,350 9, '150 9,1 50 4
181 ,998 2,708,676 2,708,676 5
5 65 65 b
20.677 141,479 141,479
576,823 14,356,955 14,356,955 8
426,243 426,243 I
68 2,100 2,10C 10
928 28,515 28,515 11
5,877 126,598 126,598 12
2,083 151 ,825 151,825 13
3,497 3,457 14
0 0 0 0 0
2,863,637 0 69,701 ,180 9,455,357 79,1 56,537
2,E63,637 0 69,70't,180 9,455,3s7 79,1 56,537
FERC FORi' NO. I (ED. 12-90)Page 31'1.4
S:Date of Report
(Mo, Da, Yr)
a4t16t2019ldaho Power Company
(1)
(2)
An Original
A Resubmission
Year/Period of Report
End of 2018iQ4
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 ene€y
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
lF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule orTariff Number
(c)
Averaoe
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
Averaoe
Monthly NCF Demanr
(e)
Averaoe
Monthly CPrDemand
(0
1 The Energy Authority, lnc.SF WSPP
2 The Energy Authority, lnc.OATT
a TransAlta Energy Marketing (U.S.) lnc.SF WSPP
4 TransAlta Energy Marketing (U.S.) lnc.OATT
5 Utah Associated Municipal Power Systems SF WSPP
b Utah Associated Municipal Power Systems os oArr
7 Westar Energy, lnc.SF WSPP
8 Transmission Penalty Distribution o.s
I
10
11
12
IJ
14
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORM NO.1 (ED.12-90)Page 310.5
os
OS
Name of Respondent
ldaho Power Company (1)
(2t
An Original
A Resubmission
Date of Report
(Mo, Da, Yr)
0411612019
Year/Period of Report
End of 20181Q4
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 adiustments 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), identifu 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 (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 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 (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
4O1,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours
Sold
(s)
REVENUE Totar ($)
(h+i+i)
(k)
Line
No.Demand Charges
($)
(h)
Energy Charges
($)
(i)
OtherCharges
(i)
121,031 2,859,594 2,859,594 1
3,658 3,658 2
70,099 2,063,037 2,063,O37
68,811 68,81 1 4
5,000 89,688 89,688 E
2,803 2,803 6
15 7
'18,009 18,009 8
9
10
11
12
13
14
0 0 0 0 0
2,863,637 0 69,701.180 9,455,357 79,1 56,537
2,863,637 0 69,701,1E0 9,455,357 79,1 s6,537
FERC FORM NO.1 (ED.12-90)Page 311.5
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(21 A Resubmission
Date of Report
(Mo, Da, Yr)
0411612019
Year/Period of Report
2018/Q4
FOOTNOTE DATA
Schedule Page: 310 Line No.: I Column: b
ADM Investor Services, fnc Futures Accouna
Schedule Page:310 Line No.:3 Column: bFinanciai Transmission Lcsses
Schedute Page: 310 Line No.: 5 Column: b
Non-firm Sales
Schedule Page: 310 Line No.:7 Column: bFinancial Transm"ission Losses
Schedule Page: 310 Line No.: I Column: bNon-firm Sales
Schedule Page: 310 Line No.: 10 Column: b
Non-firm Sales
Schedule Page: 310 Line No.: 12 Column: btrinanciai Transmission Losses
Schedute Page: 310 Line No; 13 Column: bFinancial- Transmi-ssion Losses
Schedule Page: 310.1 Line No; 2 Column: bFinancial Transmission Losses
Schedule Page: 310.1 Line No-:7 Column: b
ISDA Master Agreement with Citigroup Energy
Schedule Page: 310.1 Line No.: I Column: bEi-nancial Transmission Losses
Schedule Page: 31Q,! Line No.: 11 Cotumn: bFi-nanciai Transmission Losses
Schedule Page: 310.1 Line No.: 14 Column: bFinanciai Transmission Losses
Schedule Page: 310.2 Line ?i*.: 3 Cei*r:':r',' l:
Document, dated May 5, 2AI5
Inc. dated March 7, 2071
ISDA Master Agreement with J. Aron & Company dated April 30,
Schedule Page: 310.2 Line No.: 6 Column: b
Financlal Transmission Losses
Schedule Page:310.2 Line No.:7 Cotumn: b
ISDA MasLer Agreement with Macquarie Energy, LLC dated Aprj-1
Schedule Page: 310.2 Line No.: I Column: bFinancial Transmission Losses
Schedule Page: 310.2 Line No.: I Cotumn: b
i.lln-.i-::i, i;Le:.;
Schedule Page: 310.2 Line No.: 11 Column: bFinanciai Transmission Losses
Schedule Page: 310.2 Line No.: 13 Cotumn: bFinancial Transmi-ssion Losses
Schedule Page: 310.3 Line No; 2 Column: b
!'inanclal Transmissicn Losses
Schedule Page: 310.3 Line No.: 3 Column: b
|lcn-firn.Sales
Schedule Page: 310.3 Line No.: 5 Column: bSpinning or Oper:aling Reserves
Schedule Page: 310.3 Line No.: 6 Column: b
Financial Transmission Losses
Schedule Page: 310.3 Line No.:7 Column: bFinancial Transmi-ssion Losses
Schedule Page: 310.3 Line No.:9 Column: bFinancial Transmission Losses
Schedule Page: 310.3 Line No.: 10 Cotumn: bNon-firm Sales
2014
12, 2011
FERC FORM NO. 1 (ED. 12-871 Page 450.1
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04t't6t2019
YearlPeriod of Report
2018tQ4
FOOTNOTE DATA
Schedule Page: 310.3 Line No.: 12 Column: b
Finan,:ial- Transrnissiorr Losses
Schedule Page: 310.4 Line No.: 2 Column: b
Financial Transnission Losses
Schedule Page: 310.4 Line No.: 4 Column: b
Non-firm SaLes
Schedule Page: 310.4 Line No.:6 Column: bSplnning or Operating Reser:ves
Schedule Page: 310.4 Line No.:7 Column: b
Non-fi rm Sales
Schedute Page: 310.4 Line No.: 9 Column: b
Financiai Tran-smissi.on Losses
tchedule Page: 310.4 Line No.: 10 Column: b$pinninq or Operating Reserves
Schedule Page: 310.4 Line No.: 14 Column: b
Financial Transmi"ssion Losses
Schedule Page: 310.5 Line No.: 2 Column: b
Financi.. lransnrissron Los=e;
Schedule Page: 310.5 Line No.: 4 Column: b
Fi.nancial Transmission Losses
Schedule Page: 310.5 Line No.: 6 Column: b
Financiaf Transmission Losses
Schedule Page: 310.5 Line No.: I Column: b
Transni-ssicn penalty distribution creoi's
FERC FORM NO. 1 (ED. 12-871 Page 450.2
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5]Rn orisinal(2) fiA Resubmission
Date of Report(Mo, Da, Yr)
04t16t2019
Year/Period of Report
End of 20181Q4
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
lf the amount for previous year is not derived from previously reported flgures, explain in footnote,
Line
No.
Account
(a)dB8Hiv35,(b)
Amount forPrevious Year
(c)
1 1. POWER PRODUCTION EXPENSES
2 A. Steam Power Generation
Operation
4 (500) Operation Supervision and Enqineering 1,204.942 978,720
5 (501 ) Fuel 115,523.571 107,893,663
6 (502) Steam Expenses 9,912,734 8,s01,434
7 (503) Steam from Other Sources
8 (Less) (504) Steam Transfened-Cr.
9 (505) Electric Exoenses 1,868,433 1,396,032
10 (506) Miscellaneous Steam Power Expenses 9,'134,293 't1,6S4,905
11 (507) Rents 250,861 328,946
12 (509) Allowances
13 TOTAL Operation (Enter Total of Lines 4 thru 12)137,895,234 130,793,700
14 Maintenance
15 (510) Maintenance Supervision and Engineering 213,256 55.228
16 (51 1) Maintenance of Structures 349 440.434
17 (512) Maintenance of Boiler Plant 10,847,201 1't,031,366
't8 (513) Maintenance of Electric Plant 4,545,026 4,331,373
19 (514) Maintenance of Miscellaneous Steam Plant 7142.704 5,935,275
20 TOTAL Maintenance (Enter Total of Lines 15 thru 19)23,097,610 21,793,676
21 TOTAL Power Production Expenses-Steam Power (Entr Tot lines 13 & 20)160,992,844 152,587.376
22 B. Nuclear Power Generation
23 Operation
24 (517) Ooeration Suoervision and Enqineerinq
25 (518) Fuel
26 (519) Coolants and Water
27 (520) Steam Expenses
28 (521) Steam from Other Sources
29 (Less) (522) Steam Transferred-Cr
30 (523) Electric Expenses
31 (524) Miscellaneous Nuclear Power Expenses
32 (525) Rents
33 TOTAL Operation (Enter Total of lines 24lhru 32'7
34 Maintenance
35 (528) Maintenance Supervision and Enqineerino
36 (529) Maintenance of Structures
37 (530) Maintenance of Reactor Plant Equipment
38 (53'1 ) Maintenance of Electric Plant
39 (532) Maintenance of Miscellaneous Nuclear Plant
40 TOTAL Maintenance (Enter Total of lines 35 thru 39)
41 TOTAL Power Production Expenses-Nuc. Power (Enh tot lines 33 & 40)
42 C. Hydraulic Power Generation
43 Operation
44 (535) Operation Supervision and Engineering 5,629,020 s,699,366
45 (536) Water frcr Power 9,123.648 5.857,068
46 (537) Hydraulic Expenses 15,387,250 15,008,403
47 (538) Elechic Exoenses 1,884,840 1,912,278
48 (539) Miscellaneous Hydraulic Power Generation Expenses 5,600,843 8.270.822
49 (540) Rents 246,704 24',t.787
50 TOTAL Operation (Enter Total of Lines 44 thru 49)37,872,305 36,989,724
51 C. Hydraulic Power Generation (Continued)
52 Maintenance
53 (541) Mainentance Supervision and Engineering 93,530 94,013
54 (542) Maintenance of Structures 745,081 1,139,09s
55 (543) Maintenance of Reservoirs. Dams, and Wateruvavs 332,571 821,883
56 (544) Maintenance of Electric Plant 2,988,299 1,877,280
57 (545) Maintenance of Miscellaneous Hydraulic Plant 2,666,883 2,819,560
58 TOTAL Maintenance (Enter Total of lines 53 thru 57)6,826,364 6,7s1,831
59 TOTAL Power Production Expenses-Hydraulic Power (tot of lines 50 & 58)44,698,669 43,741,555
FERC FORM NO.1 (EO.12-93)Page 320
Name of Respondent
ldaho Power Company
This Reoort ls:(1) []An orisinal(2) fiA Resubmission
Date of Report(Mo. Da, Yr)
04t16t2019
Year/Period of Report
End of 2O18lQ4
lf the amount for previous year is not derived ftorn previously reported flgures, explain in footnote.
Line
No.
Account
(a)
Amount forCunent Year
(b)
Amount forPrevious Year
(c)
60 D. Other Power Generation
61 Operation
62 (546) Operation Supervision and Engineering 648.947 687,916
63 (547) Fuel 17.673.949 37,935,1 65
64 (548) Generation Exoenses 4,513,426 4,171.674
65 (549) Miscellaneous Other Power Generation Expenses 1,406,549 986,828
66 (550) Rents
67 TOTAL Operation (Enter Total of lines 62 thru 66)24,242,871 43,781 .579
68 Maintenance
69 (551) Maintenance Supervision and Engineering 40 226
70 (552) Maintenance of Strucfures 215,293 335,09'1
71 (553) Maintenance of Generating and Electric Plant 1 595,0B5
72 (554) Maintenance of Miscellaneous Other Power Generation Plant 2,641,0A4 2,226,109
73 TOTAL Maintenance (Enter Totial of lines 69 thru 72)2,980,980 3,1s6.511
74 TOTAL Power Production Expenses-Other Power (Enter Tot of 67 & 73)27,223,851 46,938.090
75 E. Other Power Supply Expenses
76 (555) Purchased Power 287,762,141 244.381.204
77 (556) System Control and Load Dispatching 5.331 2,885
78 (557) Other Exgenses 46,535,908 56,007,259
79 TOTAL Other Power Supply Exp (Enter Total of lines 76 thru 78)334,303,380 300,391,348
80 TOTAL Power Produclion Expenses (Total of lines 21, 41 , 59, 74 & 79\567,218,744 543,658,369
81 2. TRANSMISSION EXPENSES
82 Operation
83 (560) Operation Suoervision and Enqineerinq 3,318,397 3,150,433
84
85 (561.1 ) Load Dispatch-Reliability 10,084 '1 1 ,169
86 (561 .2) Load Dispatch-Monitor and Operate Transmission System 2,117,726 1,620,215
87 (561 .3) Load Dispatch-Transmission Service and Scheduling 1,440,U2 1,526,249
88 (561.4) Schedulinq, System Control and Dispatch Services 6,438
89 (561.5) Reliability, Planning and Standards Development
90 (561.6) Transmission Service Studies
91 (561.7) Generation lnterconnection Studies 35,961 32,101
92 (561.8) Reliability, Planning and Standards Development Services 1 ,715,639 1,698,457
93 (562) Station ExDenses 2,855.188 2,887,872
94 (563) Overhead Lines Expenses 878,708 1,070,029
95 (564) Underground Lines Expenses
96 (565) Transmission of Electricity by Others 3,602,155 4,568,399
97 (566) Miscellaneous Transmission Expenses 1 5,1 65 25
98 (567) Rents 2,710,673 4,782,018
99 TOTAL Operation (Enter Total of lines 83 thru 98)18,706,976 21,346,967
100 Maintenance
101 (568) Maintenance Supervision and Engineering 712,201 154,736
102 (569) Maintenance of Structures -2,653
103 (569.1) Maintenance of Computer Hardware 31,344
104 (569.2) Maintenance of Computer Software 1.024,304 925,878
105 (569.3) Maintenance of Communication Equipment 15,553 8,099
106 (569.4) Maintenance of Miscellaneous Regional Transmission Plant
107 (570) Maintenance of Station Equipment 1,721,024 1,925,172
108 (571) Maintenance of Overhead Lines 832,096 883,265
109 (572) Maintenance of Underqround Lines
110 (573) Maintenance of Miscellaneous Transmission Plant 3,357
111 TOTAL Maintenance (Total of lines 101 thru 1 10)3,931,851
112 TOTAL Transmission Expenses (Total of lines 99 and 111)23,043,358 25,278.818
FERC FORM NO.1 (EO. 12-93)Page 321
33,85i
Name of Respondent
ldaho Power Company
This
(1)
(2)
An
A Resubmission
Date of Report(Mo. Da, Yr)
04t16t2019
Year/Period of Report
End of 2A18lA4
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)
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 Rights Market Facilitation
118 (575.4) CapaciV Market Facilitation
1'19 (575.5) Ancillary Services Market Facilitation
120 (575.6) Market Monitoring and Compliance
121 (575.7) Market Facilitation, Monitorinq and Compliance Services 411,723
122 (575.8) Rents
123 Total Operation (Lines 115 thru 122)411,723
124 Maintenance
125 (576.1) Maintenance of Structures and lmprovements
126 (576.2) Maintenance of Computer Hardware
127 (576.3) Maintenance of Computer Software
't28 (576.4) Maintenance of Communication Equipment
129 (576.5) Maintenance of Miscellaneous Ma*et Operation Plant
130 Total Maintenance (Lines 125 thru 129)
''t31 TOTAL Regional Transmission and Market Op Expns (Total 123 and 130)411,723
132 4. DISTRI BUTION EXPENSES
133 Operation
134 (580) Operation Supervision and Engineering 4.550.S06 4,208,616
135 (581) Load Dispatchinq 4,354,562 4,166,896
't36 (582) Station Expenses 1,565,905 1,555,734
137 (583) Overhead Line Expenses 3,896,819 4,916,620
138 (584) Underqround Line Exoenses 3,392,139 3.615.140
139 (585) Street Lighting and Signal System Expenses 157,86'r 1 18,675
140 (586) Meter Expenses 4,574,706 4,904,91S
141 (587) Customer lnstallations Expenses 1.287.251 1.276.382
142 (588) Miscellaneous Expenses 4,939,645 6,886,864
143 (589) Rents 1,203,806 381,320
144 TOTAL Operation (Enter Total of lines 134 thru 143)29,919,600 32,031,166
145 Maintenance
146 (590) Maintenance Supervision and Engineerinq 604,934 -'t,643,939
147 (591) Maintenance of Structures -1,048
148 (592) Maintenance of Station Equipment 4,482,318 3,887,1 58
149 (593) Maintenance of Overhead Lines 17,401,297 13,8't8,926
150 (594) Maintenance of Underground Lines 703.795 748,181
151 (595) Maintenance of Line Transformers 45,593 23,843
152 (596) Maintenance of Street Liqhtinq and Siqnal Svstems 589,31 3 554,421
153 (597) Maintenance of Meters 911.444 982,875
154 (598) Maintenance of Miscellaneous Distribution Plant 214.170 240,442
155 TOTAL Maintenance (Total of lines 146 thru 154)24,951 ,816 18,61 1 ,907
156 TOTAL Distribution Expenses (Total of lines 144 and 155)54,871,416 50,643,073
157 5. CUSTOMER ACCOUNTS EXPENSES
158 Operation
159 (901) Supervision 1,116,501 945,821
160 (902) Meter Reading Expenses 1,790,s12 1,544,764
161 (903) Customer Records and Collection Expenses 13,951 ,1 12 14,205,692
162 (904) Uncollectible Accounts 3,350,112 5.732.560
163 (905) Miscellaneous Customer Accounts Expenses -4 -944
164 TOTAL Customer Accounts Expenses fiotal of lines 159 thru 163)20,208,233 22,427,893
FERC FORM NO.1 (ED.12.93)Page 322
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
lf the amount for previous year is not derived from previously reported figures, explain in footnote.
Line
No.
Account
(a)
Amount forCunent Year
(b)
Amounl forPrevious Year
(c)
165 6, CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
166 Operation
167 (907) Supervision 802.563 821 ,144
168 (908) Customer Assistance Expenses 42.486,187 44,176,525
169 (909) lnformational and lnstructional Expenses 341 ,699 444.538
170 (910) Miscellaneous Customer Service and lnformational Expenses 627,857 641,841
171 TOTAL Customer Service and lnformation Expenses (Total 167 thru 't70)44.258.306 46,084,048
172 7. SALES EXPENSES
173 Operation
174 (91 1) Supervision
175 (912) Demonstratinq and Sellinq Expenses
176 (913) Advertising Expenses
177 (91 6) Miscellaneous Sales Expenses
178 TOTAL Sales Expenses (Enter Total of lines 1 74 thru 177)
179 8. ADMINISTRATIVE AND GENERAL EXPENSES
180 Operation
181 (920) Administrative and General Salaries 88,828,776 79,079.418
182 (921) Office Supplies and Expenses 14,790,380 14,134,583
183 (Less) (922) Administrative Expenses Transfened-Credit 29.219,B',t1 27,762,969
't84 (923) Outside Services Employed 7,744,'.133 6,769,731
185 (924) Prooertv lnsurance 3,010,285 3,1 17,561
186 (925) lniuries and Damages 5,617,495 5,647,112
187 (926) Employee Pensions and Benefils 52,315.074 46,786,554
188 (927) Franchise Requirements
1B9 (928) Regulatory Commission Expenses 5,021.358 4,260,709
190 (929) (Less) Duolicate Charqes-Cr.
191 (930.1 ) General Advertising Expenses 603,786 3M,410
192 (930.2) Miscellaneous General Expenses 3,605,153 3,556,441
193 -350(931) Rents
194 TOTAL Operation (Enter Total of lines 181 thru 193)152,316,629 135,953,200
195 Maintenance
196 (935) Maintenance of General Plant 6,842,171 6,737,813
197 TOTAL Administrative & General Expenses (Total of lines 194 and 196)159,158,800 142,691 ,013
198 869,170,580 830,783,2't4TOTAL Elec Op and Maint Expns (Total 80,112,13'1,156,164,171,178,197)
ldaho Power Company
(1)
(2)
Original
A Resubmission
(Mo, Da, Yi)
a4n6t2019 End of 20181Q4
FERC FORM NO. 1 (EO. 12.93)Page 323
-
t\atne ur r1eslJonoent
ldaho Power Company
I ills
(1)
(2)
It t5.
An Original
A Resubmission
ua(e or Kepon(Mo. Da, Yr)
YearFenoo or Kepon
End of 2A1B|Q4
o4116t20'.t9
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 longterm 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{erm" 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.
Actual Demand (MW)Line
No.
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Average
Monthly NCP Demanr
(e)
Average
Monthly CP Demand
(f)
Name of Company or Public Authority
( Footnote Affi liation s)
(a)
Statistical
Classifi-
cation
(b)
1 American Falls Solar, LLC LU N/A N/A N/A
N/A2American Falls Solar ll, LLC LU N/A N/A
J AgPower Jerome LLC - Double A Digester LU N/A N/A N/A
4 Allan RavenscrofUMalad River LU N/A N/A N/A
5 Baker City Hydro LU N/A N/A N/A
N/A6Bannock County, ldaho LU N/A N/A
7 Bennett Creek Wind Farm LU N/A N/A N/A
8 Benson Creek Wind Farm LU N/A N/A N/A
I Bettencourt DryCreek Biofactory LU N/A N/A N/A
10 Big Sky West Dairy Digester LU N/A NiA N/A
11 N/A N/A N/ABlack Canyon Bliss LU
12 Blind Canyon Hydro LU N/A N/A N/A
13 Branchflower - Trout Company LU NIA N/A N/A
NiA14Burley Butte Wind Park LU N/A N/A
Total
FERC FORM NO.1 (ED.l2-90)Page 326
t\atne ot nesponoenl
ldaho Power Company
I iltD
(1)
(2)
udtE ur nuPur (
(Mo, Da, Y0 End of 20181Q4
I Udlrrslruu ul nEyur L
An Original
A Resubmission 0411612019
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-rninute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (0
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. lf more energy was delivered than received, enter a negative amount. lf the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401 ,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as required and provide explanations following all required data.
POWER EXCHANGES COST/SETTLEMENT OF POWERMegaWatt Hours
Purchased
(s)
MegaWatt Hours
Received(h)
Megawatt Hours
Delivered(i)
Demand Charges
($)
U)
Energy Charges
($)
(k)
Other Charges
($)
fl)
r)
($)
Total (J+k+l
of Settlement
(m)
Line
No.
42,667 1,335,77C 1,335,770 I
243,754 1,287,14!1,287,145
25,591 2,364,512 2,364,513 3
2,151 155,672 89,027 244,699 4
86:47,21e 47,216 5
678,65€678,656 610,98(
43,44t 2,899,05C 2,899,05C 7
30,91t 1,734,234 1,734,234 8
1,034,439 I1 1 ,31(1,034,43S
9,11:597,711 597,7',t1 10
141 4,788 4,788 11
4,411 234,475 234,479 12
85:60,06s 60,069 13
61,29(3,553,00C 3,s53,000 14
5,389,494 106,210 145,'139 894,680 285,529,748 't ,337 ,713 287,762,141
FERC FORM NO.1 (ED.12-90)Page 327
t\ame oI Kesponoent
ldaho Power Company
l nts
(1)
(2)
IS:uale ot Keport
(Mo, Da. Yr)
YeailPenod ot Report
End of 20181Q4An Original
A Resubmission o411612019
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.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveiies of LF service). This category should nofbe 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 longterm 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 availabitity 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.
Actual Demand (MW)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)
Average
Monthly NCP oeman(
(e)
Average
Monthly CP Demand
(f)
1 CAFCO ldaho Refuse Management LLC - Sl LU N/A N/A N/A
2 Camp Reed Wind Park LU N/A N/AN/A
3 Cassia Wind Farm LU N/A N/A N/A
4 CCP OR Tenant '1, LLC - Grove LU N/A N/A N/A
5 CCP OR Tenant 1, LLC - Hyline LU N/A N/A N/A
6 CCP OR Tenant 1, LLC - Open Range LU N/A N/A N/A
I CCP OR Tenant 1, LLC - Railroad LU N/A N/A N/A
8 CCP OR Tenant 1, LLC - Vale Air LU N/A N/A N/A
I CCP OR Tenant 1, LLC - Thunderegg LU N/A N/A N/A
10 City of Hailey LU N/AN/A N/A
11 City of Pocatello LU N/A N/A N/A
12 Clear Springs Food lnc.LU N/A N/A NiA
13 Clifton E. Jenson - Birch Creek LU N/A N/A N/A
14 Cold Springs Windfarm, LLC LU N/A N/A N/A
Total
FERC FORM NO.1 (ED. t2-90)Page 326.1
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.
ldaho Power Company
(1)
(2)
An Original
A Resubmission End of 2UB1A4
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), identiflT 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 (rn) 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/SETTTEMENT OF POWERMegawatt Hours
Purchased
(s)
MegaWatt Hours
Received(h)
MegaWatt Hours
Delivered
(i)
Demand Charges
($)
U)
Energy Charges
($)
(k)
Other Charges
($)
(t)
Total (j+k+l)
of Settlement ($)
(m)
Line
No.
279,512 18,533 279,512
66,824 5,499,67(5,499,676 2
24,869 1,376,18t 1 ,376,1 88 J
13,314 80s,81i 805,812 4
20,273 1,233,78€1,233,789
22,543 1,366.00(1,366,000 b
10,064 610,482 610,482 7
21,769 1,321 ,022 1,321,022 o
22,246 1,348,242 1,348,243 I
11 11 10
1,36i 101.114 101,114 11
281,42C 281,420 123,06i
35(17,50C 14,482 31,982 13
49,79t 3,753,121 3,753.121 '14
894,68C 285,529,748 1 ,337,7',t3 287,762,14',15,389,494 106,210 145,139
FERC FORM NO.1 (ED.12-90)Page 327.1
(ffi;D;,Vff '
04t16t2019
trdiltE ut nEsPuttuEttt
ij i"
(2)
Original
udrv ur nEpur t(Mo, Da, Yr)
r Ydt/TUt tuu ut nvPut t
ldaho Power Company Resubmission 04t16t20't9 End of 2O18lQ4
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 seruice 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 availabilig and reliabilig of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any seftlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Actual Demand (MW)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)
Average
Monthly NCP Demanr
(e)(0
Average
Monthly CP Demand
1 College of Southern ldaho - Pristine S LU N/A N/A N/A
College of Southern ldaho - Pristine S LU N/AN/A N/A
3 Consolidated Hydro lnc. / Enel
4 Barber Dam LU N/A N/A N/A
t Dietrich Drop LU N/A N/A N/A
6 Lowline #2 LU N/A N/A N/A
7 Rock Creek #2 LU N/A N/A N/A
8 Crystal Springs Hydro LU N/A N/A N/A
o Curry Cattle Company LU N/A N/A N/A
10 Cycle Horseshoe Bend Wind, LLC LU N/A N/A N/A
11 David R Snedigar LU N/A N/A N/A
12 Desert Meadow Windfarm LU N/A N/A N/A
13 Durbin Creek Windfarm LU N/A N/A N/A
14 Eightmile Hydro Corp LU N/A N/A N/A
Total
FERC FORM NO.1 (ED.12-90)Page 326.2
t\arlte ot l1esponoent I ilt)
(1)
(2)
t 19.udtts ut ncput t(Mo, Da, Yr)
r udrlTEuuu ut nEPUtt
End of 20181Q4ldaho Power Company An Original
A Resubmission 04t16t2019
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). l/onthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (0
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondenl. 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.
POWER EXCHANGES COST/SETTLEMENT OF POWER
Demand Charges
($)
(i)
Energy Charges
($)
(k)
MegaWatt Hours
Purchased
(g)
Megawatt Hours
Received
(h)
MegaWatt Hours
Delivered
(i)
Other Charges
($)
(t)
Total (i+k+l)
of Settlement ($)
(m)
Line
No
773 51 ,741 51,74',1 1
1,191 67,028 67,028 I
3
12,22C 611,00i 611,007 4
14,24C 798,24e 5798,246
9,750 517,39€517,398 6
5,171 278J3e 278,136 7
't1,124 756,672 756.672 8
71!1232e 50,83C 63, 1 5€o
17,63(1,151,359 1 ,151,359 10
1,30(92,30192,301 11
60,14(4,526,15C 4,526j54 12
27,90C 1,566,269 1,566,26S 13
1,524 102,666 102,666 14
5,389,494 145,'t 39 894,680 285,529,748 1,337,713 287,762,141106,210
FERC FORM NO.1 (ED.12-90)Page 327.2
PUHUHI
r rvsPv' rvvr.r (i i-
(2)
An Original
A Resubmission
(-rffi:6;:Yri'v, , rvyv, \
ldaho Power Company 04t16t2019 End of 20181Q4
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. ln column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). ln addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be intenupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.9., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the 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.
Actual Demand (MW)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)
Average
Monthly NCP Demanr
(e)
Average
Monthly CP Demand
(0
1 El Dorado Hydro - Elk Creek LU N/A N/A N/A
2 Faulkner Brothers Hydro lnc.LU N/A N/A N/A
3 N/AFisheries Development LU N/A N/A
4 Fossil Gulch Wind LU N/A N/A NiA
5 G2 Energy Hidden Hollow LU N/A N/A N/A
6 Golden Valley Wind Park LU N/A N/A N/A
7 Grand View PV Solar Two, LLC LU N/A N/A N/A
B Hammett Hill Windfarm, LLC LU N/A N/A NiA
9 Hazelton B Power Company LU N/A N/A N/A
10 High Mesa Energy LU N/A N/A N/A
11 H.K. Hydro lVlud Creek S & S LU N/A N/AN/A
12 Horseshoe Bend Hydro LU N/A N/A N/A
13 Hot Springs Wind Farm LU N/A N/A N/A
14 lD Solar 1, LLC LU N/A N/A NiA
Total
FERC FORM NO- 1 (ED.12-90)Page 326.3
Name oI Kesponoenr
ldaho Power Company
I ilts
(1)
(2)
t 15-
An Original
A Resubmission
ua(e or xepor((Mo, Da, Yr)
04t1612019
r eat, rerroo ur Ne]rur r
End of 20181Q4
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. Dernand reported in columns (e) and (0
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. lf more energy was delivered than received, enter a negative amount. lf the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
POWER EXCHANGES COST/SETTLEMENT OF POWERMegaWatt Hours
Purchased
(g)
Megawatt Hours
Received(h)
MegaWatt Hours
Delivered
(i)
Demand Charges
',li
Energy Charges
($)
(k)
Other Charges
($)
(t)
)($)
Total (j+k+l
of Settlement r
(m)
Line
No.
3.243 222,178 222,178 1
301 ,1 35 23,874 301 ,13t
39€7,47t 7,474 2
26,383 't,586,27t 1,586,278 4
21,891 't,522,22t 1,522,224 A
1 ,954,173 1,954,173 632,708
183,049 10,1 47,55€10,147,556 7
56,987 4,296,704 4,296,705 8
1,664,222 1,664,222 I22,839
96,497 5,012,86t 5,012,868 10
1,64i 88,99C 88,990 11
12M,462 3,170,792 3,170,792
38,1 6(2,545,67e 2,545,676 13
97,31:5,024,382 5,O24,382 14
5,389,494 106,210 1 45,1 39 894,680 285,529,748 1,337,713 287,762,141
FERC FORM NO. 1 (ED.12-90)Page 327.3
ud(E ut ngput t(Mo, Da, Yr)End of 20181Q4
r gdrlrErrvu vr N9PU|(
ldaho Power Company (1)
(2)
An Original
A Resubmission 04t16t2019
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 senvice in its system resource planning). ln addition, the reliability of requirement service must
be the same as, or second only to, the supplie/s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.9., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
lF - for intermediale-term f rm 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.
Actual Demand (MW)Line
No.
Name of Company or Public Authority
(Footnote Affi liations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
trtlonthly Billing
Demand (MW)
(d)(e)
Average
Monthly NCP Demanr
Average
Monthly CP Demand
(f)
1 ldaho Winds - Sawtooth Wind Project LU N/A N/A N/A
2 IU N/A N/A NiAJ R Simplot Co.
3 J.M. Miller/Sahko Hydro LU N/A N/A N/A
4 Jett Creek Windfarm LU NiA N/A N/A
5 John R LeMoyne LU N/A N/A N/A
6 Kasel & Witherspoon LU N/A N/A N/A
7 Kootenai Electric Cooperative - Fighti LU N/A N/A N/A
8 Koosh lnc. Geo Bon #2 LU N/A N/A N/A
I Koyle Hydo lnc.LU N/A N/A N/A
10 N/ALateral 10 Ventures LU NiA N/A
't1 Lemhi Hydro Power Co.- Schaffner LU N/A N/A N/A
12 Lime Wind LU N/A N/A N/A
13 Little Mac Power Co./Cedar Draw LU N/A N/A N/A
14 Little Wood River lrrigation District LU N/A N/A N/A
Total
FERC FORM NO.1 (ED.12-90)Page 326.4
nESPUt tUEt tt
t\aIIle ol r(espunoenl r tIJ
(1)
(2)
tD,L/U(C Ul ilt pur L(Mo, Da, Yr)
0411612019
rEdrrTeiluu ur ncPurt
End of 20181Q4ldaho Power Company An Original
A Resubmission
AD - for out-of-period adjustment. Use this code for any accounting adiustments 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 (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplie/s system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. lf more energy was delivered than received, enter a negative amount. lf the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory foolnote.
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.
COSTISETTLEMENT OF POWERPOWER EXCHANGES
Other Charges
($)
(l)
Total (i+k+l)
of Settlement ($)
(m)
Line
No.
Megawatt Hours
Purchased
(s)
Megawatt Hours
Received
(h)
MegaWatt Hours
Delivered
(i)
Demand Charges
($.)
U)
Energy Charges
($)
(k)
4,719,182 4,719,183 I55,62t
63,821 3,262,801 3,262,801 2
'1 ,36:114,427 114,421 3
1,661,284 1,661,284 429,46C
64(35,BBS 35,88S 5
33:29,843 29,843 6
14,09i 1,164,24e 't,164,24e 7
3,81?284,219 284,219 I
3,41 322,698 322,698 I
7.122 449,534 449,534 10
't04,27e 104.276 111,37t
6,07€471,255 471,255 12
6,11t 393,244 393,244 13
452,74i 452,743 146,s0c
'145,139 894,680 285,529,748 1,337,713 287,762,1415,389,494 106,210
FERC FORM NO.1 (ED.12-90)Page 327.4
rrorrrs vr r\g9yur rugr ll udrts ur [Epur t(Mo, Da, Yr)
o4t16t2019ldaho Power Company (1)
(2)
An Original
A Resubmission
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any seftlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation lhe 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 reliabilig 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 seftlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Actual Demand (MW)FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Average
t\4onthly NCP Demant
(e)
Line
No.
Name of Company or Public Authority
(Footnote Affi liations)
(a)
Statistical
Classifi-
cation
(b)
Average
Monthly CP Demand
(0
1 Magic Reservoir Hydro LU N/A NiA N/A
2 Mainline Windfarm LU N/A N/A N/A
J Marco Rancher's lrrigation lnc.LU N/A N/A N/A
4 Marysville Hydro Partners- Falls River LU N/A N/A N/A
(McCollum Enterprises -Canyon Springs LU N/A N/A N/A
6 Milner Dam Wind Park LU N/A NiA N/A
7 LU N/AMountain Home Solar l, LLC N/A N/A
B Mud Creek White Hydro, lnc LU N/A N/A N/A
I Murphy Flat Power, LLC LU N/A N/A N/A
10 New Energy One - Rock Creek Dairy LU N/A N/A N/A
11 N/A NiA N/ANorth Gooding Main, Hydro LU
12 North Side Energy Company lnc
13 Bypass Limited LU N/A NIA N/A
14 Hazelton A LU N/A N/A N/A
Total
FERC FORM NO.1 (ED.12-90)Page 326.5
r uatrret tuu ut Ne]rut t
End of 20181Q4
r\arne oT xesponoenr l iltt
(1)
(2)
t5,uirtt or Keport(Mo, Da, Yr)
r ear/refioo ut Nepul t
End of 20181Q4ldaho Power Company An Original
A Resubmission 04116t2019
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 rale schedules, tarifts 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 lhan 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.
COST/SETTLEMENT OF POWERPOWER EXCHANGESMegaWatt Hours
Purchased
(s)
Megawatt Hours
Delivered
(i)
Demand Charges
($)
(i)
Energy Charges
($)
(k)
Other Charges
($)
(l)
Total (j+k+l)
of Settlement ($)
(m)
Line
No.Megawaft Hours
Received
(h)
20,025 1,071 ,801 '1,071,801 1
57,625 4,340,57(4,340,576 2
3,004 210,08:210,083 J
3,972,6'.t7 458,588 3,972,611
483 11,32(11 ,320 t
56,611 3,297,78t 3,297,786 6
47,038 1 ,514,391 1,514,391 7
545 37,254 37,254 8
45.755 1,470,321 1,470,327 I
6,224 571,174 571,174 10
4,761 403,90€403,906 11
12
26,86t 1,462,76i 1,462,763 13
'1,943,067 1,943,067 1423,80t
5,389,494 106,2'10 145,139 894,680 285,529,748 1 ,337,713 287,762.141
FERC FORM NO.1 (ED.12-90)Page 327.5
PUl<UFII
. rvetv..eet.r
(1)
(2)
An Original
A Resubmission
eqrs vr r \ePvr (
(Mo, Da, Yr)
ur r \sPUr r
ldaho Power Company 04t16t2019 End of 2O18lQ4
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 lhe nature
of the service in a footnote for each adjustment.
Actual Demand (MW)Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Stratistical
Classifi-
cation
(b)
Average
Monthly NCP Demanr
(e)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Average
Monthly CP Demand
(f)
1 Head of U Canal LU N/A N/A N/A
2 Orchard Ranch Solar, LLC LU N/A N/A N/A
3 Oregon Trail Wind Park LU N/A N/A N/A
4 Owyhee lrrigation District
5 Mitchell Butte LU N/A N/A N/A
6 LU N/A NIA N/A
7 Tunnel #1 LU N/A NIA N/A
8 Paynes Ferry Wind Park LU N/A N/A N/A
I Pico Energy - 86 Anaerobic Digester LU N/A N/A N/A
10 Pigeon Cove Power LU N/A N/A N/A
11 Pilgrim Stage Station Wind Park LU N/A N/A N/A
12 Prospector Windfarm LU NiA N/A N/A
13 Reynolds lrrigation District LU N/A N/A NIA
14 Richard Kaster
Total
FERC FORM NO. 1 (ED. 12.90)Page 326.6
Owyhee Dam
Name oI Kesponoenr
ldaho Power Company
r ilI5
(1)
(2t
t 15.
An Original
A Resubmission
uate or Kepoft(Mo. Da, Yr)
teaflFenoo or Keporl
End of 20181Q4aq16t20't9
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 lhe contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identifled in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) dernand 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 repo(ed in columns (e) and (0
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not repo( 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 ail required data.
POWER EXCHANGES COST/SETTLEMENT OF POWERMegaWatt Hours
Purchased
(g)
MegaWatt Hours
Received
(h)
MegaWatt Hours
Delivered
(i)
Demand Charges
($)
U)
Energy Charges
($)
(k)
Other Charges
($)(rl
r)
($)
Total U+k+lof Seftlement
(m)
Line
No.
4,27i 385,028 38s,028 1
47,731 1,408,69€1,408,696 2
37,867 2,271,688 2,271,688 3
4
5,513 163,24C 163,240 5
12,554 306,438 306,438 6
14,605 482,693 482,693 7
62,994 5,213,137 5,213,137 I
13,361 1,238,30C 1,238,300 o
7,1 9€381,438 258,636 640,1 34 10
33,492 2,021,411 2,0?1 ,411 11
28,523 '1,599,537 1,599,537 12
1,081 81,67t 8'1,676 13
14
5,389,494 106,210 145,1 39 894,680 285,529,748 1 ,337 ,713 287,762,141
FERC FORM NO.1 (ED.12-90)Page 327.6
Name oI Kesponoenl
ldaho Power Company
rilt5
(1)
(2)
t t5.uare or Kepon(Mo. Da, Yr)
0411612019
rear/refloo or Keport
End of 2018/Q4An Original
A Resubmission
power
1 . Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any seftlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. ln column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). ln addition, the reliability of requirement service must
be the same as, or second only to, the supplie/s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means flve years or longer and "firm" means that service cannot be intenupted for
economic reasons and is intended to remain reliable even under adverse conditions (e,9., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the eadiest date that either buyer or seller can unilaterally get out of the contract.
lF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliabilig of the designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any seftlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Actual Demand (MW)
Average
Monthly CP Demand
(f)
Line
No.
Name of Company or Public Authority
(Footnote Affi liations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monlhly Billing
Demand (MW)
(d)
Average
Monthly NCP Deman<
(e)
1 Box Canyon LU N/A N/A N/A
2 Briggs Creek LU N/A N/A N/A
2 LU N/A N/A N/ARiverside Hydro - Mora Drop
4 Riverside lnvestments
E Arena Drop LU N/A N/A NiA
6 Fargo Drop LU NiA N/A N/A
7 Rockland Wnd Project LU N/A N/AN/A
I Ryegrass \A/indfarm LU N/A N/A N/A
o Salmon Falls Wind Park LU N/A N/A N/A
10 Shingle Creek LLC LU N/A N/A N/A
11 Shorock Hydro lnc.
12 Rock Creek #1 LU N/A N/A N/A
13 Shoshone CSPP LU N/A N/A N/A
14 Shoshone #2 LU N/A N/A N/A
Total
FERC FORM NO. r (EO.12-90)Page 328.7
l\ame oI r{esponqen(I ilta
(1)
(2)
-.udlB ur nEpur (
(Mo, Da, Yr)
04116t2015
r 6arrTEIUU Vr nVPUr r
ldaho Power Company An Original
A Resubmission End of 20181Q4
AD - for out-of-period adjustment. Use this code for any accounting adjustrnents 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 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 repo(ed 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.
COST/SETTLEMENT OF POWERPOWER EXCHANGESMegaWatt Hours
Purchased
(s)
MegaWatt Hours
Received
(h)
MegaWatt Hours
Delivered(i)
Demand Charges
($)
U)
Energy Charges
($)
(k)
Other Charges
($)
(t)
r)
($)
Total U+k+lof Settlement
(m)
Line
No.
1,81t 121,B',t0 't21,810 1
3,64i 248,617 248,617 2
a4,36(272,09e 272,098
4
1,614 148,57e 148,576 E
2 Cl21 237.987 237.987 6
16,450,83C 16,450,830 7245,271
54,292 4,095,751 4,095,751 8
65,013 3,865,361 3,865,361 I
62,569 62,56S 101,032
11
10,917 46.O42 619,57(665,618 12
1,729 101,97:10',1 .973 13
2,623,181 ,99(1 81 ,990 14
5,389,494 106,21C 145,1 39 894,680 285,529,748 1,337,713 287,762,141
FERC FORM NO. 1 (ED.12-90)Page 327.7
t\ame or Kesponoent
ldaho Power Company
I ilts
(1)
(2)
t ts.uare oI Kepon(Mo, Da, Yr)
YeailPenod ol Kepon
End of 20181Q4An Original
A Resubmission 04t16t2019
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 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 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 "intermediateterm" 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 exp€ct 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.
Actual Demand (MW)Line
No.
Name of Company or Public Authority
(Foohote Affiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Average
Monthly NCP Demanr
(e)
AverageI Monthly CP Demand
(0
'l LU N/ASimcoe Solar, LLC N/A N/A
2 Snake River Pottery LU N/A N/A N/A
3 South Forks Joint Venture-Lowline Cana LU N/A N/A N/A
4 Tamarack Energy Partnership LU N/A N/A N/A
5 N/A N/ATasco - Nampa N/A
6 Tasco - Twin Falls N/A N/A N/A
7 Thousand Springs Wnd Park LU N/A N/A NiA
8 Tiber Montana LLC - Tiber Dam LU N/A N/A N/A
I LUTuana Gulch Wind Park N/A N/A N/A
10 Tuana Springs Expansion LU N/A N/A N/A
11 Twin Falls Energy-Lowline Midway Hydro LU N/A N/A N/A
12 Two Ponds Windfarm LU N/A N/A N/A
13 N/AWhite Water Ranch LU N/A N/A
14 Wi ll iam Arkoosh-Littlewood/Arkoosh LU N/A N/A N/A
Total
FERC FORM NO. 1 (ED.12-90)Page 326.8
os
os
Name ot Hesponoent
ldaho Power Company
I nts
(1)
(2)
ts.
An Original
A Resubmission
uate or Kepon(Mo, Da, Yr)
Yearrenoo or Kepon
End of 20181Q4
04t16t2019
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), identiflT 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 reporled in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawafthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement, Do not report net exchange,
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. lf more energy was delivered than received, enter a negative amount. lf the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 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 POWERMegaWaft Hours
Purchased
(s)
MegaWatt Hours
Received(h)
MegaWatt Hours
Delivered
(i)
Demand Charges
($)
U)
Energy Charges
($)
(k)
Other Charges
($)
(t)
Total (j+k+l)
of Settlement ($)
(m)
Line
No.
1,543,838 "l49,202 1,543,83t
28,81t 28,816 z42C
29,462 2,125,63:2,125,633 J
27,07e 281 ,702 1,570,60(1,852,302 4
E4
6
32,514 1,948,24t 1,948,244 7
1,573,871 826,02C 1,573,871
1,789,982 1,789,982 I29,883
76,235 5,509,55t 5,509,555 't0
543,761 543,767 119,118
4,433,87t 4,433,876 1259,244
75e 51,86'1 51,861 13
285,736 143,821 285.73t
894,680 285,529,748 1,337,713 287,762,1415,389,494 106,210 1 45,1 39
FERC FORM NO.1 (ED.12-90)Page 327.8
r \soPvr rver r(
ii i"
(2)
uotc vr NEPUT t(Mo, Da, Yr)End of 20181Q4
r Edrrrvr rvu ur ngPur r
0411612019ldaho Power Company An Original
A Resubmission
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 Classi{ication Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). ln addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be intenupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.9., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the eadiest date that either buyer or seller can unilaterally get out of the contract.
lF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all lirm 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 unil. "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.
Actual Demand (MW)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)
Average
Monthly NCP Demanr
(e)
Average
Monthly CP Demand
(f)
1 \Mlliam Arkoosh- Littlewood River Ranc LU N/A N/A NiA
2 Willow Spring Windfarm LU N/A N/A N/A
3 Wilson Power Company LU N/A N/A N/A
4 Wood Hydro
Black Canyon #3 LU N/A N/A N/A
6 Jim Knight LU N/A N/A N/A
7 Mile 28 LU N/A N/A N/A
I Sagebrush LU N/A N/A N/A
I Yahoo Creek Wind Park LU N/A N/A N/A
10 Scheduling Deviation (3)
11 ADM lnvestor Services, lnc.WSPPOS N/A N/A N/A
12 Arizona Public Service Co SF WSPP N/A N/A N/A
13 AVANGRID RENEWABLES, LLC SF WSPP N/A NiA N/A
14 Avista Corp.r-12OS N/A N/A N/A
Total
FERC FORM NO.1 (EO.12-90)Page 326.9
Name ol Hesponoent
ldaho Power Company
I nts
(1)
(2t
ts,
An Original
A Resubmission
uate or Kepon
(Mo, Da, Y0
Yeaflrenoo or Kepon
End of 20181Q4
04t1612019
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.
POWER EXCHANGES COST/SETTLEMENT OF POWERMegaWatt Hours
Purchased
(s)
MegaWatt Hours
Received
(h)
MegaWatt Hours
Delivered
(i)
Demand Charges
($)
U)
Energy Charges
($)
(k)
Other Charges
($)
(r)
)
($)
Total (j+k+l
of Settlement r
(m)
Line
No.
4,262 268,395 268,395 1
1,795,837 1,795,837 231,932
26,349 1,920,86t 1,920,868 3
4
255 't8,57t 18,578 5
56,08:56,083 6724
4,1 05 273,731 273,739 7
895370,51:70,513
65,458 5,381,781 5,381,784 9
5,268 10
-6,474,592 -6,474,592 11
1,343,68C 1,343,680 1245,80t
25,93t 't,112,98r 1,112,985 't3
(233 233 14
287,762,1415,389,494 1 06,210 145,139 894,680 285,529,748 1,337,713
FERC FORM NO. 1 (ED. 12-90)Page 327.9
Name oI Kesponoent
ldaho Power Company
I [ltl;
(1)
(2)
ts.uale or Kepon(Mo, Da, Yr)
04t16t2419
YeanFenoo oI Kepon
End of 20181Q4An Original
A Resubmission
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 Classilication Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements seruice. 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 reliabilig of the designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longerthan one year but less than five years.
EX - For exchanges of 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.
Actual Demand (MW)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)
Average
Monthly NCP Deman<
(e)
Average
Monthly CP Demand
(f)
1 Avista Corp.SF WSPP NiA N/A N/A
2 Avista Corp.OS WSPP N/A N/A N/A
3 Black Hills Power lnc.SF WSPP N/A N/A N/A
4 Bonneville Power Administration OS rwspp N/A N/A N/A
5 Bonneville Power Administration SF WSPP N/A N/A N/A
6 Bonneville Power Administration OS WSPP N/A N/A N/A
7 BP Energy Company SF WSPP N/A N/A N/A
I Brookfield Energy Marketing LP SF WSPP N/A NiA N/A
I California lndependent System Operator SF CAISO N/A N/A N/A
10 Calpine Energy Services, L.P SF WSPP N/A NIA N/A
Chelan Co PUD OS WSPP N/A N/A N/A
12 Chelan Co PUD SF WSPP N/A N/A N/A
4a Citigroup Energy lnc.SF WSPP N/A N/A N/A
14 Citigroup Energy lnc.os ISDA N/A N/A N/A
Total
FERC FORM NO.1 (ED.12-90)Page 326.10
11
t\ame oT t(esponoenr
ldaho Power Company
r iltS
(1)
(2)
t 15.
An Original
A Resubmission
uatg oI(Mo, Da
xeporr
r, Yr)
0411612019
r eaTlrenoo oI Keport
End of 20181Q4
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.
POWER EXCHANGES COST/SETTLEMENT OF POWERMegaWatt Hours
Purchased
(s)
MegaWatt Hours
Received(h)
Megawatt Hours
Delivered(i)
Demand Charges
($)o
Energy Charges
($)
(k)
Other Charges
($)
(t)
Total 6+k+1;of Settlement ($)
(m)
Line
No.
44,672 't,253,798 1,253,799 1
294,s57 294,557 2
21C 1,14C 1jAA 3
77 1,953 1,953 4
62.855 1,633,252 1,633,252 5
378,348 378,348 6
138,825 4,272,4844,272,484 7
2,404 34,89€34,896 8
326,24A 5,4s5,234 5,455.234 I
35,30i 1,299,272 1,299,272 10
23 23 11
21,20C 587,904 587,904 12
3,166,2291 18,95(3,166,229 13
-266,809 -266,809 '14
5,389,494 106,210 1 45,1 39 894,680 285,529,748 1,337,713 287,762,141
FERC FORM NO.1 (ED.12-90)Page 327.10
tYatlte ot ne5poiloct ll.I ilts
(1)
(2)
uate ul ncpur t(Mo, Da, Yr)
04116t2019
r tarlTEiluu ut nc]r9r r
ldaho Power Company An Original
A Resubmission End of 2018tQ4
1. Report all power purchases made during the year. Also reporl exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enterthenameofthesellerorotherpartyinanexchangetransactionincolumn(a). Donotabbreviateortruncatethenameoruse
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 flrm 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 flrm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any 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.
Actual Demand (MW)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)
Average
Monthly NCP Demanr
(e)
Average
Monthly CP Demand
(0
1 Clatskanie PUD SF WSPP N/A N/A N/A
2 NiA NiADTE Energy Trading, lnc.SF WSPP N/A
3 EDF Trading North America, LLC SF WSPP N/A N/A N/A
4 EDF Trading North America, LLC ISDAOS N/A N/A NiA
5 Energy Keepers, lnc SF WSPP N/A N/A N/A
N/A6Eugene Water & Eleclric Board SF WSPP N/A N/A
7 Exelon Generation Company, LLC SF WSPP N/A N/A N/A
8 Grant CO Public Utility District #2 -N/A N/A N/A
9 Gridforce Energy Management, LLC OS 'WSPP N/A N/A N/A
10 N/A N/AJ.Aron & Company LLC SF WSPP N/A
11 J.Aron & Company LLC OS ISDA N/A N/A NiA
12 Los Angeles Department of Water & Powe SF WSPP N/A N/A N/A
13 Macguarie Energy LLC SF WSPP N/A N/A N/A
14 Morgan Stanley Capital Group lnc.SF ISDA N/A N/AN/A
Total
FERC FORM NO.1 (ED.12-90)Page 326.11
OS WSPP
rrar [c ur ncsPur rucr rr I illD
(1)
(2)
a r!_uate or xepur((Mo, Da, Yr)
04t't6t2019
rear/refloo 0r xeporr
End of 20181Q4ldaho Power Company An Original
Resubmission
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for seruice 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 conlract designations underwhich service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (0
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. lf more energy was delivered than received, enter a negative amount. lf the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
COST/SETTLEMENT OF POWERPOWER EXCHANGES
MegaWatt Hours
Delivered
(i)
Demand Charges
($)
(i)
Energy Charges
($)
(k)
Other Charges
($)
(t)
Total (i+k+l)
of Settlement ($)
(m)
Line
No.
MegaWatt Hours
Purchased
(s)
MegaWatt Hours
Received
(h)
37,38:37,383 1823
17C 3,61e 3,619 2
a172,94e 4,572,033 4,572,033
-532,194 -532,194 4
5,681 115,453 1 15,453 5
7,62C 207.18C 207,18C 6
739,843 1,143,073 1,1$,473
195 40E 81
4 160 16C o
807,936 1030,80c 807,93€
-554,156 -554,'156 11
12e 3,647 3,647 12
8,505 149,5'14 149,514 13
1 ,1 31 ,853 I ,131 ,853 1443,402
894,680 285,529,748 1,337,713 287.762,1415,389,494 106,210 1 45,1 39
FERC FORM NO.1 (ED.12-90)Page 327.11
t\ame or Kesponoenr I iltD
(1)
(2)
t t!.uatc or Kepor((Mo. Da, Yr)
r eatlreltou ur xepur t
End of 2A18lQ4ldaho Power Company An Original
A Resubmission 04t16t2019
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 ftom third parties to maintain delivenes of LF service). This category should not be used for long-term firm service flrm service
which meets the definition of RQ service. For all transactlon 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
year or less.
Use this category for all lirm services, where the duration of each period of commitment for service is one
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.
Actual Demand (MW)Line
No.
Name of Company or Public Authority
(Footnote Affi liations)
(a)
Statistical
Classifi-
cation
(b)
FERG Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Average
Monthly NCP Demanr
(e)
Average
Monthly CP Demand
(f)
1 Nevada Power Company, dba NV Energy SF WSPP N/A N/A N/A
2 NorthWestern Energy T-7OS N/A N/A N/A
J NorthWestern Energy SF WSPP N/A N/A N/A
4 NorthWestern Energy (Transmission )OS WSPP N/A N/A N/A
E PacifiCorp os r-13 NIA N/A N/A
6 PacifiCorp SF WSPP N/A N/A N/A
7 PacifiCorp lnc.OS ]WSPP NiA N/A N/A
8 Portland General Electric Company os ,1-14 N/A N/A N/A
I Portland General Elechic Company SF WSPP N/A N/A N/A
10 Portland General Electric Company OS N/A N/A N/A
11 Powerex Corp,SF WSPP N/A N/A N/A
12 Public Service Company of Colorado SF WSPP N/A N/AN/A
13 Puget Sound Energy, lnc.T-9os N/A N/A N/A
14 Puget Sound Energy, lnc.SF WSPP N/A N/A N/A
Total
FERC FORM NO.I (ED.12-90)Page 326.12
rYarne or Kesponoent
ldaho Power Company
t tI)
(1)
(2)
t5.
An Original
A Resubmission
uale oI xeport(Mo, Da, Yr)
04t16t2019
Year/renoo or r(epor{
End of 2018/Q4
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior repo(ing
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 (0
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7, Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. lf more energy was delivered than received, enter a negative amount. lf the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401 ,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as required and provide explanations following all required data.
COST/SETTLEMENT OF POWERPOWER EXCHANGESMegawatt Hours
Purchased
(s)
MegaWatt Hours
Received
(h)
MegaWatt Hours
Delivered(i)
Demand Charges
($)
U)
Energy Charges
($)
(k)
Other Charges
($)
(t)
Total (j+k+l)
of Settlem€nt ($)
(m)
Line
No.
8,203 341,05:341,055 ,|
€152 't52 2
2.434 45,884 45,884
1 81 81 4
7C 1,827 1,827 R
23,879 749,649 749,64S 6
3,63B 3,638 7
1A 487 487 8
55,071 607,322 607,322 o
986,398 986,398 't0
39,912 2,185,463 2,185,463 11
77,40(3,624,348 3,624,346 12
2C 498 498 13
103,81 (3,536,977 3,536,977 14
s,389,494 106,210 145,139 894,680 285,529,748 1,337,713 287,762,141
FERC FORM NO.1 (ED.12-90)Page 327.12
tvame oI Kespottuent
ldaho Power Company
I tID
(1)
(2)
t),uatc or Kep0il,(Mo, Da, Yr)
r Ear/rur ruu ur [ePUr r
End of 2018iQ4An Original
A Resubmission 04t16t2A',l9
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 seruice 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 seruice 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 aftempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
lF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any 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)
Monthly
(e)(f)
Actual Demand
Monthly
1 Raft River Energy I LLC LU N/A NiA N/A
2 Rainbow Energy Marketing Corporation SF WSPP N/A N/A NIA
3 Salt River Project SF WSPP N/A N/A N/A
4 Seattle City Light OS .WSPP N/A N/A NiA
5 Seattle City Light SF WSPP N/A N/A N/A
6 Shell Energy North America (US) L.P SF WSPP NiA N/A N/A
7 Siena Pacific Power Co., dba NV Energ N/A N/A N/A
8 Snohomish County PUD SF WSPP N/A N/A N/A
9 Tacoma Power SF WSPP N/A NiA N/A
10 The Energy Authority, lnc.SF WSPP N/A NIA N/A
11 TransAlta Energy Marketing (U.S.) lnc.SF WSPP N/A NIA NIA
12 Tucson Electric Power Company SF WSPP N/A N/A NIA
13 Westar Energy, lnc.OS .WSPP N/A N/A N/A
14 Westar Energy, lnc.SF WSPP N/A N/A N/A
Total
FERC FORM NO.1 (ED. 12-90)Page 326.13
OS T-55
rrdilru ur ngspuuuErr(
ldaho Power Company
I tili I n.
An Original
A Resubmission
UAIE UI(Mo, Da
nEpur t
r, Yr)
0411612015
Igat/Tciluu ut [cPUtt
End of 20181Q4(1)
(2)
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), 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 (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak, Demand reported in columns (e) and (0
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. lf more energy was delivered lhan 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
($)
(i)
Energy Charges
($)
(k)
Other Charges
($)
(t)
Total 0+k+l)of Settlement ($)
(m)
Line
No.
83,122 5,669,475 5,669,475 1
42t 20,03c 20,030 2
164,00(4,907,732 4,907,732 2
154 154 4
22,041 741 ,597 741,597 A
39,77C 1,070,258 1,070,258 6
4C 1,059 1,05S 7
2,61C 10'1,845 101,845 8
3,03S 75,214 75,214 o
2,157 36,931 36,931 10
86,85C 4,564,480 4,564,480 1'l
2,524 69,984 69,984 12
1,07 42,304 42,304 13
1,2',t4 45,482 45,482 14
5,389,494 106,210 145,139 894,680 285,529,748 1,337,713 287,762,141
FERC FORM NO.1 (ED.12-90)Page 327.13
r\ame or F{esponoenr
ldaho Power Company
I ilts
(1)
(2)
An Original
A Resubmrssion
uate oI Keporr
(Mo, Da, Yr)
rearrenoo or Kepon
End of 20181Q404t1612019
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 Classiflcation Code based on the original contractual terms and conditions of the service as follows
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). ln addition, the reliability of requirernent 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 dale 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-terrfi 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 intermediale-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 credils 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.
Actual Demand (MW)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)
Average
Monthly NCP Demanr
(e)
Average
Monthly CP Demand
(f)
1 Telocaset Wind Power Partners LLC LU APP.A N/A N/A N/A
2 Neal Hot Springs Unit #1 LU N/A N/A N/A
3 Oregon Solar Customers OS N/A N/A N/A
4 Avista Corp,EX
5 Bonneville Power Administration EX
6 NorthWestern Energy EX
7 PacifiCorp lnc.EX
8 Sierra Pacific Power Co., dba NV Energ EX
9 Clatskanie PUD EX 1s3
10 Acctg Valuation of Clatskanie PUD OS 0 N/A N/A N/A
11 Demand Response Avoided Energy OS N/A N/A N/A
12
'13
14
Total
FERC FORM NO. 1 (ED.12-90)Page 326.14
Name ol Hesponoent
ldaho Power Company
I nts
(1)
(2)
ts.
An Original
A Resubmission
uate oI(Mo, Da
Kepon
L, Yr)
04l't6t2019
Y earrefloo or Kepon
End of 20181Q4
AD - for out-of-period adjustment. Use this code for any accounling 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 (O), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the 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 tota{led 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 repo(ed 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)
MegaWaft Hours
Delivered
(i)
Demand Charges
(q)
U)
Energy Charges
($)
(k)
Other Charges
($)
Ir)
r)
($)
Total (l+k+l
of Settlement
(m)
Line
No.
314,81:19,741,40?19,741,403 ,|
176,491 20,234,669 20,234.669 2
775 17,879 17,879 3
18 4
20,261 t
87 6
8,687 106,060 7
2,792 8
36,200 I77,244
283,788 283,788 10
7,151,730 7,151,730 11
12
't3
14
s,389,494 106,2'10 145,139 894,680 285,529,748 1,337,713 287,762,141
FERC FORM NO.1 (ED.12-90)Page 327.14
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
0411612019
Year/Period of Report
2018tQ4
FOOTNOTE DATA
Schedule Page:326.3 Line No.: 9 Column: bIda ?,,est, a subsidiary of IdaCorp (1daho Pohier Company's parent company) ,
c,wnersh ' p o-r chis pro j ec - .
Schedule Page: 326.5 Line No.:1 Column: b
Ida West, a subsidiary of IdaCorp (Idaho Power Company's parent company),ownershlp of this projecL.
Schedule Page: 326.8 Line No.: 3 Column: bIda West, a subsid"iary of ldaCorp (Idaho Power Company's parent cornpany),
1:1.:rJl,.l. .1 l-rLs i'rl = .
Schedule Page: 326.8 Line No.: 5 Column: b
iir-,:-t Fi -rirt Pu:cl:ase-s
Schedute Page:326.8 Llne No.:6 Column: b
llcrtr F r I'ln ljt,.r-L clrases
Scfiedule Page: 326-9 Line No.: 3 Column: bIda West, a subsidiary of TdaCorp (Idaho Power Ccmpany's parent company),
cwnership of this projecc.
Schedule Page: 326.9 Line No; 11 Column: b
ADM lnvestor Services, lnc Futures Account Document, dated May 5, 2015
Schedule Page: 326.9 Line No.: 14 Column: b
Spinning or Operating Reser.res
Schedule Page: 326.10 Line No.: 2 Column: bFinan,--ial fransmission I osses
Schedute Page:326.10 Line No.:4 Column: b
Spinning or Operating Reserves
Schedule Page: 326.10 Line No.: 6 Column: h
F-inancial Ir rnsrr.issi on L,rsses
Schedule Page: 326.10 Line No.: 11 Column: b
Spinning cr Operating Reserves
Schedule Page: 326.10 Line No.: 14 Column: b
ISDA Mast-er Agreer,ent With Cit:-group, dated March 7,
Scfiedule Page: 326.11 Line No.:4 Column: b
ISDA Master .Agreeren- [,r]i th F.)F Tlad j n 7 lilor-t h Amsrica,
'Schedule Page: 326.11 Line No.: I Column: b
Spinning or Operating R.er.erves
Scheduls Page: 326.11 Line No.: I Column: bSpinning or Operating Reserves
Schedule Page:326.11 Line No.: 11 Column: b
lSDA Master Agreement With .-I.Aron & Company LLC, dated April
Schedule Page: 326.12 Line No.: 2 Column: b
Spinnrnq cr Operatin.t Reser.;es
Schedule Page: 326.12 Line No.: 4 Column: b
Spirrning or Operat. n; R.eserve..
Schedule Page: 326.12 Line No.: 5 Column: b
Spinning or Operating Reserves
Schedule Page: 326.12 Line No.:7 Column: b
Financi,a-L Transmission Losses
Schedule Page: 326.12 Line No.: I Column: b
Spinning or 0peraling Reserves
$ehedule Page: 326.12 Line No-: 10 Column: b
Operarl-inq agreement with Portf and Ceneral Elecl-::ic t-o still
Polver Plant of f line - tsoardrnan Assureil
Schedute Page: 326.12 Line No.: 13 Column: b
Spinning or Operating Reserves
Schedule Page:326.13 Line No.:4 Column: b
has partial
has partial
has partial
has partial
2oti
LLC, dateri October 25, 2O!2
30, 2014
provide power if Boar,lman
FERC FORM NO. 1 (ED. 12-871 Page 450.1
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
041't612019
Year/Period of Report
20181Q4
FOOTNOTE DATA
Spinning or Operating Reserves
Schedule Page: 326.13 Line No.:7
Spinning or Operating Reserves
Schedule Page: 326.13 Line No.: 13Spinning or Operating Reserves
Schedule Page: 326.14 Line tVo.r 3
Column: b
Column: b
Column: b
Schedufe 88 Oregon Sol ar
Line No.:4Schedule Page: 326.Column: bPhysical Transmission Losses
Sciedule Page: 326.14 Line No.: 5 Column: b
Ptiysical Transmission Losses
Schedule Page: 326.14 Line No.:6 Column: bPhysical Transmiss ion Losses
Scfiedule Page: 326.14 Line No.:7 Column: b
Fhys -cal Transmi ssi cn Losses
Echedule Page: 326.14 Line No.: I Column: b
Physical Transmission Losses
Schedute Page: 326.14 Line No.: 9 Column: b
Energy exchanqe between Clatsk.inre PUD and Idaho Power Company at Arror^irock Dant
Schedule Page: 326.14 Line No.: 10 Column: b
Energy excl.ange between Clatskanie PUD and Idaho Power Conrpany at Arroirrock Dar
Schedute Page: 326.14 Line No.: 11 Column: bIncentive proqram. for customers to reduce Cemand during peak hours
FERC FORM NO. 1 (ED. 12-871 Page 450.2
r\arile oI xesponqenl t ilrD
(1)
(2)
uate or Keporl(Mo, Da, Yr)
04116t2019
r ear/renoo or Keport
End of 20181Q4ldaho Power Company An Original
A Resubmission
I HAN:MISSION OI. E,LE,C I RICI I Y FOH O IHERS (I
lncludinq transaclions refened to as'wheelinq'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. Repo( 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 fo
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
1 Bonnevllle Power Mministaton - OTEC Bonneville Power Administration Oregon Trails Electric Co-op FNO
2 Bonnevllle Poryer Admlnlffion - USBR Bonneville Power Administration United States Bureau of Reclamati FNO
Bonncdlle Powcr Admlnlshaffon - Ff FNO1Bonneville Power Administration Priority Firm Customers
4 Milnar ln|gaton Olet{ct United States Bureau of Reclamati Milner lrrigation District OLF
5 Morgan Stsnlcy Capital Group lnc.Seattle Ci9 Light Bonneville Power Administration OS
6 PacifiCorp PacifiCorp West PacifiCorp West FNO
t nlt3d Stato8 tsursau of lndlgn Afiairg OS7Bonneville Power Administration United States Bureau of lndian Af
8 Cyde Honeshos Bend WInd, LLC PacifiCorp East PacifiCorp East os
9 Cycle Horseshoe Bend Wind, LLC PaciftCorp East PacifiCorp East OS
10
11 PacifiCorp lnc.PacifiCorp East Bonneville Power Administration LFP
12 PacifiCorp lnc.PacifiCorp East PacifiCorp West LFP
LFP13PacifiCorp lnc.PacifiCorp East PacifiCorp West
14 Morgan Stanley Capital Group lnc.ldaho Power Company Bonneville Power Administration LFP
15 Bonneville Power Administration PacifiCorp West PacifiCorp East LFP
LFP16Bonneville Power Administration PacifiCorp West PacifiCorp East
17
18 Avangrid Renewables, LLC PacifiCorp East Bonneville Power Adm inistration NF
19 Avangrid Renewables, LLC PacifiCorp East Sierra Pacific Power NF
20 Sierra Pacific Power NFAvangrid Renewables, LLC NorthWestern/Pacifi Corp East
21 Avangrid Renewables, LLC Bonneville Power Administration PacifiCorp East NF
22 Avangrid Renewables, LLC Bonneville Power Administration Sierra Pacific Power NF
23 Avangrid Renewables, LLC Avista PacifiCorp East NF
NF24Avangrid Renewables, LLC Avista Sierra Pacific Power
25 Avangrid Renewables, LLC Sierra Pacific Power NorthWestern/Pacifi Corp East NF
26 Avangrid Renewables, LLC Sierra Pacific Power Bonneville Power Administration NF
27 Avangrid Renewables, LLC PacifiCorp West PacifiCorp East NF
28 PacifiCorp East NFAvista Corporation Avista
29 Avista Corporation Avista Sierra Pacific Power NF
30 Avista Corporation Sierra Pacific Power Avista NF
a4 Black Hills Power PacifiCorp East PacifiCorp East NF
32 PacifiCorp East Sierra Pacific Power NFBlack Hills Power
33 Black Hills Power Bonneville Power Administration PacifiCorp East NF
34 Black Hills Power Bonneville Power Administration PacifiCorp East NF
TOTAL
FERC FORM NO. 1 (ED.12-90)Page 328
Name of Respondent
ldaho Power Company
Th.S
(1)
(2)
tb.
An Original
A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
04116t2019
S AS
t 456)(Continued)
5. ln column (e), identiff the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. ln column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. ln column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specifled 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.
TRANSFER OF ENERGY Line
No.
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(f)
Point of Delivery
(Substation or Other
Designation)
(s)
Eilling
Demand
(MW)
(h)
tvlegawatt Hours
Received(i)
Megawatt Hours
Delivered
0)
9 332.530 332,53C 1
I 241,422 241,422 2
o 1,335,909 1.33s.909 3
LcAacy Minidoka, ldaho Various in ldaho 7,985 7,385 4
4 349,894 349.894 5
I 2,000 2,00c 6
Legacy LaGrande, Oregon Various in ldaho 16,612 16,612 7
5t6 IPCOEAST 3,902 3,902 8BRDY
5/6 IPCOEAST 1 3,1 15 13,115 oJEFF
10
11BORALAGRANDE537,597 537,59;
HURR 342,844 342,841 127t8KPRT
7t8 BORA HURR 574,326 574,32t 13
7t8 LYPK LAGRANDE 3,710 3,71C 14
KPRT 132,746 132.74t 157t8Ms00
7t8 SMLK KPRT 274.426 274,42e 16
17
718 BORA LAGRANDE 242 242 18
M345 107 101 1g7t8BORA
7t8 M345 380 38C 20BPAT.NWMT
7t8 LAGRANDE BORA 980 9BC 21
7t8 LAGRANDE M345 2,700 2,70C 22
BORA 200 20c 237t8LOLO
7t8 LOLO M345 '13 13 24
132 257t8M345BPAT.NWMT 132
LAGRANDE 3,191 3,191 267t8M345
7lB SMLK BORA 171 171 27
7t8 LOLO BRDY 785 785 2B
ru345 488 488 297t8LOLO
7t8 M345 LOLO 13 13 30
7tB JBSN BORA 140 144 31
30 3(JZ7t8JBSNM345
7t8 BORA 137 131 JJLAGRANDE
7/8 LAGRANDE JBSN 128 12t!34
0 7,243,160 7,243,16(
FERC FORM NO.1 (ED.12-e0)Page 329
718
Name of Respondent
ldaho Power Company
tnts
(1)
(2)
rs:uale ot Kepon(Mo. Da, Yr)
0411612019
YeailHenoo ol Repon
End of 20181Q4An Original
A Resubmission
TRANS MII'SIUN UI- ELEU I KIUI I Y hUH (JIHE,KS (P
lncludinq transactions refened to as'wheelinq'ccounl 4b0.1)
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifiTing 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 Afiiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Aftiliation)
(c)
Statistical
Classifi-
cation
(d)
1 Black Hills Power PacifiCorp West PacifiCorp East NF
2 Bonneville Power Administration NorthWestern/Pacifi Corp East PacifiCorp East SFP
3 NFBonneville Power Administration NorthWestern/Pacifi Corp East Sierra Pacific Power
4 Bonneville Power Administration NorthWestern/Pacifi Corp East Sierra Pacific Power SFP
5 Bonneville Power Administration PacifiCorp East Sierra Pacific Power NF
6 Bonneville Power Administration Bonneville Power Administration PacifiCorp East NF
7 Bonneville Power Administration Bonneville Power Administration PacifiCorp East NF
8 Bonneville Power Administration Bonneville Power Adminisfation Bonneville Power Administration NF
I Bonneville Power Administration Bonneville Power Adminisfation Siena Pacific Power NF
10 Bonneville Power Administration Bonneville Power Administration NFBonneville Power Administration
11 Bonneville Power Administration Avista Bonneville Power Administration NF
't2 Bonneville Power Administration Avista Siena Paciflc Power NF
13 Bonneville Power Adm inistration PacifiCorp East NFSierra Pacific Power
14 Bonneville Power Administration PacifiCorp West Sierra Pacific Power NF
15 Bonneville Power Administration PacifiCorp West PacifiCorp East NF
16 Bonneville Power Administration PacifiCorp East SFPPacifiCorp West
17 Bonneville Power Administration PacifiCorp West PacifiCorp East SFP
18 Bonneville Power Administration PacifiCorp West Sierra Pacific Power SFP
SFP19Brookfield Energy Marketing LP PacifiCorp East Sierra Pacific Power
20 CWP Energy lnc.PacifiCorp East Sierra Pacific Power NF
21 EDF Trading North America, LLC NorthWestern/Pacifi Corp East Bonneville Power Administration NF
22 EDF Trading North America, LLC PacifiCorp East Bonneville Power Administration NF
23 Bonneville Power Administration NFEDF Trading North America, LLC PacifiCorp East
24 EDF Trading North America, LLC Bonneville Power Administration PacifiCorp East NF
25 Energy Keepers, lnc.PacifiCorp East Sierra Pacific Power SFP
26 Energy Keepers, lnc.Avista PacifiCorp East NF
27 Macquarie Energy, LLC PacifiCorp East PacifiCorp East NF
28 Macquarie Energy, LLC PacifiCorp East PacifiCorp East SFP
29 Macquarie Energy, LLC PacifiCorp East Sierra Pacific Power NF
30 Macquarie Energy, LLC PacifiCorp East Sierra Pacific Power SFP
31 Macquarie Energy, LLC PacifiCorp East Sierra Pacific Power SFP
32 Macquarie Energy, LLC PacifiCorp East Sierra Pacific Power NF
33 Macquarie Energy, LLC PacifiCorp East Sierra Pacific Power NF
34 Macquarie Energy, LLC Sierra Pacific Power PacifiCorp East NF
TOTAL
FERC FORM NO.1 (ED.12-90)Page 328.1
Name of Respondent
ldaho Power Company
I nrs
(1)
(2',)
lst
An Original
A Resubmission
Uate ot Report
(Mo, Da, Yr)
Year/Period ot Keport
End of 20181Q4
0411612019
as
t 4S6XContinued)
5. ln column (e), identify the FERC Rate Schedule or Tariff Number, On separale lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. ln column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. ln column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j) the total megawatthours received and delivered.
TRANSFER OF ENERGYPoint of Delivery
(Substation or Other
Designation)
(s)
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(f)
Billing
Demand
(MW)
(h)
Megawatt Hours
Received(i)
Megawatt Hours
Delivered(i)
Line
No.
BRDY 5 E 17t8M500
7t8 BPAT.NWMT BORA 7,126 7,12e 2
7t8 BPAT.NWMT M345 101 101 J
M3457t8BPAT.NWMT 9,893 9,893 4
7t8 BRDY M345 61 61 5
718 LAGRANDE BORA 183 183 6
7t8 LAGRANDE KPRT 25 25 7
LAGRANDE 1,728 1,72e 87t8LAGRANDE
7t8 LAGRANDE M345 5,662 5,662 I
7t8 LAGRANDE OTEC 20 2C 10
LAGRANDE 1,32C 11718LOLO1,320
7t8 M34s 257 257 12LOLO
7t8 M345 BORA 4 4 13
7t8 M500 M345 121 121 14
BORA 157t8SMLK't49 14S
7t8 SMLK BORA 81,075 81 ,07t 16
7t8 SMLK BRDY 195 19f 17
7t8 SMLK M345 97,s33 97,53:18
M345 42,698 42,69t 197t8BRDY
7t8 BRDY M345 1,483 1,48:20
7tB BPAT.NWMT LAGRANDE 1,150 1 ,"t5C 21
1,82e 22718BRDYLAGRANDE1,826
LAGRANDE 72 72 237t8JEFF
7t8 LAGRANDE BRDY 57 57 24
M345 32,023 25718BRDY32,022
BRDY 2 z 267t8LOLO
7t8 BRDY BORA 115 115 27
7t8 BRDY BORA 2,023 2,023 28
M345 214 214 297t8BRDY
7t8 BRDY M345 4,286 4,28e 30
718 GSHN M345 160 16C 31
M345 32718JBSN2727
718 JEFF M345 250 25(33
7tB M345 BORA 525 525 34
0 7,243,164 7,243,16C
FERC FORM NO.I (ED.12-90)Page 329.'l
Name ot Respondent
ldaho Power Company
tnls
(1)
(2)
IS:uale ot Hepon(Mo, Da, Yr)
YeailPenoo or K.epon
End of 2018/Q4An Original
A Resubmission 04t1612019
I RANS
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 narne 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 Afiiliation)
(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 Macquarie Energy, LLC Sierra Pacific Power PacifiCorp East NF
2 Mag Energy Solutions PacifiCorp East Sierra Pacific Power NF
3 Mag Energy Solutions PacifiCorp East Sierra Pacific Power NF
4 Morgan Stanley Capital Group Inc.NorthWestern/Pacifi Corp East PacifiCorp East NF
5 Morgan Stanley Capital Group lnc.NorthWestern/Pacifi Corp East Bonneville Power Administration NF
6 Morgan Stanley Capital Group Inc.NorthWestern/Pacifi Corp East Sierra Pacific Power NF
7 Morgan Stranley Capital Group Inc.PacifiCorp East Bonneville Power Administration NF
8 Morgan Stanley Capital Group lnc.PacifiCorp East Bonneville Power Administration SFP
I Morgan Stanley Capital Group lnc.PacifiCorp East Avista NF
10 Morgan Stanley Capital Group lnc.PacifiCorp East Sierra Pacific Power NF
11 Morgan Stanley Capital Group lnc.NorthWestern/Pacifi Corp East PacifiCorp East NF
12 Morgan Stanley Capital Group lnc.NorthWestern/Pacifi Corp East PacifiCorp East SFP
13 Morgan Stanley Capital Group lnc.No(hWestern/Pacifi Corp East PacifiCorp East NF
14 Morgan Stanley Capital Group Inc.NorthWesterniPacifi Corp East PacifiCorp East SFP
15 Morgan Stanley Capital Group Inc.NorthWestern/PacifiCorp East Bonneville Power Administration NF
16 Morgan Stanley Capital Group lnc.NorthWestern/Pacifi Corp East Sierra Pacific Power NF
17 Morgan Stanley Capital Group lnc.NorthWestern/PacifiCorp East Sierra Pacific Power SFP
18 Morgan Stanley Capital Group lnc.PacifiCorp East NorthWestern/Pacifi Corp East NF
19 Morgan Stanley Capital Group lnc.PacifiCorp East PacifiCorp East NF
20 Morgan Stanley Capital Group lnc.PacifiCorp East PacifiCorp East SFP
21 Morgan Stanley Capital Group lnc.PacifiCorp East NorthWestern/Pacifi Corp East NF
22 Morgan Stanley Capital Group Inc.PacifiCorp East NFBonneville Power Administration
23 Morgan Stanley Capital Group lnc.PacifiCorp East Avista NF
24 Morgan Stanley Capital Group lnc.PacifiCorp East Sierra Pacific Power NF
25 Morgan Stanley Capital Group lnc.PacifiCorp East Sierra Pacific Power SFP
26 Morgan Stanley Capital Group lnc.ldaho Power Company NorthWestem/Pacifi Corp East NF
27 Morgan Stanley Capital Group lnc.ldaho Power Company NorthWestern/Pacifi Corp East NF
28 Morgan Stanley Capital Group lnc.PacifiCorp East PacifiCorp East NF
29 Morgan Stanley Capital Group lnc.PacifiCorp East PacifiCorp East SFP
30 Morgan Stanley Capital Group lnc.PacifiCorp East PacifiCorp East NF
31 Morgan Stanley Capital Group lnc.PacifiCorp East Sierra Pacific Power NF
32 Morgan Stanley Capital Group lnc.PacifiCorp East PacifiCorp East NF
33 Morgan Stanley Capital Group lnc.PacifiCorp East PacifiCorp East SFP
34 Morgan Stanley Capital Group lnc.PacifiCorp East PacifiCorp East NF
TOTAL
FERC FORM NO. 1 (ED.12-90)Page 328.2
Name ot Kespondent
ldaho Power Company
I nrs
(1)
(2)
IS:uate ot Keport
(Mo. Da, Y0
YeailPenoo ot F(eport
End of 20181Q4An Original
A Resubmission 04t16t2019
as
! 4SOXL,ontrnue0)
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 identilication 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 megawafthours received and delivered.
TRANSFER OF ENERGYFERC Rate
Schedule of
Tariff Number
(e)
Designation)
(f)
Point of Receipt
(Subsatation or Other
Point of Delivery
(Substation or Other
Designation)
(s)
Billing
Demand
(MW)
(h)
Megawatt Hours
Received(i)
Megawatt Hours
Delivered(i)
Line
No.
BRDY7t8M345 259 25(1
7t8 M345 14,055 2BRDY
7t8 JEFF M345 14,90:
7tB AVAT.NWMT BORA 45 4t 4
LAGRANDE 739 -71C E7tBAVAT.NWMT
7tB M345 4,54t 6AVAT.NWMT
7t8 BORA LAGRANDE 3,091 3,091 7
718 BORA LAGRANDE 8,822 8,822 I
7t8 LOLO 400 40c IBORA
7t8 BORA M345 57C 10
7t8 BPAT.NWTVIT BORA 53 51 11
BORA 31,632 31 ,632 127t8BPAT.NWMT
7t8 BPAT.NWMT BRDY 2{13
7t8 BPAT.NWMT BRDY 1,104 1,104 14
718 BPAT.NWMT LAGRANDE J.OO /3,66i 15
M345 9,1 84 167t8BPAT.NWMT
7t8 BPAT.NWMT M345 71,25C 17
7t8 BRDY AVAT.NWMT 50 5C 1B
7tB BRDY BORA 7,363 7,363 19
BORA 4,483 207tBBRDY
7t8 BRDY BPAT.NWMT 272 21
7t8 BRDY LAGRANOE 13,864 13,86r 22
LOLO 83 8:ZJ7t8BRDY
7t8 M345 34,40i 24BRDY
7t8 BRDY M345 85,747 85,741 ,q
267t8IPCOGENAVAT.NWMT 11
7tB IPCOGEN BPAT.NWMT 2C 27
718 JBSN BORA 11,993 11,9S:28
7t8 JBSN BORA 5,213 5,21i 29
7t8 BRDY 1C 30JBSN
7t8 JBSN M345 613 613 3'1
BORA 3Z7t8JEFF43,691 43,691
BORA 2,254 337tBJEFF
7tB JEFF BRDY 1,466 '1,466 34
0 7,243,160 7,243,',t60
FERG FORM NO.1 (8D.12-90)Page 329.2
14,0551
14,e031
4,5441
5761
201
9,1841
71,2501
4,4831
2721
34,4071
141
201
101
2,2541
Name ot Kesponoent
ldaho Power Company
tnls
(1)
(2)
IS:uate oI Keoon(Mo, Da, Yi)
Year/Henoo ol Kepon
End of 20181Q4An Original
Resubmission o4t16t2019
TRANS MISSION OF ELECTRICITY FOR OTHERS (P
lncluding transaclions referred to as'wheelinq'ccount 4co.'r )
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authorig. 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 Afiiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Afiiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
1 Morgan Stanley Capital Group lnc.PaciliCorp East Bonneville Power Administration NF
2 Morgan Stanley Capital Group lnc.PacifiCorp East Sierra Pacific Power NF
J Morgan Stanley Capital Group lnc.PacifiCorp East Siena Pacific Power SFP
4 Morgan Stanley Capital Group lnc.Bonneville Power Administration NorthWestem/Pacifi Corp East NF
5 Morgan Stanley Capital Group lnc.Bonneville Power Administration PacifiCorp East NF
6 SFPMorgan Stanley Capital Group lnc.Bonneville Power Administration PacifiCorp East
7 Morgan Stanley Capital Group lnc.Bonneville Power Administration PacifiCorp East NF
8 Morgan Stanley Capital Group lnc.Bonneville Power Administration Sierra Paclfic Power NF
I Morgan Stanley Capital Group lnc.Bonneville Power Administration Sierra Pacific Power 5rr
'10 Morgan Stanley Capital Group lnc.Avista PacifiCorp East NF
11 Morgan Stanley Capital Group lnc.Avista PacifiCorp East SFP
12 Morgan Stanley Capital Group lnc.Avista PacifiCorp East NF
13 Morgan Stanley Capital Group lnc.Avista Sierra Pacific Power NF
14 Morgan Stanley Capital Group lnc.Avista Siena Pacific Power SFP
15 Morgan Stanley Capital Group lnc.ldaho Power Company NorthWestemlPacifi Corp East NF
16 Morgan Stanley Capital Group lnc.ldaho Power Company PacifiCorp East NF
't7 Morgan Stanley Capital Group lnc.ldaho Power Company PacifiCorp East SFP
't8 Morgan Stanley Capital Group lnc.ldaho Power Company NorthWestern/PacifiCorp East NF
19 Morgan Stanley Capital Group lnc.ldaho Power Company PacifiCorp East NF
20 Morgan Stanley Capital Group lnc.ldaho Power Company Avista NF
21 Morgan Stanley Capital Group lnc.ldaho Power Company Sierra Pacific Power NF
22 Morgan Stanley Capital Group lnc.ldaho Power Company Sierra Pacific Power SFP
23 Morgan Stanley Capital Group lnc.Sierra Pacific Power NorthWestern/PacifiCorp East NF
24 Morgan Stanley Capital Group lnc.Sierra Pacific Power PacifiCorp East NF
25 Morgan Stanley Capital Group lnc.Sierra Pacific Power NorthWestem/Pacifi Corp East NF
26 Morgan Stanley Capital Group lnc.Sierra Pacific Power PacifiCorp East NF
27 Morgan Stanley Capital Group lnc.Bonneville Power Adm inistration NFSierra Pacific Power
28 Morgan Stanley Capital Group lnc.Sierra Pacific Power Avista NF
29 Morgan Stanley Capital Group lnc.ldaho Power Company NorthWestern/Pacifi Corp East NF
30 Morgan Stanley Capital Group lnc.PacifiCorp West PacifiCorp East NF
a4 Morgan Stanley Capital Group lnc.PacifiCorp West PacifiCorp East SFP
32 Morgan Stanley Capital Group lnc.PacifiCorp West Sierra Pacific Power NF
33 Morgan Stanley Capital Group lnc.ldaho Power Company PacifiCorp East NF
34 Morgan Stanley Capital Group lnc.ldaho Power Company PacifiCorp East NF
TOTAL
FERC FORM NO.1 (ED.12-90)Page 32t.3
Name of Responclent
ldaho Power Company
tnts
(1)
(2)
IS:
An Original
A Resubmission
uate ot F(eport(Mo, Da, Yr)
Year/Penoo ot Hepon
End of 20181Q4
o411612019
as
5. ln column (e), identifiT the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. ln column (0, report the
designation for the substalion, 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.
TRANSFER OF ENERGY
Designation)
(s)
Point of Delivery
(Substation or Other
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(0
Billing
Demand
(MW)
(h)
Megawatt Hours
Received(i)
Megawatt Hours
Delivered
0)
Line
No,
7t8 LAGRANDE 322 1JEFF
7t8 JEFF M345 53,922 2
7t8 JEFF M345 1,404 1,404 J
7t8 LAGRANDE AVAT.NWMT 316 316 4
7t8 LAGRANDE BORA 12,932 E
7t8 LAGRANDE EORA 10,69S 10,699 6
7t8 LAGRANDE BRDY 3,4'1S 3,4't I 7
7t8 M345 110,211 1't0,211 8LAGRANDE
718 LAGRANDE M345 9(o
7t8 LOLO BORA 33,699 33,69t 10
BORA 5,43(117t8LOLO5,439
7t8 LOLO BRDY 282 12
7t8 LOLO M345 283,043 283,043 13
7t8 LOLO M345 153,240 't53,24C 14
AVAT.NWMT 5477t8LYPK 541 15
7t8 LYPK BORA 1,82C 16
7t8 LYPK BORA 31,373 31 ,373 17
1,239 1,238 18718LYPKBPAT.NWMT
7t8 BRDY 2,42C 19LYPK
7t8 LYPK LOLO 500 50c zu
7tB LYPK M345 4,194 4,194 21
M3457t8LYPK 302,387 302,38i 22
7t8 AVAT.NWMT I 23M345
7t8 M345 BORA 242 24
BPAT.NWMT 3,152 3,152 257t8M345
7t8 M345 BRDY 2,967 26
7t8 M345 LAGRANDE 33,77a 33,775 27
7t8 M345 LOLO 10,332 10,332 28
AVAT.NWMT 1a 297t8OBBLPR
7t8 SMLK BORA 248,83i 30
7t8 SMLK BORA 2,284 2,28(31
M345 1,980 1,98(327t8SMLK
7t8 BORA 156,06(33WALLAWALLA
7tB WALLAWALLA BRDY 23 z:34
0 7,243,',t60 7,243j64
FERC FORM NO.1 (ED. r2-90)Page 329.3
t 456XUontinued)
322l|
53.s22|
12,e321
e0l
2B2l
1,S201
2,4201
8l
2421
2,9671
131
248,8321
1 56,0661
Name ot Kesponoent
ldaho Power Company
I nts
(1)
(2)
IS:
Original
uate oI Hepon(Mo, Da, Yr)
Yea?Fenoo or Kepon
End of 20'l8lQ4A Resubmission 04116t2019
TRANS MISSION OF ELECTRICITY FOR OTHERS (F
lncluding transactions referred to as'wheelinq'ccount 456.',!)
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualirying facilities, non{raditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. ln column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General lnstruction for definitions of codes.
Line
No.
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Affiliation )(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
1 Morgan Stanley Capital Group lnc.ldaho Power Company Sierra Pacific Power NF
2 Nevada Power Company NFPacifiCorp East Sierra Pacific Power
3 Nevada Power Company PacifiCorp East Sierra Pacific Power SFP
4 Nevada Power Company Avista Sierra Pacific Power SFP
5 Nevada Power Company Siena Pacific Power Bonneville Power Adm inistration NF
6 Northwestern Energy PacifiCorp East Bonneville Power Adm inistration NF
7 PacifiCorp lnc.PacifiCorp East ldaho Power Company NF
8 PacifiCorp lnc.PacifiCorp East Avista NF
I PacifiCorp lnc.PacifiCorp East Avista SFP
10 PacifiCorp lnc.PacifiCorp East PacifiCorp East NF
11 PacifiCorp lnc.PacifiCorp East PacifiCorp East NF
12 PacifiCorp lnc.Bonneville Power Admin istration NFPacifiCorp East
13 PacifiCorp lnc.PacifiCorp East Avista NF
14 PacifiCorp lnc.PacifiCorp East NorthWestern/Pacifi Corp East NF
15 NFPacifiCorp lnc.PacifiCorp West PacifiCorp East
to PacifiCorp lnc.PacifiCorp West PacifiCorp East NF
17 PacifCorp lnc.PacifiCorp East ldaho Power Company NF
18 PacifiCorp lnc.PacifiCorp East PacifiCorp East NF
19 PacifiCorp lnc.Bonneville Power Administration PacifiCorp East NF
20 PacifiCorp lnc.Bonnevi lle Power Administration PacifiCorp East NF
21 PacifiCorp lnc.Bonnevi lle Power Administration Sierra Pacific Power NF
22 PacifiCorp lnc.Avista PacifiCorp East NF
23 PacifiCorp lnc.Avista PacifiCorp East NF
24 PacifiCorp lnc.Avista Bonneville Power Administration NF
.E PacifiCorp lnc.PacifiCorp West PacifiCorp East NF
to PacifiCorp lnc.PacifiCorp West PacifiCorp East NF
27 PacifiCorp EastPacifiCorp lnc.ldaho Power Company NF
28 PacifiCorp lnc.ldaho Power Company PacifiCorp East NF
29 PacifiCorp Inc.ldaho Power Company Bonneville Power Administration NF
30 Portland General Electric PacifiCorp East Bonneville Power Adm inistration NF
31 Portland General Electric PacifiCorp East Bonneville Power Administration SFP
32 Portland General Electric PacifiCorp East Bonneville Power Administration NF
33 Portland General Eleckic PacifiCorp East Bonneville Power Administration SFP
34 Portland General Electric NFPacifiCorp East Bonneville Power Administration
TOTAL
FERC FORM NO.1 (ED.12-90)Page 328.4
Name ot Responclent
ldaho Power Company
tnrs
(1)
(2)
IS:uate ot Heport(Mo, Da, Yr)
04t16t2019
Year/Penod ol Kepon
End of 2018/Q4An Original
A Resubmission
t 4Strxuontnuecl)
as
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 receipl and delivery locations for all single conlract 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) musl 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.
TRANSFER OF ENERGYFERC 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)
MegaWatt Hours
Received(i)
Megawatt Hours
Delivered
0)
Line
No.
7t8 WALLAWALLA M345 236 23t 1
1,632 1,631 27t8BRDYM345
M345 2,688 2,68€37t8BRDY
7t8 LOLO tvl345 1,120 1,12(4
15(57t8M34sLAGRANDE150
LAGRANDE 165 16r 67tBBRDY
BORA lPco 4 I7t8
8718BORALOLO15015(
LOLO 255,418 255,41t I7t8BORA
BORA 780 78(107t8BRDY
7t8 BRDY BRDY 66 6(11
4,748 4,74t 127t8BRDYLAGRANDE
LOLO 152 15i 137t8BRDY
7t8 BRDY MLCK 4,446 4,44t 14
7t8 HURR BORA 1,889 1,88!15
60s 60!'16718HURRBRDY
EGSY 4.752 4,752 17718JEFF
7t8 JEFF BORA 1 1 18
7t8 LAGRANDE BORA 3,634 3,634 19
BRDY 3,410 3,41C 207t8LAGRANDE
M345 49 4t 217lBLAGRANDE
7tB LOLO BORA 513 51:22
375 237t8LOLOBRDY375
LAGRANDE 434 434 247t8LOLO
7tB SMLK BORA 98s 985 25
62C 267t8SMLKBRDY620
BORA 2,440 2,44C 277t8WALLAWALLA
7t8 BRDY 2,848 2,84e 28WALLAWALLA
7t8 WALLAWALLA LAGRANDE 490 49C 29
R C 307t8BORALAGRANDE
LAGRANDE 29,075 29,071 317t8BORA
7t8 BRDY LAGRANDE 69 6g 32
16,096 16,03€337t8BRDYLAGRANDE
LAGRANDE 2 2 347t8JBSN
0 7,243,160 7,243,160
FERC FORM NO.'t (ED.12-90)Pag€ 329.4
Name ot Respondent
ldaho Power Company
I nrs
(1)
(2)
ts:uate or(Mo, Da
Kepon
r, Yr)
Yeaflrenoo or Kepon
End of 2O18lQ4An Original
A Resubmission 04116t2019
TRANS MISSIUN UI. KLIL; I HIUI I Y I-UK O I HbHS (F
lncludinq transactions referred to as 'wheelinq'ccount 456.'l )
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 Pubiic Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
1 Powerex Corporation NorthWestern/Pacifi Corp East Bonneville Power Administration NF
2 Powerex Corporation PacifiCorp East NorthWestern/PacifiCorp East NF
J Powerex Corporation PacifiCorp East NorthWestern/Pacifi Corp East SFP
4 Powerex Corporation PacifiCorp East Bonneville Power Administration NF
5 Powerex Corporation PacifiCorp East Bonneville Power Administration SFP
6 Powerex Corporation PacifiCorp East Avista SFP
Powerex Corporation PacifiCorp East Sierra Pacific Power NF
8 Powerex Corporation NorthWestern/Pacifi Corp East PacifiCorp East NF
I Powerex Corporation NorthWesterniPacifl Corp East PacifiCorp East SFP
10 Powerex Corporation NorthWestern/Pacifi Corp East PacifiCorp East NF
11 Powerex Corporation NorthWestern/Pacifi Corp East Bonneville Power Administration NF
12 Powerex Corporation PacifiCorp East PacifiCorp East NF
13 Powerex Corpo.ation PacifiCorp East NorthWestern/Pacifi Corp East SFP
14 Powerex Corporation PacifiCorp East PacifiCorp West NF
15 Powerex Corporation PacifiCorp East Bonneville Power Administration NF
't6 Powerex Corporation PacifiCorp East Sierra Pacific Power NF
't7 Powerex Corporation PacifiCorp East PacifiCorp East NF
't8 Powerex Corporation PaciliCorp West PacifiCorp East NF
1S Powerex Corporation PacifiCorp West PacifiCorp East NF
20 Powerex Corporation PacifiCorp East PacifiCorp East NF
21 Powerex Corporation PacifiCorp East Bonneville Power Administration NF
22 Powerex Corporation PacifiCorp East Sierra Pacific Power NF
23 Powerex Corporation Bonneville Power Administration PacifiCorp East NF
24 Powerex Corporation Bonneville Power Administration NFPacifiCorp East
25 Powerex Corporation Bonneville Power Administration Siena Pacific Power NF
20 Powerex Corporation Avista PacifiCorp East NF
27 Powerex Corporation Avista PacifiCorp East NF
28 Powerex Corporation Avista Sierra Pacific Power NF
29 Powerex Corporation Sierra Pacific Power PacifiCorp East NF
30 Powerex Corporation Sierra Pacific Power Bonneville Power Administration NF
3'1 Powerex Corporation PacifiCorp West PacifiCorp East NF
32 Powerex Corporation PacifiCorp West PacifiCorp East NF
33 Powerex Corporation PacifiCorp West PacifiCorp East NF
34 Powerex Corporation ldaho Power Company PacifiCorp East NF
TOTAL
FERC FORM NO.1 (ED.12-90)Page 328.5
l\ame oI Kesponoenl
ldaho Power Company
II[5
(1)
(2)
1t5.uate ot(Mo. Da
l(epon
, Yr)
Iear,/Fenoo or Neport
End of 20181Q4An Original
A Resubmission 04t1612019
t 45ttXContinuec,)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 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 transmlssion 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.
TRANSFER OF ENERGYFERC 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)
MegaWatt Hours
Received(i)
Megawatt Hours
Delivered
U)
Line
No.
7t8 AVAT.NWMT LAGRANDE 471 471 I
7t8 BORA BPAT.NWMT 50 5C 2
7t8 BPAT.NWMT 102 102 3BORA
7t8 BORA LAGRANDE 6,736 6,73(4
718 BORA LAGRANDE 18 18 5
718 BORA LOLO 538 53€o
718 BORA M345 306 30€7
7t8 BPAT.NWMT BORA 35 ,a 8
7t8 BPAT.NWMT BORA 100 10c I
7t8 BRDY 42 42 10BPAT.NWMT
718 BPAT.NWMT LAGRANDE 33 aa 11
718 BRDY BORA 144 144 12
718 BRDY BPAT.NWMT 2C 2C 13
718 HURR 6C 6C 14BRDY
718 BRDY LAGRANDE 2,587 2,587 15
7t8 BRDY M345 1,189 1,18S '16
BRDY 36 36 177t8GSHN
7t8 HURR BORA 31 31 18
7t8 HURR BRDY 4 4 19
7t8 JEFF BORA 184 18t 20
LAGRANDE 252 25i 217t8JEFF
7t8 JEFF M345 B I 22
718 LAGRANDE BORA 9,217 9,211 23
7t8 LAGRANDE BRDY 2,258 2,25t 24
7t8 LAGRANDE M345 1,693 1,69:25
718 LOLO BORA 136 13€26
7t8 LOLO BRDY 45 4a 27
7t8 M345 122 122 28LOLO
718 M345 BORA 11 '11 29
7t8 M345 LAGRANDE 878 B7€30
BORA 122 122 317t8POP
7t8 SMLK BORA 2,360 2,36C sz
7t8 SMLK BRDY 328 32e 33
BORA 2,580 2,58C 347tBWALLAWALLA
0 7,243,164 7,243,16(
FERC FORM NO. I (ED.'r2-90)Page 329.5
Name ot Respondent
ldaho Power Company
r nts
(1)
(2)
IS:uate ol Kepon
(Mo, Da, Yr)
YeailHenoo oI Kepon
End of 20181Q4An Original
A Resubmission 04t16t2019
TRANS MISSION OF ELECTRICITY FOR OTHERS (A
lncluding transactions refened to as'wheeling'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), (n) 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 authorig. Do not abbreviate or truncale 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-
calion
(d)
1 Powerex Corporation ldaho Power Company PacifiCorp East NF
2 Powerex Corporation ldaho Power Company Siena Pacific Power NF
2 Rainbow Energy Marketing Coporation PacifiCorp East NorthWestern/Pacifi Corp East SFP
4 Rainbow Energy Marketing Coporation PacifiCorp East Bonneville Power Administration NF
5 Rainbow Energy Marketing Coporation PacifiCorp East Bonneville Power Administration SFP
6 Rainbow Energy Marketing Coporation PacifiCorp East Avista NF
7 Rainbow Energy Marketing Coporation NorthWestern/Pacifi Corp East PacifiCorp East SFP
8 Rainbow Energy Marketing Coporation NorthWestern/Pacifi Corp East Sierra Pacific Power SFP
I Rainbow Energy Marketing Coporation PacifiCorp East SFPBonneville Power Administration
10 Rainbow Energy Marketing Coporation PacifiCorp East PacifiCorp East NF
11 Rainbow Energy Marketing Coporation PacifiCorp East PacifiCorp East SFP
12 Rainbow Energy Marketing Coporation Avista PacifiCorp East NF
13 Rainbow Energy Marketing Coporation Siena Pacific Power NorthWestern/Pacifi Corp East NF
14 Rainbow Energy Marketing Coporation Siena Pacific Power Bonneville Power Adm inistration NF
15 Shell Energy North America (US), L.P PacifiCorp East NorthWestern/Pacifi Corp East NF
16 Shell Energy North America (US), L.P PacifiCorp East Bonneville Power Administration NF
17 Shell Energy North America (US), L.P PacifiCorp East Avista NF
18 Shell Energy Norlh America (US), L.P PacifiCorp East Siena Pacific Power NF
19 Shell Energy North America (US). L.P PacifiCorp East Sierra Pacific Power SFP
20 Shell Energy North America (US), L.P NorthWestem/Pacifi Corp East PacifiCorp East NF
21 Shell Energy North America (US), L.P No(hWestern/Pacifi Corp East PacifiCorp East NF
22 Shell Energy North America (US), L.P NorthWestem/Pacifi Corp East Sierra Pacific Power NF
23 Shell Energy Norlh America (US), L.P PacifCorp East NorthWestern/Pacifi Corp East NF
24 Shell Energy North America (US), L.P PacifiCorp East Bonneville Power Administration NF
25 Shell Energy North America (US), L.P PacifiCorp East Avista NF
26 Shell Energy Norlh America (US), L.P PacifiCorp East Siena Pacific Power NF
27 Shell Energy North America (US), L.P PacifiCorp East Sierra Pacific Power SFP
28 Shell Energy North America (US), L.P PacifiCorp East PacifiCorp East NF
29 Shell Energy North America (US), L.P PacifiCorp East Bonneville Power Administration 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 Bonneville Power Admin istration PacifiCorp East NF
JJ Shell Energy North America (US), L.P Bonneville Power Administration PacifiCorp East NF
34 Shell Energy North America (US), L,P Bonneville Power Administration PacifiCorp East SFP
TOTAL
FERC FORM NO.1 (ED.12-90)Page 328.6
Name ot Respondent
ldaho Power Company
I nts
(1)
(2)
IS:uate ot Kepon(Mo, Da, Yr)
04116t2019
Yea7Henoo oI Kepon
End of 2U8lA4An Original
A Resubmission
t 4S6XConttnued)
to as
5. ln column (e), identiflT the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. ln column (0, report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. ln column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts- Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j) the total megawatthours received and delivered.
TRANSFER OF ENERGYFERG 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)
Megavvatt Hours
Received(i)
Megawa( Hours
Delivered(i)
Line
No.
7t8 WALLAWALLA BRDY 363 Jb,.:1
27t8WALLAWALLAM3451,823 1,823
BPAT.NWMT 413 37t8BORA
7t8 BORA LAGRANDE 312 312 4
57tBBORALAGRANDE5,980 5,98C
425 425 6718BORALOLO
7t8 BRDY 19,441 7BPAT.NWMT
718 BPAT.NWMT M34s 2,678 2,678 8
1,6787t8BRDYLAGRANDE1,678 I
BRDY 4,748 107t8JEFF
7t8 JEFF BRDY 1,152 11
718 LOLO BORA 330 33(12
BPAT.NWMT 46!13718M345
7t8 LAGRANDE 2,90i 14M345
7t8 BORA BPAT.NWMT 45 4a 15
3,81t 167t8BORALAGRANDE3,815
LOLO 36:17718BORA
7t8 M345 40(18BORA
7tB BORA M345 96 9€19
100 10(7t8 BPAT.NWMT BORA 20
BRDY 10t 217t8BPAT.NWMT
718 BPAT.NWMT M345 838 838 22
7t8 BRDY BPAT.NWMT 136 13€23
4,16€247t8BRDYLAGRANDE4,1 68
7tB BRDY LOLO 443 25
7t8 BRDY M345 6,338 6,338 26
M34s 21 .773 277t8BRDY
7t8 BORA 63i 28JBSN
7lB JBSN LAGRANDE 1,748 1,74e 29
)E 307t8JEFFLAGRANDE25
t\4345 40c 317t8JEFF
7t8 LAGRANDE BORA 24,412 24,412 32
8,49t 337t8LAGRANDEBRDY8,498
BRDY 638 63t 347tBLAGRANDE
0 7,243,16t
FERC FORM NO. 1 (ED.12-90)Page 329'6
41 3l
1s,4411
4,7481
1,1s21
46sl
2.9021
3631
4001
1 o8l
443,
21,7731
6371
4001
7,249,1601
Name of Respondent
ldaho Power Company
lhrs
(1)
(2)
IS:Date ot Report(Mo, Da, Yr)
YearlPeriod ot Report
End of 2018/Q4An Original
A Resubmission 0411612019
I KANI MtSS|UN Ul- ELEU I Hlut r Y t-UK () t HEr-{s (f
lncludinq lransactions referred to as 'wheelinq'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 Aulhority)
(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 Bonneville Power Administration PacifiCorp East NF
2 Shell Energy North America (US), L.P Bonneville Power Administration Sierra Pacific Power NF
3 NFShell Energy North America (US), L.P Avista PacifiCorp East
4 Shell Energy North America (US), L.P Avista PacifiCorp East NF
5 Shell Energy North America (US). L.P Avista Sierra Pacific Power NF
SFP6Shell Energy North America (US), L.P Avista Sierra Pacific Power
I Shell Energy North America (US), L.P,Siera Pacific Power PacifiCorp East NF
I Shell Energy North America (US), L.P Sierra Pacific Power NorthWestern/Pacifi Corp East NF
I Shell Energy North America (US), L.P Sierra Pacific Power Bonneville Power Administration NF
10 Shell Energy North America (US), L.P Sierra Pacific Power Avista NF
11 Shell Energy North America (US), L.P PacifiCorp West PacifiCorp East NF
12 Shell Energy North America (US), L.P PacifiCorp West Sierra Pacific Power NF
13 Shell Energy North America (US), L.P ldaho Power Company PacifiCorp East NF
14 Shell Energy North America (US), L.P ldaho Power Company PacifiCorp East SFP
15 Shell Energy North America (US), L.P ldaho Power Company PacifiCorp East NF
16 Shell Energy North America (US), L.P ldaho Power Company PacifiCorp East SFP
17 Shell Energy North America (US), L.P ldaho Power Company Sierra Pacific Power NF
18 Shell Energy North America (US), L.P ldaho Power Company Sierra Pacific Power SFP
NF19Tenaska Power Services PacifiCorp East Sierra Pacific Power
20 Tenaska Power Services PacifiCorp East Sierra Pacific Power NF
21 Tenaska Power Services PacifiCorp East Sierra Pacific Power SFP
22 The Energy Authority, lnc.PacifiCorp East Bonneville Power Administration NF
23 PacifiCorp East NFThe Energy Authority, lnc.Bonneville Power Administration
24 The Energy Authority, lnc.Bonneville Power Administration Sierra Pacific Power NF
25 The Energy Authority, lnc.Sierra Pacific Power Bonneville Power Adm inistration NF
26 The Energy Authority, lnc.PacifiCorp West PacifiCorp East NF
27 The Energy Authority, lnc.PacifiCorp West PacifiCorp East NF
28 Transalta Energy Marketing (U.S.) lnc.PacifiCorp East NorthWestern/Pacifi Corp East NF
29 Transalta Energy Marketing (U.S.) lnc.PacifiCorp East Bonneville Power Administration NF
30 Transalta Energy Marketing (U.S.) lnc.PacifiCorp East Avista NF
31 Transalta Energy Marketing (U.S.) lnc.NorthWestem/PacifiCorp East Bonneville Power Administration NF
32 Transalta Energy Marketing (U.S.) lnc.NorthWestem/Pacifi Corp East Sierra Pacific Power NF
33 Transalta Energy Marketing (U.S.) lnc.PacifiCorp East Bonneville Power Administration NF
34 NFTransalta Energy Marketing (U.S.) lnc.PacifiCorp East PacifiCorp East
TOTAL
FERC FORM NO. r (ED. 12-90)Page 32E'7
Name of Respondent
ldaho Power Company
ThiS
(1)
(2)
IS:Date of Report
(Mo, Da, Yr)
0411612019
Year/Period of Report
End of 20181Q4An Original
A Resubmission
rt 456XContanuecl)as
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. Reporl 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.
TRANSFER OF ENERGYFERC Rate
Schedule of
Tariff Number
(e)
Designation)
(f)
Point of Receipt
(Subsatation or Other
Designation)
(s)
Point of Delivery
(Substation or Other
Billing
Demand
(MW)
(h)
Megawatt Hours
Received(i)
MegaWatt Hours
Delivered
0)
Line
No.
7t8 LAGRANDE JBSN 912 91i 1
7t8 LAGRANDE M345 82,658 82,65t 2
7t8 BORA 1,587 1,581LOLO 3
7t8 LOLO BRDY o,zot O,ZOt 4
7t8 LOLO M34s 106,523 106,52t 5
7t8 LOLO M345 63,459 63,45!6
7t8 M345 BORA 373 37i 7
7t8 M345 BPAT.NWMT 231 231 8
7tB M345 LAGRANDE 4,019 4,01e I
LOLO 68 6t 10718M345
7t8 SMLK BRDY 1.477 1,471 11
7t8 SMLK M345 24 24 12
BORA7t8WALLAWALLA 41 ,306 41,30€13
7t8 BORA 16 1€14WALLAWALLA
7t8 WALLAWALLA BRDY 16,057 16,057 15
718 WALLAWALLA BRDY 9,962 I,e62 16
M345 21,813718WALLAWALLA 21,813 17
7t8 M345 3,073 3,073 18WALLAWALLA
7t8 BORA M345 57 57 19
7t8 BRDY M345 1,394 1,394 20
M345 1,527 21718BRDY1,52't
7t8 BRDY LAGRANDE 864 864 22
7t8 LAGRANDE BRDY 528 528 23
M3457lBLAGRANDE 249 249 24
7t8 M345 LAGRANOE 1,418 1,41t 25
7t8 SMLK BORA 1.722 1,72i 26
BRDY 50 5C7t8SMLK 27
7t8 BORA BPAT.NWMT 2,006 2,00e 28
7t8 BORA LAGRANDE 3,377 3,371 2S
LOLO7t8BORA 239 239 30
7t8 LAGRANDE 840 84(BPAT,NWMT 31
7/8 BPAT.NWMT M345 50 5C 32
7tB BRDY LAGRANDE 1,461 1,461
7t8 BORA 1 1 34JBSN
0 7,243,160 7,243,160
FERC FORM NO.1 (ED. r2-90)Page 329.7
Name of Respondent
ldaho Power Company
lhis
(1)
(2)
IS:Date of Report(Mo. Da, Yr)
44n6t2019
Year/Penod ot Report
End of 20181Q4An Original
A Resubmission
TRANT MISi,IUN UF ELtsUIKIUI I Y FUH UIHEKti (P
lncluding transactions refened to as'wheeline'ccount 4cti.1 )
I
1 . Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualirying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. ln column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Terrn 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.Bonneville Power Administration PacifiCorp East NF
2 Transalta Energy Marketing (U.S.) lnc.Bonneville Power Administration Sierra Pacific Power NF
3 Transalta Energy Marketing (U.S.) lnc.Avista PacifiCorp East NF
4 Transalta Energy Marketing (U.S.) lnc.Avista Sierra Pacific Power NF
5 Transalta Energy Marketing (U.S.) lnc.Sierra Pacific Power Bonneville Power Administration NF
6 fransalta Energy Marketing (U.S.) lnc.Sierra Pacific Power Avista NF
I Transalta Energy Marketing (U.S.) lnc.PacifiCorp West PacifiCorp East NF
8 Transalta Energy Marketing (U.S.) lnc.PacifiCorp West Sierra Pacific Power NF
I Transalta Energy Marketing (U.S.) lnc.ldaho Power Company PaciliCorp East NF
10 Transalta Energy Marketing (U.S.) lnc.ldaho Power Company Sierra Pacific Power NF
11 Utah Associated Municipal Power Systems PacifiCorp East Siena Pacific Power NF
12 Utah Associated Municipal Power Systems PacifiCorp East Sierra Pacific Power SFP
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 32E.E
Name of Respondent
ldaho Power Company
This
(1)
(2)
ls:
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4o4t16t2019
to as t 456XContinued)
5. ln column (e), identi! 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), 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. Repo( in column (i) and (j) the total megawatthours received and delivered.
TRANSFER OF ENERGYFERC Rate
Schedule of
Tariff Number
(e)
Designation)
(f)
Point of Receipt
(Subsatation or Other
Point of Delivery
(Substation or Other
Designation)
(s)
Billing
Demand
(MW)
(h)
Megawatt Hours
Received(i)
Megawatt Hours
Delivered
0)
Line
No.
7t8 LAGRANDE BORA 7,536 7,53(1
7t8 LAGRANDE M345 19,435 19,43t 2
7t8 LOLO BORA 378 37t J
7t8 LOLO M345 30 3C 4
7t8 M345 LAGRANDE 4,1 56 4,15t 5
718 M34s LOLO 428 42t 6
718 SMLK BORA 15,623 't5,623 7
718 SMLK M345 100 10c 8
7t8 WALLAWALLA BORA 4,813 4,813 I
7t8 M345WALLAWALLA 1,458 1,458 10
7t8 BORA M345 2,039 2,03S 11
7t8 BRDY M345 844 844 12
13
14
15
't6
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
0 7,24316A 7,243,16t
FERC FORM NO.1 (ED.12-90)Page 329.8
An Original
A Resubmission
Date of Reoort
(Mo, Da, Yi)
Year/Period of Report
End of 20181Q4
0411612019
Name of Respondent
ldaho Power Company (1)
(2)
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 fom all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). lf no monetary settlement was made, enter zero (1101 1) in column
(n). Provide a footnote explaining the nature of the non-monetary seftlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and U) 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 ($)
(k+l+m)
(n)
Line
No.
1,861,',t22 110,174 1,971,296 1
1,700,511 127,383 't,827,894 2
7,092,195 450,580 7,542,775 3
12,936 12.936 4
1 13,393 1 13,393 5
10,953 883 11,836 6
54,759 54,759 7
3,639 3,639 8
12.229 12,229 I
10
4,928,159 4,928,159 11
4,214,425 4,214,425 12
B,190,939 8,190,939 13
3,432,717 3,432,7',t7 14
3,398,730 3,398,730 15
3,398,730 3,398,730 16
17
1,720 1,720 18
761 761 19
2,701 2,701 20
6,965 6,965 21
19,'t 90 1 9,1 90 22
1,421 1,421 23
92 92 24
938 938 25
22,680 22,680 26
1,215 1,215 27
5,'190 5,190 28
3,226 3,226 29
86 86 30
874 874 JI
187 187 32
856 856 33
799 799 34
10,664,781 40,66/',251 0 s1,329,032
FERC FORM NO.1 (ED.12-90)Page 330
Name of Respondent
ldaho Power Company
t his
(1)
(2)
ls:Date of Report(Mo, Da, Yr)
YearlPeriod of Report
End of 20181Q4An Original
A Resubmission 04t16t20't9
AS
9. ln column (k) through (n), report the revenue amounts as shown on bills or vouchers. ln column (k), provide revenues from demand
charges related to the billing demand reported in column (h). ln column (l), provide revenues from energy charges related to the
amount of energy transferred. ln column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). lf no monetary settlement was made, enter zero (1 101 1 ) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(t)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Lrne
No.
31 31 1
3,282 3,282 2
47 47 3
44,557 4,557
28 28 5
84 B4 o
71212
796 8796
2,608 2,608 9
I I 10
608 11608
118 't2118
2 2 13
56 56 14
69 1569
37,345 37,345 16
90 90 17
1844,925 44.925
171,831 19171,831
10,341 10,341 20
5,142 5J02 21
8,101 228,101
319 23319
253 253 24
126,065 25126,06s
8 8 26
1,378 1,378 27
24,237 2824,237
2,564 2,564 29
51 ,349 51,349 30
1,917 1,917 31
323 32323
2,995 2,995 33
346,338 6,338
0 51,329,03210,664,781 40,46/,251
FERC FORM NO. r (ED.12-90)Page 330.1
This
(1)
(2)
ls:Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4ldaho Power Company An Original
A Resubmission 04t16120'lg
AS
9. ln column (k) through (n), report the revenue amounts as shown on bills or vouchers. ln column (k), provide revenues from demand
charges related to the billing demand reported in column (h). ln column (l), provide revenues from energy charges related to the
amount of energy transfened. ln column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). lf no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(t)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Line
No.
3,1 03 3,103 1
105,674 2105,674
112,049 112,049 3
136 136 4
2,234 2,234 5
13,737 613,737
9,345 9,345 7
26.671 26,67',|8
't,209 1,209 I
'1,741 1,741 10
160 160 11
9s,630 1295,630
60 60 13
3,338 3,338 14
151 1,086 11,086
27,765 27,765 't6
215,443 215,403 17
151 151 18
22,260 22,264 19
13,553 '13,553 20
822 822 21
2241,914 41,914
251 251 23
104,019 1 04,019 24
259,230 259,230 25
42 42 26
60 2760
36,257 36,2s7 28
15,760 15,760 29
303030
1,853 '1 ,853 31
132,087 132,087 32
6,814 6,814 33
4,432 4,432 34
10,664,781 40,664,251 0 51,329,032
FERC FORM NO.1 (ED.12-90)Page 330.2
Name of Respondent
ldaho Power Company
This
(1)
(2)
ls:Date of Report
(Mo. Da, Yr)
0411612019
Year/Period of Report
End of 20181Q4An Original
A Resubmission
to as
9. ln column (k) through (n), report the revenue amounts as shown on bills or vouchers. ln column (k), provide revenues from demand
charges related to the billing demand reported in column (h). ln column (l), provide revenues from energy charges related to the
amount of energy transferred. ln column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). lf no monetary settlement was made, enter zero (1 101 I ) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401 , Lines 16 and 17 , respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Energy Charges
($)
(t)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Line
No.
Demand Charges
($)
(k)
973 973 1
fi3,417 't 63,017 2
4,245 34,245
s55 955 4
39,096 39,096 5
32,345 32,345 6
10,336 710,336
333,1 90 333,1 90 8
272 272 I
101,879 10101 ,879
16,443 16,443 11
853 853 12
13855,695 855,695
463,275 14463,275
1,654 1,654 15
5,502 5,502 16
94,847 1794,847
3,746 3,746 18
7.316 7,316 19
1,512 1,512 20
12,679 2112,679
914,176 914,176 22
24 24 23
732 732 24
9,529 9,529 25
8,970 8,970 26
102,1 09 271 02,1 09
31,236 31,236 28
39 39 29
30752,269 752,269
6,893 6,893 31
s,986 5,986 32
471,818 47',\,818 33
70 70 34
40,664,251 0 51,329,03210,664,781
FERC FORM NO.1 (ED.12-90)Page 330'3
S:Date of Report(Mo, Da, Yr)
04t16t2019
Year/Period of Report
End of 2A18lQ4Original
A Resubmission
Name of
ldaho Power Company (1)
t2)
as
9. ln column (k) through (n), report the revenue amounts as shown on bills or vouchers. ln column (k), provide revenues from demand
charges related to the billing demand reported in column (h). ln column (l), provide revenues from energy charges related to the
amount of energy transferred. ln column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). lf no monetary settlement was made, enter zero (1 101 1) in column
(n). Provide a footnote explaining the nature of the non-monetary seftlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401 , Lines 16 and 17 , respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(t)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Ltne
No.
713 713 1
8,88'l 8,881 2
14,628 14,628 3
6,095 6,095 4
816 816 5
589 589 6
20 20 7
743 743 8
1,2U,489 1,264,489 I
3,862 3,862 10
327 327 11
23,506 23,506 12
753 753 13
22,011 22,011 14
9,352 9,352 15
2,995 2,995 '16
23,526 23,526 17
5 5 18
17,991 17,991 '19
16,882 16,882 20
243 243 21
2,540 2,540 22
'1,856 1,856 23
2,149 2,149 24
4,876 4,876 25
3,069 3,069 26
12,080 12,080 27
14,099 14,099 28
2,426 2,426 29
64 64 30
373,461 373,461 31
886 886 32
206,749 206,749 33
26 26 34
10,664,781 40,664,251 0 51,329,032
FERC FORM NO.1 (ED.12-90)Pags 330.4
Name of Respondent
ldaho Power Company
I has
(1)
12)
IS Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4An Original
A Resubmission 0411612019
as
9. ln column (k) through (n), report the revenue amounts as shown on bills or vouchers. ln column (k), provide revenues from demand
charges related to the billing demand reported in column (h). ln column (l), provide revenues from energy charges related to the
amount of energy transferred. !n column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). lf no monetary settlement was made, enter zero (1 101 1 ) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
1 1. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(l)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Lrne
No.
5,266 15,266
559 559 2
1,140 1.140 2
75,315 75,315 4
201 201 5
6,01 5 6,015 6
3,421 3,421 7
391 8391
1,118 1,'118 I
470 470 10
1',!369 369
1 ,610 121,610
224 224 13
14671671
28,525 '1528,925
13,294 13,294 16
403 403 17
347 347 18
45 45 19
2,057 2,057 20
2,818 2.818 21
228989
103,054 23103,054
25,246 25,246 24
18,929 2518,929
1,521 1,521 lo
503 503 27
281,364 't,364
123 29123
9,817 9,817 30
1,364 1,364 31
26,387 3226,387
3,667 3.667 33
28,847 28.847 34
51,329,03210,664,781 40,664,251 0
FERC FORM NO.1 (EO. 12-90)Page 330.5
Name of Respondent
ldaho Power Company
This
(1)
(2)
ls:
An Original
A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period ot Report
End of 201BlQ404t16t2A19
as
9. ln column (k) through (n), report the revenue amounts as shown on bills or vouchers. ln column (k), provide revenues from demand
charges related to the billing demand reported in column (h). ln column (l), provide revenues from energy charges related to the
amount of energy transferred. ln column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). lf no monetary settlementwas made, enterzero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401 , Lines 16 and 17 , respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(t)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Line
No.
4,059 4,059 1
20,383 20,383 2
2.541 2,541 3
1,919 1 ,919 4
36,790 36,790 5
2,615 2,615 6
1 19,603 119,603 7
16,475 16,475 8
10,323 10,323 9
29,210 29,210 10
7,087 7,087 11
2,030 2,030 12
2,861 2,861 13
17,853 17,853 14
290 290 15
24,555 24,559 16
2,337 2.337 17
2,575 2,575 1B
618 618 19
u4 644 20
695 695 21
5,395 5,395 22
876 876 23
26,832 26,832 24
2,852 2,852 25
40,801 40,801 26
140,165 1 40,1 65 27
4,'.t01 4,101 28
11,2s3 11,253 29
161 161 30
2,575 2.575 31
157,154 157,154 JZ
54,706 54,706 33
4,107 4,107 34
10,664,7E1 40,60/,251 0 51,329.032
FERC FORM NO.1 (ED.12-90)Page 330.6
Name of Respondent
ldaho Power Company
This
(1)
(2)
ls:Date of Report
(Mo, Da, Yr)
YeariPeriod of Report
End of 2O18lQ4An Original
A Resubmission 04116t2019
to as
9. ln column (k) through (n), report the revenue amounts as shown on bills or vouchers. ln column (k), provide revenues from demand
charges related to the billing demand reported in column (h). ln column (l), provide revenues from energy charges related to the
amount of energy transferred. ln column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). lf no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401 , Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(l)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Lrne
No.
5,871 5,871 1
532,117 532,117 2
10,216 10,216 J
40.312 4A312 4
685,749 685,749 5
408,522 408,522 6
2,401 2,401 7
't,487 1,487 8
25,873 25,873 9
438 438 10
9.508 119,508
155 155 12
265,910 265,910 13
103 103 14
103,368 103,368 15
64,131 64,131 ID
't40,423 140,423 17
1819,783 19,783
252 252 19
6,1 73 6,173 20
6.762 6,762 21
4,996 224,936
3,053 3,053 23
1,440 1,440 24
8,199 258,199
9,957 9,957 26
289 289 27
2812,120 12j20
20,404 20,404 29
1,444 1,444 30
5,075 5,075 31
302 302 32
8,827 8.827 33
6 6 34
40,664,251 0 s1,329,03210,664,781
FERC FORM NO.1 (ED. 12-90)Page 330.7
Name of Respondent
ldaho Power Company
This
(1)
(2)
ls:Date of Report(Mo, Da, Yr)
YeariPeriod of Report
End of 20181Q4An Original
A Resubmission 04t16t2019
as
9. ln column (k) through (n), report the revenue amounts as shown on bills or vouchers. ln column (k), provide revenues from demand
charges related to the billing demand reported in column (h). ln column (l), provide revenues from energy charges related to the
amount of energy transfened. ln column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). lf no monetary settlement was made, enter zero (1101 1) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401 , Lines 16 and 17 , respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(l)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Line
No.
4s,532 45,532 1
117,425 117,425 2
?,284 2,284 3
181 181 4
25,110 25,110 5
2,586 2,586 b
94,393 94,393 7
604 604 I
29,080 I29,080
8,809 8,809 10
1113,395 13,395
5,541 5,541 12
13
14
15
16
17
18
'19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
10,664,781 40,6&.,251 0 51,329,032
FERC FORM NO.1 (ED.12-90)Page 330.8
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
04t16t2019
Year/Period of Report
20181Q4
FOOTNOTE DATA
Schedule Page: 328 Line No.: 1 Column: a
The network servi-ce agreement- between Idaho Power and the Bonnevill*e Power Administrationfor the Oregon Trail Electric Cooperative expires September 30, 2A28.
Schedule Page:328 Line No.: 1 Column: e9. Open Access Transmission Tariff, Schedule 9 Network InEegration 'l'ransmission Service
Schedute Page: 328 Line No.:1 Column: h
The bj-lling demand for network servj-ce is the cusLomer's demand aE the time of Irlaho Power
Qgmpany transmission system peak and varies by month.
Sehedule Page: 328 Line No.: 2 Column: a
The network service agreement beLween Idaho Power and the Bonnevil-Le Power AdminisLrationfor the USBR expi-res December 31, 2023.
Sciedule Page:328 Line No.:3 Column: a
The network service agreement between Idaho Power and the Bonnevifle Power Administrationfor the Prlority Firm Customers expires September 30, 2028.
Scfiedute Page:328 Line No.:4 Column: a
The contract fJetween Idaho Power and the Milner Irrigation District expires December 31,
Schedule Page: 328 Line No.:4 Column: eLegacy, contract prior to the Open Access '-lransmission Tarif f
Sctredute Page:328 Llne No.: 5 Column: a
The agreement between fdano Power and the City of Seattle expires December 31, 2019. Cit-ycf Seattle has re-so1d this transmission service request to Morgan Stanley and MorganStanley is now responsible for payment.
Schedule Page:328 Line No.:5 Column: e4, Open Access Transmission Tariff, Schedule 4 Energy Imbalance Servi-ce
Schedule Page:328 Line No.:6 Column: a
The contract between ldaho Power and PacifiCorp - Imnaha expires on March 31, 2021.
Schedute Page:328 Line No.:7 Column: a
The agreement between Idaho Power and the United States Department of the Interior, Bureauof Tndian Affairs is subject to termi-naLion upon 90 days written notice by the Bureau.
Schedule Page:328 Line No.: I Column: a
The agree:nent betr.reen Idano Pcwer and Cycle Hcrseshoe Bend Wind, LLC has no expirationdate and can be terminated by either party at any time.
S{neAute Page:326 Line No.:8 Column: e5/6, Open Access Transnission Tariff, Schedule 5,/6 Operating Reserve:^
Schedule Page:328 Line No.: 11 Column: e
i /8, Open Access T::ansmission 'larif f , Schedule 7,/8 Firm/Non-Firm Point-to-Point-
Transmission Service
FERC FORM NO. 1 (ED. 12-871 Page 450.'l
ldaho Power Company
This(1)
(2)
Report ls:
IAn Original
Date of Report(Mo, Da, Yr)
04t16t2019
YearlPeriod of Report
End of 2018/Q4
A Resubmission
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
(lncluding transactions referred to as "wheeling")
1. Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public
authorities, qualifying facilities, and others for the quarter.
2. ln column (a) report each company or public authority that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. ln column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General lnstructions for deflnitions 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.
TRANSFER OF ENERGY EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERSLine
No.Name of Company or Public
Authori ty (Footnote Affi liations)
(a)
Statistical
Classification
(b)
Magawatt-hoursReceived
(c)
Magawat-hoursDelivered
(d)
DemanoCharoes($I
(e)
Enerov
Char<i'6s($r
(0
umerCharoes($I
(q)
Total Cost of
Tranffission
1 Avista Corp-WWP Div NF 10,27s 10,275 84,472 84,472
2 Avista Corp-WWP Div SFP 191,760 191,760 681,357 68 1,357
J Bonneville Power Admin LTP 215,473 215,473 1,134,792 1,134,792
4 Bonneville Power Admin SFP 6,981 6,98'l 33,312 33,312
5 Bonneville Power Admin NF 342 342 1,447 1,447
6 Bonneville PowerAdmin 6,234 6,234
7 239,481 239,481Bonneville Power Admin
8 Bonneville Power Admin QS 77,464 77,464
I Bonneville Power Admin o8 30,836 30,836
OS'10 Bonneville Power Admin 6,219 6,219
11 Bonneville Power Admin 08 10,615 10,615
0s 2,500 2,s0012Bonneville Power Admin
13 NorthWestem Energy SFP 18 18 3,117 3,117
14 NorthWestem Energy NF 1,229 1,229 7,837 7,837
15 Northwestem Energy 0s 566 566
to PacifiCorp lnc.lfP 1,531 1,s31 1,045,1 90 1,045,1 90
TOTAL 555,22i 555,222 3,251,876 350,279 3,602,155
FERC FORM NO. 1/3-Q (REV. 02,04)Page 332
os
08
Name of Respondent
ldaho Power Company
is Reoort ls:
5.1nn Original
Date of Report
(Mo, Da, Yr)
Thi
(1)
(2)
Year/Period of Report
End of 2018/Q4
A Resubmission 04t16/2019
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
(lncluding transactions referred to as "wheeling")
1. Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public
authorities, qualifying facilities, and others for the quarter.
2. ln column (a) report each company or public authority that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. ln column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point{o- Point Transmission Reservations, NF - Non-Firm Transmlssion
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 nalure 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.
TRANSFER OF ENERGY EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERSLine
No.Magawan-hoursReceived
{c}
Name of Company or Public
Authority (Footnote Affi liations)(a)
Statistical
Classification(b)
Magawarl-
hoursDelivered
(d)
uemano
Charoes($r
(e)
Enerov
Char<i'rls($I
(t)
umer
Charoes($r
(s)
Total Cost of
Trans/$rjssion
(h)
1 PacifiCorp lnc.SFP 3,517 3,517
PacifiCorp lnc,NF 2,479 2,479 24,814 24,814
3 PaciliCorp lnc,08 44,060 44,060
o84PacifiCorp lnc,-s,348 "5,348
5 PacifiCorp lnc.-38,764 -38,764
0,zbJ6PaciliCorp lnc.6,263
AOPacifi0orp lnc.-1,036 1,036
8 2,049 2,049PacifiCorp lnc.
ADIPacifiCorp Inc.94,s30 94,530
10 AD -256 -256Pacificorp lnc.
SFP11Puget Sound Energy, lnc 60,682 60,682
12 Seattle Clty Light SFP 8,640 8,640
SFP13Snohomish County PUD 134,941 134,941
14 Tacoma Power 8FP 27,758 27,758
1C
16
TOTAL 555,22i 555.222 3,251,876 354,279 3,602,1 55
FERC FORM NO. 1/3-Q (REv. 02-04)Page 332.1
AO
AD
AD
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2\ _A Resubmission
Date of Report
(Mo, Da, Yr)
04116t2019
Year/Period of Report
2018tQ4
FOOTNOTE DATA
Schedule Page: 332 Line No.:3 Column: bContract Expirat j-on Date 72/3L/2C21
Schedule Page:332 Line No.:6 Column: b
Spinning,/supplemental reserrres
Schedule Page: 332 Line No.:7 Column: bAncillary Ser,,'ices
Scfiedule Page: 332 Line No.:8 Column: b
BPAT is provider for capacity reassignment set:Iecl with Snohcmish County PUD
Schedule Page:332 Line No.:9 Column: b
BPAT is provider for capacity reassignment settled with Puget Sound Energy.
Schedule Page:332 Line No;10 Column: h
BPAT is provider for capacily reassiqnnenl seitlecl with Seattle Cj.cy Liqht.
Schedule Page: 332 Line No; 11 Column: b
BPAT is provider for capacity reassignment settled with 'l'acoma Power.
Schedule Page: 332 Line No.: 12 Column: b
Processing Eee for Transmission Service
Schedute Page: 332 Line No.: 15 Column: bAnciIIary Servtces
Sehedule Page: 332 Line No.: 16 Column: bContract Expiration Date 05/3L/2A79
Scheduta Page: 332.1 Line No.: 3 Column: b
Ancillary Services
Schedute Page: 332.1 Line No.: 4 Column: b
April 2018 Intertie Adj
Scfiedule Page: 332-1 Line No.: 5 Column: b
20L2-20L6 EERC rrue-Up
Schedule Page: 332.1 Line No.: 6 Column: b
20L4 ?TP True-Up
Schedule Page: 332.1 Line No.:7 Cotumn: b
2015 PTP True-Up
Schedule Page: 332.1 Line No.: I Column: b2016 ?TP True-Up
Schedule Page: 332.1 Line No.: I Column: b
2011 PTP True-Up
Sc_hgdule Page: 332.1 Line No.: 10 Column: b
201? EERC Refund
Schedute Page: 332.1 Line No.: 11 Column: b
BPAT rs provider for capacity reasslgnment settled with Puget Sound Energy
Schedule Page: 332.1 Line No.: 12 Column: b
BPAT is provider for capacity reassiqnmenl settlecl wj-th Seattle Cir-y Light
Schedule Page: 332.1 Line No.: 13 Column: b
BPAT is provider for capacity reassignment settled with Snohomish County PUD
Schedule Page: 332.1 Line No.: 11 Column: b
BPAT is providei: for capacity reassignnent sett-Led wit-h Tacoma Pcvrer
FERC FORM NO. I (ED. 12-871 Page 450.1
MISCELLANEOU S GENERAL EXPENSES (Account 930,2) (ELECTRIC)
Line
No-
Descriotion(a)
Amount
(b)
I lndustry Association Dues 543,835
2 Nuclear Power Research Expenses
3 Other Experimental and General Research Expenses
4 Pub & Dist lnfo to Stkhldrs...expn servicing outstanding Securities 1,702,311
5 Oth Expn >=5,000 show purpose, recipient, amount. Group if < $5,000
b
7 Director Fees and Expenses
8 Thomas Carlile 84,150
I Richard Dahl 103,455
10 Annette Elg 86,1 30
11 Ronald Jibson 80,190
12 Judith Johansen 86,130
13 Dennis Johnson 82,170
14 Lamont Keen 30,938
15 Christine King 93,060
16 Richard Navarro 86,130
17 Robert Tintsman 187.110
18 Director travel and lodging 18,735
19
20 Corporate Memberships and Subscriptions
21 Arizona State University 50,000
22 22,O00Associated Taxpayers of ldaho
23 Bannock Development Corp 8,500
24 CEATI lnternational, lnc.15,250
25 ESource 31 ,624
26 ldaho Association of Commerce and lndustry 15,500
27 National Association of Oirectors 8,075
28 National Hydropower Association 38,201
29 North American Energy Standard 7,000
30 Pacific NW Utilities 52,093
5,000Southern ldaho Economic Developement
32 Sun Valley Economic Developement 5,500
33 Misc. Memberships under $5,000 41,700
34
35 Chamber of Commerce and Other Civic Organizations 46,O41
36
37
38
39
40
41
42
43
44
45
46 TOTAL 3,605,153
Name ot Respondent
ldaho Power Company
lhis FleDort ls:(1)lxl An Original
uate ot KeDort(Mo. Da, Yi)Year/Penoo ol Kepon
End of 201BlQ4
(2)A Resubmission 04t1612019
FERC FORM NO.1 (ED.12-94)Page 335
31
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(21 A Resubmission
Date of Report
(Mo, Da, Yr)
0411612019
Year/Period of Report
2018tQ4
FOOTNOTE DATA
$chedule Page: 335 Line No.:4
Recipient
American Stock Transfer & Trust
Bloomberg Finance LP
Broadridge Financial Solutions
Deutsche Bank
EQ Shareholder Services
NASDAQ Corp Solutions
New York Stock Exchange
OKAPI Partners, LLC
Payroll Related Expenses
PR Newswire
Rivel Research Group
Stock Based Compensation
Union Bank, N.A.
Trave I Expense-Stock Related
Wells Fargo Shareowner Services
Column: b
Purpose
Mgmt Services
Misc Expense
Misc Expense
Broker Fees
Mgmt Services
Mgmt Services
Listing Services
Mgmt Services
Misc Expense
Misc Expense
Mgmt Services
Misc Expense
Misc Expense
Misc Expense
Mgmt Services
Amount
5 7L,602
24,506
49,767
30,000
87,57t
52,947
64,025
19,800
Lt7,463
L7,2gg
15,840
1,039,102
9,690
15,868
26,752
5 7,702,3!t
Schedule Page: 335 Line No.: 5
Recipient
Bank of New York
lnvestis, lnc.
Retirement Related Expense
Port of Morrow, Poll Contr
Miscellaneous Under S5000
Column: b
Purpose
Revenue Bonds
Website Design
Misc Expense
Misc Expense
Misc Expense
Amount
$ 7,450
7,325
10,000
5,475
44,075s 74,32s
FERC FORM NO. 1 (ED.',12-871 Page 450.1
Name of Respondent
ldaho Power Company An
(2)A Resubmission
Dale of Report(Mo, Da, Y0
o4116t2019
Year/Period of Report
End of 20181Q4
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Account403, 404,405)
(Except amortization of aquisition adjustments)
1 . Report in section A for the year the amounts for ; (b) Depreciation Expense (Account 403; (c) Depreciation Expense for Asset
Retirement Costs (Account 403.1; (d) Amortization of Limited-Term Electric Plant (Account 404); and (e) Amortization of Other Electric
Plant (Account 405).
2. Report in Section 8 the rates used to compute amortization charges for electric plant (Accounts 404 and 405). State the basis used to
compute charges and whether any changes have been made in the basis or rates used from the preceding report year.
3. Report all available information called for in Section C every flffh year beginning with report yeat 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. ldentifu at the bottom of Section C the type of plant
included in any sub-account used.
ln column (b) report all depreciable plant balances to which rates are applied showing subtotals by functional Classifications and showing
composite total. lndicate at the bottom of section C the manner in which column balances are obtained. lf average balances, state the
method of averaging used.
For columns (c), (d), and (e) report available information for each plant subaccount, account or functional classification Listed in column
(a). lf plant mortality studies are prepared to assist in estimating average service Lives, show in column (f) the type mortality curve
selected as most appropriate for the account and in column (g), if available, the weighted average remaining life of surviving plant. lf
composite deprecialion 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 lo 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 Glassifi cation
(a)
DeoreciationExpense
(Account 403)
(b)
Depreciation
Expense for Asset
Retirement Costs
(Account 403.1 )(c)
Amortization of
Limited Term
Electric Plant
(Account 404)
(d)
Amortization ofOther Electric
Plant (Acc 405)
(e)
Total
(0
1 lntangible Plant 6,981,078 6,981,078
2 Steam Production Plant 47,229,753 566,665 47,796,418
3 Nuclear Production Plant
4 Hydraulic Production Plant-Conventional 16,289,503 16,289,503
5 Hydraulic Production Plant-Pumped Storage
6 Other Production Plant 16,055,212 16,055,212
7 Transmission Plant 22.288.563 22,288,563
I Distribution Plant 3S,058,129 39,058,129
o Regional Transmission and Market Operation
10 General Plant 15,411,427 15,411,427
11
12
Common Plant-Eleckic
TOTAL '156,332,587 566,665 6,981,078 163,880,330
B. Basis for Amortization Charges
Acct 404 Balance 11112018 2018 Amortization Balance 1213112018 Remaining Months(1) 0 12,000 48,000 48(2) 8,736,987 522,009 8,214,978(3) 4,684,179 189,691 4,494,488 284(4) 12,134,210 5,849,562 17,327,222(5) 2,884,300 287,899 2,596,400 108(6) 169,657 56,544 113,113 24(7) 1,797,458 63,373 4,488,479Total 30,406,791 6,981,078 37,282,680
('l) Shoshone-BannockTribeLicense&UseAgreement.(NewfiveyearadvancepaymentstartingJanuary20l8,witha
December 31, 2022 termination date.)
(2) Middle Snake Relicensing Costs (Amortized over a 30 year license period; licenses expire 07131134 and 02128135).
(3) Swan Falls Relicensing Costs (Amortized over a 30 year license period, license expires August 31,2042).
(4) Computer Software packages (Amortized over a 62 month period).
(5) Shoshone-Bannock Right of Way (Termination dale 12131127).
(6) Boardman Retrofit Tech Analysis (Scheduled decommission dale 12131120).
(7) FERC License Compliance Costs (Termination date will be expiration date of the applicable FERC Licenses)
FERC FORM NO. 1 (REV. 12-03)Page 336
Name of Respondent
ldaho Power Company
This
(1)
\2)
Reoort ls:
5]An orisinal Date of Report(Mo, Oa, Yr)
Year/Period of Report
End of 20181Q4
A Resubmission 04t't6t2019
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line
No.Account No.
(a)
ueprectaDle
Plant Base(ln Thousands)(b)
trsllmaIeo
Avg. Service
Life(c)
NEI
Salvage(Percent)
(d)
Appileo
Depr. rales(Percent)
(e)
MOnarrry
Curve
'[f"(o')
Average
Remaining
Life
12 75.00310.20 649 4.48 R4.0 '17.90
13 31 1.00 156,069 '100.00 -9.00 3.17 s0.5 17.90
14 193,633 70.00 -5.00312.10 3.47 s1.0 18.10
15 312.20 565,862 53.00 -8.00 4.15 R1.5 17.00
16 4,341 35.00 6.10312.30 10,00 R3.0 13.50
17 314.00 172394 45.00 -7.00 4.94 s0.5 16.50
18 315.00 74,658 60.00 -3.00 3.15 s1.5 16.80
1g 3't6.00 14,908 3s.00 2.00 7.53 s0.0 14.60
20 31 6.1 0 401 13.00 15.00 7.43 12.0 5.40
21 316.40 25C 13.00 15.00 1.24 L2.0
22 316.50 1,363 13.00 15.00 4.98 L2.0 11.80
23 316.60 45 3.90
24 268316.70 21.00 15.00 0.33 s1.0 12.20
25 316.80 4,782 20.00 25.00 4.77 01.0 17.80
26 316.90 14 35.00 15.00 2.43 s1 .0 30.60
27 3'17,00 14,157
28 SubbhlStmm 1,203,790
29 331.00 199,926 120.00 -25.00 2.08 R2.5 35.80
30 332.10 19,461 120.00 -20.00 0.98 s1 ,5 46.20
31 120.00332.20 250,254 -20.00 1.80 s1.s 31.20
32 332.30 5,472 1 .15 Square 55.10
33 100.00333.00 291,047 -10.00 1.92 R2.5 30.60
34 334.00 63,782 65.00 -10.00 2.82 R1.5 27.80
35 26,077 90.00 -5.0c R2.0335.00 2.18 3',1.20
36 335.1 0 140 15.00 7.92 Square 7.90
37 335.20 42 20.00 0.80 Square 9.20
3B 335,30 359 5.00 14.42 Square 2.50
39 336,00 11,882 100.00 2.58 R3.0 22.70
40 Subtotal Hydro 868.442
41 341 .00 143,33S 2.72 Square 32.80
42 342.00 10,715 50.00 2.81 s2.5 28.70
43 343.00 227,444 40.00 3.18 R2.0 26.00
44 344.00 66,619 s0.00 2.45 s2.0 28.40
45 344..10 95 25.00 4.00
46 345.00 91 ,83i 55.00 2.91 R2.0 29.30
47 346.00 6,491 35.00 3.24 R2.5 24.00
48 Subtotal Other 546,54C
100.0049350.20 34,291 0.89 R4.0 85.20
50 198 30.00350.22 3.33
FERC FORM NO. I (REV.12-03)Page 337
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5]Rn original(2\ T-] A Resubmissiontt
Date of Report(Mo, Da. Yr)
0411612019
Year/Period of Report
End of 2A18lA4
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line
No.Account No.
(a)
uepreoaDre
Plant Base(ln Thousands)' (b)
ESttmaleo
Avg. Service
Life
{c)
Salvaoe(Percei0
Appleo
Depr. rates
(Percent)tel
MOnarrry
Curve
'ffi"
AVerage
Remaining
Life(o)
12 352.00 9,424 65.00 -33.00 1.88 R3.0 53.20
'13 3s3.00 441 ,026 52.00 -1 0.00 't.s7 s0.5 42.00
14 354.00 211,358 80.00 -10.00 1.07 R4.0 71.10
15 355.00 193,820 65.00 -80.00 2.64 R1.5 53.90
16 355.10 1,388 10.00 10.00
17 356.00 233,1 63 74.00 -50.00 1.87 Rl.5 62.30
18 359.00 390 65.00 0.91 R2.5 33.30
19 Subtotal Transmission 1 ,196,664
2A 360.22 874 30.00 3.35
21 361.00 40,284 70.00 -50.00 2.17 R3.0 54.40
22 362.00 254,363 55.00 -6.00 1.85 R1.5 42.90
23 364.00 266,497 58.00 -50.00 2.17 R1.5 44.',t0
24 364.10 5,1 99 12.00 8.34
25 365.00 1 40,485 49.00 -30.00 2.65 R1 ,0 34.40
26 366.00 52,238 65.00 -25.00 '1.89 R2.5 49.1 0
27 367.00 275,969 s0.00 -1 1.00 1.90 R1.5 39.40
28 368.00 587,592 42.00 -7.00 2.17 R0.5 34.80
29 369.00 61.920 55.00 -40.00 1.58 R1 .5 43.40
30 370.00 17,034 30.00 -s.00 2.05 01.0 25.70
31 370.10 76,293 18.00 -5.00 5.39 R1 .5 14.00
32 371.20 3,124 21 .O0 -5.00 2.A8 R1 .0 14.70
33 373.24 4,589 40.00 -30.00 1.73 R1.0 29.00
34 374.00 143
35 Subtotal Distribution 1,786,604
36 390.11 32,377 90.00 -3.00 2.08 s1.0 33.20
37 390.1 2 95,142 55.00 -3.00 2.11 R2.0 38.80
38 391 .1 0 14,761 20.00 4.00 Square 12.30
39 391.20 26,565 5.00 20.00 Square 2.70
40 391.21 7,181 8.00 12.50 Square 3.50
41 392.'t0 872 13.00 15.00 7.07 L2.0 9.30
42 392.30 4,563 15.00 40.00 4.13 s2.5 9.70
43 392.40 25,932 13.00 15.00 6.20 12.0 8.50
44 392.50 1,524 13.00 15.00 6.34 L2.0 8.90
45 392.60 44.g',t5 21.00 '15.00 3.95 s1.0 '14.00
46 392.70 9,1 58 21 .00 15.00 4.16 s1.0 12.30
47 392.90 5,905 35.00 15.00 2.24 s1.0 24.30
48 393.00 3,023 25.00 4.00 Square 17.40
49 394.00 11,095 20.00 5.00 Square 12.40
50 395.00 13,703 20.00 5.00 Square 10.60
FERC FORM NO.1 (REV.12-03)Page 337.1
Name of Respondent
ldaho Power Company (1)
(2)
An
A Resubmission
Date of
(Mo. Da
Report
r, Yr)
o4t16t2019
Year/Period of Report
End of 2018/Q4
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line
No.Account No.
(a)
uepreqaDle
Plant Base(ln Thousands)(b)
Eslrmateo
Avg.Service
Life(c)
Net
Salvaoe(Perceht)(d)
Appltecl
Depr. rales(Percent)(e)
MOna[Iy
Curve
'Lf'
AveGlge
Remainino
Life
io)
12 396.00 19,234 20.00 25.00 2.97 o1.0 1 6.70
13 397.1 0 2,796 15.00 6.67 Square 4.70
14 397.20 25,443 1s.00 6.67 Square 8.10
15 397.30 4,020 15.00 6.67 Square 9.70
to 397.40 19,671 15.00 6.02 Square 1 3.10
17 398.00 7,377 15.00 6.67 Square 8.60
18 Subtotal General 375,253
19 Total Plant 5,977,293
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
3B
39
4A
41
42
43
44
45
46
47
48
49
50
FERC FORM NO. 1 (REV. 12-031 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)
04116t2019
Year/Period of Report
2018tQ4
FOOTNOTE DATA
Schedule Page:336 Line No.: 28 Column: a
(Column: c,d,f, g) Plant accounts 31020 through 31650 and 31670 through 31590 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 2016 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.
(Column: e) An average plant balance was used in computing these rates by plant account.
Schedule Page: 336 Line No.: 45 Column: a
Plant account 34410 (created in 2018) was not in the last depreciation study and has not been subject to depreciation
study review.
Schedule Page: 336.2 Line No.: 19 Column: a
Steam, hydro, and other production depreciation and amortization of certain electric plant is maintained by plant
location. Effective April L,L993 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.
FERC FORM NO. 1 (ED. 12-871 Page 450.1
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5]Rn orlsinal(2) nA Resubmission
Date of Report(Mo. Da, Yr)
o4116t2019
Year/Period of Report
End of 20181Q4
REGULATORY COMMISSION EXPENSES
1. Report particulars (details) of regulatory commission expenses incurred during the current year (or incuned in previous years, if
being amortized) relating to format cases before a regulatory body, or cases in which such a body was a party.
2. Report in columns (b) and (c), only the current year's expenses that are not deferred and the current year's amortization of amounts
deferred in previous years.
Line
No
Description
(Fumish name of regulatory commission or body lhe
docftet or case number and a description of lhe case)
(a)
Assessed bvRegulatory
Commission
(b)
Expenses
of
Utility
(c)
TotalExoense forCuirent Year(b) + (c)
(d)
Deferredin Account
182.3 atBeginning of Year
(e)
1 Federal Energy Regulatory Commission:
2 Annual admin charges assessed by FERC 4,033,711 4,033,717
3
4 General Regulatory Expenses and
5 Various other Dockets 33,1 70 33,1 70
6
7 Oregon Hydro - Fees Amortization 158,501 158,501
8
I Regulatory Commission Expenses - ldaho
10 Rate Case - Misc expenses 81,752 81,752 47,835
11
12 Regulatory Commission Expenses - Oregon
13 Rate Case - Misc expenses 147.671 147,671
14 General Regulatory 528,500 528,500
15 Other OPUC expenses 38,047 38,047
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46 TOTAL 4,192,218 829,140 5,021,358 47,835
FERC FoRm NO. 1 (EO.12-96)Page 350
Name of Respondent
ldaho Power Company
This Reoort ls:(1) EAn Orisinal(2) nA Resubmission
Date of Reoort(Mo, Da, Yi)
0411612019
YeariPeriod of Report
End of 20181Q4
REGULATORY COMMISSION EXPENSES (Continued)
3. Show in column (k) any expenses incurred in prior years which are being amortized. List in column (a) the period of amortization.
4. List in column (0, (S), and (h) expenses incurred during year which were charged currently to income, plant, or other accounts.
5. Minor items (less than $25,000) may be grouped.
EXPENSES INCURRED DURING YEAR AMORTIZED DURING YEAR
CURRENTLY CHARGED TO Deferred to
Account 182.3
(i)
Contra
Account
(i)
Amount
(k)
Deferred inAccount 1 82.3
End of Year
fl)
Line
No.uepafiment
(0
AUWUTITNo.(q)
Amount
(h)
1
Electric 928 4,033,717 2
3
4
Electric 928 33,1 70 5
6
Electric 928 158,50'l 7
I
I
Electric 928 -606 62,242 928203 82,358 27,719 10
11
12
Electric 928 147,671 13
Electric 928 528,s00 14
Electric 928 38,047 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
4,939,000 62,242 82,358 27.719 46
FERC FORM NO.1 (ED.12-e6)Page 351
Name of
ldaho Power Company (1)
(2)
An Original
A Resubmission 04t16t2019
Year/Period of Report
End of 20181Q4
RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES
1. Describe and show below costs incurred and accounts charged during the year for technological research, development, and demonstration (R, D &
D) prolect initiated, continued or concluded during the year. Report also support given to others during the year for jointly-sponsored projects.(ldentify
recipient regardless of affiliation.) For any R, D & D work carried with others, show separately the respondent's cost for the year and c,ost chargeable to
others (See definition of research, development, and demonstration in Uniform System of Accounts).
2. lndicate in column (a) the applicable classification, as shown below:
Classifications:
A. Eleckic R, D & D Performed lnternally:
(1) Generation
a. hydroelectric
i. Recreation fish and wildlife
ii Other hydroelectric
b. Fossil-fuel steam
c. lnternal 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 (Classify and include items in excess of $50,000.)
(7) Total Cost lncurred
B. Electric, R, O & 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 2018.
3
4
5
6
7
8
I
10
11
12
't3
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
FERC FORM NO. t (ED.12-87)Page 352
Date of Report(Mo, Da, Yr)
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5l1Rn Orisinat(2) 1-1A Resubmission End of 20181Q4
0411612019
(2) Research Support to Edison Electric lnstitute
(3) Research Support to Nuclear Power Groups
(4) Research Support to Others (Classify)
(5) Total Cost lncurred
3. lnclude in column (c) all R, D & D items performed internally and in column (d) those items performed outside the company costing $50,000 or more,
briefly describing the specific area of R, D & D (such as safety, corrosion control, pollution, automation, measurement, insulation, type of appliance, etc.).
Group items under $50,000 by classifications and indicate the number of items grouped. Under Other, (A (6) and B (4)) classify items by type of R, D &
D activity.
4. Show in column (e) the account number charged with expenses during the year or the account to which amounts were capitalized during the year,
iisting Account 107, Construction Work in Progress, first. Show in column (0 the amounts related to the account charged in mlumn (e)
5. Show in column (g) the total unamortized accumulating of costs of projects. This total must equal the balance in Account 188, Research,
Developmont, and Demonstration Expenditures, Outstanding at the end of the year.
6. lf costs have not been segregated for R, D &D activities or projects, submit estimates for columns (c), (d), and (f) with such amounts identitied by
"Est."
7. Report separately research and related testing facilities operated by the respondent.
Costs lncuned lntemally
Cune,SJYear
Costs lncurred Externally
Current Year
(d)
AMOUNTS CHARGED IN CURRENT YEAR Unamortized
Accumulation
(s)
Line
No.Account
(e)
Amount
(f)
1
2
a
4
5
6
7
8
I
10
11
12
'13
14
15
16
17
18
19
20
21
22
ZJ
24
25
26
27
28
29
30
31
32
33
34
35
36
FERC FORM NO. I (ED.12-87)Page 353
uate ot Report(Mo, Da, Yr)
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5]en Orisinat
(21 1A Resubmission
Date of Report(Mo, Da, Yr)
041',t612019
YearlPeriod of Report
End of 2018/Q4
DISTRIBUTION OF SALARIES AND WAGES
Report below the distribution of total salaries and wages for the year. Segregate amounts originally charged to clearing accounts to
Utility Departments, Constructlon, 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 conect results may be used.
Line
No.
Classification
(a)
Direct PavrollDistribution
(b)
Total
(d)
I Electric
2 Operation
3 Production 21,306,744
4 Transmission 6,914,725
5 Regional Market
6 Distribution 17,654,144
7 Customer Accounts 9,224,652
I Customer Service and lnformational 4,581,573
I Sales
't0 Administrative and General 78,819,31 7
11 TOTAL Operation (Enter Total of lines 3 thru 10)1 38,501,1 55
12 Maintenance
13 Production 4,032,892
14 Transmission 2,789,1 19
15 Regional Market
16 Distribution 7,667,503
17 Administrative and General 1,066,068
1B TOTAL Maintenance (Total of lines 13 thru '17)'15,555,582
19 Total Operation and Maintenance
20 Production (Enter Total of lines 3 and 13)25,339,636
21 Transmission (Enter Total of lines 4 and 14)9,703,844
22 Regional Market (Enter Total of Lines 5 and 15)
23 Distribution (Enter Total of lines 6 and 16)25,321,647
24 Customer Accounts (Transcribe from line 7)9,224,652
25 Customer Service and lnformational (Transcribe from line E)4,581,573
26 Sales (Transcribe from line 9)
27 Administrative and General (Enter Total of lines 10 and 1 7)79,885,385
28 TOTAL Oper. and Maint. (Total of lines 20 thru 27)1 54,056,737 154,056,737
29 Gas
30 Operation
31 Prod uctio n-Ma n ufactured Gas
32 Production-Nat. Gas (lncluding Expl. and Dev.)
aa Other Gas Supply
34 Storage, LNG Terminaling and Processing
at Transmission
36 Distribution
37 Customer Accounts
38 Customer Service and lnformational
39 Sales
40 Adminiskative and General
41 TOTAL Operation (Enter Total of lines 31 thru 40)
4Z Maintenance
43 Production-Man ufactured 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
Date of Report(Mo, Da, Yr)An Original
A Resubmission
YeariPeriod of Report
End of 20181Q4
0411612019ldaho Power Company
(1)
(2)
OISTRIBUTION OF SALARIES AND WAGES (Continued)
Line
No.
Classification
(a)
Direct Pavroll
Distribution
(b)
Allocatron olPavroll charoed forCl6arino AciountsIc)
Total
(d)
48 Distribution
49 Administrative and Genoral
50 TOTAL Maint. (Enter Total of lines 43 thru 49)
51 Total Operation and Maintenance
52 Production-Manufacfured 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 lin6s 33 and 45)
55 Storage, LNG Terminaling and Processing (Total of lines 31 thru
56 Transmission (Lines 35 and 471
57 Distdbution (Lines 36 and 48)
58 Customer Accounts (Line 37)
59 Customer Service and lnformational (Line 38)
60 Sales (Line 39)
61 Administrative and General (Lines 40 and 49)
62 TOTAL Operation and Maint. (Total of lines 52 thru 61)
63 Other Utility Departments
64 Operation and Maintenance
65 TOTAL All Utility Dept, (Total of lines 28, 62, and 64)1 54,056,737 154,0s6,737
66 Utility Plant
67 Construction (By Utility Departments)
68 Electric Plant
69 Gas Plant
70 Other (prcvide details in footnote):
71 TOTAL Construction (Total of lines 68 thru 70)
72 Plant Removal (By Utility Departments)
73 Electric Plant
74 Gas Plant
75 Other (provide details in footnote):
76 TOTAL Plant Removal (Total of lines 73 thru 75)
77 Other Accounts (Specifu, provide details in footnote):
78 Store Expense 4,787,013 4,787,013
79 Other Clearing Accounts 3,551,789 3,551,789
80 Construction Work in Progress 60,474,567 60,474,567
81 Other Work in Progress 3,788,499 3,788,499
82 Other Accounts 5,131,177 5,131 ,177
83 lndirect Loading 47,057,467 47,057,467
84
85
B6
87
88
89
90
91
92
93
94
95 TOTAL Other Accounts 77,733,045 47,057,467 124,790,512
96 TOTAL SALARIES AND WAGES 231,789,782 47,057,467 278,U7,249
FERC FORM NO.I (ED.12-8E)Page 355
I
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2\ _ A Resubmission
Date of Report
(Mo, Da, Yr)
o4l't6t2019
Year/Period of Report
2018tO4
FOOTNOTE DATA
Schedule Page: 354 Line No.: 83 Column: a
Amount reported is total amount of i-ndirect loading
deparLments based on labor charges.
The loading is al-Iocated to
FERC FORM NO. 1 (ED. 12-871 Page 450."1
Name of Respondent
ldaho Power Company
This
(1)
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
0411612019
Year/Period of Report
End of 20181Q4
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), (O), (e), (f) and (g) report the amount of ancillary services purchased and sold during the year
(2) On line 2 columns (U) (c), (O), (e), (f), and (g) report the amount of reactive supply and voltage control services purchased and sold
during the year.
(3) On line 3 columns (n) (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), (Q, 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)
1 Scheduling, System Control and Dispatch x:265,665
2 Reactive Supply and Voltage 18,441
,l Regulation and Frequency Respoflse 3,043,661 KW 298,127
4 Energy lmbalance 703 KWH 14,011
5 Operating Reserve - Spinning 3,411 4,134,901 KW 405,014
b 0perating Reserve - Supplement 2,823 4,1 34,901 KW 405,014
7 0ther
8 Total (Lines 1 thru 7)290,340 1 1 ,314,166 1,122j66
FERC FORM NO. 1 (New 2-04)Page 398
Name of Respondent
ldaho Power Comgany
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t16t2019
Year/Period of Report
2018/Q4
FOOTNOTE DATA
Schedule Page: 398 Line No.: 1 Column: bfdaho Power does not systemaLical ly record tne number cf units refated to ancillarv
services purchased.
FERC FORM NO. 1 (ED. 12-871 Page 450.1
Name of Respondent
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
04116t2019
Year/Period of Report
End of 20181Q4
(1) Report the monthly peak load on the respondent's transmission system. lf the respondent has two or more power systems which are not physicelly
integrated, furnish the required information for each non-integrated system.
(2) Report on Column (b) by month the transmission system's peak load.
(3) Report on Columns (c ) and (d) the specified information for each monthly transmission - system peak load reported on Column (b).
(4) Report on Columns (e) through 0) by month the system'monlhly maximum megawatt load by stetistical classifications. See General lnstruction for
the definition of each statistical classification.
NAME OF SYSTEM:
Line
No.Month
(a)
fUonthly Peak
MW - Total
(b)
Day of
Monthly
Peak
(c)
Hour of
Monthly
Peak
(d)
Firm Network
Service lor Self
(e)
Firm Network
Seruice for
Others
(0
Long-Term Firm
Point-to-point
Reservations
(s)
Other Long-
Term Firm
Service
(h)
Short-Term Firm
Pointto-point
R€seNation
(i)
Other
Seryice
U)
1 January 3,324 2 90c 1,542 224 o7e 585
2 February 3,104 25 200c 1,292 191 973 648
3 March 3,171 7 80c 1,445 212 o72 542
4 Total for Quader I 4,279 627 2,919 1,775
5 April 2,91t ZJ 80c 993 211 973 738
b t\,tay 3,49r 8 1 70C 2,041 294 973 228
7 June 4,421 27 200c 2,793 372 o71 285
I Total lor Ouarler 2 5,787 883 2,919 1,251
I July 4,59r 2a 1 80C 3,021 35S 973 241
10 August 4,641 C 170C 3,241 361 973 67
't1 Septemb€r 3,85r t 2000 2,420 ,01 973 168
't2 Total lor Quader 3 8,682 1,013 2,9'19 476
13 0ctober 2,99:1t 800 1,389 243 97:388
14 November 3,13r 1:800 1,397 209 973 556
15 December 3,36{1:800 1,334 24C 973 821
16 Total for Quarter 4 4120 692 2,91S 1,765
17 Total Yoar to
Dateffeil 22,868 3,215 '11,676 5,267
FERC FORM NO. 1/3.Q (NEW.07-04)Page 400
MONTHLY TRAN
Name of Respondent
ldaho Power Company
This(1)
(2)
ls:
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
04116t2419
ELECTRIC ENERGY ACCOUNT
Report below the information called for concerning fte disposition of electic energy generated, purchased, exchanged and wheeled during the year,
Line
No.MegaWatt Hours
(b)
Line
No.
Item
(a)
Item
(a)
MegaWatt Hours
(b)
1 SOURCES OF ENERGY 2'l DISPOSITION OF ENERGY
2 Generation (Excluding Station Use):22 Sales to Ultimate Consumers (lncluding
lnterdepartmental Sales)
14,586,522
3 Steam 3,274,144
4 Nuclear 23 Requirements Sales for Resale (See
instruction 4, page 311.)5 Hydro-Conventional 8,681,81 1
6 Hydro-Pumped Storage 24 Non-Requirements Sales for Resale (See
instruction 4, page 311.)
2,863,637
7 Other 1,407,862
25 Energy Furnished Without ChargeILess Energy for Pumping
26 Energy Used by the Company (Electric
Dept Only, Excluding Station Use)
I Net Generation (Enter Total of lines 3
through 8)
13,363,81i
27 Total Energy Losses 1,267,436't0 Purchases s,389,494
11 Power Exchanges:28 TOTAL (Enter Total of Lines 22 Through
27) (MUST EQUAL LrNE 20)
18,7'17,595
12 106,21CReceived
13 Delivered 145,1 3S
14 Net Exchanges (Line 12 minus line 13)-38,92S
15 Transmission For Other (Wheeling)
16 Received 7,243,16C
17 7,239,947Delivered
s,21318Net Transmission fior Other (Line 16 minus
line'17)
19 Transmission By Others Losses
20 18,717,595TOTAL (Enter Total of lines 9, 10, 14, 18
and 19)
FERC FORM NO.'t (ED.12.90)Page 401a
I
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t16t2019
Year/Period of Report
2018tQ4
FOOTNOTE DATA
Schedule Page:401 Line No.:18 Column: b
Page 329 Column I differs from page 4C1 byand BPA Energy imbalance schedules on page
328-330 are for account 456 wheeling on1y,
account 447 transmission.
3,213 MWH, reported401. The numbers thathe numbers on page
for Lucky ieak varj-ation
t are shown on pages
40i have to be adjusted for
FERC FORM NO. 1 (ED. 12-871 Page 450.1
Name of Respondent
ldaho Power Company
This
(1)
(2)
ls:Date of Report(Mo, Da, Yr)
YearlPeriod of Report
End of 201B|A4An Original
A Resubmission 0411612019
MONTHLY PEAKS AND OUTPUT
1. Report the monthly peak load and energy output. lf the respondent has two or more power which are not physically integrated, furnish the required
information for each non- integrated system.
2. Report in column (b) by month the system's output in Megawatt hours for each month.
3. Report in column (c) by month the non-requirements sales for resale. lndude 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
MONTHLY PEAKLine
No.Month
(a)
Total Monthly Energy
(b)
Monthly Non-Requirments
Sales for Resale &
Associated Losses
(c)
Megawatts (See lnstr. 4)
(d)
Day of Month
(e)
Hour
(0
29 January 1,67012e 403,276 2,145 4 0900
3C February 1,399,249 268,337 2,226 20 0800
31 March 412,8571,551,731 1,989 b 0800
JI April 1,600,07s 506,996 1,979 27 1 800
33 May 1,549,946 256,468 2,367 29 2000
34 June 1,667,528 130,332 3,1 38 25 I 900
35 July 77,882 3,3921,942,09S I 1 900
36 August I ,737,707 69,934 3,381 10 1 800
37 September 1,417,711 171,251 2,744 6 'r 800
38 October 1,239,754 152,788 1,806 15 0900
39 November 206,771 2.025 131,381,78S 0800
40 December 1,559,876 206,745 2,267 6 0800
41 TOTAL 18,717,595 2,863,637
FERC FORM NO. 1 (ED.12-90)Page 401b
Name of Respondent
ldaho Power Company
This Report ls:(1) fiAn Original
(2) l--l A Resubmission
Dale of Report(Mo, Da, Yr)
04t16t2019
Year/Period of Report
End of 2018/Q4
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, 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 burned (Line 41) must be mnsistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20. 8. lf more lhan one
fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
Line
No.
Item
(a)
Plant
Name: Jirn Bridger
(b)
Plant
Name: Boardman
(c)
I Kind of Plant (lntemal Comb, Gas Turb, Nuclear Steam Steam
2 Type of Constr (Conventional, Outdoor, Boiler, etc)Semi-Outdoor Boiler Conventional
3 Year Originally Constructed
4 Year Last Unit was lnstalled 1979 1 980
5 Total lnstalled Cap (Max Gen Name Plate Ratings-MW)
6 Net Peak Demand on Plant - MW (60 minutes)702 60
7 Plant Hours Connected to Load 8764 3208
8 Net Continuous Plant Capability (Megawatts)0 0
I When Not Limited by Condenser Water I
10 When Limited by Condenser Water 0 0
11 Average Number of Employees U 0
12 Net Generation, Exclusive of Plant Use - KWh 251 1 81 4000 I 51 51 7000
13 Cost of Plant: Land and Land Rights 509671 I 0661 0
14 Structures and lmprovements 71 591 785 12626048
15 Equipment Costs 637997616 640574't8
16 Asset Retirement Costs 9164040 s046008
17 Total Cost 719263112 81 836084
18 Cost per KW of lnstalled Capacity (line 17l5) lncluding 933.5018 1274.7054
19 Production Expenses: Oper, Supv, & Engr 174038 455021
20 Fuel 87601038 4049522
21 Coolants and Water (Nuclear Plants Only)0 0
22 Steam Expenses 5691s35 707167
23 Steam From Other Sources n 0
24 Steam fransferred (Cr)0 0
25 Electric Expenses 0 0
26 Misc Steam (or Nuclear) Power Expenses 6791 168 665880
27 Rents 250861 0
28 Allowances 0 0
29 Maintenance Supervision and Engineering 100602 1 1 2653
30 Maintenance of Structures 0 50779
31 Maintenance of Boiler (or reacto| Plant 7148511 1 15654
32 Maintenance of Electric Plant 2613274 1 329883
33 Maintenance of Misc Steam (or Nuclear) Plant 6963587 66027
34 Total Production Expenses 117334614 7552586
35 Expenses per Net KWh 0.0467 0.0498
36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)Coal oil Coal oit
37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)Tons Barrel Ions Barrels
38 Quantity (Units) of Fuel Bumed 1423953 6257 0 89853 796 0
39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)9276 1 40000 0 8650 1 38800 0
40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 57.743 1 05.1 97 0.000 42.009 99.690 0.000
41 Average Cost of Fuel per Unit Burned 61.035 76.113 0.000 44.O57 90.385 0.000
42 Average Cost of Fuel Burned per Million BTU 3.290 12.944 0.000 2.548 15.501 0.000
43 Average Cost of Fuel Bumed per KWh Net Gen 0.035 0.000 0.000 0.027 0.000 0.000
44 Average BTU per KWh Net Generation 10531 .000 0.000 0.000 1 0284.000 0.000 0.000
FERC FORM NO.1 (REv.12-03)
197t 1980
770.5(
(0
Page 402
Name of Respondent
ldaho Power Company
Thi
(1)
(2)
is Report ls:
fiAn Original
f-lA Resubmission
Date of Report(Mo, Da, Yr)
04116t2019
Year/Period of Report
End of 20181Q4
STEAIU-ELECTRIC GE NERATI NG PLANT STATI STI CS (Large Plants) (Cont i n ued)
9. ltems under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For lC and GT plants, report Operating Expenses, Account Nos.
547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." lndicate plants
designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear
steam, hydro, internal combustion or gas{urbine equipment, report each as a separate planl. However, if a gasturbine unit functions in a combined
cycleoperationwithaconventional steamunit,includethegas-turbinewiththesteamplant. 12. lfanuclearpowergeneratingplant,brieflyexplainby
footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units
used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the
report period and other physical and operating characteristics of plant.
Plant
Name: Valmy
(d)
Plant
Name: Danskrn
(e)
Plant
Name: Bennetl Mountain
(f)
Line
No.
Steam Gas Turbine Gas Turbine 1
Outdoor Conventional Conventional 2
2001 2005 3
1 98s 2008 2005 4
270.90 172.80 5
260 243 178 b
3765 810 1121 7
0 261 't64 B
0 0 I
0 0 10
0 6 5 11
61 0813000 127648000 1 491 58000 12
1106140 402745 0 13
71851394 6054979 1 790867 14
330860448 11115678s 53S84084 15
-s3303 0 0 '16
403764679 1 1 7614509 55774951 17
1424.2140 434.1621 322.7717 18
1 51 705 4419 19
23873411 1 9931 09 2928044 20
0 0 0 21
3514032 0 0 22
0 0 0 23
0 0 0 24
1868433 586841 423794 25
1677245 279674 I 76068 26
0 0 0 27
0 0 0 28
U 0 0 29
298643 82374 84059 30
3583035 5854 4690 31
601 869 1938409 1 6691 2 32
1 1308S 0 0 33
36105640 5037966 3787986 34
0.0591 0.0395 0.0254 35
Coal oil Gas Gas 36
Tons Barrels MCF MCF 37
325634 8080 0 1322215 0 0 1 656255 0 0 3B
9330 138778 0 't027 n 1027 0 U 39
43.968 107.119 0.000 1.507 0.000 0.000 1.768 0.000 0.000 40
69.421 104.649 0.000 1.507 0.000 0.000 1 768 0.000 0.000 41
3.804 17.954 0.000 3.3s0 0.000 0.000 3.580 0.000 0.000 42
0.039 0.000 0.000 0.016 0.000 0.000 0.020 0.000 0.000 43
9806.000 0.000 0.000 1 0638.000 0.000 0.000 1 1404.000 0.000 0.000 44
FERC FORM NO. 1 (REV. 12-03)Page 403
198'l
283.50
0
0
575883
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5!An Orisinal(2) n A Resubmission
Date of Report(Mo. Da, Yr)
0411612019
Year/Period of Report
End of 20181Q4
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. lndicate by a footnote any plant leased or operated
as a joint facility. 4. lf net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. lf any employees attend
more than one plant, report on line 1 1 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 41) must be crnsistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20. E. 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'. Langley Gulch
(b)
Plant
Name:
(c)
1 Kind of Plant (lnternal Comb, Gas Turb, Nuclear Gas Turbine
2 Type of Constr (Conventional, Outdoor, Boiler, etc)Conventional
3 Year Originally Constructed 20't2
4 Year Last Unit was lnstalled 2012
5 Total lnstalled Cap (Max Gon Name Plate Ratings-MW)318.45 0.00
6 Net Peak Demand on Plant - MW (60 minutes)298 0
7 Plant Hours Connected to Load 4287 0
8 Net Continuous Plant Capability (Megawatts)300 0
I When Not Limited by Condenser Water 0 0
10 When Limited by Condenser Water 0 0
11 Average Number of Employees 24 0
12 Net Generation, Exclusive of Plant Use - KWh 1 1 31 020000 0
13 Cost of Plant: Land and Land Rights 2287261 0
14 Skuctures and lmprovements 1 35480987 0
15 Equipment Costs 237068055 0
16 Asset Retirement Costs 0 0
17 Total Cost 374836303 0
1B Cost per KW of lnstalled Capacity (line 17i5) lncluding 1177.0649 0
19 Production Expenses: Oper, Supv, & Engr 489767 0
20 Fuel 12744946 0
21 Coolants and Water (Nuclear Plants Only)0 0
22 Steam Expenses 0 0
23 Steam From Other Sources 0 0
24 Steam Transferred (Cr)0 0
25 Electric Expenses 3502791 0
26 Misc Steam (or Nuclear) Power Expenses 824953 0
27 Rents 0 0
28 Allowances 0 0
29 Maintenance Supervision and Engineering 0 0
30 Maintenance of Structures 48859 0
31 Maintenance of Boiler (or reactor) Plant 55349 0
32 Maintenance of Electric Plant 535684 0
33 Maintenance of Misc Steam (or Nuclear) Plant 0 0
34 Total Production Expenses 18202349 0
35 Expenses per Net KWh 0.0161 0.0000
36 Fuel: Kind (Coal, Gas, Oil, er Nuclear)Gas
37 Unit (Coal{ons/Oil-barrel/Gas-mcf/Nuclear-indicate)MCF
3B Quantity (Units) of Fuel Burned 9423468 0 0 U 0 0
39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)1027 0 0 0 0
40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 1.352 0.000 0.000 0.000 0.000 0.000
41 Average Cost of Fuel per Unit Bumed 1.352 0.000 0.000 0.000 0.000 0.000
42 Average Cost of Fuel Burned per Million BTU 2.980 0.000 0.000 0.000 0.000 0.000
43 Average Cost of Fuel Burned per KWh Net Gen 0.011 0.000 0.000 0.000 0.000 0.000
44 Average BTU per KWh Net Generation 8557.000 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)
04116t2019
Year/Period of Report
20181Q4
FOOTNOTE DATA
Schedule Page:402 Line No.:3 Column: bThis foctnote applies io lrres 3 and 4. rrre Jin Eriaqea FowerPIan: consists of four equal units constructed jointiy by Idaho
Power Company and Pacific Power and Light Company, wli-h Idairo
owning 1,/3 and Paclf iCorc ownrng 2,/3. Unit #1 was placed 1nconrnercial operal:icn November 30 , 191 4, Un:-t- f 2 December 1, 191 5 tUnj-t #3 September 1, 791 6, and Unit #4 November 29, 19'79.
Schedule Page: tl02 Line No.: 3 Column: cThis footnote applies to lines 3 and 4. The Boardman pJ-ant
consists of one uni-t constructeci jointly by Portland General
Electric Company, fdaho Power Company, and Paciflc NorthwestGenerating Company, with ldaho Power Company owning 10%. Thre
unit was placed in commercial operatj-on August 3, 1980.
Schedule Page: 403 Line No.: 3 Column: dThis footnote applies to fines 3 and 4. The Valmy plant consistsof two units constructed jorntly by Sierra Paciflc Power Company
and Idaho Power Company, wif-h Sierra owning Ll2 and Idaho owningL/2. Unit #1 was plaeed in commercial operation December 11, 1981and Unit *2 May 2L, 1985.
Sche$tl9 Page: 402 Llne- No; 5 Column: bThis footnote applies to line 5 and lines 12 through,13.
Inf o rnatlon re f Iects idaho Power Companr7' s share as expla.i-nedin note for -Line 3 paEe 402 column B.
Seheduie Page:402 Line No.:5 Column: c
Thi s ioorno:e appl j es to .I .rne 5 and - ir,es 12 through -l 3 .
fnfo::nation reflects ldaho Power Company's share as explainedin note on line 3 paqe 402 column C
Schedule Page:403 Line No.: 5 Column: dThis footnote applies to line 5 and lines 1"2 throutTh 43.
Informatior: reflects ldaho Power Company's share as explainedin note for J-ine 3 page 403 column D.
Schedule Page:402 Line No.:9 Column: b
This footnote applies to lines 9, 10, and 11. PacifiCorp
as operator of the plant will repcrt this
infornation.
Schedule Page:402 Line No;9 Column: cThis footnote applies to lines 9, 10, and 11. Portland General-Electric Company, as operator will report thi-s information.
Schedule Page: tl03 Line No.:9 Column: dThis footnote applies to lines 9, 1C, and 11. Sierra Pacrfi-c
Power, as operator of the pIant, will report this information.
FERC FORM NO. 1 (ED. 12.871 Page 450.1
Name of Respondent
ldaho Power Company
This(1)
(2)
Reoort ls:
5.1An Orisinat
nA Resubmission
Date of Report(Mo. Da, Yr)
04t16t2019
Year/Period of Report
End of 2O18lQ4
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Large plants are hydro plants of 10.000 Kw or more of installed capacity (name plate ratings)
2. lf any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, inclicate such facts in
a footnote. If 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 11 the approximate average number of employees assignable to each
plant.
Line
No.
Item
(a)
FERC Licensed Project No. 2736
Plant Name: American Falls
(b)
FERC Licensed Project No. 1975
Plant Name: Bliss
(c)
1 Kind of Plant (Run-of-River or Storage)Run-of-River Run-of-River
2 Plant Construction type (Conventional or Outdoor)Outdoor Outdoor
3 Year Originally Constructed 1 978 1 949
4 Year Last Unit was lnstalled 1 978 1 950
5 Total installed cap (Gen name plate Rating in MW)92.30 75.00
6 Net Peak Demand on Plant-Megawatts (60 minutes)107 E'
7 Plant Hours Connect to Load 6,972 8,613
8 Net Plant Capability (in megawatts)
I (a) Under Most Favorable Oper Conditions 110 76
10 (b) Under ttre Most Adverse Oper Conditions 0 1
11 Average Number of Employees 4 4
12 Net Generation, Exclusive of Plant Use - Kwh 489,268,000 353,493,000
13 Cost of Plant
14 Land and Land Rights 875,319 768,366
15 Structures and lmprovements 11,970,406 1,757,779
16 Reservoirs, Dams, and Watenrays 4,293,075 9,087,082
17 Equipment Costs 33.375,913 2',t,215,167
18 Roads, Railroads, and Bridges 839,276 486,477
19 Asset Retirement Costs 0 U
20 TOTAL cost (Total of 14 thru 19)51,353,989 33,318,871
21 Cost per KW of lnstalled Capacity (line 20 / 5)556.38't2 444.2516
22 Production Expenses
23 Operation Supervision and Engineering 224,759 760,767
24 Water for Power 1 ,841,919 810,710
25 Hydraulic Expenses 182,',t32 918,291
26 Electric Expenses 60,215 65,676
27 Misc Hydraulic Power Generation Expenses 347,490 479,288
28 Rents 187 4,797
29 Maintenance Supervision and Engineering 6,016 4,482
30 Maintenance of Structures 108,471 34,773
31 Maintenance of Reservoirs, Dams, and Waterways 6,594 11,079
32 Maintenance of Electric Plant 185,333 80,324
33 Maintenance of Misc Hydraulic Plant 100,014 172,129
34 Total Production Expenses (total 23 thru 33)3,063,130 3,342,316
35 Expenses per net KWh 0.0063 0.0095
FERC FORM NO. ' (REV.12-03)Page 406
Name of Respondent
ldaho Power Company
This
(1)
(2)
Reoort ls:
51nn Original
nA Resubmission
Date of Reoort
(Mo, Da, Yi)
04116t2019
Year/Period of Report
End of 2O18lQ4
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC Licensed Project No. 1971
Plant Name: Brownlee
(d)
FERC Licensed Project No. 2848
Plant Name: Cascade
(e)
FERC Licensed Project No. 1971
Plant Name: Oxbow
(f)
Line
No.
Storage Run-of-River Storage 1
Outdoor Outdoor Outdoor 2
1958 1 983 1961 3
1980 1 984 1 961 4
652.60 12.42 190.00 5
581 14 210 6
8,736 8,736 8,736 7
I
747 15 221 I
220 1 202 10
I 2 6 11
2,418,886,000 46,879,000 1,090,414,000 12
13
18,382,251 82,142 1,212,767 14
39,790,736 7,328,252 13,91't,719 15
67,636,458 3,145,630 31,ss0,233 16
114,036,450 't3,486,249 22,010,550 17
1,458,769 122,668 585,876 18
0 0 0 '19
241,304,664 24,164,941 69,271,145 20
369.7589 1,945.6474 364.5850 21
22
610,156 179,709 453,620 23
553,819 226,366 397,342 24
1 ,1 97,804 4U,107 876,365 25
385,880 119,254 263,515 26
644,079 262,533 541,250 27
1 18,503 73 19,430 28
27,457 2,051 7,089 29
43,903 8,297 85,074 30
38,484 4 19,895 31
1,236,198 25,828 't49,786 32
597,192 108,954 254,051 33
5,453,475 1,417,176 3,067,417 34
0.0023 0.0302 0.0028 35
FERC FORM NO.1 (REV.12-03)Page 407
Name of Respondent
ldaho Power Company
This ReDort ls:(1) 5]nn Originat(2) f-l A Resubmission
Date of Reoort(Mo, Da, Yi)
o4t16t2019
Year/Period of Report
End of 20181Q4
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Large plants are hydro plants of '10,000 Kw or more of installed capacity (name plate ratings)
2. lf any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in
a footrnote. lf licensed project, give project number.
3. lf net peak demand for 60 minutes is not available, give that which is available specifying period.
4. lf a group of employees attends more than one generating piant, report on line 11 the approximate average number of employees assignable to each
plant.
Line
No.
Item
(a)
FERC Licensed Project No. 1971
Plant Name: Hells Canyon
(b)
FERC Licensed Project No. 2726
Plant Name: Malad
(c)
1 Kind of Plant (Run-of-River or Storage)Storage Run-of-River
2 Plant Construction type (Conventional or Outdoor)Outdoor Outdoor
3 Year Originally Constructed 't967 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 PlanFMegawatts (60 minutes)435 22
7 Plant Hours Connect to Load 8,733 8,731
I Net Plant Capability (in megawatts)
I (a) Under Most Favorable Oper Conditions 445 25
10 (b) Under he Most Adverse Oper CondiUons 137 21
11 Average Number of Employees 5 1
12 Net Generation, Exclusive of Plant Use - Kwh 2,194,877,O00 136,032,000
13 Cost of Plant
14 Land and Land Rights '1,880,38't 205,376
15 Struc{ures and I mprovements 2.992,730 3,954,760
16 Reservoirs, Dams, and WateMays 53,033,657 6,952,853
17 Equipment Costs 22,562,4'tO 15,703,831
'18 Roads, Railroads, and Bridges 922,781 1,507,442
19 Asset Retirement Costs 0 0
20 TOTAL cost (Total of 14 thru 19)81,39't,959 28,324,262
21 Cost per KW of lnstalled Capacity (line 20 / 5)207.8977 1.301.0685
22 Production Expenses
23 Operation Supervision and Engin€ering 382,960 161,624
24 Water for Power 386,745 809,253
25 Hydraulic Expenses 839,422 232,895
26 Electric Expenses 224,884 39,427
27 Misc Hydraulic Power Generation Expenses 598,388 155,367
28 Rents 32,319 0
29 Maintenance Supervision and Engineering 8,884 2,647
30 Maintenance of Structures 4,186 4,469
31 Maintenance of Reservoirs, Dams, and Watemays 38,768 37,229
32 Maintenance of Electric Plant 136,214 47,158
33 Maintenance of Misc Hydraulic Plant 440,678 87,343
34 ToEl Production Expenses (total 23 thru 33)3,093,448 1,577,412
35 Expenses per net KWh 0.0014 0.0116
FERC FORM NO.1 (REV.12-03)Page 406.1
Name of Respondent
ldaho Power Company
This
(1)
(2t
Reoort ls:
5]an Orisinal
l-lA Resubmission
Date of Report(Mo, Da, Yr)
04t16t2019
Year/Period ol Report
End of 20181Q4
HYOROELECTRIC GENERATING PLANT STATI STICS (Large Plants) (Continued)
5. The items under Cost of Plant ropresent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6. Report as a separate plant any plant equipped with mmbinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC Licensed Project No. 2055
PlantName: CJStrike
(d)
FERC Licensed Project No. 503
Plant Name: Swan Falls
(e)
FERC Licensed Project No.
Plant Name: Twin Falls
(f)
't8 Line
No.
Run-of-River Run-of-River Run-of-River 1
Outdoor Conventional Conventional 2
1952 "t910 1 935 2
1952 1 994 1 995 4
82.80 27.17 52.90 E
92 23 51 6
8,736 8,435 7,852 7
8
9'l 24 53 9
84 14 50 10
5 4 '11
568,652,000 123,727,000 262,039,000 12
't3
5,725,987 292,113 255,499 14
9,944,637 27,522,981 11,184,280 15
11,419124 15,989,465 8,968,780 16
14,557,460 32,113,032 22,346,634 't7
1,602,868 835,946 1 ,917,603 't8
0 0 0 19
43,250,080 76,753,537 44,672,796 20
522.3440 2,824.9370 844.4763 21
22
784,431 424,066 431,353 23
870,409 485,862 302,89s 24
1,169,627 598,892 214,798 25
84,862 76,877 71,378 26
649,984 427,720 237.963 27
51,684 8,028 3,572 28
6,377 7,472 2,860 29
1 't 5,940 54,669 50,087 30
48,851 26,264 1,367 31
149,713 284,662 89,630 32
109,902 131,714 49,267 33
4,041,780 2,526.226 1,455,170 34
0.0071 0.0204 0.0056 35
FERC FORM NO. I (REV.12-03)Page 407.1
Name of Respondent
ldaho Power Company
This Reoort ls:(1) fiAn Original(2) nA Resubmission
Date of Report(Mo, Da, Yr)
0411612019
YearlPeriod of Report
End of 2O't8lQ4
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1 . Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. lf any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in
a footnote. lf licensed project, give project number.
3. lf net peak demand for 60 minutes is not available, give that which is available specifoing 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 (Run-of-River or Storage)Run-of-River Run-of-River
2 Plant Construction type (Conventional or Outdoor)Outdoor Conventional
a Year Originally Constructed 1937 1907
4 Year Last Unit was lnstalled 1947 1921
5 Total installed cap (Gen name plate Rating in MW)34.50 11.50
6 Net Peak Demand on Plant-Megawatts (60 minutes)35 13
7 Plant Hours Connect to Load 8,736 7,1 99
I Net Plant Capability (in megawatts)
I (a) Under Most Favorable Oper Conditions 39 14
10 (b) Undor the Most Adverse Oper Conditions 32 11
11 Average Number of Employees 1 a
12 Net Generation, Exclusive of Plant Use - Kwh 245,042,000 82,751,000
13 Cost of Plant
14 Land and Land Rights 202,399 313,328
15 Structures and I mprovements 2,805,131 't,563,244
16 Reservoirs, Dams, and Waterways 7,290,730 9,868,914
17 Equipment Costs 9,020,362 4,843,239
18 Roads, Railroads, and Bridges 29,359 115,108
19 Asset Retirement Costs 0 0
20 TOTAL cost (Total of 14 thru 19)19,347,981 16,703,833
21 Cost per KW of lnstalled Capacity (line 20 / 5)560.81 10 1,452.5072
22 Production Expenses
23 Operation Supervision and Engineering 156,937 291 ,313
24 Water for Power 196,614 305,661
25 Hydraulic Expenses 257,792 342,250
zo Electric Expenses 117,643 41,112
27 Misc Hydraulic Power Generation Expenses 181,359 290,334
28 Rents 0 203
29 Maintenance Supervision and Engineering 4,534 4,092
30 Maintenance of Structures 59,964 34,827
Maintenance of Reservoirs, Dams, and WateMays 22,230 3,809
JZ Maintenance of Electric Plant 127,891 172,399
33 Maintenance of Misc Hydraulic Plant 91,677 61,315
34 Total Production Expenses (total 23 thru 33)1,216,641 1,547,31s
35 Expenses per net KWh 0.0050 0.0187
FERC FORM NO.1 (REv.12-03)Page 406.2
3'1
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5]An orisinat
(2)trA Resubmission
Date of Report
(Mo, Da, Yr)
04116t2019
Year/Period of Report
End of 20181Q4
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accounls or combinations ofaccounts prescribed by the Uniform System ofAccounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC Licensed Project No. 1971
Plant Name: Common Facilities
(d)
FERC Licensed Project No. 2061
Plant Name: Lower Salmon
(e)
FERC Licensed Project No. 28gg
Plant Name: Milner
(0
Line
No.
Run-of-River Run-of-River 1
Outdoor Conventional 2
1949 1992 )
'1949 1992 4
0.00 60.00 59.45 5
U 62 60 o
0 8,729 7,104 7
I
0 64 61 I
0 60 1 10
0 6 2 11
0 327.431 ,000 294,476,000 12
13
I 14,368 424,428 138,'t 00 14
50,401,118 3.s61,030 10,663,927 15
13,556,785 7,754,799 17,767,AO2 16
2,459,974 17,750,696 29,294,641 't7
142,581 88,693 501,877 18
0 0 0 19
66,714,826 29,579,646 58,365,547 20
0.0000 492.9941 981.7586 21
22
0 442,923 262,033 23
0 390,644 1,471,384 24
7,337,458 468,480 176,309 25
0 182,453 61,225 26
128 369,552 311,777 27
0 4,110 3,798 28
U 4,533 3,444 29
0 81,289 't8,683 30
0 13,884 51,433
0 123,444 80,199 32
231,546 83,459 78,910 33
7,569,1 32 2,164,367 2,519,'t95 34
0.0000 0.0066 0.0086 35
?age 407.2
3'r
FERC FORM NO. ,l (REV.12-03)
r\ame oI ile5ponqenr
ldaho Power Company
IIIli
(1)
(2)
t ts,uate or Kepon
(Mo, Da, Yr)
YearP€noo ol Kepon
End of 20181Q4An Original
A Resubmission 04t16t2019
1. Small generating plants are steam plants of, less than 25,000 Kw; internal combustion and gas turbine-plants, conventional hydro plants and pumped
storage plants of less than 10,000 Kw inslalled 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 loint facility, and give a concise statement of the facts in a footnote. lf licensed project,
give project number in footnote.
Line
No.
Year
Orio.
Con-st.
(b)
Cost of Plant
(0
Name of Plant
(a)
lnstalled CaoacitvName Plate hatiri:
(ln MW)
(c)
Net PeakDemand
MW(60,4in.)(e)
Net Generation
ExcludinoPlant LJsE
1 Hydro:
2 Clear Lakes 1 S37 2.50 2.9 17,281 3,565,864
3 Thousand Springs 1912 6.80 7.4 30,563 12,013,559
4
5
6 lntemal Combustion:
7 Salmon Diesel 1 967 5.00 4.0 36 909,259
8
I
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO. 1 (REV. 12-03)Page 410
ldaho PowerCompany (1)
(2)
An Original
A Resubmission
Date of Report(Mo. Da, Yr)
0411612019
YearlPeriod of Report
End of 2A1B|Q4
3. List plants appropriately under subheadings for steam, hydro, nuclear, internal combustion and gas turbine plants. For nuclear, see instruction 11,
Page 403. 4. lf net peak demand for 60 minutes is not available, give the which is available, specifying period. 5. lf any plant is equipped with
combinations of steam, hydro internal combustion or gas turbine equipment, report each as a separate plant. However, if the exhaust heat from the gas
turbine is utilized in a steam turbine regenerative feed water cycle, 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)
Production Expenses
Kind of Fuel
(k)
Fuel Costs (in cents
(per Million Btu)
(t)
Line
No.FUEI
(i)
Maintenance
(i)
1
1,426,346 168,784 64,735 2
1,766,700 252,307 158,640 3
4
5
6
181 ,852 Diesel 7
I
9
10
11
12
13
14
15
16
't7
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO.1 (REV.12-03)Page 411
34
Name of Respondent
ldaho Power Company
This Reoort ls:(1) p{An orisinat
Date of Reporl(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
(2)A Resubmission 0411612019
TRANSMISSION LINE STATISTICS
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121 , Nonutility Property.
5. lndicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction lf a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the
remainder of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the crst 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.
I]ESIGNAI ION VOLTAGE (KV)(lndicate wherdblher than
60 cvcle. 3 ohase)
LENGTH (Pole miles)(ln the Dase.ofunderoround linesreport Eircuit miles)
Line
No.
From
(a)
To
(b)
Operating
(c)
Designed
(d)
Type of
Supporting
Structure
(e)
of LineDesi96ated
(,n strucluresof AnotherLrne(s)(h)
Number
of
Circuits
1 Borah Mldpolnt 345.0(500.00 S Tower 62,35 1
2 Boardman Statt s00.0(500.00 S Tower 1.79 1
J Summer lake {emlngray 500.0t s00.00 S Tower 008 1
4 Hemingway Mldpolnt 500.0(500.00 S Tower 0,15
5 Summer Lake H€mlngway 500.0(S Tower 53.08 1500.00
Mldpolnt6Hemingway 500.0(500.00 S Tower 47.76 1
7
8 Jim Bridger Goahen 345.0(345.00 S Tower 66.13 I
I State Line Midpoint 34s 0t S Tower 76.06 2345.00
10 Kinport Borah 19.81 1345.0(345.00 S Tower
Pogulus11Jim Bridger 345.0(345.00 S Tower 60.91 1
12 Populus Kinport 345.0(345,00 S Tower 742 1
13 Jim Bridger Populus 345.0(345,00 S Tower 61.08 1
14 Populus Eorah 345.0(345.00 S Tower 905 1
Kinport15Goshen 345.0(345.00 S Tower 7.48 1
16 Midpoint Borah #'t 345.0(345,00 H Wood 51.07 1
17 Midpoint Borah #2 34s.0(345.00 H Wood 49 98 2
18 Adelaide Tap Adetalde 34s.0(345.00 H Wood 1a1 I
19
20 QuarE LaGrande 230.0(230.00 H Wood 45 97 1
21 Midpoint Hunt 230.0(230.00 S Tower 0.70 2
22 Brady Antelope 230.0(230.00 H Wood 56.38 1
l3 Brady Treasureton 230.0t 230.00 H Wood 0,08 1
24 Brady#1 &#2 Kinport 230.0t 230.00 S Tower 17.94 2
25 Brownlee Ontario 230.0t 230.00 S Tower 72.67 1
26 Mora Bowmont '138.0(S P Wood 9.99 1230.00
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 33.49 1Caldwell230.0(230.00 H Wood
31 Boise Bench Cloverdale 230 0c 230.00 S Tower 'r5,91 2
32 Boardman Oalroed Sub 230,0c 230.00 H Wood t.o/1
33 Brownlee 714 Oxbow 230.0c 230.00 SP Steel 11.04 2
34 Caldwell Ontario 230,0c 230.00 H Wood 30.06 'I
2E Caldwell Ontario 230.0c 230.00 S Tower 3.14 1
36 TOTAL 4,754.64 11.02 205
FERC FORM NO.1 (ED.12-87)Page 422
ldaho Power Company 1)Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04t16t2019
Year/Period of Report
End of 2018/Q4
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. lf two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion lhereof for which the respondent is not the sole owner. lf such property is leased fom another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as per@nt ownership by respondent in lhe line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-ownerr or
other party is an associated company.
9. Designate any kansmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns U) to (l) on the book cost at end of year.
Size of
Conductor
and Material
(i)
COST OF LINE (lnclude in Column 0) Land,
Land rights, and clearing right-of-way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES
Line
No.
Land
(])
Construction and
Other Costs(k)
Total Cost
(t)
Operation
Expenses(m)
Maintenance
Expenses
(n)
Rents
(o)
Total
Expenses(p)
1272 ACSR 256,381 15,977,941 16,234324 1
ZX17EO ACSR 446,70€446,708
,272 ACSR 3
I2Z2 ACSR 4
]X1272 ACSR 18,826,061 18,826,061 5
lx'1272 ACSR '17,078,061 '17,078,061 b
7
1272 ACSR 483,30S 5,330,79C 5,8 14,09S 8
795 ACSR 571,97S 11,226,882 1 1,798,86'l o
'1272 ACSR 344,22C 4,397,073 4,741,293 10
1272 ACSR 9,534,541 9,534,541 11
1272 ACSR 12
'1272 ACSR 9,257,404 9,257,404 aa
1272 ACSR 14
2X1272 ACSR 583,947 583,947 15
715,5 ACSR 283,141 '12,832,864 13,1 16,007 16
715.5 ACSR 64,8s1 15,978,637 16,043,488 17
715,5 ACSR 51,44i 224,249 275,697 1B
19
795 ACSR 62,21t 7,078,093 7,140,311 IU
i15,5 ACSR 9,14a 998,452 1,007,597 21
1272 ACSR 108,30 3,399,123 3,507,424 22
/95 ACSR 6,'186 o, Io0 23
715.5 ACSR 18,82(1,'144,918 1,163,747 24
2X954 ACSR 1,676,83t 20,s51,937 22,228,775 25
715.5 ACSR 413,79:2,377,905 2,79't,698 26
/15.5 ACSR 27
1590 ACSR 2,378,43t 8,77s,086 11,153,522 28
1272 ACSR 1]48,20i 7,740,608 9,488,810 ,o
/15.5 ACSR 30
1272 ACSR 3,062,812 6,582,985 9,645,797 31
295 AAC 89,08S 89,089 cz
}54 ACSR 34,174 16,026,470 16,060,644 JJ
2X954 ACSR 236,152 9,384,090 9,620,242 34
1272 ACSR
34,835,917 639,95s,720 674,791,637 7,787 ,36C 1,s44,297 2,710,673 12,042,33("36
FERC FORM NO.1 (ED.12-87)Page 423
TRANSI\4ISSION LI NE STATISTICS
35
Name of Respondent
ldaho Power Company
This
(1)
(2)
ReDort ls:
5]nn Orisinal
nA Resubmission
Date of(Mo, Da
Report
r, Yr)
04t16/2019
YearlPeriod of Report
End of 2O18lQ4
TRANSMISSION LINE STATISTICS
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each lransmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Iransmission 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 mnstruction 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 llnes. 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 mlumns (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). h 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 wherdbther than
60 cvcle. 3 ohase)
Type of
Supporting
Structure
(e)
LENGTH (Pole miles)(ln the tase.ofunderorounc, ltnesreport Eircrit miles)
Number
of
Circuits
(h)
From
(a)
To
(b)
Operating
(c)
Designed
(d)
UN DIofDesi
Lrn ttrucluresof AnolherLine
(s)
1 Bennett Mtn PP Rat0esnake TS 230,0c 230.00 SP Steel 4.43 1
2 Borah Hunt 230.0(230 00 H Steel 68.12 1
3 Danskin Hubbard 230.0(230,00 H Steel 36.2s 1
4 Danskin Hubbard 230 0c 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 Steel 12.94 1
I Langley Gulch Galloway Rd 138.0(230.00 SP Steel 14.19 1
I Galloway Rd Willis Tap 138.0(230.00 SP Steel 2.09 I
10 Walla Walla 230.0(230.00 H Wood 30.55 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 108.68 1
13 Brownlee QuarE Jct 230 0(230.00 S Tower 1.51 1
14 Brownlee QuarE Jct 230 0(230.00 H Wood 41.30 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 '10.3s 2
17 Boise Bench Midpoint #2 230 0(230.00 S Tower 3.49 1
18 Boise Bench Midpoint #2 230 0t 230 00 H Wood 102.17 1
19 Oxbow Pallette Jct 230 0(230.00 S Tower 2A11 2
20 Pallette Jct lmnaha 230,0(230.00 H Wood 24.43 2
21 Hells Canyon Paiette Jct 230,0(230.00 S Tower 9.05 2
22 Brownlee Boise Bench 230 0(230.00 S Tower 102.11 2
23 Boise Bench Midpoint #3 230 0(230.00 H Wood 106.29 1
24 Palette Jct Enterprise 230.0(230.00 H Wood 29.60 1
25 Borah Brady #2 230.0i 230.00 S Tower 0,42 1
26 Borah Brady #2 230.04 230.00 H Wood 3.5i 1
27 Borah Brady #1 230.0c 230.00 H Wood 3,84 1
28
29 Goshen Stata LIne 161.0[161.00 H Wood 40.8S 1
30 Don Goshen 161,0t 161.00 S Tower 2.31 7
31 Don Goshen 161,0C 161,00 H Wood 48.42
Antelope 161.0C 161.00 H Wood 5.67 I
33 Goshen Stat6 Lino 161.0C 161,00 H Wood 10 93 1
34 Goshen State Llnc 16'1.0c 161,00 H Wood 7,84 1
35
36 TOTAL 4,754.64 11.02 205
FERC FORM NO.'t (ED.12.87)Page 422.1
tclurenerated
I
Hunlcane
Goghan
Narne of Respondent
ldaho Power Company
This Reoort ls:(1) []An orisinal
(2)A Resubmission
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 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, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9. Designate any lransmission line leased to another mmpany 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)
COST OF LINE (lnclude in Column (j) Land
Land rights, and clearing rightof-way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES
Line
No
Land
(i)
Construction and
Other Costs(k)
Total Cost
(t)
Operation
Expenses(m)
Maintenance
Expenses
(n)
Rents
(o)
Total
Expenses(p)
1272 ACSR 81,701 1,666,354 1,748,055 1
1590 ACSR 624,911 22,467,321 23,092,238 2
1590 ACSR 15,210,561 15,210,561 J
1590 ACSR 4
1590 ACSR E
1590 ACSR 3,528,033 3,528,033 6
1s90 ACSR 1,854,996 9,277p84 11,132,976 7
1590 ACSR s48,166 9,067,609 10,015,775 8
1272 ACSR I
1272 ACSR 6 471,944 6,471,944 10
715.5 ACSR 385,287 14,623,370 15,008,657 11
715.5 ACSR 12
795 ACSR 53,06t 4,833,736 4,886,804 13
795 ACSR 14
VARIOUS 289,92i 9,'198,927 9,488,850 '15
1272 ACSR 14,81(1,296,859 1,311,669 16
215.5 ACSR 227,B1t 17,830,886 1 8,058,700 17
VARIOUS 18
1272 ACSR 87,46t 3,933,'180 4,020,648 19
1272 ACSR 171,081 2,081,470 2,252,551 20
1272 ACSR 44,68i 1,252,130 1,296,817 21
354 ACSR 184,80r 6,411,734 6,596,539 22
715.5 ACSR 247,84t 8,032,328 8,280,174 23
1272 ACSR 84,01t 1,927 ,018 2,011,032 24
1272 ACSR 3,06t 531,106 534,174 25
/'15.5 ACSR 16
1 272 ACSR 7,24t 421,273 428,521 al
28
250 COPPER 375,57t 2,879,058 3,254,634 29
715.5 ACSR 88,204 2,597,887 2,686,091 30
397.5 ACSR 31
397.5 ACSR 784,659 784,659 32
250 COPPER 1 16,873 1,322,937 1,439,810 33
250 COPPER 76,96€482,272 559,241 34
2E
34,835,917 639,955,720 674,791,637 7,187 364 1,s44,297 2,71A,671 12,042,33(36
Date of Report(Mo. Da, Yr)
Year/Period of Report
End of 20'l8lQ4
04t16t2015
FERC FORM NO. 1 (ED.12-87)Page 423.1
ldaho Power Company (1)
(2)
An Original
A Resubmission
(Da,
04t16t2019
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 mvered 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.
UESIGNAIIUN Type of
Supporting
Structure
(e)
LENGTH (Pole miles)(ln the tase-ofunderoround linesreport Eircuit miles)
Number
of
Circuits
(h)
From
(a)
To
(b)
Operating
(c)
Designed
(d)
UN DIolDesi,
un :iuuclur€sof AnotherLrne(s)
1 American Falls Power Plant Adelaide 138.0(138,00 H Wood 14.07 n
2 American Falls Power Plant Adelaide 138.0(138,00 S P Wood 0.12 2
J Minidoka Loop Adelaide 138.0(138.00 S Tower 1 .13 I
4 Nampa Caldwell 138 0(138.00 S P Wood 9,s9 2
E Upper Salmon Mountain Home Jct 138.0(138.00 H Wood 54 36 1
6 Upper Salmon criff 138.0('138.00 H Wood 30 8'1 1
7 Eastgate Russet 138.0(138.00 S P Wood 206 I
8 Brady Fremont 138,0(138,00 S Tower 1,01 2
o Brady Fremont 138.0(138.00 H Wood 24.38 2
10 Brady Fremont 138.0t 138,00 S P Wood 24.33 2
11 King Lower Malad 138.0t 138.00 H Wood 84.73 2
12 Emmett Jct Payette 138.0(138.00 H Wood 66.46 2
13 Mountain Home AFB Tap 138.0(138.00 H Wood 6.20 1
14 Ontario Quark 138,0(138 00 H Wood 73.20 1
15 King American Falls PP 138.0(138 00 S Tower 0,91 2
16 King American Falls PP 138.0C 138 00 H Wood 142.16 1
17 King American Falls PP 138,0(138,00 S P Wood 3.71 1
18 Duffin Clawson 138.0(138 00 H Wood 6.19 1
19 American Falls Brady Tie 138.0(138 00 H Wood 0.33 1
20 Upper Salmon A-B King 138.0(138.00 H Wood 5.66 1
21 Upper Salmon B Wells 138,0(138,00 H Wood 125.54 1
22 King Wood River 138.0(13800 H Wood 63.94 1
23 Toponis Pocket 130.0(138.00 S P Wood 9.8C 1
24 Boise Bench Grove 138.0(138.00 S P Wood 10.3i 2
25 QuarE John Day 138 0(138.00 H Wood 67.3C 1
26 Sinker Creek Tap 138.0(138.00 H Wood 2.79 1
27 Mora Cloverdale 138.0t 138.00 H Wood 2.s1 I
28 Mora Cloverdale 138,0(138 00 S P Wood 22.2t,1
29 Mora Cloverdale 138,0(138.00 S P Steel 0.9€2
30 Stoddard Jct Stoddard Sub 138.0(138.00 S P Steei 3.8C 1
31 Fossil Gulch Tap 138.0(138.00 H Wood '1.81 1
32 Wood River Midpoint 138.0t 138.00 H Wood s3.08 z
33 Wood River Midpoint 138.0C 1 38.00 S P Wood 16.69 2
34 Oxbow McCall 1 38.0(138.00 H Wood 37.1a 1
35 Oxbow McCall 1 38.0(138.00 S P Wood 2.32 1
36 TOTAL 4,754.64 11.02 205
End of 2018/Q4
FERC FORM NO.1 (ED. r2-87)Page 422.2
Name of Respondent
ldaho Power Company
This
(1)An
ls:
Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04t16t2019
Year/Period of Report
End of 2018/Q4
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line, Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. lf two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. lf such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining tre
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of corcwner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and ac@unts 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 mmpany.
1 0. Base the plant cost figures called for in columns (i) to (l) on the book cost at end of year.
COST OF LINE (lncluc,e in Column U) Land,
Land rights, and clearing right-of-way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES
Total Cost
(t)
Size of
Conductor
and Material
(i)
Land
(i)
Construction and
Other Costs(k)
Operation
Expenses(m)
Maintenance
Expenses
(n)
Rents
(o)
Total
Exo,e;ses !ine
No.
250 COPPER 26,50i 423,656 450,163 1
250 COPPER 2
/15.5 ACSR 21,321 249,232 270,559 3
295 AAC 1,731 ,58{4,845,1 10 6,576,699 4
5,119,371i95 ACSR 78,07t 5,041,293 5
/95 ACSR 43,s6[2,995,670 3,039,238 6
795 AAC 270,822 561,s61 832,384 7
/ARIOUS 564,93i 4,733,97!s,298,911 I
/ARIOUS 9
/ARIOUS 10
/ARIOUS 76,822 3,725,128 3,801,951 11
/ARIOUS 55,521 4,706,354 4,761,87a 12
397.5 ACSR 86,92!s,08€81,843 13
VARIOUS 34,42e 6,851 ,738 6,886,166 14
715.5 ACSR 216,91e 1 0,955,64C 11,172,559 15
715.5 ACSR to
715,5 ACSR U
4\0 4,191 467,90S 472J1C 18
954 ACSR 96,921 96,921 19
250 COPPER 7s6,6662,74 753,925 20
VARIOUS 28,49(5,062,29i 5,090,787 21
VARIOUS 1 86,1 9t 24,499,074 24,685,272 22
397.5 ACSR 23
VARIOUS 1,646,308 1,871,910225,601 24
397.5 ACSR 96,58i 2,699,802 2,796,384 25
VARIOUS 1 1,08:133,347 144,430 26
/15.5 ACSR 3,123,38(9,714,182 12,837,562 27
YARIOUS t6
/95AAC 29
1272 ACSR 30
250 COPPER 45(1 87,84B 188,298 31
]97.5 ACSR 349,71i 7 ,121,949 7,471,661 32
]97.5 ACSR 22
197,5 ACSR 2,886,748141,s34 2,745,214 34
397,5 ACSR 35
674,791,637 7]87 36434,835,917 639,955,720 1 ,544,297 2,710,673 12,042,33C 36
FERC FORM NO.1 (ED. 12-87)Page 423.2
TRANSMISSION LINE STATISTICS
Name of Respondent
Idaho Power Company (1)
(2)
An , Da,
A Resubmission o4t16t2019
Year/Period of Report
End of 2018/Q4
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 from this page any transmission lines for which plant costs are included in Account 121 , Nonutility Property.
5. lndicate whether the type of supporting struclure 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 footnole, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line
No.
DESIGNATION VOLTAGE (KV)(lndicate wherdbther than
60 cvcle. 3 ohase)
Type of
Supporting
Structure
(e)
LENGTH (Pole miles)(ln the taso.ofun0eroround lrnes
report Eircuit miles)
Number
of
Circuits
(h)
From
(a)
To
(b)
Operating
(c)
Designed
(d)
un slrucruresof AootherLrn€(s)
1 Lowell Jct Nampa 138.0t '138.00 S P Wood 7.49 2
Hunt Milner 138.0(138.00 S P Wood 19.42 1
3 Strike Bruneau Bridge 138.0(138.00 H Wood 13.49 1
4 American Falls Kramer Sub 138.0(138.00 S P Wood 18 46 ,
5 Pingree Haven 138.0C 138.00 S P Wood 11,72 1
6 Midpoint Twin Falls 138.0(138.00 S P Wood 25.20 2
7 Twin Falls Russett 138.0C 138.00 S P Wood 1.71 1
I Blackfoot Aiken 46.0C 138.00 S P Wood 622 2
I Peterson Tendoy 69.0C '138.00 H Wood 57 02 1
10 Eastgate Tap Eastgate 138.0(138.00 S P Wood 6.36 1
11 Kimberly Tap Kimberly 138.0C 138.00 S P Steel 1,84 2
12 Boise Bench Mora 138.0C 138.00 H Wood 13.11 2
13 Bowmont-Caldwell Simplot Sub 138.0(138.00 S P Wood 0,51 1
14 Gary Lane Eagle 138.0C 138.00 S P Wood 6,6s 1
15 Locust Grove Blackcat Sub 138.0C 138.00 S P Steel 925 2.98 1
16 Boise Bench Butler 138.0C 138,00 S P WoOd 0.'14 4.02 1
17 Eagle Strar 138.0C 138.00 S P Wood 6.75 1
18 Star Lansing 138.0C 138.00 S P Steel 5.50 1
19 Karcher Sub Zilog Tap 138.0C 138 00 S P Steel 349 1
20 Zilog Can Ada 138.0C 138.00 S P Steel 150 1
21 Cloverdale - 712 712 -Wye 138.0C 138.00 S P Steel 0,42 4.02 1
22 Victory Jct Victory 138.0C 138.00 S P Steel '1,89 1
23 Butler wye 130.0(138.00 S P Steel 2.94 1
24 Horseflat Starkey 138.0C 138.00 H Wood 33.97 1
25 Starkey Mccall 138.0C 138.00 S P Steel LtJ ,}
26 Starkey Mccall 138.0C 138.00 H Wood 3,8C 1
27 Starkey Mccall 138.0C 138.00 S P Steel 1,5C 1
28 Starkey Mccall 138.0C 138.00 S P Wood 17,61 1
29 Chestnut Happy Valley 138.0C 1 38.00 S P Steel 2.78 1
30 Garnet Ward 1 38.00
31 McCall Lake Fork 138.0C 138.00 S P Wood aoo 1
32 McCall Lake Fork 138.0C 138.00 S Steel 2.90
33 Caldwell Willis 138.00 138,00 S P Steel 1.30 1
34 Caldwell Willis 138.00 138.00 S P Steel '1.59 1
35 Caldwell Willis 138.0(138,00 S P WOOd 0.87 I
36 TOTAL 4,754.64 11.02 20s
FERC FORM NO.1 (ED.12.87)Page 422.3
ofIDesig nerated
Name of Respondent
ldaho Power Company
This
(1)
(2)
ls:
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
04t16t20't9
7. Do not report the same transmission line structure twice. Reporl 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 lossor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of cn-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
COST OF LINE (lnclude in Column (j) Land,
Land rights, and clearing rightof-way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of
Conductor
and Material
(i)
Land
0)
Construction and
Other Costs(k)
Tobl Cost
0)
Operation
Expenses
(m)
Maintenance
Expenses
(n)
Rents
(o)
Total
Expenses
(p)
l-ine
No.
/15.5 ACSR 211,131 1,454,87t 1,666,010 1
215.5 ACSR 3,324 1,470,273 1,473,597 2
t97.5 ACSR 717,47|"732,40214,921
215.5 ACSR 1,086,02813,734 1,072,294 4
397.5 ACSR 18,223 '1,30'1,873 1,320,096 5
VARIOUS 66,28€3,219,49!3,28s,785 6
/15.5 ACSR 16,79C 213,033 229,823 7
543,372715.5 ACSR 13,616 529,756 I
397.5 ACSR 395,696 3,s04,326 3,900,02i o
715.5 ACSR 343,9ss 2,184,427 2,s28,382 10
795 ACSR 11
715,5 ACSR 14,69i 736,552 751,249 12
795 AAC En 2io 50,31S 13
795 AAC 308,141 2,165,954 2,474,495 14
1272 ACSR 93s,81C 3,442,874 4,378,684 15
'1272 ACSR 34,687 838,605 873,292 16
715.5 ACSR 179,81;6,681,791 6,861,608 17
/95 AAC 18
795 AAC 434,34'1 478,252 '1943,91
/95 AAC 20
1272 ACSR 140,41i 2,577,075 2,717,487 21
1272 ACSR 22
795 ACSR 1,s39,907 23134,471 1,405,436
/15.5 ACSR 2,473,83!19,029,573 21,503,406 24
215.5 ACSR 25
/15.5 ACSR td
/15.5 ACSR 27
21s.5 ACSR 28
1272 ACSR 78,57!2,219,508 2,298,087 IY
40,58(40,580 30
/15.5 ACSR 4,682,87!5,014,418 31331,539
32
1272 ACSR 704,76(2,141,218 2,845,9i8 21
/95 ACSR 34
35795 ACSR
34,835,917 639,955,720 674,791,637 7,787 364 1,544,297 2,710,673 12,042,331 Jb
FERC FORM NO.1 (ED.12-87)Page 423.3
TRANSMISSION LI NE STATISTICS
Name of Respondent
ldaho Power Company
This(1)
(2)
Report ls:
IAn Original
f-lA Resubmission
Date of Report(Mo, Da, Yr)
04t16t2019
Year/Period of Report
End of 2O18lQ4
TRANSMISSION LINE STATISTICS
1. Report information concerning transmission lines, cost of lines, and expenses lor 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
repo(ed 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 strucfures are included in the expenses reported for the line designated.
Line
No.
UESIGNAIION VOLIAGE (KV)(lndicate whereblher than
60 cvcle. 3 ohase)
Type of
Supporting
Structure
(e)
LENGTH (Pole miles)(ln the bass.ofunoerorouno ltnes
report -circuit miles)
Number
of
Circuits
(h)
From
(a)
To
(b)
Operating
(c)
Designed
(d)
un 5lofDesi
UcIUTE
-inernated
0
un Sruclurgsof AnotherLrne
(s)
1 Valivue Tap 138.0(138 00 S P Steel 0.7s 2
2 Bowmont Happy Valley 138.0C 138 00 S P Steel 8.65 I
3 Antelope Soovllle 138.0C 138.00 H Wood 0.12 1
4 American Falls 138 0C 138.00 H Wood 1.05 1
E Kinport Don #1 138,0C '138.00 S Tower 1.27 n
6 Donn HOKU 138 0C 138.00 S P Steel 2.68 1
7 HOKU Alamed 138.0C 138.00 S P Steel 0.22 2
8 HOKU Alamed 138,0C 138.00 S P Steel 0.23 2
I HOKU Alamed 138,0C 138.00 S P Steel 2.85 ,1
10 Rockland Jct Rockland Wind Farm '138.0C 138.00 S P Steel 5.18 1
11 King Justice 138 0C 138.00 S P WOOd 007 1
12 NorthView Tap 138 0(138 00 S P Wood 6.17 1
13 Twin Falls PP Tap 138.0C 138.00 H Wood 099 1
14 American Falls PP Amercian Falls Trans ST 138.0C 138 00 S P Steel 0,37 1
15 Lower Salmon King Tie 138 0C 138,00 H Wood 0.11 1
16 C J Strike Strike Jct '138,0c 138.00 S Tower 4,30 2
17 Strike Jct Mountain Home Jct 138.0C 138 00 H Wood 23,42 1
18 Strike Jct Bowmont 138 00 H Wood 005 1
19 Strike Jct Bowmont 138 0C '138 00 S Tower 0.36 1
20 Strike Jct Bowmont 138.0C 138 00 H Wood 67,87 1
21 Lucky Peak Lucky Peak Jct 138,0C 138 00 H Wood 4.48 2
22 Bliss King 138.0C 138 00 H Wood 10.51 I
23 Milner Deadend Milner PP 138.0C 138.00 S P Wood 1.3C 1
24 Swan Falls Tap 138.0C 138.00 H Wood 095 1
25
26
27
28 Hines BPA (Harney)1 15,0C 115.00 H Wood 12r 1
29
30
JI 69 Kv Lines 69,0(69 00 H Wood 205.81 1
32 69 Kv Lines 69,0(69 00 S P Wood 880.67 1
33
34
35 46 Kv Lines 46.0(46,00 S P Wood 380,07 1
36 TOTAL 4,754.64 11.02 205
FERC FORM NO. 1 (ED.12-87)Page 422.4
Wheolon
Name of Respondent
ldaho Power Company
This
(1)
(2)
ReDort ls:
[]An Orisinal
[-l A Resubmission
Date of Report(Mo, Da, Yr)
04t16t2019
Year/Period of Report
End of 2O18lQ4
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. lf two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. lf such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of cr-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns fi) to (l) on the book cost at end of year.
Size of
Conductor
and Material
(i)
COST OF LINE (lnclude in Uolumn U) Land,
Land rights, and clearing rightof-way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES
Line
No.
Land
0)
Construction and
Other Costs
(k)
Total Cost
(t)
Operation
Expenses
(m)
Maintenance
Expenses(n)
Rents
(o)
Total
Expenses(p)
i95 ACSR 351,497 351,497 1
1272 ACSR 691,72t 6,045,286 6,737,014 2
397.5 ACSR 7'1,018 71 ,018
250 COPPER 105,472 105,472 4
z'15.5 ACSR 1,171 207J40 208,314 5
1272 ACSR 303,86t 4,594 308,462 6
1272 ACSR 7
295 ACSR 8
/95 ACSR 9
/95 ACSR -16,973 -16,973 10
1590 ACSR 60,659 60,659 11
/15.5 ACSR 105,93:4,125,054 4,230,987 12
250 COPPER 5t 63,264 63,322 13
r15.5 ACSR 176,736 176,736 14
197,5 ACSR 4,406 4,406 15
i 15.5 ACSR 1,07t 636,545 637,619 16
197.5 ACSR 6,33i 2,566,1 7S 2,572,511 17
215.5 ACSR 86,651 4,864,294 4,950,945 18
715.5 ACSR 19
IU
715.5 ACSR 287,67e 287,683 21
715,5 ACSR 5,62(1,737 ,275 1,742,89a 22
715.5 ACSR 14,96€I 83,606 198,574 ,1
397.5 ACSR 17,201 261,512 278,719 24
25
26
27
397.5 ACSR 1,97t 63,404 65,382 ,a
29
JU
VARIOUS 1 ,813,793 81,431,83S 83,245,632 JI
VARIOUS 32
33
34
VARIOUS 198,291 20,370,559 20,s68,850 at
34,835,917 639,955,720 674,791,637 7,787 364 1,544,291 2,710,673 12,042,33(36
FERC FORM NO.1 (ED.12.87)Page 423.4
Name of Respondent
ldaho Power Company
This
(1)
(2)
ls:
Original
Date of Report(Mo. Oa, Yr)
Year/Period of Report
End of 2018/04
Resubmission 0411612019
TRANSMISSION LINE STATISTICS
1 . Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage,
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3. Report datra 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 hansmission line. Show in column (f) the pole miles of line on shuctures 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.
DESIGNATION LENGTH (Pole miles)(ln the tase ofunderorounc, lines
report Eiro.rit miles)
Line
No.
From
(a)
To
(b)
Operating
(c)
Designed
(d)
Type of
Supporting
Structure
(e)
LJN DIofDesi
un nrucureso[ AnotherUne(s)
Number
of
Circuits
(h)
1
2 Total all lines 4,754.64 11.02 205
3
4
5
6
7
8
I
10
11
12
13
14
15
16
17
't8
19
20
21
22
23
24
25
26
27
28
29
30
31
3Z
33
34
35
36 TOTAL 4,754.64 11.02 205
FERC FORM NO.1 (ED.12-87)Page 422'5
ame This
(1)
(2)
ls:Date of Report(Mo, Da, Yr)
0411612019
YearlPeriod of Report
End of 201BlQ4ldaho Power Company An Original
A Resubmission
IRANSMISSION LINE STATISTICS
7. Do not report the same transmission line structure twice. Repo( 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 kom another company,
givenameoflessor,dateandtermsofLease,andamountofrentforyear. Foranytransmissionlineotherthanaleasedline,orportlonthereof,for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line. and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
cosl oF LlNt (lnclucle in uolumn u) Lano,
Land rights, and clearing rightof-way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of
Conductor
and Material
(i)
Land
(i)
Construction and
Other Costs(k)
Total Cost
(t)
Operation
Expenses
(m)
Maintenance
Expenses
(n)
Rents Total
Exoenses'(p)
line
No.
7,787,360 1,544.297 2,710,673 12,042334 1
639,955,720 674/91,637 7,787,36C 1,544,297 2,710,673 12,042334 234,835,91i
3
4
5
6
7
o
I
10
11
12
13
14
15
16
17
18
19
20
21
22
a,
24
26
LI
28
29
30
31
32
33
34
2A
34,83s,917 639,955,720 674,791,637 7,787,36C 1,544,297 2,710,673 12,042,33(36
FERC FORM NO.1 (ED.12.87)Page 423.5
(o)
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2\ _ A Resubmission
Date of Report
(Mo, Da, Yr)
04t16t2019
Year/Period of Report
2018tQ4
FOOTNOTE DATA
Schedule Page:422 Llne No.: 1 Column: bThis l-ine is jointly owned wilh Pacif iCorp and Idaho Power trwns 73 .2t, of. this 85.4 nril-eIine,
Schedule Page:422 Line No.:2 Column: bThis line rs jointly owned with L'ortlanci General El,ectritl andthis 17.B mrle l1ne.
Sclredule Page:422 Line No.: 3 Cotumn: b
Idaho Power owns 10.0? of
'Ihr-s -Lane 1sline.
Schedule Page:
Th i.s Iine i s
I-Lne.
Schedsle Page:This line is
jointly owned
422 Line No.:4
loinLly owned
422 Line No.: 5j ointJ-y owned
with PacifrCorp and Idaho Power owns
Column: b;ith iacifrCorp and rdaho Power owns
Column: bwith PacifiCorp and Idaho Power owns
3?.0e5
22.02
31 .jet
of
of
of
thrs
this
rh is
aA1
129
24L
3 mile
3 mile
J m1-Le
I ine
Sche;lule Page: 422 Line No.: 6 Column: bThis line is jointly owned with PacifrCorpfine.
Schedule Page:422 Line No.:8 Column: hThis line is jointly owned with FacifrCorp'I i ne.
Schedute Page:422 Line No.: 10 Column: bThis line rs jointly owned wit-h PacifiCorp
l-ine.
Schedule Page: 422 Line No.: 11 Column: b
This line rs jolntly owr:ed with PacifiCorpapproxlmately i93 mil,e line.
Sclredule Page: 422 Line No.: 12 Column: bThis }ine is jointly owned with PacifiCorp
t t -.^aa11c -
Schedule Page:422 Line No.: 13 Column: bThis llne is jointly owned with FacifiCorp
approxlmately 193 mile 1ine.
Scfiedule Page:422 Line No;14 Column: b?his l-i-ne is jointly owned wiLh PacifiCorpfine.
Schedule Page:422 Line No.: 15 Column: bThis line rs jointly owr,ecl with PacifiCorpfine.
Scfiedule Page: 422 Line No.: 16 Column: bThis Iine rs jointly owned with PacifrCorpfine.
Sehedule Page: 422 Line No.: 17 Column: b
Thr-s line rs joinlLy owned with Pacif iCorpIine.
:Schedule Page:422 Line No.: 18 Column: bThis line is jointly owned with PacifrCorp
and
and
and
and
and
and
and
and
and
and
and
I daho
-LOano
Idaho
I daho
I daho
Idaho
Idaho
Idaho
I daho
Idaho
Idah<.r
Power
Power
Power
Power
PoWCI.
Power
Power
Power
Power
Power
Power
OWNS
OWNS
OWNS
OWNS
owns
owils
O f,lrll S
owns
Ol.lnS
OWNS
OWNS
of this 129.3 m1le
29.22 of this 226.6 niLe
'73.2e; of thls 21. L m-i"1e
29.22 of this
29.2ed of thi-s 41.2 mil-e
29.2?; of this
29.2\ oll this 4l.3 mife
18.3? of this 40.9 mile
64.4% of this 79.5 mile
64 - 4e" of thls 77.9 mile
64.4% of this 0.9 mile
line.
Schedute Page: 422 Line No.: 32 Cotumn: bThis I ine is jointly ownerl wiLh Port-land General- E-Lectric and Idaho Fower owns 10.0':. of
th.Ls I 6.7 m:-1e L rne.
Sehedute Page:422.1 Line No.: 10 Cotumn: bThis -l-ine rs jointly owned with PacifrCorp and Tdaho Power owns 40.8?, of this 77.5 m1l-e
1ine.
Schedute Page:422-1 Line No.: 29 Column: b
FERC FORM NO. 1 1 450.'1
Name of Respondent
ldaho Power Company
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
0411612019
Year/Period of Report
2018tQ4
FOOTNOTE DATA
This line is jointly owned with PacifiCorp. Idaho Pcwer owns 37.8? of Gosherr- Jefferson28.9 mife segment, 3f.8? of the iefferson- Big Grassy 20.8 mile segment and 1001 of theBlg Grassy* Slatq Line 40.9 mile segment.
Schedule Page: 42-2.1 .Line No.: 32 Column: bThis llne is;ointly owned with PacifiCorp and Id.aho Power owns 2l-.9't of this 25.8 mileline.
lSchadula Page: 422.1 lrne IVo.: 33 Column: b ,This line is 3ointly owned r^rith Pacj-fiCorp. Idaho Power owns 37.8t of Goshen- Jefferson28.9 mile sesment, 31.88 of the Jefferson- Big Grassy 2A.B mile segment and 100% of theBiq Grassy- State Line 40.9 mile se t
Schedule Page:422.1This iine is lcin
Line Na.:34 btly owned r^rith PacifiCo rp. Idaho Power owns 37.88 of Goshen- Jefferson28.9 mile segment, 31.8t] of the Jefferson- Big Grassy 20.8 mil-e segment and 100? of theBiq Grassy- State Llne 4,0-.9 mile segment.
Schedule Page:422.4 Line No.: 3 Column: bThis line is jointLy owned with PaclfiCorp and Idahc Power owns 11.5o of this 1 miie fine.
Scftedule Page:422.4 Line No.:4 Column: b
This line is jointly owned r^rith PacifiCorp
l-Lre.
and Idaho Power owns 7.22 of this 29.1 mile
FERC FORM NO. 1 (ED. 12-871 Page 450.2
ldaho Power Company (1)
(2)
An Original
A Resubmission
Oate of Report(Mo, Da, Yr)
04116t2019
Year/Period of Report
End of 20181Q4
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 colurnns the
Line
No.
LINE DESIGNATION LtneLength
tnMiles
(c)
CIRCUITS PER SIRUCTUR
From
(a)
To
(b)
Type
(d)
AVeIaqgNumbeiper
Miles
(e)
Present
(f)
Ultimate
(g)
1 Star Lansing 5.50 Steel LD 21.64 I 1
2 Zilog Can Ada 1.50 Steel LD 12.61 1 1
J
4
5
6
7
8
o
10
11
12
13
14
1E
'16
17
18
ao
20
21
22
23
24
25
zo
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44 TOTAL 7.00 34.31 2 2
FERC FORM NO.1 (REV. 12-03)Page 424
Name of Respondent
ldaho Power Company
This Reoort ls:(1) fiRn Originat
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
(2)A Resubmission 0411612019
TRANSMISSION LINES ADDED DURING YEAR (Continued)
costs. Designate, however, if estimated amounts are reported. lnclude costs of Clearing Land and Rights-of-Way, and Roads and
Trails, in column (l) with appropriate footnote, and costs of Underground Conduit in column (m).
3. lf design voltage differs from operating voltage, indicate such fact by footnote; also where line is other than 60 cycle, 3 phase,
indicate such other characteristic.
L;ONL'UC IOKS LINI (;OS I
Size
(h)
Specification
(i)
Confiouration
and Spaclng
(i)
Voltage
KV
(o0e,11tins)
Land and
Land Rights
fl)
Poles, Towers
and Fixtures
(m)and Devices(n)
Conductors Asset
Retire. Costs(o)
Total
(p)
Line
No
795 ACSR TAS & TVS 138 2,215,49t '1,536,381 3,751,879 I
795 ACSR TAS & TVS 138 682,25l.86't,838 1,544,088 2
3
4
5
D
7
I
I
10
11
12
13
14
15
16
17
18
't9
20
21
22
23
24
25
26
27
28
29
30
JI
32
33
34
35
36
37
38
39
40
41
42
43
2,897,741 2,398,219 5,295,967 44
FERC FORM NO.1 {REV.12-03)Page 425
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04t16t2019
Year/Period of Report
20181Q4
FOOTNOTE DATA
Schedule Page: 424 Line No.: 1Estimateci amount.s are repcr
Column: o
tec
Schedule Page:424 Line No.: 2 Column: oEstimated amounts are reported
FERC FORM NO. 1 (ED. 12-871 Page 450.'l
Name of Respondent
ldaho Power Company
S:
(1)
(2)
An Original
A Resubmission
Oate of Report(Mo. Da, Yr)
04t16t2019
Year/Period of Report
End of 20181Q4
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4, lndicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line
No.Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (ln MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 AdCalde 'transmission 345.00 138.00 13.80
2 Aiken distribution 46.00 13.00
3 Alameda distribution '138.00 13.00
4 Alameda distribution 138.00 13.09
5 American Falls PP - attended transmission 138.00 13.80
6 American Falls transmission 138.00 46.00 12.47
'7 transmission 230.00 161.00 13.80
8 Artesian distribution 46.00 13.00
I Bannock Creek distribution 46.00 't3.00
10 Bennett Mounhin Power Plant- attended transmission 230.00 18.00
11 Bennett Mountain Power Plant- attended diskibution '18.00 4.16
12 Bethel Court distribution 138.00 13.00
13 transmission 161 .00
14 Black Cat dishibution 138.00 't3.09
15 Black Mesa distribution 138.00 13.00
16 Blackfoot distribution 46.00 13.00
17 Blackfoot transmission 161 .00 46.00 12.47
18 Blackfoot distribution 161 .00 138.00 12.98
19 Bliss - attended transmission 138.00 13.80
20 Blue Gulch diskibution 138.00 3s.00
21 Boise Bench transmission 230.00 138.00 13.20
22 Boise Bench distribution 138.00 35.00
23 Boise Bench transmission 138.00 69.00 12.98
24 Boise Bench transmission 230.00 138.00 13.80
OE Boise distribution '138.00 13.00
26 Borah transmission 345.00 230,00 13.80
27 Border distribution 138.00 13,00
28 Border distribution 35.00
29 Bowmont distribution 138.00 35.00
30 Bowmont transmission 138.00 69.00 12.98
31 Bowmont transmission 138.00 69.00 12.47
32 Bowmont transmission 230.00 138.00 13.80
33 Brady transmission 230.00 138.00 13.80
34 Brady transmission 138.00 46.00 12.47
35 Brady distribution 46.00 13.00
36 Brownlee - attended transmission 230.0c 13,80
37 Bruneau Bridge distribution 138.00 35.00
38 Bruneau Bridge distribution 138.00 36.20
39 Buckhorn distribution 69.00 35.00
40 Bucyrus distribution 46.00 7.20
FERC FORM NO.1 (ED.12-96)Page 426
Antslopo
Big Grassy
Name of Respondent
ldaho Power Company
ThiS
(1)
(2)
ls:
An Original
A Resubmission
Date of Reoort(Mo, Da, Yi)Year/Period ot Report
End of 2O18lQ4
04116t2019
5. Show in columns (l), (j), and (k) special eguipment 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. SpecifiT in each case whether lessor, co-owner, or other party is an associated company.
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
Type of Equipment
(i)
Total Capacity(ln MVa)
(k)
Line
No.
Capacity of Substation
(ln Service) (ln MVa)
(0
Number of
Transformers
ln Service
(s)
Number of
Spare
Transformers
(h)
Number of Units
0)
12
27 22
30 1 3
4301
5120I
6471
1 7254
14 I 8
o141
102251
1151
12281
13
90 2 14
'15111
16562
1 17o22
181351
1986a
20482
2 21448
22702
231253
244482
117 J 25
2675AJ1
27111
285J
30 1 29
30461
3147,1
326002
33312
1 34
352814
1 367525
37301
45 1 38
3937I
1 1 40
FERC FORM NO. 1 (ED.12-96)Page 427
50(
ldaho Power Company (1)
(?',)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
04116t2019
Year/Period of Report
End of 20181Q4
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. lndicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line
No.Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (ln MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 Buhl distribution 46.00 13.20
2 Burley Rural distribution 69.00 13.00
3 Burley Rural distribution 69.00 13.09
4 Butler distribution 138.00 13.09
5 Caldwell distribution 138.00 13.00
6 Caldwell transmission 230.00 138,00
7 Caldwell distribution 138.00 13.09
8 Caldwell transmission 138.00 69,00 12.47
I Caldwell transmission 230.00 138.00 12.47
10 Camas distribution 35.00
11 Camas distribution 35.00 14.40
12 Can-Ada distribution 138.00 13.09
13 Canyon Creek distribution 138.00 36.20
14 Canyon Creek transmission 138.00 69.00 12.98
15 Cartwright distribution 138.00 13.00
16 Cascade Power Plant - attended transmission 69.00 4.60
17 Cascade distribution 69.00 13.00
'18 Cascade diskibution 69.00 13.10
19 Cascade distribution 25.00
20 Chestnut distribution 138.00 13.00
21 Chestnut distribution 138.00 13.09
22 Cinder distribution 46.00 13.00
23 Clear Lake - attended transmission 46.00 2.40
24 criff transmission 138.00 46.00 12.50
25 criff transmission 138.00 46.00 12.95
26 Cloverdale distribution 138.00 13.00
27 Cloverdale distribution 138.00 13.09
28 Council distribution 69.00 13.00
29 Crane Creek distribution 69.00 13.00
30 Crater distribution 46.00 13.00
31 Dale distribution 46.00 4.60
32 Dale distribution 46.00 13.00
33 Dale distribution 69.00 13.00
34 Dale distribution 138.00 36.20
35 Dale transmission 138.00 46.00 12.47
36 Danskin- attended transmission 230.00 18.00
37 Danskin- attended transmission 230.00 138.00 13.80
38 Danskin- attended distribution 18.00 4.16
39 Danskin- attended transmission 138.00 12.00
40 Danskin- attended distribution 35.00 13.80
FERC FORM NO.1 (ED.12-96)Page 426.1
ls:Date of Report(Mo, Da, Yr)
YeariPeriod of Report
End of 201BlQ4An Original
A Resubmission 04t16t2019
Name of
ldaho Power Company (1)
(2)
5. Show in columns (l), (j), and (k) special eguipment 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
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.Type of Equipment
(i)
Number of Units
(i)
Total Capacity
(ln MVa)
(k)
1 4
1 2
45 1 3
90 2 4
28 1 5
200 1 6
45 1 7
140 3 8
200 1 9
5 J 1 10
10 J 1 11
45 1 12
45 1 13
20 1 14
't1 I '15
16 ,|16
7 1 17
't4 1 18
5 1 19
45 1 20
45 1 21
11 1 22
5 1 23
2',!2 1 24
10 1 25
45 1 26
45 1 27
14 1 28
11 I 29
11 I 30
1 31
7 32
1
a1
45 1 34
47 1 35
233 I 36
300 1 37
6 I 38
160 2 39
5 I 40
FERG FORM NO. I (EO. t2-96)Page 427,1
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
04t16t2019
Year/Period of Report
End of 20181Q4
SUBSTATIONS
1 . Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than '10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. lndicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line
No.Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (ln MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 Deen distribution 46.00 13.00
2 Dietrich distribution 46.00 13.09
3 Don distribution 138.00 7.60
4 Don diskibution '138.00 13.20
5 Don diskibution 138.00 13.00
6 DRAM dishibution 13B.00 't3.09
7 DRAM transmission 230.00 138.00 13.80
8 DRAM distribution 138.00 12.47
I DRAM distribution 138.00 13.00
10 Duffin distribution 138.00 35.00
11 Eagle diskibution 138.00 13.09
12 Eastgate distribution 138.00
13 Eastgate distribution 138.00 13.00
14 Eckert distribution 138.00 36.20
15 Eden distribution 138.00 36.20
16 Eden transmission 138.00 46.00 12.98
17 Elkhorn distribution 138.00 12.47
18 Elkhorn distribution 138.00 't 3.00
19 Elmore distribution 138.00 3s.00
20 Elmore transmission 138.00 69.00 12.50
21 Elmore transmission 138.00 69.00 12.98
22 Emmett distribution 138.00
23 Emmett transmission 138.00 69.00 12.47
24 Falls distribution 46.00 't3.00
25 Filer distribution 46.00 13.00
26 Flat Top distribution 46.00 13.00
27 Flying H dishibution 69.00 2.40
28 Fort Hall diskibution 46.00 13.00
29 Fossil Gulch distribution 138.00 35.00
30 Fremont transmission 138.00 46.00 12.50
31 Gary distribution 138.00 13.09
aa Gary distribution 138.00 13.00
33 Gem distribution 69.00 13.00
34 Gem distribution 69.00
35 Glenns Ferry diskibution 138.00 13.00
36 Gooding Rural distribution 46.00 13.00
37 Golden Valley distribution 69.00 13.00
38 Goahan transmission 345.00 161 .00 69.00
39 Gowen Substation dishibution 138.00 3s 00
40 Grindstone dishibution 35.00
FERC FORM NO. r (ED.12-96)Page 426.2
Name of Respondent
ldaho Power Company (1)
(2)
An Original
A Resubmission 04t1612019
SUBSTATIONS
5. Show in columns (l), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(ln Service) (ln MVa)
(f)
Number of
Transformers
ln Service
(s)
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 I 1
14 1 2
1 )
180 6 1 4
44 1 5
168 6 6
212 2 7
28 1 8
28 I I
60 2 10
67 2 11
45 ,|12
30 1 13
30 1 14
45 1 15
20 1 to
11 'l 17
11 ,|'18
28 1 19
,4 1 20
2A 1 21
45 1 22
47 1 23
28 2 24
14 1 25
17 2 26
20 2 27
14 1 1 28
28 1 29
67 3 1 30
37 1 31
28 1 32
14 1 1 33
14 I 34
11 1 35
20 2 36
14 I ,1 aa
908 4 38
45 1 39
7 1 40
Year/Period
End of
Report
20181Q4
FERC FORM NO.1 (ED.12-96)Page 427.2
Name
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
04t16t2015
YeariPeriod of Report
End of 20181Q4
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 nol 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)
,|Grindstone distribution 35.00 2.40
2 Grove distribution 138.00 13.09
J Grove distribution 138.00 13.00
4 Hagerman distribution 46.00 13.00
5 Hagerman distribution 69.00 13.00
6 Hailey distribution 138.00 13.00
7 Happy Valley distribution 138.00 13.09
8 Haven distribution 138.00 35.00
I Haven transmission 138.00 46.00
10 transmission 500.00 230.00 34.50
11 Hewlett Packard distribution 138.00 13.00
12 Hidden Springs distribution 138.00 13.00
13 Highland distribution 138.00 13.00
14 Hiil distribution 138.00 't3.00
15 Hillsdale distribution 138.00
16 Homedale distribution 69.00 '13.00
17 Horse Flat transmission 230.00 138.00 13.80
18 Horseshoe Bend distribution 35.00
19 Horseshoe Bend distribution 69.00 36.20
20 Horseshoe Bend distribution 69.00 2s.00
2',!Huston distribution 69.00 13.00
22 Hulen distribution 46.00 13.00
23 Hunt transmission 230.00 138.00 13.80
24 Hydra distribution 138.00 36.20
25 lsland distribution 69.00 13.00
26 Jefficrson transmission 161.00
27 Jerome distribution 138.00 13.00
28 Jerome distribution 138.00 13.09
29 Julion Clawson distribution 138.00 35.00
30 Joplin distribution 138.00 13.00
3'1 Joplin distribution 138.00 36.20
32 Justice transmission 230.00 138.00 13.80
33 Karcher distribution 138.00 13.00
34 Kenyon distribution 69.00 13.00
35 Ketchum distribution 138.00 13.00
36 Kimbedy diskibution 138.00 13.09
37 Kinport transmission 161.00 46.00 13.20
38 Kinport transmission 230.00 138.00 12.47
39 Kinport transmission 230.00 138.00 13.80
40 Kinport transmission 345.00 230.00 13.80
FERC FORM NO.1 (ED.12-96)Page 426.3
Hemlngrray
Name of Respondent
ldaho Power Company
This
(1)
(2)
IS:Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of 20'l8lQ4An Original
A Resubmission 04t',!6t2019
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.
CONVERSION APPARATUS AND SPECIAL EOUIPMENT
Number of Units
(i)
Capacity
MVa)(k)
Total
(ln
Line
No.
Capacity of Substation
(ln Service) (ln MVa)
(0
Number of
Transformers
ln Service
(q)
Number of
(h)
Spare
Transformers Type of Equipment
(i)
171
2s02
3451
14 I 4
A6I
6371
1 730
8201
I471
1 101 000 3
37 ,|11
12111
'13301
14732
1545,|
16342
17100,|
187I
1922I
2071
2114I
14 1 22
233363
24902
25201
26
27371
28371
29562
30281
31451
323001
33201
34252
35752
36451I
7 37
38300I
393001
401'1000 3
FERC FORM NO. r (ED.12-96)Page 427 '3
Name S:
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
041't612019
YearlPeriod of Report
End of 20181Q4
SUBSTATIONS
1 . Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. lndicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line
No.Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (ln MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 Kramer diskibution 138.00 35.00
2 Kramer distribution 138.00 36.20
3 Kuna distribution 138.00 13.09
4 Lake distribulion 69.00 13.00
5 Lake Fork distribution 138.00 36.20
6 Lake Fork transmission 138.00 69.00 12.54
7 Lamb distribution 138.00 13.00
8 Langley Gulch- attended transmission 230.00 138.00 '13.80
I Langley Gulch- attended transmission 230.00
10 Langley Gulch- attended transmission 230.00 150.00
11 Lansing distribution 138.00 13.09
12 Lincoln distribution 138.00 13.09
IJ Linden distribution 138.00 13.00
14 Locust distribution 138.00 36.20
15 Locust transmission 230.00 138.00 13.80
16 Lower Malad - attended transmission 138.00 7.20
17 Lower Salmon - attended transmission 138.00 13.80
18 Map Rock distribution 69.00 13.00
19 McCall distribution 138.00 13.09
20 McCall distribution 138.00 36.20
21 Melba distribution 69.00 13.00
22 Meridian distribution 138.00 13.00
23 Micron distribution 138.00 13.09
24 Micron distribution 138.00 13.00
25 Midpoint transmission 230.00 138.00 13.80
26 Midpoint transmission 345.00 230.00 13.80
27 500.00 345.00
28 Midrose distribution 138.00 13.09
29 Milner transmission 138.00 69.00 12.47
30 Milner distribution 6S.00 46.00 6.90
31 Milner diskibution 138.00 35.00
32 Milner PP - attended transmission 138.00 13.80
JJ Moonstone distribution 138.00 35.00
34 Mora distribution 138.00 13.0S
35 Mora distribution 138.00 36.20
36 Moreland dishibution 46.00 13.00
37 Mountain Home distribution 69.00 13.00
38 Mountrin Home Air Force Base distribution 69.00 13.00
39 Mountain Home Air Force Base distribution 138.00 13.00
40 Nampa transmission 230.00 '138.00 13.80
FERC FORM NO.1 (ED.12-96)Page 426.4
Mldpolnt transmission
of
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo. Da, Yr)
04t1612019
Year/Period of Report
End of 2018/Q4
SUBSTATIONS
5. Show in columns (l), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or maior 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. SpecifiT in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(ln Service) (ln MVa)
(0
Number of
Transformers
ln Service
(s)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.Type of Equipment
(i)
Number of Units
(i)
Total Capacity
(ln MVa)
(k)
20 1 1
30 1 2
45 1 3
14 ,|4
30 1 5
20 1 6
30 1
636 2 8
410 2 I
1 10
40 1 11
14 1 12
58 2 13
134 ?14
600 2 't5
16 1 16
70 4 17
13 1 18
22 1 19
30 1 20
11 1 21
60 2 22
40 2 23
40 2 24
200 1 25
1400 2 1 26
1 500 2 1 27
45 1 28
125 2 1 29
8 1 1 30
50 2 3'1
60 ,|32
20 I 2?
45 ,|34
45 1 35
28 2 36
28 1 37
1 3B
34 1 39
300 1 40
FERC FORM NO.1 (ED.12.96)Page 427.4
Name of Respondent
ldaho Power Company
This
(1)
(2')
ls:Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of 201A|A4An Original
Resubmission 04t16t2019
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. lndicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
VOLTAGE (ln MVa)Line
No.Name and Location of Substation
(a)
Character of Substation
(b)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 Nampa distribution 138.00 13.00
2 New Meadows distribution 138.00 36.20
?New Plymouth distribution 69.00 13.00
4 Northview distribution 138.00
A Notch Butte distribution 138.00 13.09
6 Orchard 69.00 36.20distribution
7 Orchard diskibution 69.00
8 Parma diskibution 69.00 13.00
o Parma distribution 69.00 35.00
10 Paul distribution 138.00 35.00
11 Paul diskibution 138.00 36.20
12 Payette diskibution 138.00
13 Pingree transmission 138.00 46,00 12.50
14 Pingree distribution 138.00 35.00
15 Pleasant Valley distribution 138.00 35.00
16 Pleasant Vailey 138.00 36.20distribution
17 Pocatello distribution 46.00 13.00
18 Pocket distribution 138.00 36.20
'19 138.00 13.09Poleiinedistributlon
20 transmission 345.00
21 Portneuf distribution 138.00 35.00
22 Portneuf diskibution 46.00 35.00
23 Rockford distribution 46.00 13.00
24 Russett distribution 138.00 13.00
25 Sailor Creek diskibution 138.00 2.40
26 Sailor Creek distribution 138.00 35.00
27 Salmon diskibution 69.00 13.00
28 Salmon distribution 69.00 34.50 12.47
2S Salmon distribution 69.00 7.24
30 Shoshone distribution 46.00 13.09
31 Shoshone distribution 46.00 7.20
32 Shoshone Falls - attended transmission 46.00 2.30
33 Shoshone Falls - attended transmission 46.00 6.60
34 Siiver distribution 138.00 35.00
35 Simplot distribution 138.00 13.00
36 Sinker Creek distribution 138.00 3s.00
37 Siphon distribution 138.00 35.00
3B South Park distribution 46.00 13.00
39 Spring Valley distribution 138.00 12.47
40 Star distribution 138.00 13.09
FERC FORM NO.1 (ED.12-96)Page 426.5
Populus
Name of Respondent
ldaho Power Company (1)
(2\
An Original
A Resubmission
Date of Report(Mo. Da, Yr)
04t16t2019
YearlPeriod of Report
End of 20181Q4
SUBSTATIONS
5. Show in columns (l), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other parg is an associated company.
Capacity of Substation
(ln Service) (ln MVa)
(n
Number of
Transformers
In Service
(o)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.Type of Equipment
fi)
Number of Units
(i)
Total Capacity
(ln MVa)
(k)
87 3 1
22 1 2
13 I
45 1 4
14 I R
8 I 6
33 1 7
14 1 I
20 1 I
30 1 1 10
45 1 11
45 1 12
67 )13
34 2 14
30 1 15
45 1 't6
60 2 '17
45 1 18
30 1 19
20
30 1 21
1 22
25 2 ZJ
30 1 24
21 2 25
28 1 26
14 1 4 27
'10 2 1 28
1 29
I 30
2 3 31
I 5Z
14 1 33
20 ,|34
53 2 35
20 1 36
55 2 37
14 1 3B
11 1 39
30 1 40
FERC FORM NO.1 (ED.12-96)Page 427.5
This
(1)
(2)
ls:
An Original
A Resubmission
Date of Report(Mo. Da, Yr)Year/Period of Report
End of 201B|A404t16t2019Idaho Power Company
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. lndicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
VOLTAGE (ln MVa)Line
No.Name and Location of Substation
(a)
Character of Substation
(b)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 Starkey transmission 138.00 69.00 12.47
2 State distribution 69.00 13.00
a Sterling distribution 46.00 13.00
4 Stoddard 13.00distribution138.00
5 Strike Power Plant - attended transmission 138.00 13.80
6 Sugar distribution 138.00 35.00
7 Swan Falls - attended transmission 138.00 6.90
8 Taber dishibution 46.00 13.00
I Tamarack distribution 138.00 2.40
10 Ten Mile dishibution 138.00 13.09
11 Terry diskibution 138.00 13.09
't2 Terry 138.00 13.00distribution
13 Thousand Springs - attended transmission 46.00 7.20
14 Three Mlle ]Goll transmission 345.00
15 33.00Toponisdistribution138.00
't6 Twin Falls distribution 138.00 13.09
17 Twin Falls transmission 138.00 46,00 12.98
18 Twin Falls PP - attended 7.20transmission138.00
19 Twin Falls PP - attended transmission '138.00 13.20
20 Tyhee distribution 46.00 13.00
21 Upper Malad - attended transmission 45.00 7.20
22 Upper Salmon- attended transmission 138.00 7.20
Ustick distribution 138.00 13.00
24 Vallivue distribution 138.00 't 3.0s
25 Victory distribution 138.00 13.00
26 Mctory distribution 138.00 13.09
27 Ware distribution 69.00 13.00
28 13.00Weiserdistribution69.00
29 Weiser transmission 138.00 69.00 12.47
30 \Mlder distribution 6S.00 13.00
31 Willis distribution 138.00 13.09
32 Willow Creek diskibution 138.00 13.00
33 wye diskibution 138.00 13.00
34 wye distribution 138.00 13.09
35 Zilog distribution 138.00 13.09
36
37
38 The above are all State of ldaho
39
40 Montana:
FERC FORM NO.1 (ED.12-96)Page 426.6
of ent
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report
(Mo, Da, Y0
o4t't612019
Year/Period of Report
End of 20181Q4
5. Show in columns (l), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(ln Service) (ln MVa)
(0
Number of
Transformers
ln Service
(s)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.Type of Equipment
(i)
Number of Units
(i)
Total Capacity(ln MVa)
(k)
30 1 1
58 2 2
11 2 3
28 1 4
104 J 5
28 2 6
34 1 7
6 I I
11 1 I
90 2 10
20 1 11
50 2 12
8 1 13
14
30 1 15
82 2 16
50 2 17
13 1 1B
72 'l 19
14 I 20
8 I 21
42 4 22
77 2 23
30 I 24
45 I 25
30 1 26
20 1 I 27
28 2 1 28
42 1 2S
14 1 30
30 1 31
11 1 32
60 2 a)
37 1 34
45 1 35
36
37
38
39
40
FERC FORM NO.1 (ED. 12-96)Page 427.6
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q404t1612019
ame
ldaho Power Company (1)
(2)
SUBSTATIONS
1 . Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. lndicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line
No.Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (ln MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 Mill Creek transmission 230.00
2 Peterson transmission 230.00 69.00 13.20
4 Nevada
5 Valmy - attendd transmission 345.00 18.00
6 Valmy - atended transmission 345.00 22.O0
7 Wells transmission 138.00 69.00 13.00
8
I Oregon:
10 Adrian distribution 69.00 13.00
11 transmission 500.00 24.00
12 Boadman - attended transmission 230.00 7.20
13 Boardman - atbnded transmission 24.00 7.20
14 Burns transmission 500.00
15 Cairo distribution 69.00 13.00
16 Hells Canyon - attended transmission 230.00 '13.80
17 Hells Canyon - attended distribution 69.00 0.50
't8 Hines transmission " 138.00 11s.00 12.47
19 Hunicane 230.00
20 Jacobson Gulch distribution 69.00 2.40
21 Malheur Butte distribution 69.00 34.50
22 Nyssa distribution 69.00 13.00
23 Ontario distribution 138.00 13.00
24 Ontario transmission 138.00 69.00 12.47
25 Ontario transmission 230.00 138.00 13.80
26 Ontario transmission 138.00 69.00 12.98
27 Ontario transmission 138.00 69.00 13.09
28 Ontario transmission '138.00 69.00 12.50
29 Ore-lda distribution 69.00 13.00
30 Oxbow - attended transmission 138.00 69.00 13.00
31 Oxbow - attended transmission 230.00 13.80
32 Oxbow - attended transmission 230.00 138.00 13.80
33 Quartz transmission 138.00 69.00 12.50
34 Quartz transmission 230.00 138.00 12.98
35 Quartz transmission 138.00 69.00 12.98
36 Summer Lake transmission 500.00
37 Vale distribution 69.00 13.00
38
39 Washington
40 Walla Walla transmission 230.00
FERC FORM NO.1 (ED. 12-96)Page 426.7
Boardman - attended
transmission
(1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
0411612019
Year/Period of Report
End of 2O18lQ4
SUBSTATIONS
5. Show in columns (l), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(ln Service) (ln MVa)
(0
Number of
Transformers
ln Service
(s)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.Type of Equipment
(i)
Number of Units
(i)
Total
(ln
Capacity
MVa)
(k)
1
30 3 1 2
3
4
315 I E
300 1 6
25 3 1 7
B
I
11 1 10
685 3 11
55 1 12
55 1 13
14
20 1 '15
560 3 16
1 1 17
50 1 18
19
11 ,|20
11 3 1 21
28 2 22
67 2 1 23
47 1 24
400 2 25
93 2 26
1 27
1 28
28 1 29
13 3 1 30
274 2 1 31
100 1 32
25 1 33
167 3 1 34
20 1
2E
36
14 1 37
38
39
40
FERC FORM NO.1 (ED.12-96)Page 427.7
Name of Respondent
ldaho Power Company
Name Respondent
ldaho Power Company (1)
(2t
An Original
A Resubmission
Oate of Report(Mo, Da, Yr)
0411612019
YearlPeriod of Report
End of 20181Q4
SUBSTATIONS
1 . Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serue only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.4. lndicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (0.
VOLTAGE (ln MVa)Line
No.Name and Location of Substation
(a)
Character of Substation
(b)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1
2 Wyoming:
3 transmission 345.00 22.00 34.50
4
5
6
8
I Transformers-distribution substations under 10,000
10 KVA 61 unattended
11
12
13
14
15
16
17
18
'19
20
21
22
23
24
ai
ZO
27
28
29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO.1 (EO.12-96)Page 426.8
Jlm 3rldger - stended
Name An Original
A Resubmissionldaho Power Company
(1)
(2)
Date of Report
(Mo. Da, Yr)
04t16t2019
YearlPeriod of Report
End of 20181Q4
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 othen ,ise 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. Forany substation orequipmentoperated otherthan by reason of sole ownership orlease, 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. SpeciflT 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
(s)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
NoType of Equipment
(i)
Number of Units
(i)
Total Capacity
(ln MVa)
(k)
1
2
2244 4 3
4
5
6
7
8
I
214 10
't1
12
13
't4
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
3'1
32
33
34
35
36
37
3B
39
40
FERC FORM NO.I (ED.12-96)Page 427.8
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2\ _A Resubmission
Date of Report
(Mo, Da, Y0
04t16t2019
YearlPeriod of Report
2018tQ4
FOOTNOTE DATA
Schedule Page: 426 Line No.: 1 Column: aPacifiCorp has an ownershi-p interest in cerLain high-voltage transmission related and
interconnection equipment located at fdaho Power's AdeLaide station. Ownership interestvaries by terminal. 1002 of the capacLty is reported.
'Schedule Page: 426 Line No.: 1 Column: fFor al.l of co-Lumn F:
Top rating capacity repo::ted unless ot-herwise noted.
Schedule Page:426 Line No.:7 Column: aIdaho Power has an ownership interest in cerl-ain hi-gh-voltage t-ransmission related and
interconnection equipment located at PacifiCorp's Antelope station. Ownership interesEvaries by terminal. 10{? of the capacity reported.
Schedule Page:426 Line No.: 13 Column: aIdaho Power has an ownership interest in certaj-n high-volEage transmission related and
interconnection equipment located aL PacifiCorp's Big Grassy station. Ownership interestvarj-es by terminal.
Schedute Page:426 Line No.:26 Column: a
PacifiCorp has an ownership interest in certain high-voltage transm.issic.n related and
interconnection equipment locat-erl at Idaho Power's Borah station. Ownership inLerest
varies by termlnal. 100? of l-he capacity is reported.
Schedule Page:426.2 Line No.: 38 Column: a
fdaho Power has an ownership incerest in.'ercain high-voitage tran-smission related and
interconneclion equipment focated at PacifiCorp's Goshen station. Ownership interestvaries by term:-nal 100? of the capacity reporteci.
Schedute Page:426.3 Line No.: 10 Column: a
PacifiCorp has an ownersirlp interest in certaln high-vo.ltage transmission related and
interconnection eqr.:ipment locateci at Idaho Power's Hemingway station. Ownership interest-
vari-es by terminar . 100? of the capacity i*s reported.
Schedule Page:426.3 Line No.: 26 Column: aIdaho Power has an ownership interest in certain high-voltage transmission related and
interccnnection equipmenL located at PacifiCorp's Jefferson station. Owner:ship interest
varies by terminal.
Schedute Page: 426.3 Line No.: 40 Column: aPacifiCorp has an ownership interest in certain high-voltage transmj-sslon rel-ated andinterconnection equlpment located at Idaho Power's Klnport station. Ownershlp i-nLerestvarj-es by terminal
ii:i?1'.'.fit?;^'r'u:1,;;1,1??Li;f'r^r??l!Inil .*,tuin hish-vorr.ase transn,ission related andinterconnect-ior-t equipnrent -Iocated at Idaho Power' s Midpoint station. Ownership interest
varies by terminal- 100? of the capacrty 1s reported.
Schedule Page:426.5 Line No.: 20 Column: a
fdaho Power has an or^rnership interest irr certain high-voltage transmi-ssion related andinterconnection equipment Located aE PacifiCorp's Populus stat-ion. Ovrnership interest
varies by termi-na1.
Schedule Page:426.6 Line No.: 11 Column: aIdaho Power has an ownersnip interest in certain high-voltage transmj-ssion related andint-erconnection equipment- located at Pacrfj-Corprs Three MiIe Knoll station. Ownership
interest vari.es by termina.l-.-Schedute Page: 426.7 Line No.: 1 Column: aIdaho Power has 32? ownership interest in certain transmission refated equipment located
at Nort-hwestern Energy's MiIl Creek Station.
Schedule Page: 426.7 Line No.: 5 Column: aJuint-ly owned with Sierra Paci I ic Power Company, d/b/t NV Energy. Idahc Power has a 50':
share of ownership. 1002 of the capacity reported.
Schedule Page: 426.7 Line No.: 6 Column: aJoLntly owned wlth Sierra Pacific Power Company, d/b/a NV Energy. Idaho Power has a 50tshare of ownershi-p. 100% of the capaclty reported.
FERC FORM NO. 1 (ED. 12-871 Page 450.1
1001 of the capacrty is reported.
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(21 A Resubmission
Date of Report
(Mo, Da, Yr)
04116120',19
Year/Period of Report
201BtQ4
FOOTNOTE DATA
$chedule Page:426.7 Line No.: 11 Column: aJointly owned with Portland Generat ELectric, Power Resources Cooperative and BA Leasing
BCS, LLC. ldaho Power has a 109o share of Lhe lointly owned capacity. 100? of the capacity
is reported.
Schedule Page: 426.7 Line No.: 12 Column: a
Jointly owned wit-h Portland Gener:al Electr:ic, Pr:wer Resources Cooperative and BA Leasing
BCS, LLC. ldaho Power has a 10? share of the lointly owne<l capacity. 100ti of t-he capacityis reported.
Schedule Page: 426.7 Line No.: 13 Column: a
Joint-ly owned with Portland General Eleclric, Power Resources Cooperat-ive and BA Leasing
BCS, LLC. idaho Power has a 10?; share of the jorntly owned capacity. 1002 of the capacityis reported.
Schgdule Page: 426.7 Line No.: 14 Column: aIdaho Power has a 22ee ownarship interest in certain high-voltage transmission related andinterconnection equipment located at PacifiCorp's Burns station.
Schedule Page: 426.7 Line No.: 19 Column: aIdaho Power has an ownership interest in certain high-voltage transmission rel-ated andinterconnection equipment located at PacifiCorp's Hurricane station, Ownership j-nterest
varies by terminal.
Schedule Page:42A.7 Llne No.: 36 Column: aIdaho Powei has an ownership i.nterest in certain high-voltage transm-Lssj-on related andinterconnecti-on equipment located at PacifiCorp's Summer Lake st-ation. Ownershlp interestvaries by terminal.
Schedule Page:426.7 Line No.:10 Column: aldaho Power has an ownership interest in certain hrgh-voltage transmission refated andlnterconnectj-on equipment located aL Pacif iCorp's WaI-La WalIa stati-on. Ownership int-erestvaries by termj-naL
Schedule Page:426.8 Line No.: 3 Column: aJorntly owned with PacificCorp. Tdaho Power has a 33.3,. share of ownership. 100t of thecapacity is reported.
FERC FORM NO. 1 (ED. 12-871 Page 450.2
Name
ldaho Power Company
(1)
(2\
An
A Resubmission
Date of Report
(Mo, Da, Yr)
o4t't6t2019
Year/Period of Report
End of 20181Q4
1. Report below the information called for concerning all non-power goods or services received from or provided to associated (affiliated) companies.
2. The reporting threshold for reporting purposes is $250,000. The threshold applies to the annual amount billed to the respondent or billed to
an associated/affiliated company for non-power goods and services. The good or service must be specific in nature. Respondents should not
attempt to include or aggregate amounts in a nonspecific category such as "general".
3. Where amounts billed 1o oireceived from the associated (afiiliated) 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/Affil i ated
Company
(b)
Account
Charged or
Credited
(c)
Amount
Charged or
Credited
(d)
1 Non-power Goods or Services Provided by Afliliated
2
3
4
5
6
7
8
I
10
11
12
13
't4
15
16
17
18
19
20 Non-power Goods or Services Provided for Affiliate
21 Managerial Expenses IDACORP,INC.417420 450,915
22 922000 28,844
23
24
25
26
27
28
29
30
JI
5t
33
34
35
36
37
38
39
40
41
42
FERC FORM NO.1 (New)
FERC FORM NO. 1.F (New)
Page 429
December 31, 2018
ANNUAL REPORT
IDAHO SUPPLEMENT TO FERC FORM 1
MULTI-STATE ELECTRIC COMPANIES
INDEX
Page
Number Title
Statement of lncome for the Year
Taxes Allocated to ldaho
Notes and Accounts Receivable
1
2
3
3
4
5
6
Accumulated Provision for Uncollectible Accounts
7-10
Receivables from Associated Companies
Gain or Loss on Disposition of Property
Professional or Consultative Services
Electric Plant in Service
Electric Operating Revenues
Electric Operation and Maintenance Expenses
Number of Electric Department Employees
11
12-15
15
IDAHO SUPPLEMENT
December 31, 2018
STATEMENT OF INCOME FOR THE YEAR
1. 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 414, Other Utility Operating lncome, in the same manner as accounts 412 and 4'13 above.
3. ReportdataforlinesT,9,andl0forNatural Gascompaniesusingaccounts404.1,404.2,404.3,407.1 ,and407.2.
4. Usepagel22forimportantnotesregardingthestatementofincomeoranyaccountthereof.
5. Give concise eplanations concerning unsettled rate proceedings where a contingency exists such that refunds of a
material amount may need to be made to the utility's customers or which may result in a material refund to the utility
with respect to power or gas purchases. State for each year affected the gross revenues or costs to which the contingency
relates and the tax effects together with an explanation of retain such revenues or recover amounts paid with respect
to power and gas purchases.
6. Give concise explanations concerning significant amounts of any refunds made or received during the year.
Line
No.
Account
(a)
(Ref.)
Page
No.
(b)
TOTAL
Current Year
(c)
Previous Year
(d)
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
UTILITY OPERATING INCOME
Operating Revenues (400).................
Operating Epenses
Operation Epenses (401 )...
Depreciation Expense (403).
Amort. & Depl. of Utility Plant (404-405)
Amort. of Utility Plant Acq. Adj. (406)
Amort. of Property Losses, Unrecovered Plant and
Accretion Expense (41 1 )
Regulatory Study Costs (407)...
Amort. of Conversion Epenses (407)...
Regulatory Debits/Credits (407.3 & 407.4)...
Taxes Other Than lncome Taxes (408.1)..
lncome Taxes - Federal (409.1)..............
- Other (409.1)
Provision for Deferred lncome Taxes (41 0. 1 & 41 1.1 ) Net...............
lnvestment 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 Allowances (411.8)..
Losses from Disposition of Allowances (411.9).
TOTAL Utility Operating Epenses (Enter Total of lines 4 thru 22)........
Net Utility Operating lncome (Enter Total of line 2 less 24)...
11
15
15
2
2
2
2
2
$ 1,298,775,094 $ 1,280,695,095
763,585,1 14
65,949,'185
150,355,989
6,558,945
217,614
5,068,410
32,41 1,860
19,012,075
(2,241,849)
(7,145,592)
5,180,71 0
1,038,952,461
734,257,170
57,900,000
't47,829,833
5,882,411
212.100
1,075,354
3'l ,671,383
43,471 ,706
10,223,599
(24,713,707)
7,105,14'.1
1 ,014,9 14,989
$ 259,822,633 $ 265,780,106
IDAHO SUPPLEMENT
TAXES ALLOCATED TO IDAHO
Kind of Tax
Taxes Charged
Durino Year
Taxes Other Than lncome Taxes:
Labor Related:
FrcA.............
FUT4...........
State Unemployment................
Payroll Deduction & Loading....
Total Labor Related.......
Property Taxes...........
Kilowatt-hour Tax.........................
Licenses.......
Regulatory Commission Fees......
lrrigation P1C...............
Canada Sales Tax.....
$ 14,862,163
90,031
235,946
(1 5,1 88,140)
0
27,613,224
1,797 ,547
4,173
2,724,231
272,685
0
Total Taxes Other Than lncome Taxes.32,411,860
Federal lncome Taxes...........
State lncome Taxes...........
Deferred lncome Taxes...........
lnvestment Tax Credit Adjustment - Net..........
19,012,075
(2,241,849)
(7,145,5s2)
5,180,710
Total Taxes Allocated to ldaho.$ 47,21 7,203
December 31, 2018
IDAHO SUPPLEMENT
December 31, 2018
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
I
9
10
11
12
13
14
15
16
17
18
19
20
Notes Receivable (Account 141)...
Customer Accounts Receivable (Account 142)
Other Accounts Receivable (Account 143)
(Disclose any capital stock subscription received)
Total
Less: Accumulated Provision for Uncollectible
Accounts-Cr. (Account 144\..........
Total, Less Accumulated Provision for
Uncollectible Accounts.
$(86,399)
77,764,379
28,1 69,330
$ 105,847,309
2j92,252
$ 103,655,057
$(84,743)
79.182,408
6,330,066
$ 85,427,731
1,989,131
$ 83,438,601
ACCUMULATED PROVISION FOR UNCOLLECTIBLE ACCOUNTS - CR. (Account'144)
1. Report below the information called for concerning this accumulated provision.
2. Eplain 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
31
32
33
Balance Beg of Year:
Uncollectible Retail Electric Sales
Uncollectible Damage Claims
Uncollectibe Other Revenues
Balance end of year.......
$ (2,192,252)
270,598
(84,355)
16,878
i $
$
$
$
(2,192,2_52)
270,598
(84,355)
16,878
$
$
$ (1,989,131)$$$$ (1,989,131)
IDAHO SUPPLEMENT
December 31, 2018
RECE IVABLES F ROM ASSOCIATED COM PAN I ES (Accounts 1 45, 1 46)
'1. Report particulars of notes and accounls receivable from associated companies at end of year.
2. Provide separate headings and totals for accounts 145, Notes Receivable from Associated Companies, and 146,
Accounts Receivable from Associated Companies, in addition to a total for the combined accounts.
3. For notes receivable list each note separately and state purpose for which received. Show also in column
(a) date of note, date of maturity and interest rate.
4. lf any note was received in satisfaction of an open account, state the period covered by such open account.
5. lnclude in column (f) interest recorded as income during the year, including interest on accounts and notes
held at any time during the year.
6. Give particulars of any notes pledged or discounted, also of any collateral held as guarantee of payment
of any note or account.
Line
No.(a)
Balance
Beginning
of Year
(b)
Totals for Year Balance
End of Year
(e)
lnterest
For Year
(f)
Debits
(c)
Credits
(d)
1
2
3
4
5
6
7
I
I
10
1',!
12
13
14
15
16
17
18
19
20
2',|
22
23
24
25
26
27
28
29
30
3'l
32
Account 145:
tERCO.........
Total Account 145..
Account 146:
IDACORP, lnc.
Total Account 146....................
$$$$
$4,719,060 $ 4,719,060 c
$$ 4,719,060 $ 4,719,060 $
IDAHO SUPPLEMENT
Particulars
December 31, 2018
STATE OF IDAHO - TOTAL SYSTEM DATA
GAIN OR LOSS ON DISPOSITION OF PROPERry (Account 421.1 and421.2)
'l . Give a brief description of property creating the gain or loss. lnclude name of party acquiring the property (when
acquired by another utility or associated company) and the date transaction was completed. ldentify property
by type; Leased, Held for Future Use, or Nonutility.
2. lndividual gains or losses relating to property with an original cost of less than $50,000 may be grouped, with the
number of such transactions disclosed in column (a).
3. Give the date of Commission approval of journal entries in column (b), when approval is required. Where approval
is required but has not been received, give erplanation following the item in column (a). (See account 102, Utility
Plant Purchased or Sold.)
Line
No.
Description of Property
(a)
Original Cost
of Related
(b)
Date Journal
Entry Approved
(When Required)
(c)
Accl421 .1
(d)
Acct 421 .2
(e)
$s $
$ (263,750.33)
$ (881.67)
$ 2,281,758 $ (264,632.00)
S 48,950.20 s 48,950.20
$48,950 $48,950
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
IDAHO SUPPLEMENT
property:
Common Property:
Gain $2,281,702
interest in certain Common Boardman property
to Portland General Electric to be used in the
operation of the Carty Generating Station as captured
in the Boardman balancing account and annual
compliance filing to IPUC Order 32549.
Bench Substation:
Partial land disposal to highway district.$55 95
Disposal of Non-Utility Property
December 31,2018
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
I
I
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
ACS ELECTRICAL SERVICE INC
ADAMS COUNTY SHERIFF'S OFFICE
AGREE TECHNOLOGIES AND SOLUTIO
ALLPHIN, RANDY C
ANDERSON SCHWARTZMAN WOODARD B
AVERTRA CORPORATION
BAKER BOTTS LLP
BARKER, ROSHOLT & SIMPSON LLP
BOARDVANTAGE, INC
BONFIRE TRAINING
CLEAREDGE PARTNERS
CME, INC. OF IDAHO
COMPUNET, INC
DAVIS WRIGHT TREMAINE LLP
EQ SHAREOWNER SERVICES
EVERGREEN CONSULTING GROUP, LL
FORMATION CAPITAL CONSTRUCTION
GIVENS PURSLEY LLP
HOLLAND & HART LLP
HONEYWELL INTERNATIONAL INC
ICEBERG NETWORKS CORPORATION
INDUSTRIAL HYGIENE RESOURCES,
INTELLITECT
ITRON, INC.
J M ROCHE AND ASSOCIATES
JENSEN HUGHES
JONES GLEDHILL FUHRMAN GOURLEY
KEANE
KEMA INC
KLISH GROUP
MCDOWELL RACKNER & GIBSON PC
MODISE&T,LLC
MORROW & FISCHER PLLC
NASDAQ CORPORATE SOLUTION
NIELSEN GROUP INC, THE
PACIFIC SOURCE ELECTRIC LLC
PERKINS COIE LLP
PRICE ASSOCIATES
PROFESSIONAL TRAIN ING SYSTEMS
PW CONSULTING INC
QUALITY COMMUNICATIONS INC
QUESTLINE INC
QUINTEL-MC INC
REED HARRIS ENVIRONMENTAL LTD
RESOURCE DATA, INC
Consulting Services
Management Services
lT Services
Management Services
Legal Services
Management Services
LegalServices
Legal Services
Management Services
Training Consultants
Training Consultants
Design Services
lT Services
Legal Services
Management Services
Management Services
Management Services
LegalServices
LegalServices
Management Services
lT Services
LegalServices
Management Services
lT Services
Consulting Services
Consulting Services
Legal Services
LegalServices
Management Services
Management Services
Legal Services
Training Consultants
Legal Services
Management Services
lT Services
Construction Services
Legal Services
LegalServices
Training Consultants
Consulting Services
lT Services
lT Services
lT Services
Environmental Services
lT Services
40,763.36
15,000.00
50,090.00
16,935.00
202,882.48
526,420.00
194,610.64
459,533.03
26,023.00
12,500.00
87,500.00
10,500.17
102,244.58
531,856.75
87,671.02
477,973.51
15,000.00
70,633.00
84,429.66
34,947.48
58,375.00
21,873.17
54,690.00
24,318.15
62,590.26
19,091 .06
12,017.00
19,120.00
16,810.64
20,000.00
310,051.66
15,016.75
21,760.17
26,803.69
162,149.76
23,399.50
214,476.43
10,000.00
11,243.55
43,200.00
54,245.95
16,000.00
20s,076.00
20,124.54
504,517.50
IDAHO SUPPLEMENT
Page 6
December 31,2018
STATE OF IDAHO - TOTAL SYSTEM DATA
PROFESSIONAL OR CONSULTATIVE SERVICES - ITEMS $1O,OOO AND OVER
Line
No.
PAYEE
(a)
SERVICE TYPE
(b)
Amount
(c)
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
81
82
83
84
RIGHT SYSTEMS, INC
RM ENERGY CONSULTING
SPLUNK PROFESSIONAL
STOEL RIVES LLP
SULLIVAN & CROMWELL
TALBOTT ASSOCIATES INC
TETRA TECH MA INC
TIBCO SOFTWARE INC
TRINOOR LLC
TUERI LLC
UNIVERSITY OF IDAHO
VAN NESS FELDMAN
VOLT MANAGEMENT CORP
WINANDY AND ASSOCIATES LLC
WINNER MANAGEMENT INC
ZASIO ENTERPRISES
lT Services
Management Services
Management Services
LegalServices
LegalServices
Consulting Services
Consulting Services
lT Services
lT Services
HR Consulting
Management Services
Management Services
LegalServices
Consulting Services
Management Services
Management Services
'17,510.00
31 1,831.56
25,931.25
24,912.52
85,355.26
16,058.55
80,637.75
143,971.38
248,973.81
13,294.00
304,658.21
398,734.70
21,771.39
26,658.87
11,909.82
74,000.00
TOTAL $ 6,800,674
IDAHO SUPPLEMENT
Page 6A
December 31, 2018
Line
No.
PROFESSIONAL OR CONSULTATIVE SERVICES
ITEMS $5,OOO OR MORE BUT LESS THAN $1O,OOO
PREDOMINANT
NATURE OF SERVICEPAYEE I nuouNr
1
2
3
4
5
6
7
II
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
ABB ENTERPRISE SOFTWARE INC
ABBOTT, STRINGHAM, & LYNCH
AKIN GUMP STRAUSS HAUER & FELD
CYBER ARK SOFTWARE INC
FIRE CAUSE ANALYSIS
FISERV
HAWLEY TROXELL ENNIS & HAWLEY
HEPLERBROOM LLC
IDAHO EMPLOYMENT LAWYERS, PLLC
KLARQUIST SPARKMAN LLP
MARNE AND ASSOCIATES
MICRO FOCUS SOFTWARE INC
PATRIOT ELECTRIC INC
POWER SYSTEMS CONSULTANTS INC
RAMLOW & RUDBACH PLLP
TOWERS WATSON DELAWARE INC
WITHERSPOON KELLEY
woMBLE BOND DICKINSON (US) LLP
lT Services
Legal Services
Legal Services
lT Services
LegalServices
Management Services
Legal Services
LegalServices
LegalServices
Legal Services
Consulting Services
lT Services
Electrical Contracting Services
Consulting Services
Legal Services
HR Consulting
LegalServices
Legal Services
8,937.50
8,500.00
7,913.00
9,600.00
8,250.50
7,500.00
7,962.00
6,245.79
9,400.00
5,823.55
8,195.95
6,000.00
9,640.00
8,000.00
6,460.00
9,900.00
7,063.20
6,875.00
TOTAL $ 142,266
IDAHO SUPPLEMENT
Page 6B
ELECTRIC PLANT lN SERVICE (Accounts 101,102,103 and 106)
1 . Report below the original cost of electric plant in seNice according to the prescribed accounts.
2. lnadditiontoAccountl0l,ElectricPlantinService(Classified),thispageandthenextincludeAccountl02,ElectricPlant
Purchased or Sold; Account 103, Eleerimental Electric Plant Unclassified; and Account 106, Completed Construction
Not Classified - Electric.
3. lncludeincolumn(c)or(d),asappropriate,correctionsofadditionsandrelirementsforthecunentorprecedingyear.
4. Enclose in parentheses credit adjustments of plant accounts to indicate the negative effect of such accounts.
5. ClassifyAccountl06accordingtoprescribedaccounts,onanestimatedbasisif necessary,andincludetheentriesin
column (c) . Also to be included in colum n (c) are entries for reversals of tentative distributions of prior year reported in
column(b).Likewise,iftherespondenthasasignificantamount ofplantretirementstheendoftheyear,includein
column (d) a tentative distribution of such retirements, on an estimated basis, with appropriate contra entry to the account
foraccumulateddepreciataonprovision. lncludealsoincolumn(d)reversalsoftentativedistributionsofprioryearofun-
classifed retirements. Attach supplemental statement sho /ing the account distributions of these tentative classifications in
columns (c) and (d), including the reversals of the prior years tentative account distributions of these amounts. Careful ob-
servance ofthe above instructions and the texts ofAccounts 101 and 106 will avoid serious omissions ofthe reportd amount
of respondent's plant actually in service at end of year.
Line
No.
Account
(a)
Beginning of year
(b)(c)
Additions
I
2
3
4
E
b
7
8
9
10
11
12
13
14
'15
15
17
'18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
5t
38
39
40
41
42
43
,I. INTANGIBLE PLANT
(301) Organization.
(302) Franchises and Consents..
(323) Turbogenerator Units..........
(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.
(31 1 ) Structures and lmprovements................
(3'12) Boiler Plant Equipment.
(3'13) Engines and Engine Driven Generators.
(314) Turbogenerator Units.
(315) Accessory Electric Equipment............. . ...
(316) Misc. Porer Plant Equipment.........
(31 7) Asset Retirement Costs for Steam Production... ......... ......
TOTAL Steam Production Plant (Enter Total of lines 8 thru 15)..........
B. Nuclear Production Plant
(320) Land and Land Rights......... .....
(32 1 ) Structures and I m provem ents......................
(322) Reactor Plant Equipment
(324) Accessory Electric Equipment.
(325) Misc. Porer Plant Equipment.
(326) Asset Retirement Costs for Nuclear Production......... .........
TOTAL Nuclear Production Plant (Enter Total of lines 17 thru24)....................
C. Hydraulic Production Plant
(330) Land and Land Rights.. .. .. ..
(332) Reservoirs, Dams, and Waterways........
(333) Water Wheels, Turbines, and Generators..
(334) Accessory Electric Equipment....... .. ... .....
(335) Misc. Power Plant Equipment...
(336) Roads, Railroads, and Bridges..
(337) Asset Retirement Costs for Hydraulic Production... ... ..
TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34).................
D. Other Production Plant
(340) Land and Land Rights.............. .
(34 1 ) Structures and I m provem ents......................
(342) Fuel Holders, Products and Accessories...
(343) Prime Movers.
(344) Generators.
(345) Accessory Electric Equipment...............
(346) Misc Power Plant Equipment.........
$5,457
28,735,693
21,722,267
50,463,418
14.807.729
1 ,1 31 ,205,806
784,225,548
December 31, 2018
IDAHO SUPPLEMENT
Page 7
ELECTRIC PLANT lN SERVICE (Accounts 1O1,1O2,103 and 106) (Continued)
Sho,v in column (f) reclassifications or transfers within utility plant accounts. lnclude also in column
(f) the additions or reductions of primary account classifications arising ftom distribution of amounts
initiallyrecordedinAccountl02. lnsho,vingtheclearanceofAccountl02,includeincolumn(e)the
amounts with respect to accumulated provision for depreciation, acquisition adjustments, etc., and show
in column (0 only the ofiset to the debits or credits distributed in column (f) to primary account classifications.
For Account 399, state the nature and use of plant included in this account and if substantial in amount
submit a supplementary statement showing subaccount classification of such plant conforming to the
requirements of these pages.
For each amount comprising the reported balance and changes in Account 102, state the property purchased
or sold, name of vendor or purchaser, and date of transaction. lf proposed journal entnes have been filed
with the Commission as requircd by the Uniform System of Accounts, give also date of such filing.
Retirements
(d)
Adjustments
(e)
Transfers
(0
End of Year
(s)
Line
No.
$5,466
32,124,089
27,823,244
(301)
(302)
(303)
1
2
?
4
5
o
7
q
I
10
11
12
13
14
15
16
18
,o
20
21
22
23
24
25
26
27
28
29
30
31
32
JJ
34
35
36
37
38
39
40
41
42
43
59,952,799
13,712,874
(310)
(31 1)
(312)
(313)
(314)
(315)
(316)
(317)
1 , 1 55,582,067
(320)
(321)
(322)
(323)
(324)
(325)
(326)
(330)
(331)
(332)
(333)
(334)
(33s)
(336)
(337)
863,179,181
(340)
(341)
(342)
(343)
(344)
(345)
(34s)
December 3'1, 2018
Page 8
IDAHO SUPPLEMENT
ELECTRIC PLANT lN SERVICE (Accounts 101,102,103 and 106) (Continued)
Line
No.
Account
(a)
Balance at
Beginning of year
(b)
Additions
(c)
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
oz
63
64
65
bb
67
68
69
70
71
72
73
74
75
76
77
78
79
80
81
82
83
84
85
86
ot
88
89
90
91
92
93
94
95
96
(346) Misc. Po,ver Plant Equipment.................
TOTAL Other Production Plant (Enter Total of lines 37 thru 44)........
TOTAL Production Plant (Enter Total of lines 16, 25, 35, and 45) . .
3. TRANSMISSION PLANT
(350) Land and Land Rights
(352) Structures and lmprovements..
(353) Station Equipment.........
(354) Towers and Fixtures.......
(355) Poles and FiXures.............
(356) Overhead Conductors and Devices.... ...
(357) Underground Conduit.........
(358) Underground Conductors and Devices.......
(359.1) Asset Retirement Costs for Transmission Plant.......
TOTAL Transmission Plant (Enter Total of lines 48 thru 57).............
4. DISTRIBUTION PLANT
(360) Land and Land Rights...............
(36 1 ) Structures and I m provem ents......................
(362) Stataon Equipment.........
(363) Storage Battery Equipment......................
(364) Poles, Torvers, and Fixtures.............
(365) Overhead Conductors and Devices.......
(366) Underground Conduit.........
(367) Underground Conductors and Devices.......
(368) Line Transformers.. .....
(369) Services.
(370) Meters..... ... ....
(371) lnstallations on Customer Premises..
(372) Leased Property on Customer Premises...........
(373) Street Lighting and Signal Systems..
(374) Asset Retirement Costs for Distribution P|ant...... ... ......
TOTAL Diskibution Plant (Enter Total of lines 60 thru 74)........... ..
5. GENERAL PLANT
(389) Land and Land Rights..
(390) Structures and lm provem ents................
(391) Office Furniture and Equipment..
(392) Transportation Equipm ent..
(393) Stores Equipment.........
(394) Tools, Shop, and Garage Equipment.......
(395) Laboratory Equipment...........
(396) Po/ver Operated Equipment
(397) Com m unication Equipment...
(398) Miscellaneous Equipment....
SUBTOTAL (Enter Total of lines 77 thru 86).....
(399) Other Tangible Property.. .. . .
(399.1) Asset Retirement Costs for General Plant....
TOTAL General Plant (Enter Total of lines 87, 88 and 89)
TOTAL (Accounts 101 and 106) .. ... ...
(102) Electric Plant Purchased ..
(Less) (102) Electric Plant Sold..
(103) Eperimental Plant Unclassified.
$ 522,265,343
2,488,392,245
35,546,253
76,844,700
410,649,711
1 97,756,009
175,495,311
216,945,532
373,645
1 ,1 13,61 1 , 163
5,881 ,1 80
35,655,472
227,302,609
244,612,888
1 26,868,663
50,053,945
254,802,559
537,475,593
57,896,482
86,953, I 32
2,827,642
4,315,930
1,634,646,096
16,709,488
1 15,458,161
42,978,376
84,352,770
2,820,707
9,988,646
13,271 ,792
15,564,8't7
51,804,398
6,678,546
3s9,627,703
359,627,703
5,651,116,882
$ 5,651,1 16,882
December 3't, 2018
IDAHO SUPPLEMENT
Page 9
TOTAL Electric Plant in Service.
December 31, 2018
ELECTRIC PLANT lN SERVICE (Accounts 101,102,103 and 106) (Continued)
Retirements
(d)
Adjustments
(e)
Transfers
(f)
Balance at
End of Year
(s)
Line
No.
(346)44
45
46
47
48
49
50
5l
52
53
54
55
56
R7
58
59
60
61
oz
63
64
65
b/
68
69
70
72
l5
74
75
76
78
79
80
81
82
at
84
85
86
87
88
89
90
91
92
93
94
95
96
$ 526,712,142
2,545,473,390
37,327,053
77,699,899
422,904,710
202,688,805
1 87,1 68,607
223,575,467
374,259
(3s0)
(352)
(353)
(3s4)
(35s)
(356)
(357)
(358)
(35s)
(35s.1 )
1,'151,738,801
6,382,030
38,549,556
243,790,062
250,657,981
131,147,107
51,507,071
272,O59,620
565,31 5,523
59,063,123
90,1 78,606
2,889,339
4,377 ,841
(360)
(361)
(362)
(363)
(364)
(36s)
(366)
(367)
(368)
(36s)
(370)
(371 )
(372)
(373)
(374)
1 ,715,917,8s8
I 7,006,949
122,224,951
46,492,782
89,010,450
2,897,603
10,634,272
13,134,642
18,435,818
49,773,508
7 ,070,371
(38e)
(3e0)
(3e1)
(3s2)
(3s3)
(3s4)
(3es)
(3e6)
(3e7)
(3s8)
376,681,347
(3ee)
(3ee. 1 )
376,681,347
5,849,764,1 95
(102)
(102)
(371)
$ 5,849,764,195
IDAHO SUPPLEMENT
Page'10
ELECTRIC OPERATING REVENUES (Account 400)
1. Report below operating revenues for each prescribed account, and manufactured gas revenues in total.
2. Report number of customers, columns (0 and (g), on the basis of meters, in addition to the number of flat rate
accounts; except that where separate meter readings are added for billing purposes, one customer should be counted
for each group of meters added. The average number of customers means the average of twelve figures at the close
of each month.
3. lf previous year (columns (c), (e) and (g), are not derived from previously reported figures, eplain 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
1',!
12
13
14
15
16
17
18
19
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 lndustrial)(See lnstr. 4) (2).......
(444) Public Street and Highway Lighting.
(445) Other Sales to Public Authorities.
(446) Sales to Railroads and Railways...
(448) lnterdepartmental Sales...
TOTAL Sales to Ultimate Consumers....
(447) Sales for Resale - Opportunity....Non-Firm On|y......
TOTAL Sales of Electricity
(449) Provision for Rate Refunds..
TOTAL Revenue Net of Provision for Refunds................
Other Operating Revenues
(450) Forfeited Discounts.
(451 ) Miscellaneous Service Revenues.
(453) Sales of Water and Water Power.
(454) Rent from Electric Propefi.
(455) lnterdepartmental Rents....
(456) Other Electric Revenues...
TOTAL Other Operating Revenues.........
TOTAL Electric Operating Revenues.........
$515,102,033
445,956,751
173,792,084
3,895,933
$533,040,709
446,560,444
't79,311,752
3,935,296
1 ,138,746,80'l "
75,490,649
1,162,848,202
31,832,409
't.2't4.237 ,450
(18,755,31 1),b,U4U
't ,1 95,482, 138 1 ,183,97 4,57 1
4,376,880
15.276,378
83,639,698
4,'190,975
14,488,022
78,041,526
103,292,956 96,720,524
$'t ,298,775,095 $1,280,695,095
(1) Commercial and lndustrial sales - Small - under 1 ,000 KW and includes all irrigation customers.
(2) Commercial and lndustrial sales - Large - 1,000 KW and over.
December 31, 2018
1,194,680,611
0,
IDAHO SUPPLEMENT
Page 11
ELECTRIC OPERATING REVENUES (Account 400) (Continued)
4. Commercial and lndustrial Sales, Account 442, may be classified according to the basis of classification
(Small or Commercial, and Large or lndustrial) regularly used by the respondent if such basis of classification
is not generally greater than 1 000 Kw of demand. (See Account 442 of the Uniform System of Accounts. Explain
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 revenue by accounts.
7. lnclude unmetered sales. Provide details of such sales in a footnote.
KILOWATT HOURS SOLD AVERAGE NUMBER OF CUSTOMERS PER MONTH
Line
No.
Amount for
Current Year
(d)
Amount for
Previous Year
(e)
Amount for
Current Year
(f)
Number for
Previous Year
(s)
4,957,730,706
5,826,402,202
3,092,546,384
31,311,937
5,16'l ,44'l ,049
5,619,619,511
3,076,839,087
30,888,003
445,693
83,351
111
3,246
435.376
82,202
'I 13
2,961
1
2
3
4
5
6
7
8
I
10
11
't2
13
13,907,991 ,229 *
2,73',t,016,573
13,888,787,650
2,036,515,949
532,401
N/A
520,652
N/A
16,639,007,802 15,925,303,599 532,401 520.652
* lncludes <$6,028,313> in unbilled revenues
*" lncludes <15,218,904> KWH relating to unbilled revenues
Lines 1 1 through 21 are on an "allocated" basis.
December 3{,2018
IDAHO SUPPLEMENT
Page 1 1a
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
lf the amount for previous year is not derived from previously reported ligures, eplain in footnotes.
Line
No.Account
(a)
Amount for
Curent Year
(b)
Amount for
Previous Year
(c)
1 1. POWER PROOUCTION EXPENSES
2
3
4
5
6
7
8
9
10
1'l
12
'13
14
15
16
17
18
19
20
2'l
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
A. Steam Power Generation
Operation
(500) Operation Supervision and Engineering...
(501) Fue|.............
(502) Steam Epenses.............
(503) Steam from Other Sources........
(Less) (504) Steam Transfened-Cr.......................
(505) Electric E}penses.....................
(506) Miscellaneous Steam Power Epenses...................
(507) Rents..........
(509) Allowances..
TOTAL Operation (Enter Total of lines 4 thru 1 2).......................
Maintenance
(510) Maintenance Supervision and Engineering...
(5'l'l ) Maintenance of Struclures........
(512) Maintenance of Boiler Plant.......
(513) Maintenance of Electric P|ant....................
(5'14) Miscellaneous Steam Plant.......
TOTAL Maintenance (Enter Total of Lines 15 thru 19).......................
TOTAL Power Production Expenses-Steam Power (Enter Total of lines 'l 3 and 20
B. Nuclear Power Generation
Operation
(517) Operation Supervision and Engineering................
(518) Fue|............
(519) Coolants and Water............
(520) Steam Epenses.............
(521 ) Steam from Other Sources......
(Less) (522) Steam Transfened-Cr.............. ..... ... ..
(523) Electric Epenses.............
(524) Miscellaneous Nuclear Power E&enses...........
(525) Rents..........
TOTAL Operation (Enter Total of lines 24 thru 32).....
Mainlenance
(528) Maintenance Supervision and Engineering..............
(529) Maintenance of Structures........
(530) Maintenance of Reactor Plant Equipment.......
(531) Maintenance of Electric Plant....
(532) Maintenance of Miscellaneous Nuclear Plant......
TOTAL Power Production Epenses-Nuclear Power (Enter Tolal of lines 33 and 4
C. Hydraulic Power Generation
Operation
(535) Operation Supervision and Engineering...
(536) Water for Power.......................
(537) Hydraulic Epenses.............
(538) Electric Epenses.....................
(539) Miscellaneous Hydraulic Power Generation Epenses.............
(540) Rents..........
TOTAL Operation (Enter Total of lines 44 thru 49)................
'I ,155,520
1 1 0,1 73,838
9,453,657
't,781 ,902
8,759,642
240,572
$$937,038
102,885,430
8,1 06,81 2
1,33',t,231
1 I ,1 96,839
3r4,936
13'r ,565,131 124,772,286
204,509
335,091
10,344,847
4,334,537
6,849,739
52,876
421,677
10,5't9,310
4,1 30,31 8
5,682,502
22,068,724 20,806,683
153,633,854 1 45,578,969
5,396,1 96
8,749,433
14,756,128
1,805,309
5,371 ,1 '19
236,585
5,455,102
5,607,626
14,369,221
't,829,572
7,918,583
23',t,490
36,314,771 35,41 1,594
Oecember 31, 2018
IDAHO SUPPLEMENT
Page l2
December 31, 2018
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
lf the amount for previous year is not derived from previously reported figures, eplain in footnotes.
Line
No.Account
(a)
Amount lor
Curent Year
(b)
Amount lor
Previous Year
(c)
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
81
82
83
84
85
86
87
88
89
90
9'l
92
93
94
95
96
97
98
99
100
101
102
'103
104
C. Hydraulic Power Generation (Continued)
Maintenance
L (541 ) Maintenance Supervision and Engineering...
l(542) Maintenance of Struclures......
(543) Maintenance of Reservoirs, Dams, and Walerways..
(544) Maintenance of Electric Plant.... ...
(545) Maintenance of Miscellaneous Hydraulic P|ant....................
TOTAL Maintenance (Enler Total of lines 53 thru 57). ... ................
TOTAL Power Production Epenses-Hydraulic Power (Enter Total of lines 50 and 5
D C)lher Power Generation
Operation
(546) Operation Superuision and Engineering...
(547) Fue|............
(548) Generation Epenses..............
(549) Miscellaneous Other Power Generation Epenses..
(550) Rents..........
TOTAL Operation (Enter Total of lines 62 thru 66).......................
Maintenance
(551) Maintenance Supervision and Engineering...
(552) Maintenance of Structures.........
(553) Maintenance of Generating and Electric P|ant.....................
(554) Maintenance of Miscellaneous Other Power Generation P|ant...........
TOTAL Maintenance (Enter Total of lines 69 thru 72)................
TOTAL Power Production Epenses-Other Power (Enter Total of lines 67 and 73)..
E. Other Power Supply Epenses
(555) Purchased Power...................
(556) System Control and Load Dispatching..
(557) Other Epenses.............
TOTAL Other Power Supply Epenses (Enter Total of lines 76 thru 78)..................
TOTAL Power Production Epenses (Enter Total of lines 21 , 41,59,74, and 79)....
2, TRANSMISSION EXPENSES
Operation
(560) Operation Superuision and Engineering...
(561 ) Load Dispatching..........
(562) Station Epenses.............
(563) Overhead Line Epenses......
(564) Underground Line Expenses......
(565) Transmission of Electricity by Others.............
(566) Miscellaneous Transmission Epenses.............
(567) Rents..........
TOTAL Operation (EnterTotal of lines 83 thru 90).......................
Mainlenance
(568) Maintenan@ Supervision and Engineering...
(569) Maintenance of Structures.........
(570) Maintenance of Station Equipment............
(57'l ) Maintenance of Overhead Lines....................
(572) Maintenance of Underground Lines....................
(573) Maintenance of Miscellaneous TEnsmission P|ant.....................
(575) Transmission Market Administration - E1M.......... ITOTAL Maintenance (Enter Total of lines 93 thru 98).......................
TOTAL Transmission Epenses (EnlerTotal of lines 9'l and 99).............................
3. DISTRIBUTION EXPENSES
Operation
(580) Operation Supervision and Engineering..
$89,694
714,521
318,930
2,858,509
2,557,498
$90,009
1,090,583
786,880
1 ,795,1 '18
2,699,480
6,539,1 52 6,462,O71
42,853,923 41,873,665
622,330
16,855,435
4,318,143
1,348,858
0
658,619
36,174,281
3,987,044
944,800
0
23,144,766 41,764,744
38
206,463
'119,167
2,532,681
2',t7
320,820
567,680
2,131,303
2,858,348 3,O20,O21
26,003,1 15 44,784,765
274,440,071
5,112
46,425,241
233,O48,178
2,762
55,329,959
320,870,425 288,380,900
543,361 ,31 7 520,6 1 8,298
3,1 82,043
5,108,212
2,737,873
842,589
3,435,332
't4,542
2,599,291
3,016,021
4,680,012
2,764,665
1,024,360
4,356,342
24
4,577,995
17,919,884 20,419,423
682,937
1 ,027 ,121
1 ,650,310
797,893
0
394,805
1 48,1 35
924,202
'1,843,040
845,567
3,214
0
4,553,067 3,764,',t57
22.472,951 24,1 83,580
4,357,348 4,023,195
IDAHO SUPPLEMENT
Page'13
December 31, 2018
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
lf the amount for previous year is not derived from previously reported ligures, eplain in footnotes.
Lrne
No.Account
(a)
Amount for
Cunent Year
(b)
Amount for
Previous Year
(c)
105
106
't07
'108
109
110
111
112
113
't14
115
1'16
1',t7
118
't 19
120
121
122
123
124
't25
126
't27
124
129
130
131
't32
133
't34
135
'136
137
138
139
'140
141
142
143
144
145
146
147
148
149
150
151
152
't53
154
3. DISTRIBUTION EXPENSES (Continued)
(581 ) Load Dispatching..........
(582) Station Epenses.............
(583) Overhead Line Epenses......
(584) Underground Line Epenses......
(585) Street Lighting and Signal System Epenses.............
(586) Meter Epenses.......................
(587) Customer lnstallalions Epenses.............
(588) Miscellaneous Distribution Expenses.............
(589) Rents..........
TOTAL Operation (Enter Total of lines 1 03 thru 1 13).....................
Mainlenance
(590) Maintenance SupeMsion and Engineering...
(591 ) Maintenance of Structures........
(592) Maintenance of Station Equiprnent............
(593) Maintenance of Overhead Lines....................
(594) Maintenance of Underground Lines....................
(595) Maintenance of Line Transformers.........................
(596) Maintenance of Street Lighting and Signal Systems...............
(597) Maintenance of Meters..............
(598) Maintenance of Miscellaneous Distribution P|ant....................
TOTAL Maintenance (Enter Total of lines 1 1 6 thru 1241.....................
TOTAL Distribution Erpenses (Enter Total of lines 1 14 and 1 25)............................
4. CUSTOMER ACCOUNTS EXPENSES
Operation
(901) Supervision..
(902) Meter Reading Epenses........
(903) Customer Records and Collection Epenses.............
(904) Uncollectible Accounts..............
(905) Miscellaneous Customer Accounts Epenses........
TOTALCustomerAccountsEpenses(EnlerTolal of lines 129thru 133)...............
5. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
Operation
(907) Supervision.
(908) Customer Assistance Epenses
(909) lnformational and lnstructional Epenses.............
(910) Miscellaneous CustomerService and lnformational E}penses.............
TOTAL Cust. SeMce and lnformational Expenses (Enter Total of lines 1 37 thru 140
6. SALES EXPENSES
Operation
(91 1) Supervision.
(9'12) Oemonstrating and Selling Expenses.............
(9'l 3) Advertising E}eenses.............
(916) Miscellaneous Sales Epenses.
TOTAL Sales Epenses (Enter Total of lines 144 thru 147)..............
7, ADMINISTRATIVE AND GENERAL EXPENSES
Operalion
(920) Administrative and General Sa|aries................
(921) Otrce Supplies and Epenses.............
(Less) (922) Administrative Epenses Transfened-Credit
4,189,473
1 ,500,814
3,609,640
3,344,179
150,601
4,416,499
1,',t90/32
4,729,553
1 ,1 52,606
$3,999,053
1,489,990
4,549,577
3,563,678
't13.144
4,737,753
1 ,'t 80,48'l
6,583,446
364,520
$
28,64',t,144 30,604,836
579,205
(1,003)
4,295,998
16,1 '18,896
693,844
43,864
562,210
880,694
198,061
(1,571,512)
0
3,722,890
12,787,293
737,53'l
22,883
528,581
949,377
222,377
23,37',t,771 17,399,4'19
52,O12,915 48,004,255
1,049,380
1,329,653
13,471 ,174
3,124,277
(4)
896,826
't,212,550
1 3,709,1 89
5,331,296
(8e0)
18,974,480 21,148,97'l
760,145
40,240,668
329,947
594,765
778,O82
4'r,859,835
429,O07
608,294
41,925,525 43.675,218
84,653,093
14,095,1 1 1
(27,846,24O)
75,372,652
'13,472,O38
(26,461,608)
IDAHO SUPPLEMENT
Page 14
Decem ber 31, 201 8
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
lf the amount for previous year is nol derived from previously reported figures, eplain in foolnotes.
Line
No.Account
(a)
Amount tor
Cunent Year
(b)
Amount Ior
Previous Year
(c)
155
156
157
'158
159
160
161
't62
163
164
165
166
't67
168
169
170
7. ADMINISTRATIVE AND GENERAL EXPENSES (Continued)
(923) Outside Seruices Employed
(924) Properly lnsurance.............
(925) lnjuries and Damages..............
(926) Employee Pensions and Benefits................
(927) Franchise Requirements.......
(928) Regulatory Commission Epenses.............
(929) Ouplicate Charges-Cr...........
(930. 1 ) General Advertising Expenses.............
(930.2) Miscellaneous General Epenses.............
(931) Rents.........
TOTAL Operation (EnterTotal oflines 151 thru 164)............
Maintenance
(935) Maintenance of General P|ant....................
TOTAL Admin and General Epenses (Enter Total of lines 165-167)...
TOTALElecOpandMaintEp(Total of 80, 100, 126, 134,'141,148,'168)...........
$7,380,095
2,886,373
5,353,427
49,572,548
0
4,123,497
575,403
3,435,682
0
$6,452,407
2,984,435
5,382,410
43,415,053
0
3,725,080
347,329
3,389,737
(335)
144,228,988 128,O79,'t97
6,558,1 23 6,447,650
150,787,112 1 34,526,848
$829,534,299 $752,157,',t70
IDAHO ONLY
NUMBER OF ELECTRIC DEPARTMENT EMPLOYEES
'l . The data on number of employees should be reported for the payroll period ending nearest to October 31
or any payroll period ending 60 days before or afier october 31.
2. lfthe respondent's payroll forthe reporting period includes any special construction personnel, include
such employees on line 3, and show the number of such special construction employees in a footnote.
3. The number of employees assignable to the electric deparlment from joint functions of combination utilities
maybedeterminedbyestimate,onthebasisofemployeeequivalents. Showtheestimatednumberofequiv-
alenl employees attributed to the electric department from joint functions.
1 Payroll Period Ended (Dale)..... .. ... ...
2 Total Regular Full-'lrme Emp|oyees.......................
3 Total Part-Time and Temporary Employees............
4 Total Emp|oyees..........................
,"*rr"rarrrrr
l
,a::l
December 31, 2018
't,972
7
1,979
IDAHO SUPPLEMENT
Page 15