2022 Annual Report.pdf

MATTHEW T. LARKIN
Revenue Requirement Senior Manager
[e-mail]
May 1, 2023
VIA ELECTRONIC FILING
Jan Noriyuki, Secretary
Idaho Public Utilities Commission
11331 W. Chinden Blvd., Bldg 8,
Suite 201-A (83714)
PO Box 83720
Boise, Idaho 83720-0074
Re: Idaho Power Company’s 2022 Annual FERC Form 1 Report
Dear Ms. Noriyuki:
Pursuant to Idaho Code § 61-405, attached for electronic filing are Idaho Power
Company’s FERC Form 1 Report and Idaho Supplement for the year ending December 31,
2022. Also included is the IDACORP 2022 Annual Report.
If you have any questions, please contact Regulatory Consultant Kelley Noe at
208-388-5736 or [e-mail].
Very truly yours,
Matthew T. Larkin
MTL:sg
Enclosures
RECEIVED
Monday, May 1, 2023 3:12:58 PM
IDAHO PUBLIC
UTILITIES COMMISSION
IPC-E
THIS FILING IS
Item 1: ☑ An Initial (Original) Submission OR ☐ Resubmission No.
FERC FINANCIAL REPORT
FERC FORM No. 1: Annual Report of
Major Electric Utilities, Licensees
and Others and Supplemental
Form 3-Q: Quarterly Financial Report
These reports are mandatory under the Federal Power Act, Sections 3, 4(a),
304 and 309, and 18 CFR 141.1 and 141.400. Failure to report may result in
criminal fines, civil penalties and other sanctions as provided by law. The
Federal Energy Regulatory Commission does not consider these reports to be
of confidential nature
Exact Legal Name of Respondent (Company)
Idaho Power Company
Year/Period of Report
End of: 2022/ Q4
FERC FORM NO. 1 (REV. 02-04)
INSTRUCTIONS FOR FILING FERC FORM NOS. 1 and 3-Q
GENERAL INFORMATION
Purpose
FERC Form No. 1 (FERC Form 1) is an annual regulatory requirement for Major electric utilities, licensees and others (18 C.F.R. § 141.1).
FERC Form No. 3-Q ( FERC Form 3-Q) is a quarterly regulatory requirement which supplements the annual financial reporting
requirement (18 C.F.R. § 141.400). These reports are designed to collect financial and operational information from electric utilities,
licensees and others subject to the jurisdiction of the Federal Energy Regulatory Commission. These reports are also considered to be
non-confidential public use forms.
Who Must Submit
Each Major electric utility, licensee, or other, as classified in the Commission’s Uniform System of Accounts Prescribed for Public Utilities,
Licensees, and Others Subject To the Provisions of The Federal Power Act (18 C.F.R. Part 101), must submit FERC Form 1 (18 C.F.R. §
141.1), and FERC Form 3-Q (18 C.F.R. § 141.400).
Note: Major means having, in each of the three previous calendar years, sales or transmission service that exceeds one of the following:
one million megawatt hours of total annual sales,
100 megawatt hours of annual sales for resale,
500 megawatt hours of annual power exchanges delivered, or
500 megawatt hours of annual wheeling for others (deliveries plus losses).
What and Where to Submit
Submit FERC Form Nos. 1 and 3-Q electronically through the eCollection portal at https://eCollection.ferc.gov, and according to the
specifications in the Form 1 and 3-Q taxonomies.
The Corporate Officer Certification must be submitted electronically as part of the FERC Forms 1 and 3-Q filings.
Submit immediately upon publication, by either eFiling or mail, two (2) copies to the Secretary of the Commission, the latest Annual
Report to Stockholders. Unless eFiling the Annual Report to Stockholders, mail the stockholders report to the Secretary of the
Commission at:
Secretary
Federal Energy Regulatory Commission 888 First Street, NE
Washington, DC 20426
For the CPA Certification Statement, submit within 30 days after filing the FERC Form 1, a letter or report (not applicable to filers
classified as Class C or Class D prior to January 1, 1984). The CPA Certification Statement can be either eFiled or mailed to the
Secretary of the Commission at the address above.
The CPA Certification Statement should:
Attest to the conformity, in all material aspects, of the below listed (schedules and pages) with the Commission's applicable
Uniform System of Accounts (including applicable notes relating thereto and the Chief Accountant's published accounting
releases), and
Be signed by independent certified public accountants or an independent licensed public accountant certified or licensed by a
regulatory authority of a State or other political subdivision of the U. S. (See 18 C.F.R. §§ 41.10-41.12 for specific
qualifications.)
Schedules Pages
Comparative Balance Sheet 110-113
Statement of Income 114-117
Statement of Retained Earnings 118-119
Statement of Cash Flows 120-121
Notes to Financial Statements 122-123
The following format must be used for the CPA Certification Statement unless unusual circumstances or conditions, explained in the
letter or report, demand that it be varied. Insert parenthetical phrases only when exceptions are reported.
“In connection with our regular examination of the financial statements of [COMPANY NAME] for the year ended on which we have
reported separately under date of [DATE], we have also reviewed schedules [NAME OF SCHEDULES] of FERC Form No. 1 for the
year filed with the Federal Energy Regulatory Commission, for conformity in all material respects with the requirements of the
Federal Energy Regulatory Commission as set forth in its applicable Uniform System of Accounts and published accounting
releases. Our review for this purpose included such tests of the accounting records and such other auditing procedures as we
considered necessary in the circumstances.
Based on our review, in our opinion the accompanying schedules identified in the preceding paragraph (except as noted below)
conform in all material respects with the accounting requirements of the Federal Energy Regulatory Commission as set forth in its
applicable Uniform System of Accounts and published accounting releases.” The letter or report must state which, if any, of the
I.
II.
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III.
a.
b.
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INSTRUCTIONS FOR FILING FERC FORM NOS. 1 and 3-QGENERAL INFORMATIONPurposeFERC Form No. 1 (FERC Form 1) is an annual regulatory requirement for Major electric utilities, licensees and others (18 C.F.R. § 141.1).FERC Form No. 3-Q ( FERC Form 3-Q) is a quarterly regulatory requirement which supplements the annual financial reportingrequirement (18 C.F.R. § 141.400). These reports are designed to collect financial and operational information from electric utilities,licensees and others subject to the jurisdiction of the Federal Energy Regulatory Commission. These reports are also considered to benon-confidential public use forms.Who Must SubmitEach Major electric utility, licensee, or other, as classified in the Commission’s Uniform System of Accounts Prescribed for Public Utilities,Licensees, and Others Subject To the Provisions of The Federal Power Act (18 C.F.R. Part 101), must submit FERC Form 1 (18 C.F.R. §141.1), and FERC Form 3-Q (18 C.F.R. § 141.400).Note: Major means having, in each of the three previous calendar years, sales or transmission service that exceeds one of the following:one million megawatt hours of total annual sales,100 megawatt hours of annual sales for resale,500 megawatt hours of annual power exchanges delivered, or500 megawatt hours of annual wheeling for others (deliveries plus losses).What and Where to SubmitSubmit FERC Form Nos. 1 and 3-Q electronically through the eCollection portal at https://eCollection.ferc.gov, and according to thespecifications in the Form 1 and 3-Q taxonomies.The Corporate Officer Certification must be submitted electronically as part of the FERC Forms 1 and 3-Q filings.Submit immediately upon publication, by either eFiling or mail, two (2) copies to the Secretary of the Commission, the latest AnnualReport to Stockholders. Unless eFiling the Annual Report to Stockholders, mail the stockholders report to the Secretary of theCommission at:SecretaryFederal Energy Regulatory Commission 888 First Street, NEWashington, DC 20426For the CPA Certification Statement, submit within 30 days after filing the FERC Form 1, a letter or report (not applicable to filersclassified as Class C or Class D prior to January 1, 1984). The CPA Certification Statement can be either eFiled or mailed to theSecretary of the Commission at the address above.The CPA Certification Statement should:Attest to the conformity, in all material aspects, of the below listed (schedules and pages) with the Commission's applicableUniform System of Accounts (including applicable notes relating thereto and the Chief Accountant's published accountingreleases), andBe signed by independent certified public accountants or an independent licensed public accountant certified or licensed by aregulatory authority of a State or other political subdivision of the U. S. (See 18 C.F.R. §§ 41.10-41.12 for specificqualifications.)Schedules PagesComparative Balance Sheet 110-113Statement of Income 114-117Statement of Retained Earnings 118-119Statement of Cash Flows 120-121Notes to Financial Statements 122-123The following format must be used for the CPA Certification Statement unless unusual circumstances or conditions, explained in theletter or report, demand that it be varied. Insert parenthetical phrases only when exceptions are reported.“In connection with our regular examination of the financial statements of [COMPANY NAME] for the year ended on which we havereported separately under date of [DATE], we have also reviewed schedules [NAME OF SCHEDULES] of FERC Form No. 1 for theyear filed with the Federal Energy Regulatory Commission, for conformity in all material respects with the requirements of theFederal Energy Regulatory Commission as set forth in its applicable Uniform System of Accounts and published accountingreleases. Our review for this purpose included such tests of the accounting records and such other auditing procedures as weconsidered necessary in the circumstances.Based on our review, in our opinion the accompanying schedules identified in the preceding paragraph (except as noted below)
conform in all material respects with the accounting requirements of the Federal Energy Regulatory Commission as set forth in its
applicable Uniform System of Accounts and published accounting releases.” The letter or report must state which, if any, of the
I.II.1.2.3.4.III.a.b.c.d.a.b.e.
applicable Uniform System of Accounts and published accounting releases.” The letter or report must state which, if any, of the
pages above do not conform to the Commission’s requirements. Describe the discrepancies that exist.
Filers are encouraged to file their Annual Report to Stockholders, and the CPA Certification Statement using eFiling. Further
instructions are found on the Commission’s website at https://www.ferc.gov/ferc-online/ferc-online/frequently-asked-questions-faqs-
efilingferc-online.
Federal, State, and Local Governments and other authorized users may obtain additional blank copies of FERC Form 1 and 3-Q
free of charge from https://www.ferc.gov/general-information-0/electric-industry-forms.
When to Submit
FERC Forms 1 and 3-Q must be filed by the following schedule:
FERC Form 1 for each year ending December 31 must be filed by April 18th of the following year (18 CFR § 141.1), and
FERC Form 3-Q for each calendar quarter must be filed within 60 days after the reporting quarter (18 C.F.R. § 141.400).
Where to Send Comments on Public Reporting Burden.
The public reporting burden for the FERC Form 1 collection of information is estimated to average 1,168 hours per response, including
the time for reviewing instructions, searching existing data sources, gathering and maintaining the data-needed, and completing and
reviewing the collection of information. The public reporting burden for the FERC Form 3-Q collection of information is estimated to
average 168 hours per response.
Send comments regarding these burden estimates or any aspect of these collections of information, including suggestions for reducing
burden, to the Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC 20426 (Attention: Information Clearance
Officer); and to the Office of Information and Regulatory Affairs, Office of Management and Budget, Washington, DC 20503 (Attention:
Desk Officer for the Federal Energy Regulatory Commission). No person shall be subject to any penalty if any collection of information
does not display a valid control number (44 U.S.C. § 3512 (a)).
GENERAL INSTRUCTIONS
Prepare this report in conformity with the Uniform System of Accounts (18 CFR Part 101) (USofA). Interpret all accounting words and
phrases in accordance with the USofA.
Enter in whole numbers (dollars or MWH) only, except where otherwise noted. (Enter cents for averages and figures per unit where cents
are important. The truncating of cents is allowed except on the four basic financial statements where rounding is required.) The amounts
shown on all supporting pages must agree with the amounts entered on the statements that they support. When applying thresholds to
determine significance for reporting purposes, use for balance sheet accounts the balances at the end of the current reporting period, and
use for statement of income accounts the current year's year to date amounts.
Complete each question fully and accurately, even if it has been answered in a previous report. Enter the word "None" where it truly and
completely states the fact.
For any page(s) that is not applicable to the respondent, omit the page(s) and enter "NA," "NONE," or "Not Applicable" in column (d) on
the List of Schedules, pages 2 and 3.
Enter the month, day, and year for all dates. Use customary abbreviations. The "Date of Report" included in the header of each page is to
be completed only for resubmissions (see VII. below).
Generally, except for certain schedules, all numbers, whether they are expected to be debits or credits, must be reported as positive.
Numbers having a sign that is different from the expected sign must be reported by enclosing the numbers in parentheses.
For any resubmissions, please explain the reason for the resubmission in a footnote to the data field.
Do not make references to reports of previous periods/years or to other reports in lieu of required entries, except as specifically
authorized.
Wherever (schedule) pages refer to figures from a previous period/year, the figures reported must be based upon those shown by the
report of the previous period/year, or an appropriate explanation given as to why the different figures were used.
Schedule specific instructions are found in the applicable taxonomy and on the applicable blank rendered form.
Definitions for statistical classifications used for completing schedules for transmission system reporting are as follows:
FNS - Firm Network Transmission Service for Self. "Firm" means service that can not be interrupted for economic reasons and is intended to
remain reliable even under adverse conditions. "Network Service" is Network Transmission Service as described in Order No. 888 and the
Open Access Transmission Tariff. "Self" means the respondent.
FNO - Firm Network Service for Others. "Firm" means that service cannot be interrupted for economic reasons and is intended to remain
reliable even under adverse conditions. "Network Service" is Network Transmission Service as described in Order No. 888 and the Open
Access Transmission Tariff.
LFP - for Long-Term Firm Point-to-Point Transmission Reservations. "Long-Term" means one year or longer and” firm" means that service
cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions. "Point-to-Point Transmission
Reservations" are described in Order No. 888 and the Open Access Transmission Tariff. For all transactions identified as LFP, provide in a
footnote the termination date of the contract defined as the earliest date either buyer or seller can unilaterally cancel the contract.
OLF - Other Long-Term Firm Transmission Service. Report service provided under contracts which do not conform to the terms of the Open
Access Transmission Tariff. "Long-Term" means one year or longer and “firm” means that service cannot be interrupted for economic reasons
and is intended to remain reliable even under adverse conditions. For all transactions identified as OLF, provide in a footnote the termination
f.
g.
IV.
a.
b.
V.
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III.
IV.
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VI.
VII.
VIII.
IX.
X.
applicable Uniform System of Accounts and published accounting releases.” The letter or report must state which, if any, of thepages above do not conform to the Commission’s requirements. Describe the discrepancies that exist.Filers are encouraged to file their Annual Report to Stockholders, and the CPA Certification Statement using eFiling. Furtherinstructions are found on the Commission’s website at https://www.ferc.gov/ferc-online/ferc-online/frequently-asked-questions-faqs-efilingferc-online.Federal, State, and Local Governments and other authorized users may obtain additional blank copies of FERC Form 1 and 3-Qfree of charge from https://www.ferc.gov/general-information-0/electric-industry-forms.When to SubmitFERC Forms 1 and 3-Q must be filed by the following schedule:FERC Form 1 for each year ending December 31 must be filed by April 18th of the following year (18 CFR § 141.1), andFERC Form 3-Q for each calendar quarter must be filed within 60 days after the reporting quarter (18 C.F.R. § 141.400).Where to Send Comments on Public Reporting Burden.The public reporting burden for the FERC Form 1 collection of information is estimated to average 1,168 hours per response, includingthe time for reviewing instructions, searching existing data sources, gathering and maintaining the data-needed, and completing andreviewing the collection of information. The public reporting burden for the FERC Form 3-Q collection of information is estimated toaverage 168 hours per response.Send comments regarding these burden estimates or any aspect of these collections of information, including suggestions for reducingburden, to the Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC 20426 (Attention: Information ClearanceOfficer); and to the Office of Information and Regulatory Affairs, Office of Management and Budget, Washington, DC 20503 (Attention:Desk Officer for the Federal Energy Regulatory Commission). No person shall be subject to any penalty if any collection of informationdoes not display a valid control number (44 U.S.C. § 3512 (a)).GENERAL INSTRUCTIONSPrepare this report in conformity with the Uniform System of Accounts (18 CFR Part 101) (USofA). Interpret all accounting words andphrases in accordance with the USofA.Enter in whole numbers (dollars or MWH) only, except where otherwise noted. (Enter cents for averages and figures per unit where centsare important. The truncating of cents is allowed except on the four basic financial statements where rounding is required.) The amountsshown on all supporting pages must agree with the amounts entered on the statements that they support. When applying thresholds todetermine significance for reporting purposes, use for balance sheet accounts the balances at the end of the current reporting period, anduse for statement of income accounts the current year's year to date amounts.Complete each question fully and accurately, even if it has been answered in a previous report. Enter the word "None" where it truly andcompletely states the fact.For any page(s) that is not applicable to the respondent, omit the page(s) and enter "NA," "NONE," or "Not Applicable" in column (d) onthe List of Schedules, pages 2 and 3.Enter the month, day, and year for all dates. Use customary abbreviations. The "Date of Report" included in the header of each page is tobe completed only for resubmissions (see VII. below).Generally, except for certain schedules, all numbers, whether they are expected to be debits or credits, must be reported as positive.Numbers having a sign that is different from the expected sign must be reported by enclosing the numbers in parentheses.For any resubmissions, please explain the reason for the resubmission in a footnote to the data field.Do not make references to reports of previous periods/years or to other reports in lieu of required entries, except as specificallyauthorized.Wherever (schedule) pages refer to figures from a previous period/year, the figures reported must be based upon those shown by thereport of the previous period/year, or an appropriate explanation given as to why the different figures were used.Schedule specific instructions are found in the applicable taxonomy and on the applicable blank rendered form.Definitions for statistical classifications used for completing schedules for transmission system reporting are as follows:FNS - Firm Network Transmission Service for Self. "Firm" means service that can not be interrupted for economic reasons and is intended toremain reliable even under adverse conditions. "Network Service" is Network Transmission Service as described in Order No. 888 and theOpen Access Transmission Tariff. "Self" means the respondent.FNO - Firm Network Service for Others. "Firm" means that service cannot be interrupted for economic reasons and is intended to remainreliable even under adverse conditions. "Network Service" is Network Transmission Service as described in Order No. 888 and the OpenAccess Transmission Tariff.LFP - for Long-Term Firm Point-to-Point Transmission Reservations. "Long-Term" means one year or longer and” firm" means that servicecannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions. "Point-to-Point TransmissionReservations" are described in Order No. 888 and the Open Access Transmission Tariff. For all transactions identified as LFP, provide in afootnote the termination date of the contract defined as the earliest date either buyer or seller can unilaterally cancel the contract.OLF - Other Long-Term Firm Transmission Service. Report service provided under contracts which do not conform to the terms of the Open
Access Transmission Tariff. "Long-Term" means one year or longer and “firm” means that service cannot be interrupted for economic reasons
and is intended to remain reliable even under adverse conditions. For all transactions identified as OLF, provide in a footnote the termination
f.g.IV.a.b.V.I.II.III.IV.V.VI.VII.VIII.IX.X.
date of the contract defined as the earliest date either buyer or seller can unilaterally get out of the contract.
SFP - Short-Term Firm Point-to-Point Transmission Reservations. Use this classification for all firm point-to-point transmission reservations,
where the duration of each period of reservation is less than one-year.
NF - Non-Firm Transmission Service, where firm means that service cannot be interrupted for economic reasons and is intended to remain
reliable even under adverse conditions.
OS - Other Transmission Service. Use this classification only for those services which can not be placed in the above-mentioned
classifications, such as all other service regardless of the length of the contract and service FERC Form. Describe the type of service in a
footnote for each entry.
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.
DEFINITIONS
Commission Authorization (Comm. Auth.) -- The authorization of the Federal Energy Regulatory Commission, or any other Commission.
Name the commission whose authorization was obtained and give date of the authorization.
Respondent -- The person, corporation, licensee, agency, authority, or other Legal entity or instrumentality in whose behalf the report is
made.
EXCERPTS FROM THE LAW
Federal Power Act, 16 U.S.C. § 791a-825r
Sec. 3. The words defined in this section shall have the following meanings for purposes of this Act, to with:
’Corporation' means any corporation, joint-stock company, partnership, association, business trust, organized group of persons, whether
incorporated or not, or a receiver or receivers, trustee or trustees of any of the foregoing. It shall not include 'municipalities, as hereinafter
defined;
'Person' means an individual or a corporation;
'Licensee, means any person, State, or municipality Licensed under the provisions of section 4 of this Act, and any assignee or successor
in interest thereof;
'municipality means a city, county, irrigation district, drainage district, or other political subdivision or agency of a State competent under
the Laws thereof to carry and the business of developing, transmitting, unitizing, or distributing power; ......
"project' means. a complete unit of improvement or development, consisting of a power house, all water conduits, all dams and
appurtenant works and structures (including navigation structures) which are a part of said unit, and all storage, diverting, or fore bay
reservoirs directly connected therewith, the primary line or lines transmitting power there from to the point of junction with the distribution
system or with the interconnected primary transmission system, all miscellaneous structures used and useful in connection with said unit
or any part thereof, and all water rights, rights-of-way, ditches, dams, reservoirs, Lands, or interest in Lands the use and occupancy of
which are necessary or appropriate in the maintenance and operation of such unit;
"Sec. 4. The Commission is hereby authorized and empowered
'To make investigations and to collect and record data concerning the utilization of the water 'resources of any region to be developed, the
water-power industry and its relation to other industries and to interstate or foreign commerce, and concerning the location, capacity,
development costs, and relation to markets of power sites; ... to the extent the Commission may deem necessary or useful for the
purposes of this Act."
"Sec. 304.
Every Licensee and every public utility shall file with the Commission such annual and other periodic or special* reports as the
Commission may by rules and regulations or other prescribe as necessary or appropriate to assist the Commission in the proper
administration of this Act. The Commission may prescribe the manner and FERC Form in which such reports shall be made, and require
from such persons specific answers to all questions upon which the Commission may need information. The Commission may require
that such reports shall include, among other things, full information as to assets and Liabilities, capitalization, net investment, and
reduction thereof, gross receipts, interest due and paid, depreciation, and other reserves, cost of project and other facilities, cost of
maintenance and operation of the project and other facilities, cost of renewals and replacement of the project works and other facilities,
depreciation, generation, transmission, distribution, delivery, use, and sale of electric energy. The Commission may require any such
person to make adequate provision for currently determining such costs and other facts. Such reports shall be made under oath unless
the Commission otherwise specifies*.10
"Sec. 309.
The Commission shall have power to perform any and all acts, and to prescribe, issue, make, and rescind such orders, rules and
regulations as it may find necessary or appropriate to carry out the provisions of this Act. Among other things, such rules and regulations
may define accounting, technical, and trade terms used in this Act; and may prescribe the FERC Form or FERC Forms of all statements,
declarations, applications, and reports to be filed with the Commission, the information which they shall contain, and the time within which
they shall be field..."
GENERAL PENALTIES
I.
II.
3.
4.
5.
7.
11.
a.
a.
date of the contract defined as the earliest date either buyer or seller can unilaterally get out of the contract.SFP - Short-Term Firm Point-to-Point Transmission Reservations. Use this classification for all firm point-to-point transmission reservations,where the duration of each period of reservation is less than one-year.NF - Non-Firm Transmission Service, where firm means that service cannot be interrupted for economic reasons and is intended to remainreliable even under adverse conditions.OS - Other Transmission Service. Use this classification only for those services which can not be placed in the above-mentionedclassifications, such as all other service regardless of the length of the contract and service FERC Form. Describe the type of service in afootnote for each entry.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.DEFINITIONSCommission Authorization (Comm. Auth.) -- The authorization of the Federal Energy Regulatory Commission, or any other Commission.Name the commission whose authorization was obtained and give date of the authorization.Respondent -- The person, corporation, licensee, agency, authority, or other Legal entity or instrumentality in whose behalf the report ismade.EXCERPTS FROM THE LAWFederal Power Act, 16 U.S.C. § 791a-825rSec. 3. The words defined in this section shall have the following meanings for purposes of this Act, to with:’Corporation' means any corporation, joint-stock company, partnership, association, business trust, organized group of persons, whetherincorporated or not, or a receiver or receivers, trustee or trustees of any of the foregoing. It shall not include 'municipalities, as hereinafterdefined;'Person' means an individual or a corporation;'Licensee, means any person, State, or municipality Licensed under the provisions of section 4 of this Act, and any assignee or successorin interest thereof;'municipality means a city, county, irrigation district, drainage district, or other political subdivision or agency of a State competent underthe Laws thereof to carry and the business of developing, transmitting, unitizing, or distributing power; ......"project' means. a complete unit of improvement or development, consisting of a power house, all water conduits, all dams andappurtenant works and structures (including navigation structures) which are a part of said unit, and all storage, diverting, or fore bayreservoirs directly connected therewith, the primary line or lines transmitting power there from to the point of junction with the distributionsystem or with the interconnected primary transmission system, all miscellaneous structures used and useful in connection with said unitor any part thereof, and all water rights, rights-of-way, ditches, dams, reservoirs, Lands, or interest in Lands the use and occupancy ofwhich are necessary or appropriate in the maintenance and operation of such unit;"Sec. 4. The Commission is hereby authorized and empowered'To make investigations and to collect and record data concerning the utilization of the water 'resources of any region to be developed, thewater-power industry and its relation to other industries and to interstate or foreign commerce, and concerning the location, capacity,development costs, and relation to markets of power sites; ... to the extent the Commission may deem necessary or useful for thepurposes of this Act.""Sec. 304.Every Licensee and every public utility shall file with the Commission such annual and other periodic or special* reports as theCommission may by rules and regulations or other prescribe as necessary or appropriate to assist the Commission in the properadministration of this Act. The Commission may prescribe the manner and FERC Form in which such reports shall be made, and requirefrom such persons specific answers to all questions upon which the Commission may need information. The Commission may requirethat such reports shall include, among other things, full information as to assets and Liabilities, capitalization, net investment, andreduction thereof, gross receipts, interest due and paid, depreciation, and other reserves, cost of project and other facilities, cost ofmaintenance and operation of the project and other facilities, cost of renewals and replacement of the project works and other facilities,depreciation, generation, transmission, distribution, delivery, use, and sale of electric energy. The Commission may require any suchperson to make adequate provision for currently determining such costs and other facts. Such reports shall be made under oath unlessthe Commission otherwise specifies*.10"Sec. 309.The Commission shall have power to perform any and all acts, and to prescribe, issue, make, and rescind such orders, rules andregulations as it may find necessary or appropriate to carry out the provisions of this Act. Among other things, such rules and regulationsmay define accounting, technical, and trade terms used in this Act; and may prescribe the FERC Form or FERC Forms of all statements,declarations, applications, and reports to be filed with the Commission, the information which they shall contain, and the time within whichthey shall be field..."
GENERAL PENALTIES
I.II.3.4.5.7.11.a.a.
The Commission may assess up to $1 million per day per violation of its rules and regulations. See FPA § 316(a) (2005), 16 U.S.C. § 825o(a).
FERC FORM NO. 1 (ED. 03-07)
The Commission may assess up to $1 million per day per violation of its rules and regulations. See FPA § 316(a) (2005), 16 U.S.C. § 825o(a).FERC FORM NO. 1 (ED. 03-07)
FERC FORM NO. 1
REPORT OF MAJOR ELECTRIC UTILITIES, LICENSEES AND OTHER
IDENTIFICATION
01 Exact Legal Name of Respondent
Idaho Power Company
02 Year/ Period of Report
End of: 2022/ Q4
03 Previous Name and Date of Change (If name changed during year)
/
04 Address of Principal Office at End of Period (Street, City, State, Zip Code)
1221 W Idaho St, P.O. Box 70 Boise, Id 83707-0070
05 Name of Contact Person
Ken Petersen
06 Title of Contact Person
VP, CAO & Treasurer
07 Address of Contact Person (Street, City, State, Zip Code)
1221 W Idaho St, P.O. Box 70 Boise, Id 83707-0070
08 Telephone of Contact Person, Including Area Code
[phone]
09 This Report is An Original / A Resubmission
(1) ☑ An Original
(2) ☐ A Resubmission
10 Date of Report (Mo, Da, Yr)
04/13/2023
Annual Corporate Officer Certification
The undersigned officer certifies that:
I have examined this report and to the best of my knowledge, information, and belief all 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
VP, CAO & Treasurer
03 Signature
Ken Petersen
04 Date Signed (Mo, Da, Yr)
04/13/2023
Title 18, U.S.C. 1001 makes it a crime for any person to knowingly and willingly to make to any Agency or Department of the United States
any false, fictitious or fraudulent statements as to any matter within its jurisdiction.
FERC FORM No. 1 (REV. 02-04)
Page 1
FERC FORM NO. 1REPORT OF MAJOR ELECTRIC UTILITIES, LICENSEES AND OTHERIDENTIFICATION01 Exact Legal Name of RespondentIdaho Power Company 02 Year/ Period of ReportEnd of: 2022/ Q403 Previous Name and Date of Change (If name changed during year)/ 04 Address of Principal Office at End of Period (Street, City, State, Zip Code)1221 W Idaho St, P.O. Box 70 Boise, Id 83707-007005 Name of Contact PersonKen Petersen 06 Title of Contact PersonVP, CAO & Treasurer07 Address of Contact Person (Street, City, State, Zip Code)1221 W Idaho St, P.O. Box 70 Boise, Id 83707-007008 Telephone of Contact Person, Including Area Code(208) 388-2761 09 This Report is An Original / A Resubmission(1) ☑ An Original(2) ☐ A Resubmission 10 Date of Report (Mo, Da, Yr)04/13/2023Annual Corporate Officer CertificationThe 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 correctstatements 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 NameKen Petersen02 TitleVP, CAO & Treasurer 03 SignatureKen Petersen 04 Date Signed (Mo, Da, Yr)04/13/2023Title 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 Statesany false, fictitious or fraudulent statements as to any matter within its jurisdiction.FERC FORM No. 1 (REV. 02-04)Page 1
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
LIST OF SCHEDULES (Electric Utility)
Line
No.
Title of Schedule
(a)
Reference Page No.
(b)
Remarks
(c)
Identification 1
List of Schedules 2
1 General Information 101
2 Control Over Respondent 102
3 Corporations Controlled by Respondent 103
4 Officers 104
5 Directors 105
6 Information on Formula Rates 106
7 Important Changes During the Year 108
8 Comparative Balance Sheet 110
9 Statement of Income for the Year 114
10 Statement of Retained Earnings for the Year 118
12 Statement of Cash Flows 120
12 Notes to Financial Statements 122
13 Statement of Accum Other Comp Income, Comp
Income, and Hedging Activities 122a
14 Summary of Utility Plant & Accumulated Provisions
for Dep, Amort & Dep 200
15 Nuclear Fuel Materials 202 NA
16 Electric Plant in Service 204
17 Electric Plant Leased to Others 213 NA
18 Electric Plant Held for Future Use 214
19 Construction Work in Progress-Electric 216
20 Accumulated Provision for Depreciation of Electric
Utility Plant 219
21 Investment of Subsidiary Companies 224
22 Materials and Supplies 227
23 Allowances 228 NA
24 Extraordinary Property Losses 230a NA
25 Unrecovered Plant and Regulatory Study Costs 230b NA
26 Transmission Service and Generation
Interconnection Study Costs 231
FERC FORM No. 1 (ED. 12-96)
Page 2
Name of Respondent:Idaho Power Company This report is:(1) ☑ An Original(2) ☐ A Resubmission Date of Report:04/13/2023 Year/Period of ReportEnd of: 2022/ Q4LIST OF SCHEDULES (Electric Utility)LineNo.Title of Schedule(a)Reference Page No.(b)Remarks(c)Identification 1List of Schedules 21General Information 1012Control Over Respondent 1023Corporations Controlled by Respondent 1034Officers1045Directors1056Information on Formula Rates 1067Important Changes During the Year 1088Comparative Balance Sheet 1109Statement of Income for the Year 11410Statement of Retained Earnings for the Year 11812Statement of Cash Flows 12012Notes to Financial Statements 12213Statement of Accum Other Comp Income, CompIncome, and Hedging Activities 122a14Summary of Utility Plant & Accumulated Provisionsfor Dep, Amort & Dep 20015Nuclear Fuel Materials 202 NA16Electric Plant in Service 20417Electric Plant Leased to Others 213 NA18Electric Plant Held for Future Use 21419Construction Work in Progress-Electric 21620Accumulated Provision for Depreciation of ElectricUtility Plant 21921Investment of Subsidiary Companies 22422Materials and Supplies 22723Allowances228 NA24Extraordinary Property Losses 230a NA25Unrecovered Plant and Regulatory Study Costs 230b NA26Transmission Service and GenerationInterconnection Study Costs 231
FERC FORM No. 1 (ED. 12-96)
Page 2
27 Other Regulatory Assets 232
28 Miscellaneous Deferred Debits 233
29 Accumulated Deferred Income Taxes 234
30 Capital Stock 250
31 Other Paid-in Capital 253
32 Capital Stock Expense 254b
33 Long-Term Debt 256
34 Reconciliation of Reported Net Income with Taxable
Inc for Fed Inc Tax 261
35 Taxes Accrued, Prepaid and Charged During the
Year 262
36 Accumulated Deferred Investment Tax Credits 266
37 Other Deferred Credits 269
38 Accumulated Deferred Income Taxes-Accelerated
Amortization Property 272 NA
39 Accumulated Deferred Income Taxes-Other Property 274
40 Accumulated Deferred Income Taxes-Other 276
41 Other Regulatory Liabilities 278
42 Electric Operating Revenues 300
43 Regional Transmission Service Revenues (Account
457.1)302 NA
44 Sales of Electricity by Rate Schedules 304
45 Sales for Resale 310
46 Electric Operation and Maintenance Expenses 320
47 Purchased Power 326
48 Transmission of Electricity for Others 328
49 Transmission of Electricity by ISO/RTOs 331 NA
50 Transmission of Electricity by Others 332
51 Miscellaneous General Expenses-Electric 335
52 Depreciation and Amortization of Electric Plant
(Account 403, 404, 405)336
53 Regulatory Commission Expenses 350
54 Research, Development and Demonstration
Activities 352
55 Distribution of Salaries and Wages 354
LIST OF SCHEDULES (Electric Utility)
Line
No.
Title of Schedule
(a)
Reference Page No.
(b)
Remarks
(c)
FERC FORM No. 1 (ED. 12-96)
Page 2
27 Other Regulatory Assets 23228Miscellaneous Deferred Debits 23329Accumulated Deferred Income Taxes 23430Capital Stock 25031Other Paid-in Capital 25332Capital Stock Expense 254b33Long-Term Debt 25634Reconciliation of Reported Net Income with TaxableInc for Fed Inc Tax 26135Taxes Accrued, Prepaid and Charged During theYear 26236Accumulated Deferred Investment Tax Credits 26637Other Deferred Credits 26938Accumulated Deferred Income Taxes-AcceleratedAmortization Property 272 NA39Accumulated Deferred Income Taxes-Other Property 27440Accumulated Deferred Income Taxes-Other 27641Other Regulatory Liabilities 27842Electric Operating Revenues 30043Regional Transmission Service Revenues (Account457.1)302 NA44Sales of Electricity by Rate Schedules 30445Sales for Resale 31046Electric Operation and Maintenance Expenses 32047Purchased Power 32648Transmission of Electricity for Others 32849Transmission of Electricity by ISO/RTOs 331 NA50Transmission of Electricity by Others 33251Miscellaneous General Expenses-Electric 33552Depreciation and Amortization of Electric Plant(Account 403, 404, 405)33653Regulatory Commission Expenses 35054Research, Development and DemonstrationActivities 35255Distribution of Salaries and Wages 354LIST OF SCHEDULES (Electric Utility)LineNo.Title of Schedule(a)Reference Page No.(b)Remarks(c)
FERC FORM No. 1 (ED. 12-96)
Page 2
56 Common Utility Plant and Expenses 356 NA
57 Amounts included in ISO/RTO Settlement
Statements 397 NA
58 Purchase and Sale of Ancillary Services 398
59 Monthly Transmission System Peak Load 400
60 Monthly ISO/RTO Transmission System Peak Load 400a NA
61 Electric Energy Account 401a
62 Monthly Peaks and Output 401b
63 Steam Electric Generating Plant Statistics 402
64 Hydroelectric Generating Plant Statistics 406
65 Pumped Storage Generating Plant Statistics 408 NA
66 Generating Plant Statistics Pages 410
0 Energy Storage Operations (Large Plants)414 NA
67 Transmission Line Statistics Pages 422
68 Transmission Lines Added During Year 424
69 Substations 426
70 Transactions with Associated (Affiliated) Companies 429
71 Footnote Data 450
Stockholders' Reports (check appropriate box)
Stockholders' Reports Check appropriate box:
☐ Two copies will be submitted
☐ No annual report to stockholders is prepared
FERC FORM No. 1 (ED. 12-96)
Page 2
LIST OF SCHEDULES (Electric Utility)
Line
No.
Title of Schedule
(a)
Reference Page No.
(b)
Remarks
(c)
56 Common Utility Plant and Expenses 356 NA57Amounts included in ISO/RTO SettlementStatements 397 NA58Purchase and Sale of Ancillary Services 39859Monthly Transmission System Peak Load 40060Monthly ISO/RTO Transmission System Peak Load 400a NA61Electric Energy Account 401a62Monthly Peaks and Output 401b63Steam Electric Generating Plant Statistics 40264Hydroelectric Generating Plant Statistics 40665Pumped Storage Generating Plant Statistics 408 NA66Generating Plant Statistics Pages 4100Energy Storage Operations (Large Plants)414 NA67Transmission Line Statistics Pages 42268Transmission Lines Added During Year 42469Substations42670Transactions with Associated (Affiliated) Companies 42971Footnote Data 450Stockholders' Reports (check appropriate box)Stockholders' Reports Check appropriate box:☐ Two copies will be submitted☐ No annual report to stockholders is prepared FERC FORM No. 1 (ED. 12-96)Page 2LIST OF SCHEDULES (Electric Utility)LineNo.Title of Schedule(a)Reference Page No.(b)Remarks(c)
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
GENERAL INFORMATION
1. Provide name and title of officer having custody of the general corporate books of account and address of office where the general
corporate books are kept, and address of office where any other corporate books of account are kept, if different from that where the general
corporate books are kept.
Ken Petersen Vice President, CAO & Treasurer, Idaho Power Company 1221 W. Idaho Street, P.O. Box 70, Boise, Idaho 83707-0070
Ken Petersen
VP, CAO & Treasurer
1221 W. Idaho Street, P.O. Box 70, Boise, Idaho 83707-0070
2. Provide the name of the State under the laws of which respondent is incorporated, and date of incorporation. If incorporated under a
special law, give reference to such law. If not incorporated, state that fact and give the type of organization and the date organized.
Idaho, June 30, 1989
State of Incorporation: ID
Date of Incorporation: 1989-06-30
Incorporated Under Special Law:
3. If at any time during the year the property of respondent was held by a receiver or trustee, give (a) name of receiver or trustee, (b) date
such receiver or trustee took possession, (c) the authority by which the receivership or trusteeship was created, and (d) date when
possession by receiver or trustee ceased.
Not Applicable
(a) Name of Receiver or Trustee Holding Property of the Respondent:
(b) Date Receiver took Possession of Respondent Property:
(c) Authority by which the Receivership or Trusteeship was created:
(d) Date when possession by receiver or trustee ceased:
4. State the classes or utility and other services furnished by respondent during the year in each State in which the respondent operated.
Class of Utility Service State Electric Idaho Electric 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) ☐ Yes
(2) ☑ No
FERC FORM No. 1 (ED. 12-87)
Page 101
Name of Respondent:Idaho Power Company This report is:(1) ☑ An Original(2) ☐ A Resubmission Date of Report:04/13/2023 Year/Period of ReportEnd of: 2022/ Q4GENERAL INFORMATION1. Provide name and title of officer having custody of the general corporate books of account and address of office where the generalcorporate books are kept, and address of office where any other corporate books of account are kept, if different from that where the generalcorporate books are kept.Ken Petersen Vice President, CAO & Treasurer, Idaho Power Company 1221 W. Idaho Street, P.O. Box 70, Boise, Idaho 83707-0070Ken PetersenVP, CAO & Treasurer1221 W. Idaho Street, P.O. Box 70, Boise, Idaho 83707-00702. Provide the name of the State under the laws of which respondent is incorporated, and date of incorporation. If incorporated under aspecial law, give reference to such law. If not incorporated, state that fact and give the type of organization and the date organized.Idaho, June 30, 1989State of Incorporation: IDDate of Incorporation: 1989-06-30Incorporated Under Special Law: 3. If at any time during the year the property of respondent was held by a receiver or trustee, give (a) name of receiver or trustee, (b) datesuch receiver or trustee took possession, (c) the authority by which the receivership or trusteeship was created, and (d) date whenpossession by receiver or trustee ceased.Not Applicable(a) Name of Receiver or Trustee Holding Property of the Respondent: (b) Date Receiver took Possession of Respondent Property: (c) Authority by which the Receivership or Trusteeship was created: (d) Date when possession by receiver or trustee ceased: 4. State the classes or utility and other services furnished by respondent during the year in each State in which the respondent operated.Class of Utility Service State Electric Idaho Electric Oregon5. Have you engaged as the principal accountant to audit your financial statements an accountant who is not the principal accountant foryour previous year's certified financial statements?(1) ☐ Yes (2) ☑ NoFERC FORM No. 1 (ED. 12-87)Page 101
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
CONTROL OVER RESPONDENT
1. If any corporation, business trust, or similar organization or a combination of such organizations jointly held control over the respondent at
the end of the year, state name of controlling corporation or organization, manner in which control was held, and extent of control. If control
was in a holding company organization, show the chain of ownership or control to the main parent company or organization. If control was
held by a trustee(s), state name of trustee(s), name of beneficiary or beneficiaries for whom trust was maintained, and purpose of the trust.
IDACORP owns 100% of Idaho Power Company's Common Stock.
IDACORP is a public utility Holding Company Incorporated effective October 1, 1998.
FERC FORM No. 1 (ED. 12-96)
Page 102
Name of Respondent:Idaho Power Company This report is:(1) ☑ An Original(2) ☐ A Resubmission Date of Report:04/13/2023 Year/Period of ReportEnd of: 2022/ Q4CONTROL OVER RESPONDENT1. If any corporation, business trust, or similar organization or a combination of such organizations jointly held control over the respondent atthe end of the year, state name of controlling corporation or organization, manner in which control was held, and extent of control. If controlwas in a holding company organization, show the chain of ownership or control to the main parent company or organization. If control washeld by a trustee(s), state name of trustee(s), name of beneficiary or beneficiaries for whom trust was maintained, and purpose of the trust.IDACORP owns 100% of Idaho Power Company's Common Stock.IDACORP is a public utility Holding Company Incorporated effective October 1, 1998.FERC FORM No. 1 (ED. 12-96)Page 102
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
CORPORATIONS CONTROLLED BY RESPONDENT
Line
No.
Name of Company Controlled
(a)
Kind of Business
(b)
Percent
Voting Stock
Owned
(c)
Footnote Ref.
(d)
1 Direct Control
2 Idaho Energy Resources Company Coal mining and mineral 100%
3 development
FERC FORM No. 1 (ED. 12-96)
Page 103
Name of Respondent:Idaho Power Company This report is:(1) ☑ An Original(2) ☐ A Resubmission Date of Report:04/13/2023 Year/Period of ReportEnd of: 2022/ Q4CORPORATIONS CONTROLLED BY RESPONDENTLineNo.Name of Company Controlled(a)Kind of Business(b)PercentVoting StockOwned(c)Footnote Ref.(d)1 Direct Control2Idaho Energy Resources Company Coal mining and mineral 100%3 developmentFERC FORM No. 1 (ED. 12-96)Page 103
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
OFFICERS
Line
No.
Title
(a)
Name of Officer
(b)
Salary for Year
(c)
Date Started in
Period
(d)
Date Ended in
Period
(e)
1 President & CEO Idaho Power
Company Lisa Grow 850,000
2 Senior Vice President,Steven R. Keen (a)397,693 2022-09-30
3 Senior Vice President, COO Adam J. Richins 485,000
4 Senior Vice President, CFO Brian R. Buckham 462,000
5 Senior Vice President, Public
Affairs Jeffery L. Malmen 372,000
6 Vice President, CAO &
Treasurer Ken W. Petersen 325,500
7 Vice President, Regulatory
Affairs Tim Tatum 275,000
8 Vice President, Power Supply Ryan N. Adelman 263,000
9 Vice President, Human
Resources Sarah E. Griffin 270,000
10 Vice President, General Counsel
and Coporate Secretary Patrick Harrington 280,000
11 Vice President, Customer
Operations & CSO Bo Hanchey 252,800
12 Vice President, Corporate
Services & Communications Debra H. Leithauser 243,500
13 Vice President, Information
Technology & CIO Jason C. Huszar 240,000
14 Vice President, Planning,
Engineering & Construction Mitch Colburn 240,000
FERC FORM No. 1 (ED. 12-96)
Page 104
Name of Respondent:Idaho Power Company This report is:(1) ☑ An Original(2) ☐ A Resubmission Date of Report:04/13/2023 Year/Period of ReportEnd of: 2022/ Q4OFFICERSLineNo.Title(a)Name of Officer(b)Salary for Year(c)Date Started inPeriod(d)Date Ended inPeriod(e)1 President & CEO Idaho PowerCompany Lisa Grow 850,0002Senior Vice President,Steven R. Keen (a)397,693 2022-09-303Senior Vice President, COO Adam J. Richins 485,0004Senior Vice President, CFO Brian R. Buckham 462,0005Senior Vice President, PublicAffairs Jeffery L. Malmen 372,0006Vice President, CAO &Treasurer Ken W. Petersen 325,5007Vice President, RegulatoryAffairs Tim Tatum 275,0008Vice President, Power Supply Ryan N. Adelman 263,0009Vice President, HumanResources Sarah E. Griffin 270,00010Vice President, General Counseland Coporate Secretary Patrick Harrington 280,00011Vice President, CustomerOperations & CSO Bo Hanchey 252,80012Vice President, CorporateServices & Communications Debra H. Leithauser 243,50013Vice President, InformationTechnology & CIO Jason C. Huszar 240,00014Vice President, Planning,Engineering & Construction Mitch Colburn 240,000FERC FORM No. 1 (ED. 12-96)Page 104
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
FOOTNOTE DATA
(a) Concept: OfficerSalary
Salary shows YTD wages.
FERC FORM No. 1 (ED. 12-96)
Page 104
Name of Respondent:Idaho Power Company This report is:(1) ☑ An Original(2) ☐ A Resubmission Date of Report:04/13/2023 Year/Period of ReportEnd of: 2022/ Q4FOOTNOTE DATA(a) Concept: OfficerSalarySalary shows YTD wages.FERC FORM No. 1 (ED. 12-96)Page 104
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
DIRECTORS
Line
No.
Name (and Title) of Director
(a)
Principal Business Address
(b)
Member of the Executive
Committee
(c)
Chairman of the Executive
Committee
(d)
1. Report below the information called for concerning each director of the respondent who held office at any time during the year. Include in
column (a), name and abbreviated titles of the directors who are officers of the respondent.
2. Provide the principle place of business in column (b), designate members of the Executive Committee in column (c), and the Chairman of
the Executive Committee in column (d).
1
(a)
Darrell T. Anderson
1528 E Garden Brook Drive,
Eagle, Idaho 83616 false false
2 Odette C. Bolano 1055 N. Curtis Rd., Boise,
Idaho 83706 false false
3 Thomas E. Carlile 611 S 8th Street, Unit 503,
Boise, Idaho 83702 false false
4 Richard J. Dahl, Board Chair PO Box 2052, McCall, Idaho
83638 true false
5 Annette G. Elg 3475 E Rivernest Lane, Boise,
ID 83706 false false
6 Lisa A. Grow, President and
CEO
Idaho Power Company, 1221
W. Idaho Street, PO Box 70,
Boise, ID 83707
true true
7 Ronald W. Jibson 417 Aerie Circle, North Salt
Lake, Utah 84054 false false
8 Judith A. Johansen, Comp
Committee Chair
10446 E. Palo Brea Dr,
Scottsdale, Arizona 85262 true false
9 Dennis L. Johnson, Corp Gov.
Chair
926 West Oakhampton Drive,
Eagle, Idaho 83616 true false
10 Richard J. Navarro, Audit Chair 1256 E Candleridge Ct., Boise,
Idaho 83712 true false
11 Dr. Mark Peters 884 Neil Avenue, Columbus,
Ohio 43215 false false
12
(b)
Jeff C. Kinneeveauk
7319 E Montebello Ave,
Scottsdale, AZ 85250 false false
FERC FORM No. 1 (ED. 12-95)
Page 105
Name of Respondent:Idaho Power Company This report is:(1) ☑ An Original(2) ☐ A Resubmission Date of Report:04/13/2023 Year/Period of ReportEnd of: 2022/ Q4DIRECTORSLineNo.Name (and Title) of Director(a)Principal Business Address(b)Member of the ExecutiveCommittee(c)Chairman of the ExecutiveCommittee(d)1. Report below the information called for concerning each director of the respondent who held office at any time during the year. Include incolumn (a), name and abbreviated titles of the directors who are officers of the respondent.2. Provide the principle place of business in column (b), designate members of the Executive Committee in column (c), and the Chairman ofthe Executive Committee in column (d).1 (a)Darrell T. Anderson 1528 E Garden Brook Drive,Eagle, Idaho 83616 false false2Odette C. Bolano 1055 N. Curtis Rd., Boise,Idaho 83706 false false3Thomas E. Carlile 611 S 8th Street, Unit 503,Boise, Idaho 83702 false false4Richard J. Dahl, Board Chair PO Box 2052, McCall, Idaho83638 true false5Annette G. Elg 3475 E Rivernest Lane, Boise,ID 83706 false false6Lisa A. Grow, President andCEO Idaho Power Company, 1221W. Idaho Street, PO Box 70,Boise, ID 83707 true true7Ronald W. Jibson 417 Aerie Circle, North SaltLake, Utah 84054 false false8Judith A. Johansen, CompCommittee Chair 10446 E. Palo Brea Dr,Scottsdale, Arizona 85262 true false9Dennis L. Johnson, Corp Gov.Chair 926 West Oakhampton Drive,Eagle, Idaho 83616 true false10Richard J. Navarro, Audit Chair 1256 E Candleridge Ct., Boise,Idaho 83712 true false11Dr. Mark Peters 884 Neil Avenue, Columbus,Ohio 43215 false false12(b)Jeff C. Kinneeveauk 7319 E Montebello Ave,Scottsdale, AZ 85250 false falseFERC FORM No. 1 (ED. 12-95)Page 105
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
FOOTNOTE DATA
(a) Concept: NameAndTitleOfDirector
Retired from the Board on May 19, 2022
(b) Concept: NameAndTitleOfDirector
Appointed to the Board on February 9, 2022
FERC FORM No. 1 (ED. 12-95)
Page 105
Name of Respondent:Idaho Power Company This report is:(1) ☑ An Original(2) ☐ A Resubmission Date of Report:04/13/2023 Year/Period of ReportEnd of: 2022/ Q4FOOTNOTE DATA(a) Concept: NameAndTitleOfDirectorRetired from the Board on May 19, 2022(b) Concept: NameAndTitleOfDirectorAppointed to the Board on February 9, 2022FERC FORM No. 1 (ED. 12-95)Page 105
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
INFORMATION ON FORMULA RATES
Line
No.
FERC Rate Schedule or Tariff Number
(a)
FERC Proceeding
(b)
Does the respondent have formula rates?
☑ Yes
☐ No
1 FERC Electric Tariff
FERC FORM No. 1 (NEW. 12-08)
Page 106
Name of Respondent:Idaho Power Company This report is:(1) ☑ An Original(2) ☐ A Resubmission Date of Report:04/13/2023 Year/Period of ReportEnd of: 2022/ Q4INFORMATION ON FORMULA RATESLineNo.FERC Rate Schedule or Tariff Number(a)FERC Proceeding(b)Does the respondent have formula rates?☑ Yes☐ No1FERC Electric TariffFERC FORM No. 1 (NEW. 12-08)Page 106
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
INFORMATION ON FORMULA RATES - FERC Rate Schedule/Tariff Number FERC Proceeding
Line
No.
Accession
No.
(a)
Document Date /
Filed Date
(b)
Docket No.
(c)
Description
(d)
Formula Rate FERC Rate
Schedule Number or Tariff
Number
(e)
Does the respondent file with the
Commission annual (or more
frequent) filings containing the inputs
to the formula rate(s)?
☑ Yes
☐ No
1 20220826-
5212 08/26/2022 ER09-1641-000
Idaho Power Company 2022
Annual Informational filing
under ER09-1641-000
FERC Electric Tariff
FERC FORM NO. 1 (NEW. 12-08)
Page 106a
Name of Respondent:Idaho Power Company This report is:(1) ☑ An Original(2) ☐ A Resubmission Date of Report:04/13/2023 Year/Period of ReportEnd of: 2022/ Q4INFORMATION ON FORMULA RATES - FERC Rate Schedule/Tariff Number FERC ProceedingLineNo.AccessionNo.(a)Document Date /Filed Date(b)Docket No.(c)Description(d)Formula Rate FERC RateSchedule Number or TariffNumber(e)Does the respondent file with theCommission annual (or morefrequent) filings containing the inputsto the formula rate(s)?☑ Yes☐ No120220826-5212 08/26/2022 ER09-1641-000 Idaho Power Company 2022Annual Informational filingunder ER09-1641-000 FERC Electric TariffFERC FORM NO. 1 (NEW. 12-08)Page 106a
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
INFORMATION ON FORMULA RATES - Formula Rate Variances
Line
No.
Page No(s).
(a)
Schedule
(b)
Column
(c)
Line
No.
(d)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
FERC FORM No. 1 (NEW. 12-08)
Page 106b
Name of Respondent:Idaho Power Company This report is:(1) ☑ An Original(2) ☐ A Resubmission Date of Report:04/13/2023 Year/Period of ReportEnd of: 2022/ Q4INFORMATION ON FORMULA RATES - Formula Rate VariancesLineNo.Page No(s).(a)Schedule(b)Column(c)LineNo.(d)1234567891011121314151617181920212223242526272829
FERC FORM No. 1 (NEW. 12-08)
Page 106b
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
FERC FORM No. 1 (NEW. 12-08)
Page 106b
INFORMATION ON FORMULA RATES - Formula Rate Variances
Line
No.
Page No(s).
(a)
Schedule
(b)
Column
(c)
Line
No.
(d)
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
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. If information which answers
an inquiry is given elsewhere in the report, make a reference to the schedule in which it appears.
1. Changes in and important additions to franchise rights: Describe the actual consideration given therefore and state from whom the
franchise rights were acquired. If acquired without the payment of consideration, state that fact.
2. Acquisition of ownership in other companies by reorganization, merger, or consolidation with other companies: Give names of
companies involved, particulars concerning the transactions, name of the Commission authorizing the transaction, and reference to
Commission authorization.
3. Purchase or sale of an operating unit or system: Give a brief description of the property, and of the transactions relating thereto, and
reference to Commission authorization, if any was required. Give date journal entries called for by the Uniform System of Accounts
were submitted to the Commission.
4. Important leaseholds (other than leaseholds for natural gas lands) that have been acquired or given, assigned or surrendered: Give
effective dates, lengths of terms, names of parties, rents, and other condition. State name of Commission authorizing lease and give
reference to such authorization.
5. Important extension or reduction of transmission or distribution system: State territory added or relinquished and date operations
began or ceased and give reference to Commission authorization, if any was required. State also the approximate number of
customers added or lost and approximate annual revenues of each class of service. Each natural gas company must also state major
new continuing sources of gas made available to it from purchases, development, purchase contract or otherwise, giving location and
approximate total gas volumes available, period of contracts, and other parties to any such arrangements, etc.
6. Obligations incurred as a result of issuance of securities or assumption of liabilities or guarantees including issuance of short-term
debt and commercial paper having a maturity of one year or less. Give reference to FERC or State Commission authorization, as
appropriate, and the amount of obligation or guarantee.
7. Changes in articles of incorporation or amendments to charter: Explain the nature and purpose of such changes or amendments.
8. State the estimated annual effect and nature of any important wage scale changes during the year.
9. State briefly the status of any materially important legal proceedings pending at the end of the year, and the results of any such
proceedings culminated during the year.
10. Describe briefly any materially important transactions of the respondent not disclosed elsewhere in this report in which an officer,
director, security holder reported on Pages 104 or 105 of the Annual Report Form No. 1, voting trustee, associated company or known
associate of any of these persons was a party or in which any such person had a material interest.
11. (Reserved.)
12. If the important changes during the year relating to the respondent company appearing in the annual report to stockholders are
applicable in every respect and furnish the data required by Instructions 1 to 11 above, such notes may be included on this page.
13. Describe fully any changes in officers, directors, major security holders and voting powers of the respondent that may have occurred
during the reporting period.
14. In the event that the respondent participates in a cash management program(s) and its proprietary capital ratio is less than 30 percent
please describe the significant events or transactions causing the proprietary capital ratio to be less than 30 percent, and the extent to
which the respondent has amounts loaned or money advanced to its parent, subsidiary, or affiliated companies through a cash
management program(s). Additionally, please describe plans, if any to regain at least a 30 percent proprietary ratio.
None.
None.
None.
None.
None.
In December 2022, Idaho Powerentered into the Bond Purchase Agreement with certain institutional purchasers,relating to the sale by Idaho Power
of $170 million in aggregate principalamount of Series N Notes. Also in December 2022, Idaho Power entered into theFifty-second Supplemental
Indenture, dated effective as of December 30, 2022,to the Indenture (Fifty-second Supplemental Indenture). The Fifty-secondSupplemental Indenture
provides for, among other items, the issuance of SeriesN Notes pursuant to the Indenture. The Series N Notes consist of:
$23 million in aggregate principal amount of Idaho Power's 4.99% first mortgage bonds due 2032, Series N Notes, Tranche 1 (Tranche 1
Bonds);
$25 million in aggregate principal amount of Idaho Power's 5.06% first mortgage bonds due 2042, Series N Notes, Tranche 2 (Tranche 2
Bonds);
$60 million in aggregate principal amount of Idaho Power's 5.06% first mortgage bonds due 2043, Series N Notes, Tranche 3 (Tranche 3
Bonds); and
$62 million in aggregate principal amount of Idaho Power's 5.20% first mortgage bonds due 2053, Series N Notes, Tranche 4 (Tranche 4
Bonds).
The Tranche 1 Bonds and Tranche 2Bonds were issued on December 22, 2022, and Idaho Power has a commitment toissue the Tranche 3
Bonds and Tranche 4 Bonds on March 8, 2023, each under theIndenture. In May and June 2022, Idaho Power received orders from the
IPUC,OPUC, and WPSC authorizing the company to issue and sell from time to time upto $1.2 billion in aggregate principal amount of debt
securities and firstmortgage bonds, subject to conditions specified in the orders.
On March 4, 2022, Idaho Powerentered into a floating rate term loan credit agreement (Term Loan Facility).The Term Loan Facility is a two-year
senior unsecured term loan facility. Itprovided for the issuance of loans not to exceed the aggregate principal amountof $150 million with a
maturity date of March 4, 2024. The interest ratesfor the floating rate advances under the Term Loan Facility were based on thehighest of (1) the
prime commercial lending rate of the lender acting asadministrative agent, (2) the federal funds rate, plus 0.5 percent, (3) TermSecured Overnight
Financing Rate administered by the Federal Reserve Bank ofNew York (SOFR) (as defined in the Term Loan Facility) for a one-month tenorthat
is published by CME Group Benchmark Administration limited (or thesuccessor administrator of such rate), plus 1 percent, and (4) zero
percent.The interest rates for SOFR Advances (as defined in the Term Loan Facility) werebased on the Term SOFR rate for the borrower-
selected period plus theApplicable Margin. The "Applicable Margin" is based on Idaho Power's seniorunsecured non-credit enhanced long-term
indebtedness credit rating, as setforth on a schedule to the Term Loan Facility. At December 31, 2022,$150 million in principal amount of one
month term SOFR advances had beendrawn and was outstanding on the Term Loan Facility. In November and Decemberof 2019, Idaho Power
received orders from the IPUC, OPUC, and WPSC authorizingthe company to borrow up to $450 million in aggregate principal amount ofshort- to
mid-term debt with maturities up to three years in duration, subjectto conditions specified in the orders.
None.
Effective 12/24/2022, a 6% general wage adjustment was implemented.
None.
None.
None.
Officer Changes in 2022:
Steve Keen retired from the company on September 30, 2022, but stepped down as CFO on March 1, 2022, and was an SVP until his retirement.
Brian Buckham became SVP and CFO on March 1. 2022.
Pat Harrington became VP, General Counsel and Corporate Secretary on March 1, 2022.
Director Changes in 2022:
Jeff C. Kinneeveauk was appointed to the Board on February 9, 2022.
Darrel Anderson retired from the Board on May 19, 2022.
Idaho 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 Idaho Power to IDACORP through a cash management program.
FERC FORM No. 1 (ED. 12-96)
Page 108-109
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Line
No.
Title of Account
(a)
Ref. Page No.
(b)
Current Year End of
Quarter/Year Balance
(c)
Prior Year End Balance 12/31
(d)
1 UTILITY PLANT
2 Utility Plant (101-106, 114)200 6,837,661,812 6,514,123,678
3 Construction Work in Progress (107)200 786,213,001 671,424,756
4 TOTAL Utility Plant (Enter Total of lines 2 and 3)7,623,874,813 7,185,548,434
5 (Less) Accum. Prov. for Depr. Amort. Depl. (108,
110, 111, 115)200 2,645,515,886 2,483,620,791
6 Net Utility Plant (Enter Total of line 4 less 5)4,978,358,927 4,701,927,643
7 Nuclear Fuel in Process of Ref., Conv., Enrich.,
and Fab. (120.1)202
8 Nuclear Fuel Materials and Assemblies-Stock
Account (120.2)
9 Nuclear Fuel Assemblies in Reactor (120.3)
10 Spent Nuclear Fuel (120.4)
11 Nuclear Fuel Under Capital Leases (120.6)
12 (Less) Accum. Prov. for Amort. of Nucl. Fuel
Assemblies (120.5)202
13 Net Nuclear Fuel (Enter Total of lines 7-11 less
12)0
14 Net Utility Plant (Enter Total of lines 6 and 13)4,978,358,927 4,701,927,643
15 Utility Plant Adjustments (116)
16 Gas Stored Underground - Noncurrent (117)
17 OTHER PROPERTY AND INVESTMENTS
18 Nonutility Property (121)4,557,979 3,646,749
19 (Less) Accum. Prov. for Depr. and Amort. (122)0 0
20 Investments in Associated Companies (123)0 0
21 Investment in Subsidiary Companies (123.1)224 14,691,519 27,909,477
23 Noncurrent Portion of Allowances 228
24 Other Investments (124)0 0
25 Sinking Funds (125)0 0
26 Depreciation Fund (126)
27 Amortization Fund - Federal (127)
28 Other Special Funds (128)66,953,493 56,140,386
FERC FORM No. 1 (REV. 12-03)
Page 110-111
29 Special Funds (Non Major Only) (129)
30 Long-Term Portion of Derivative Assets (175)578,438 890,345
31 Long-Term Portion of Derivative Assets - Hedges
(176)0 0
32 TOTAL Other Property and Investments (Lines
18-21 and 23-31)86,781,429 88,586,957
33 CURRENT AND ACCRUED ASSETS
34 Cash and Working Funds (Non-major Only)
(130)
35 Cash (131)74,192,042 49,369,572
36 Special Deposits (132-134)4,719,757 1,830,847
37 Working Fund (135)21,000 13,000
38 Temporary Cash Investments (136)34,468,327 10,392,659
39 Notes Receivable (141)0 0
40 Customer Accounts Receivable (142)119,228,349 83,325,175
41 Other Accounts Receivable (143)46,115,478 12,806,869
42 (Less) Accum. Prov. for Uncollectible Acct.-Credit
(144)5,545,578 5,015,917
43 Notes Receivable from Associated Companies
(145)14,502,758 6,169,545
44 Accounts Receivable from Assoc. Companies
(146)0 0
45 Fuel Stock (151)227 14,760,362 18,045,117
46 Fuel Stock Expenses Undistributed (152)227 1,691 0
47 Residuals (Elec) and Extracted Products (153)227
48 Plant Materials and Operating Supplies (154)227 91,871,314 73,329,824
49 Merchandise (155)227
50 Other Materials and Supplies (156)227 0 0
51 Nuclear Materials Held for Sale (157)202/227
52 Allowances (158.1 and 158.2)228
53 (Less) Noncurrent Portion of Allowances 228
54 Stores Expense Undistributed (163)227 589,580 4,221,832
55 Gas Stored Underground - Current (164.1)
56 Liquefied Natural Gas Stored and Held for
Processing (164.2-164.3)
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Line
No.
Title of Account
(a)
Ref. Page No.
(b)
Current Year End of
Quarter/Year Balance
(c)
Prior Year End Balance 12/31
(d)
FERC FORM No. 1 (REV. 12-03)
Page 110-111
57 Prepayments (165)24,395,907 24,557,592
58 Advances for Gas (166-167)
59 Interest and Dividends Receivable (171)408,892 6,639
60 Rents Receivable (172)
61 Accrued Utility Revenues (173)84,861,841 74,842,947
62 Miscellaneous Current and Accrued Assets (174)
63 Derivative Instrument Assets (175)40,917,552 6,598,152
64 (Less) Long-Term Portion of Derivative
Instrument Assets (175)578,438 890,345
65 Derivative Instrument Assets - Hedges (176)0
66 (Less) Long-Term Portion of Derivative
Instrument Assets - Hedges (176)0 0
67 Total Current and Accrued Assets (Lines 34
through 66)544,930,834 359,603,508
68 DEFERRED DEBITS
69 Unamortized Debt Expenses (181)14,610,380 15,341,796
70 Extraordinary Property Losses (182.1)230a
71 Unrecovered Plant and Regulatory Study Costs
(182.2)230b
72 Other Regulatory Assets (182.3)232 1,501,960,906 1,533,747,521
73 Prelim. Survey and Investigation Charges
(Electric) (183)849,613 291,336
74 Preliminary Natural Gas Survey and
Investigation Charges 183.1)
75 Other Preliminary Survey and Investigation
Charges (183.2)
76 Clearing Accounts (184)4,883,074 3,092,658
77 Temporary Facilities (185)0 0
78 Miscellaneous Deferred Debits (186)233 78,408,895 75,436,950
79 Def. Losses from Disposition of Utility Plt. (187)
80 Research, Devel. and Demonstration Expend.
(188)352 0 0
81 Unamortized Loss on Reaquired Debt (189)36,741,730 39,557,636
82 Accumulated Deferred Income Taxes (190)234 266,405,788 324,688,128
83 Unrecovered Purchased Gas Costs (191)
84 Total Deferred Debits (lines 69 through 83)1,903,860,386 1,992,156,025
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Line
No.
Title of Account
(a)
Ref. Page No.
(b)
Current Year End of
Quarter/Year Balance
(c)
Prior Year End Balance 12/31
(d)
FERC FORM No. 1 (REV. 12-03)
Page 110-111
85 TOTAL ASSETS (lines 14-16, 32, 67, and 84)7,513,931,576 7,142,274,133
FERC FORM No. 1 (REV. 12-03)
Page 110-111
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Line
No.
Title of Account
(a)
Ref. Page No.
(b)
Current Year End of
Quarter/Year Balance
(c)
Prior Year End Balance 12/31
(d)
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
Line
No.
Title of Account
(a)
Ref. Page No.
(b)
Current Year End of
Quarter/Year Balance
(c)
Prior Year End Balance 12/31
(d)
1 PROPRIETARY CAPITAL
2 Common Stock Issued (201)250 97,877,030 97,877,030
3 Preferred Stock Issued (204)250 0 0
4 Capital Stock Subscribed (202, 205)
5 Stock Liability for Conversion (203, 206)
6 Premium on Capital Stock (207)712,257,435 712,257,435
7 Other Paid-In Capital (208-211)253 0 0
8 Installments Received on Capital Stock (212)252
9 (Less) Discount on Capital Stock (213)254
10 (Less) Capital Stock Expense (214)254b 2,096,925 2,096,925
11 Retained Earnings (215, 215.1, 216)118 1,824,318,236 1,670,857,887
12 Unappropriated Undistributed Subsidiary
Earnings (216.1)118 12,228,426 25,446,384
13 (Less) Reaquired Capital Stock (217)250 0 0
14 Noncorporate Proprietorship (Non-major only)
(218)
15 Accumulated Other Comprehensive Income
(219)122(a)(b)(12,922,387)(40,039,894)
16 Total Proprietary Capital (lines 2 through 15)2,631,661,815 2,464,301,917
17 LONG-TERM DEBT
18 Bonds (221)256 2,014,100,000 1,970,460,000
19 (Less) Reaquired Bonds (222)256 0 0
20 Advances from Associated Companies (223)256
21 Other Long-Term Debt (224)256 169,885,000 19,885,000
22 Unamortized Premium on Long-Term Debt (225)27,858,531 28,965,492
23 (Less) Unamortized Discount on Long-Term
Debt-Debit (226)3,088,412 3,328,774
24 Total Long-Term Debt (lines 18 through 23)2,208,755,119 2,015,981,718
25 OTHER NONCURRENT LIABILITIES
26 Obligations Under Capital Leases - Noncurrent
(227)
27 Accumulated Provision for Property Insurance
(228.1)
FERC FORM No. 1 (REV. 12-03)
Page 112-113
28 Accumulated Provision for Injuries and Damages
(228.2)2,736,418 3,729,566
29 Accumulated Provision for Pensions and
Benefits (228.3)238,478,974 521,815,572
30 Accumulated Miscellaneous Operating
Provisions (228.4)0 0
31 Accumulated Provision for Rate Refunds (229)207,527,563 187,716,141
32 Long-Term Portion of Derivative Instrument
Liabilities 3,271,994 3,757,551
33 Long-Term Portion of Derivative Instrument
Liabilities - Hedges
34 Asset Retirement Obligations (230)37,556,680 36,697,825
35 Total Other Noncurrent Liabilities (lines 26
through 34)489,571,629 753,716,655
36 CURRENT AND ACCRUED LIABILITIES
37 Notes Payable (231)0 0
38 Accounts Payable (232)318,080,097 170,836,741
39 Notes Payable to Associated Companies (233)0 0
40 Accounts Payable to Associated Companies
(234)56,338,432 2,158,568
41 Customer Deposits (235)1,000,860 891,328
42 Taxes Accrued (236)262 (4,258,456)(1,558,227)
43 Interest Accrued (237)24,546,434 24,259,107
44 Dividends Declared (238)953,600 0
45 Matured Long-Term Debt (239)
46 Matured Interest (240)
47 Tax Collections Payable (241)1,471,843 1,478,743
48 Miscellaneous Current and Accrued Liabilities
(242)124,973,948 88,755,058
49 Obligations Under Capital Leases-Current (243)
50 Derivative Instrument Liabilities (244)6,787,944 5,747,262
51 (Less) Long-Term Portion of Derivative
Instrument Liabilities 3,271,994 3,757,551
52 Derivative Instrument Liabilities - Hedges (245)0 0
53 (Less) Long-Term Portion of Derivative
Instrument Liabilities-Hedges
54 Total Current and Accrued Liabilities (lines 37
through 53)526,622,708 288,811,029
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
Line
No.
Title of Account
(a)
Ref. Page No.
(b)
Current Year End of
Quarter/Year Balance
(c)
Prior Year End Balance 12/31
(d)
FERC FORM No. 1 (REV. 12-03)
Page 112-113
55 DEFERRED CREDITS
56 Customer Advances for Construction (252)19,112,288 8,350,901
57 Accumulated Deferred Investment Tax Credits
(255)266 115,285,406 109,459,666
58 Deferred Gains from Disposition of Utility Plant
(256)
59 Other Deferred Credits (253)269 12,865,420 9,055,170
60 Other Regulatory Liabilities (254)278 357,700,683 311,088,834
61 Unamortized Gain on Reaquired Debt (257)0 0
62 Accum. Deferred Income Taxes-Accel. Amort.
(281)272
63 Accum. Deferred Income Taxes-Other Property
(282)989,140,934 993,806,435
64 Accum. Deferred Income Taxes-Other (283)163,215,574 187,701,809
65 Total Deferred Credits (lines 56 through 64)1,657,320,305 1,619,462,815
66 TOTAL LIABILITIES AND STOCKHOLDER
EQUITY (lines 16, 24, 35, 54 and 65)7,513,931,576 7,142,274,134
FERC FORM No. 1 (REV. 12-03)
Page 112-113
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
Line
No.
Title of Account
(a)
Ref. Page No.
(b)
Current Year End of
Quarter/Year Balance
(c)
Prior Year End Balance 12/31
(d)
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
STATEMENT OF INCOME
Line
No.
Title of Account
(a)
(Ref.)
Page No.
(b)
Total Current
Year to Date
Balance for
Quarter/Year
(c)
Total Prior Year
to Date Balance
for Quarter/Year
(d)
Current 3
Months
Ended -
Quarterly
Only - No 4th
Quarter
(e)
Prior 3
Months
Ended -
Quarterly
Only - No 4th
Quarter
(f)
Electric Utility
Current Year to
Date (in dollars)
(g)
Electric Utility
Previous Year
to Date (in
dollars)
(h)
1
UTILITY
OPERATING
INCOME
2 Operating Revenues
(400)300 1,642,534,019 1,456,168,287 1,642,534,019 1,456,168,287
3 Operating Expenses
4 Operation Expenses
(401)320 1,021,238,677 850,660,604 1,021,238,677 850,660,604
5 Maintenance
Expenses (402)320 81,802,969 66,854,588 81,802,969 66,854,588
6 Depreciation
Expense (403)336 162,962,070 165,446,697 162,962,070 165,446,697
7
Depreciation
Expense for Asset
Retirement Costs
(403.1)
336 0 0
8 Amort. & Depl. of
Utility Plant (404-405)336 5,251,912 8,739,017 5,251,912 8,739,017
9 Amort. of Utility Plant
Acq. Adj. (406)336 15,018 15,018 15,018 15,018
10
Amort. Property
Losses, Unrecov
Plant and Regulatory
Study Costs (407)
0 0
11 Amort. of Conversion
Expenses (407.2)0 0
12 Regulatory Debits
(407.3)10,159,686 9,284,794 10,159,686 9,284,794
13 (Less) Regulatory
Credits (407.4)2,380,983 3,067,653 2,380,983 3,067,653
14 Taxes Other Than
Income Taxes (408.1)262 28,701,677 30,947,260 28,701,677 30,947,260
15 Income Taxes -
Federal (409.1)262 42,187,659 35,047,688 42,187,659 35,047,688
16 Income Taxes - Other
(409.1)262 1,940,619 13,298,956 1,940,619 13,298,956
17 Provision for Deferred
Income Taxes (410.1)
234,
272 53,504,641 22,846,006 53,504,641 22,846,006
FERC FORM No. 1 (REV. 02-04)
Page 114-117
18
(Less) Provision for
Deferred Income
Taxes-Cr. (411.1)
234,
272 64,332,926 44,552,318 64,332,926 44,552,318
19 Investment Tax Credit
Adj. - Net (411.4)266 5,825,740 11,832,897 5,825,740 11,832,897
20
(Less) Gains from
Disp. of Utility Plant
(411.6)
0 0
21 Losses from Disp. of
Utility Plant (411.7)0 0
22
(Less) Gains from
Disposition of
Allowances (411.8)
414,026 258,569 414,026 258,569
23
Losses from
Disposition of
Allowances (411.9)
0 0
24 Accretion Expense
(411.10)27,141 56,783 27,141 56,783
25
TOTAL Utility
Operating Expenses
(Enter Total of lines 4
thru 24)
1,346,489,874 1,167,151,768 1,346,489,874 1,167,151,768
27
Net Util Oper Inc
(Enter Tot line 2 less
25)
296,044,145 289,016,519 296,044,145 289,016,519
28 Other Income and
Deductions
29 Other Income
30 Nonutilty Operating
Income
31
Revenues From
Merchandising,
Jobbing and Contract
Work (415)
3,911,815 3,961,448
32
(Less) Costs and Exp.
of Merchandising,
Job. & Contract Work
(416)
4,701,875 4,522,755
33
Revenues From
Nonutility Operations
(417)
15,581 18,346
34
(Less) Expenses of
Nonutility Operations
(417.1)
(49,430)52,086
STATEMENT OF INCOME
Line
No.
Title of Account
(a)
(Ref.)
Page No.
(b)
Total Current
Year to Date
Balance for
Quarter/Year
(c)
Total Prior Year
to Date Balance
for Quarter/Year
(d)
Current 3
Months
Ended -
Quarterly
Only - No 4th
Quarter
(e)
Prior 3
Months
Ended -
Quarterly
Only - No 4th
Quarter
(f)
Electric Utility
Current Year to
Date (in dollars)
(g)
Electric Utility
Previous Year
to Date (in
dollars)
(h)
FERC FORM No. 1 (REV. 02-04)
Page 114-117
35 Nonoperating Rental
Income (418)3,613
36
Equity in Earnings of
Subsidiary
Companies (418.1)
119 8,782,042 8,991,348
37 Interest and Dividend
Income (419)12,658,172 7,129,761
38
Allowance for Other
Funds Used During
Construction (419.1)
37,285,494 31,537,344
39
Miscellaneous
Nonoperating Income
(421)
(1,358,052)(265,679)
40 Gain on Disposition
of Property (421.1)62,312 7,217
41
TOTAL Other Income
(Enter Total of lines
31 thru 40)
56,704,919 46,808,557
42 Other Income
Deductions
43 Loss on Disposition
of Property (421.2)0
44 Miscellaneous
Amortization (425)
45 Donations (426.1)2,646,442 1,638,267
46 Life Insurance (426.2)(7,106,697)(5,203,369)
47 Penalties (426.3)94,250 1,002,943
48
Exp. for Certain Civic,
Political & Related
Activities (426.4)
1,328,198 1,031,900
49 Other Deductions
(426.5)12,390,838 8,871,633
50
TOTAL Other Income
Deductions (Total of
lines 43 thru 49)
9,353,031 7,341,374
51
Taxes Applic. to Other
Income and
Deductions
52 Taxes Other Than
Income Taxes (408.2)262 36,746 24,200
53 Income Taxes-
Federal (409.2)262 496,189 (644,711)
STATEMENT OF INCOME
Line
No.
Title of Account
(a)
(Ref.)
Page No.
(b)
Total Current
Year to Date
Balance for
Quarter/Year
(c)
Total Prior Year
to Date Balance
for Quarter/Year
(d)
Current 3
Months
Ended -
Quarterly
Only - No 4th
Quarter
(e)
Prior 3
Months
Ended -
Quarterly
Only - No 4th
Quarter
(f)
Electric Utility
Current Year to
Date (in dollars)
(g)
Electric Utility
Previous Year
to Date (in
dollars)
(h)
FERC FORM No. 1 (REV. 02-04)
Page 114-117
54 Income Taxes-Other
(409.2)262 147,450 (196,593)
55 Provision for Deferred
Inc. Taxes (410.2)
234,
272 590 103,913
56
(Less) Provision for
Deferred Income
Taxes-Cr. (411.2)
234,
272 1,192,646 692,073
57 Investment Tax Credit
Adj.-Net (411.5)0
58 (Less) Investment Tax
Credits (420)0
59
TOTAL Taxes on
Other Income and
Deductions (Total of
lines 52-58)
(511,671)(1,405,264)
60
Net Other Income and
Deductions (Total of
lines 41, 50, 59)
47,863,559 40,872,447
61 Interest Charges
62 Interest on Long-Term
Debt (427)87,258,742 84,144,940
63 Amort. of Debt Disc.
and Expense (428)1,358,114 1,338,232
64
Amortization of Loss
on Reaquired Debt
(428.1)
2,851,131 2,938,715
65
(Less) Amort. of
Premium on Debt-
Credit (429)
1,106,962 1,106,961
66
(Less) Amortization of
Gain on Reaquired
Debt-Credit (429.1)
0
67
Interest on Debt to
Assoc. Companies
(430)
3,248 0
68 Other Interest
Expense (431)12,591,039 11,341,371
69
(Less) Allowance for
Borrowed Funds
Used During
Construction-Cr. (432)
13,914,276 11,992,630
70
Net Interest Charges
(Total of lines 62 thru
69)
89,041,036 86,663,667
STATEMENT OF INCOME
Line
No.
Title of Account
(a)
(Ref.)
Page No.
(b)
Total Current
Year to Date
Balance for
Quarter/Year
(c)
Total Prior Year
to Date Balance
for Quarter/Year
(d)
Current 3
Months
Ended -
Quarterly
Only - No 4th
Quarter
(e)
Prior 3
Months
Ended -
Quarterly
Only - No 4th
Quarter
(f)
Electric Utility
Current Year to
Date (in dollars)
(g)
Electric Utility
Previous Year
to Date (in
dollars)
(h)
FERC FORM No. 1 (REV. 02-04)
Page 114-117
71
Income Before
Extraordinary Items
(Total of lines 27, 60
and 70)
254,866,668 243,225,299
72 Extraordinary Items
73 Extraordinary Income
(434)
74 (Less) Extraordinary
Deductions (435)
75
Net Extraordinary
Items (Total of line 73
less line 74)
0
76
Income Taxes-
Federal and Other
(409.3)
262 0 0
77
Extraordinary Items
After Taxes (line 75
less line 76)
0 0
78 Net Income (Total of
line 71 and 77)254,866,668 243,225,299
FERC FORM No. 1 (REV. 02-04)
Page 114-117
STATEMENT OF INCOME
Line
No.
Title of Account
(a)
(Ref.)
Page No.
(b)
Total Current
Year to Date
Balance for
Quarter/Year
(c)
Total Prior Year
to Date Balance
for Quarter/Year
(d)
Current 3
Months
Ended -
Quarterly
Only - No 4th
Quarter
(e)
Prior 3
Months
Ended -
Quarterly
Only - No 4th
Quarter
(f)
Electric Utility
Current Year to
Date (in dollars)
(g)
Electric Utility
Previous Year
to Date (in
dollars)
(h)
STATEMENT OF INCOME
Line
No.
Gas Utiity Current Year to Date
(in dollars)
(i)
Gas Utility Previous Year to
Date (in dollars)
(j)
Other Utility Current Year to
Date (in dollars)
(k)
Other Utility Previous Year to
Date (in dollars)
(l)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25 0 0
27 0 0
28
29
30
31
32
33
FERC FORM No. 1 (REV. 02-04)
Page 114-117
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
STATEMENT OF INCOME
Line
No.
Gas Utiity Current Year to Date
(in dollars)
(i)
Gas Utility Previous Year to
Date (in dollars)
(j)
Other Utility Current Year to
Date (in dollars)
(k)
Other Utility Previous Year to
Date (in dollars)
(l)
FERC FORM No. 1 (REV. 02-04)
Page 114-117
66
67
68
69
70
71
72
73
74
75
76
77
78
FERC FORM No. 1 (REV. 02-04)
Page 114-117
STATEMENT OF INCOME
Line
No.
Gas Utiity Current Year to Date
(in dollars)
(i)
Gas Utility Previous Year to
Date (in dollars)
(j)
Other Utility Current Year to
Date (in dollars)
(k)
Other Utility Previous Year to
Date (in dollars)
(l)
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
STATEMENT OF RETAINED EARNINGS
Line No.Item
(a)
Contra Primary
Account Affected
(b)
Current Quarter/Year Year to
Date Balance
(c)
Previous Quarter/Year Year
to Date Balance
(d)
UNAPPROPRIATED RETAINED EARNINGS
(Account 216)
1 Balance-Beginning of Period 1,657,584,781 1,554,426,452
2 Changes
3 Adjustments to Retained Earnings (Account
439)
4 Adjustments to Retained Earnings Credit
4.1
4.2
4.3
4.4
4.5
4.6
4.7
4.8
4.9
4.10
9 TOTAL Credits to Retained Earnings (Acct. 439)
10 Adjustments to Retained Earnings Debit
10.1
10.2
10.3
10.4
10.5
10.6
10.7
10.8
10.9
10.10
15 TOTAL Debits to Retained Earnings (Acct. 439)
FERC FORM No. 1 (REV. 02-04)
Page 118-119
16 Balance Transferred from Income (Account 433
less Account 418.1)246,084,627 234,233,952
17 Appropriations of Retained Earnings (Acct. 436)
17.1
17.2
17.3
17.4
22 TOTAL Appropriations of Retained Earnings
(Acct. 436)
23 Dividends Declared-Preferred Stock (Account
437)
23.1
23.2
23.3
23.4
23.5
29 TOTAL Dividends Declared-Preferred Stock
(Acct. 437)
30 Dividends Declared-Common Stock (Account
438)
30.1 Acct 438 (114,624,278)(146,075,623)
30.2
30.3
30.4
30.5
36 TOTAL Dividends Declared-Common Stock
(Acct. 438)(114,624,278)(146,075,623)
37 Transfers from Acct 216.1, Unapprop. Undistrib.
Subsidiary Earnings 22,000,000 15,000,000
38 Balance - End of Period (Total
1,9,15,16,22,29,36,37)1,811,045,130 1,657,584,781
39 APPROPRIATED RETAINED EARNINGS
(Account 215)
39.1
39.2
39.3
STATEMENT OF RETAINED EARNINGS
Line No.Item
(a)
Contra Primary
Account Affected
(b)
Current Quarter/Year Year to
Date Balance
(c)
Previous Quarter/Year Year
to Date Balance
(d)
FERC FORM No. 1 (REV. 02-04)
Page 118-119
39.4
39.5
39.6
45 TOTAL Appropriated Retained Earnings
(Account 215)
APPROP. RETAINED EARNINGS - AMORT.
Reserve, Federal (Account 215.1)
46
TOTAL Approp. Retained Earnings-Amort.
Reserve, Federal (Acct. 215.1)13,273,106 13,273,106
47 TOTAL Approp. Retained Earnings (Acct. 215,
215.1) (Total 45,46)13,273,106 13,273,106
48 TOTAL Retained Earnings (Acct. 215, 215.1,
216) (Total 38, 47) (216.1)1,824,318,236 1,670,857,887
UNAPPROPRIATED UNDISTRIBUTED
SUBSIDIARY EARNINGS (Account Report
only on an Annual Basis, no Quarterly)
49 Balance-Beginning of Year (Debit or Credit)25,446,384 31,455,036
50 Equity in Earnings for Year (Credit) (Account
418.1)8,782,042 8,991,348
51 (Less) Dividends Received (Debit)22,000,000 15,000,000
52 TOTAL other Changes in unappropriated
undistributed subsidiary earnings for the year
52.1
53 Balance-End of Year (Total lines 49 thru 52)12,228,426 25,446,384
FERC FORM No. 1 (REV. 02-04)
Page 118-119
STATEMENT OF RETAINED EARNINGS
Line No.Item
(a)
Contra Primary
Account Affected
(b)
Current Quarter/Year Year to
Date Balance
(c)
Previous Quarter/Year Year
to Date Balance
(d)
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
STATEMENT OF CASH FLOWS
Line No.
Description (See Instructions No.1 for explanation of
codes)
(a)
Current Year to Date Quarter/Year
(b)
Previous Year to Date
Quarter/Year
(c)
1 Net Cash Flow from Operating Activities
2 Net Income (Line 78(c) on page 117)254,866,668 243,225,299
3 Noncash Charges (Credits) to Income:
4 Depreciation and Depletion 162,962,070 165,446,697
5 Amortization of (Specify) (footnote details)
5.1 Plant 5,266,930 8,754,035
5.2 Unamortized debt expense 4,324,548 4,365,718
5.3 Unamortized discount (866,599)(866,599)
5.4 Amortization of
5.5 Water Rights 1,042,009 1,042,009
5.6 Other 247,310 104,721
8 Deferred Income Taxes (Net)(10,454,124)(7,045,057)
9 Investment Tax Credit Adjustment (Net)2,019,318 4,101,519
10 Net (Increase) Decrease in Receivables (72,305,949)(6,292,909)
11 Net (Increase) Decrease in Inventory (11,626,320)990,657
12 Net (Increase) Decrease in Allowances Inventory 0 0
13 Net Increase (Decrease) in Payables and Accrued
Expenses
(a)164,086,842 (e)2,003,163
14 Net (Increase) Decrease in Other Regulatory Assets (100,178,478)(50,932,965)
15 Net Increase (Decrease) in Other Regulatory Liabilities 20,486,226 17,228,109
16 (Less) Allowance for Other Funds Used During
Construction 37,285,494 31,537,344
17 (Less) Undistributed Earnings from Subsidiary
Companies (4,884,745)(9,927,830)
18 Other (provide details in footnote):
18.1 Pension and postretirement benefit plan expense 29,268,379 33,803,097
18.2 Contributions to pension and postretirement benefit plans (44,175,136)(44,206,756)
18.3 Changes in unbilled revenues (8,479,542)(2,737,386)
18.4 Changes in prepayments 0 (6,588,935)
18.5 Changes in company owned life insurance (6,763,262)(4,961,062)
18.6 Other 2,097,770 1,321,971
FERC FORM No. 1 (ED. 12-96)
Page 120-121
18.7 Other (provide details in footnote):(b)29,351,815
22
Net Cash Provided by (Used in) Operating Activities
(Total of Lines 2 thru 21)388,769,726 337,145,812
24 Cash Flows from Investment Activities:
25 Construction and Acquisition of Plant (including land):
26 Gross Additions to Utility Plant (less nuclear fuel)(c)(469,715,418)(f)(331,509,226)
27 Gross Additions to Nuclear Fuel 0 0
28 Gross Additions to Common Utility Plant 0 0
29 Gross Additions to Nonutility Plant 0 0
30 (Less) Allowance for Other Funds Used During
Construction (37,285,494)(31,537,344)
31 Other (provide details in footnote):
31.1 Payments received from joint funding partners 17,778,170 5,876,358
31.2 Sale of renewable energy certificates and emission
allowances 2,042,118 2,230,655
31.3 Other (provide details in footnote):0 0
34 Cash Outflows for Plant (Total of lines 26 thru 33)(412,609,636)(291,864,869)
36 Acquisition of Other Noncurrent Assets (d)0 0
37 Proceeds from Disposal of Noncurrent Assets (d)0 0
39 Investments in and Advances to Assoc. and Subsidiary
Companies 0 0
40 Contributions and Advances from Assoc. and Subsidiary
Companies 0 0
41 Disposition of Investments in (and Advances to)
42 Disposition of Investments in (and Advances to)
Associated and Subsidiary Companies 0 0
44 Purchase of Investment Securities (a)(75,128,212)(16,123,299)
45 Proceeds from Sales of Investment Securities (a)63,857,030 11,327,616
46 Loans Made or Purchased 0 0
47 Collections on Loans 0 0
49 Net (Increase) Decrease in Receivables 0 0
50 Net (Increase) Decrease in Inventory 0 0
51 Net (Increase) Decrease in Allowances Held for
Speculation 0 0
52 Net Increase (Decrease) in Payables and Accrued
Expenses 0 0
STATEMENT OF CASH FLOWS
Line No.
Description (See Instructions No.1 for explanation of
codes)
(a)
Current Year to Date Quarter/Year
(b)
Previous Year to Date
Quarter/Year
(c)
FERC FORM No. 1 (ED. 12-96)
Page 120-121
53 Other (provide details in footnote):
53.1 Other (provide details in footnote):(d)5,563,106
57 Net Cash Provided by (Used in) Investing Activities (Total
of lines 34 thru 55)(418,317,712)(296,660,552)
59 Cash Flows from Financing Activities:
60 Proceeds from Issuance of:
61 Long-Term Debt (b)198,000,000 0
62 Preferred Stock 0 0
63 Common Stock 0 0
64 Other (provide details in footnote):
66 Net Increase in Short-Term Debt (c)0
67 Other (provide details in footnote):
70 Cash Provided by Outside Sources (Total 61 thru 69)198,000,000 0
72 Payments for Retirement of:
73 Long-term Debt (b)(4,359,999)0
74 Preferred Stock 0
75 Common Stock 0
76 Other (provide details in footnote):
76.1 Other (738,529)(238,230)
76.2 Other (provide details in footnote):0 0
78 Net Decrease in Short-Term Debt (c)0
80 Dividends on Preferred Stock 0
81 Dividends on Common Stock (114,447,348)(146,075,623)
83 Net Cash Provided by (Used in) Financing Activities
(Total of lines 70 thru 81)78,454,124 (146,313,853)
85 Net Increase (Decrease) in Cash and Cash Equivalents
86 Net Increase (Decrease) in Cash and Cash Equivalents
(Total of line 22, 57 and 83)48,906,138 (105,828,593)
88 Cash and Cash Equivalents at Beginning of Period 59,775,231 165,603,824
90 Cash and Cash Equivalents at End of Period 108,681,369 59,775,231
FERC FORM No. 1 (ED. 12-96)
Page 120-121
STATEMENT OF CASH FLOWS
Line No.
Description (See Instructions No.1 for explanation of
codes)
(a)
Current Year to Date Quarter/Year
(b)
Previous Year to Date
Quarter/Year
(c)
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
FOOTNOTE DATA
(a) Concept: NetIncreaseDecreaseInPayablesAndAccruedExpensesOperatingActivities
Cash (received) paid during the period for:
Note 6 Income taxes (503,713)
Note 6 Interest (net of amount capitalized)85,648,178
(b) Concept: OtherAdjustmentsToCashFlowsFromOperatingActivities
Other long-term assets ($7,650,512)
Other current assets $23,335,227
Other long-term liabilities $13,667,100
(c) Concept: GrossAdditionsToUtilityPlantLessNuclearFuelInvestingActivities
Non-cash investing activities:
Note 7 Additions to PP&E in accounts payable 84,323,931
(d) Concept: OtherAdjustmentsToCashFlowsFromInvestmentActivities
Life insurance proceeds received
(e) Concept: NetIncreaseDecreaseInPayablesAndAccruedExpensesOperatingActivities
Cash (received) paid during the period for:
Income taxes 58,279,359
Interest (net of amount capitalized)83,464,253
(f) Concept: GrossAdditionsToUtilityPlantLessNuclearFuelInvestingActivities
Non-cash investing activities:
Additions to PP&E in accounts payable 53,689,935
FERC FORM No. 1 (ED. 12-96)
Page 120-121
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
NOTES TO FINANCIAL STATEMENTS
1. Use the space below for important notes regarding the Balance Sheet, Statement of Income for the year, Statement of Retained
Earnings for the year, and Statement of Cash Flows, or any account thereof. Classify the notes according to each basic statement,
providing a subheading for each statement except where a note is applicable to more than one statement.
2. Furnish particulars (details) as to any significant contingent assets or liabilities existing at end of year, including a brief explanation of
any action initiated by the Internal Revenue Service involving possible assessment of additional income taxes of material amount, or
of a claim for refund of income taxes of a material amount initiated by the utility. Give also a brief explanation of any dividends in
arrears on cumulative preferred stock.
3. For Account 116, Utility Plant Adjustments, explain the origin of such amount, debits and credits during the year, and plan of
disposition contemplated, giving references to Cormmission orders or other authorizations respecting classification of amounts as
plant adjustments and requirements as to disposition thereof.
4. Where Accounts 189, Unamortized Loss on Reacquired Debt, and 257, Unamortized Gain on Reacquired Debt, are not used, give an
explanation, providing the rate treatment given these items. See General Instruction 17 of the Uniform System of Accounts.
5. Give a concise explanation of any retained earnings restrictions and state the amount of retained earnings affected by such
restrictions.
6. If the notes to financial statements relating to the respondent company appearing in the annual report to the stockholders are
applicable and furnish the data required by instructions above and on pages 114-121, such notes may be included herein.
7. For the 3Q disclosures, respondent must provide in the notes sufficient disclosures so as to make the interim information not
misleading. Disclosures which would substantially duplicate the disclosures contained in the most recent FERC Annual Report may
be omitted.
8. For the 3Q disclosures, the disclosures shall be provided where events subsequent to the end of the most recent year have occurred
which have a material effect on the respondent. Respondent must include in the notes significant changes since the most recently
completed year in such items as: accounting principles and practices; estimates inherent in the preparation of the financial statements;
status of long-term contracts; capitalization including significant new borrowings or modifications of existing financing agreements; and
changes resulting from business combinations or dispositions. However were material contingencies exist, the disclosure of such
matters shall be provided even though a significant change since year end may not have occurred.
9. Finally, if the notes to the financial statements relating to the respondent appearing in the annual report to the stockholders are
applicable and furnish the data required by the above instructions, such notes may be included herein.

IDAHO POWER COMPANY
NOTES TO FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Idaho Power Company (Idaho Power) is the principal operating subsidiary of IDACORP, Inc. (IDACORP), a holding company formed in 1998. Idaho Power is an electric utility
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 southern
Idaho and eastern Oregon. Idaho Power is regulated primarily by the state utility regulatory commissions of Idaho and Oregon and the Federal Energy Regulatory Commission
(FERC). Idaho Power is the parent of Idaho Energy Resources Co. (IERCo), a joint venturer in Bridger Coal Company (BCC), which mines and supplies coal to the Jim Bridger power
plant (Jim Bridger plant) owned in part by Idaho Power.

Basis of Reporting

The financial statements include the assets, liabilities, revenues and expenses of Idaho Power and have been prepared in accordance with the accounting requirements of the FERC as
set forth in the applicable Uniform System of Accounts and published accounting releases, which is a comprehensive basis of accounting other than accounting principles generally
accepted in the United States of America (U.S. GAAP). As required by the FERC, Idaho Power accounts for its investments in its majority-owned subsidiary on the equity method
rather than consolidating the assets, liabilities, revenues and expenses of the subsidiary as required by U.S GAAP. The accompanying financial statements include Idaho Power's
proportionate share of the utility plant and related operations resulting from its interest in jointly-owned plants. In addition, under the requirements of the FERC, there are differences
from U.S. GAAP in the presentation of (1) current portion of long-term debt, (2) assets and liabilities for cost of removal of assets, (3) regulatory assets and liabilities (4) deferred
income taxes, (5) income tax expense, (6) non-utility revenues, (7) accrued taxes, and (8) debt issue costs.

Management Estimates

Management makes estimates and assumptions when preparing financial statements in conformity with GAAP. 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 factors that are difficult to predict and are beyond management's control. Accordingly,
actual results could differ from those estimates.

Regulation of Utility Operations

As a regulated utility, many of Idaho Power's fundamental business decisions are subject to the approval of governmental agencies, including the prices that Idaho Power is authorized
to charge for its electric service. These approvals are a critical factor in determining Idaho Power's results of operations and financial condition.

Idaho Power meets the requirements under accounting principles generally accepted in the United States of America (GAAP) to prepare its financial statements applying the
specialized rules to account for the effects of cost-based rate regulation. Idaho Power's financial statements reflect the effects of the different ratemaking principles followed by the
jurisdictions regulating Idaho Power. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and
equipment; regulatory assets and liabilities; operating revenues; operation and maintenance expense; depreciation expense; and income tax expense. 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 represent
incurred costs that have been deferred because it is probable they will be recovered from customers through future rates. Regulatory liabilities represent obligations to make refunds to
customers for previous collections, or represent amounts collected in advance of incurring an expense. The effects of applying these regulatory accounting principles to Idaho Power's
operations are discussed in more detail in Note 3 - "Regulatory Matters."
Name of Respondent:Idaho Power Company This report is:(1) ☑ An Original(2) ☐ A Resubmission Date of Report:04/13/2023 Year/Period of ReportEnd of: 2022/ Q4NOTES TO FINANCIAL STATEMENTS1. Use the space below for important notes regarding the Balance Sheet, Statement of Income for the year, Statement of RetainedEarnings for the year, and Statement of Cash Flows, or any account thereof. Classify the notes according to each basic statement,providing a subheading for each statement except where a note is applicable to more than one statement.2. Furnish particulars (details) as to any significant contingent assets or liabilities existing at end of year, including a brief explanation ofany action initiated by the Internal Revenue Service involving possible assessment of additional income taxes of material amount, orof a claim for refund of income taxes of a material amount initiated by the utility. Give also a brief explanation of any dividends inarrears on cumulative preferred stock.3. For Account 116, Utility Plant Adjustments, explain the origin of such amount, debits and credits during the year, and plan ofdisposition contemplated, giving references to Cormmission orders or other authorizations respecting classification of amounts asplant 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 anexplanation, providing the rate treatment given these items. See General Instruction 17 of the Uniform System of Accounts.5. Give a concise explanation of any retained earnings restrictions and state the amount of retained earnings affected by suchrestrictions.6. If the notes to financial statements relating to the respondent company appearing in the annual report to the stockholders areapplicable and furnish the data required by instructions above and on pages 114-121, such notes may be included herein.7. For the 3Q disclosures, respondent must provide in the notes sufficient disclosures so as to make the interim information notmisleading. Disclosures which would substantially duplicate the disclosures contained in the most recent FERC Annual Report maybe omitted.8. For the 3Q disclosures, the disclosures shall be provided where events subsequent to the end of the most recent year have occurredwhich have a material effect on the respondent. Respondent must include in the notes significant changes since the most recentlycompleted year in such items as: accounting principles and practices; estimates inherent in the preparation of the financial statements;status of long-term contracts; capitalization including significant new borrowings or modifications of existing financing agreements; andchanges resulting from business combinations or dispositions. However were material contingencies exist, the disclosure of suchmatters 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 areapplicable and furnish the data required by the above instructions, such notes may be included herein. IDAHO POWER COMPANYNOTES TO FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Idaho Power Company (Idaho Power) is the principal operating subsidiary of IDACORP, Inc. (IDACORP), a holding company formed in 1998. Idaho Power is an electric utilityengaged in the generation, transmission, distribution, sales, and purchase of electric energy and capacity with a service area covering approximately 24,000 square miles in southernIdaho and eastern Oregon. Idaho Power is regulated primarily by the state utility regulatory commissions of Idaho and Oregon and the Federal Energy Regulatory Commission(FERC). Idaho Power is the parent of Idaho Energy Resources Co. (IERCo), a joint venturer in Bridger Coal Company (BCC), which mines and supplies coal to the Jim Bridger powerplant (Jim Bridger plant) owned in part by Idaho Power. Basis of Reporting The financial statements include the assets, liabilities, revenues and expenses of Idaho Power and have been prepared in accordance with the accounting requirements of the FERC asset forth in the applicable Uniform System of Accounts and published accounting releases, which is a comprehensive basis of accounting other than accounting principles generallyaccepted 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 methodrather than consolidating the assets, liabilities, revenues and expenses of the subsidiary as required by U.S GAAP. The accompanying financial statements include Idaho Power'sproportionate share of the utility plant and related operations resulting from its interest in jointly-owned plants. In addition, under the requirements of the FERC, there are differencesfrom U.S. GAAP in the presentation of (1) current portion of long-term debt, (2) assets and liabilities for cost of removal of assets, (3) regulatory assets and liabilities (4) deferredincome taxes, (5) income tax expense, (6) non-utility revenues, (7) accrued taxes, and (8) debt issue costs. Management Estimates Management makes estimates and assumptions when preparing financial statements in conformity with GAAP. These estimates and assumptions include those related to rateregulation, retirement benefits, contingencies, asset impairment, income taxes, unbilled revenues, and bad debt. These estimates and assumptions affect the reported amounts of assetsand 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 reportingperiod. These estimates involve judgments with respect to, among other things, future economic factors that are difficult to predict and are beyond management's control. Accordingly,actual results could differ from those estimates. Regulation of Utility Operations As a regulated utility, many of Idaho Power's fundamental business decisions are subject to the approval of governmental agencies, including the prices that Idaho Power is authorizedto charge for its electric service. These approvals are a critical factor in determining Idaho Power's results of operations and financial condition. Idaho Power meets the requirements under accounting principles generally accepted in the United States of America (GAAP) to prepare its financial statements applying thespecialized rules to account for the effects of cost-based rate regulation. Idaho Power's financial statements reflect the effects of the different ratemaking principles followed by thejurisdictions regulating Idaho Power. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, andequipment; regulatory assets and liabilities; operating revenues; operation and maintenance expense; depreciation expense; and income tax expense. The application of accountingprinciples related to regulated operations sometimes results in Idaho Power recording expenses and revenues in a different period than when an unregulated enterprise would recordsuch expenses and revenues. In these instances, the amounts are deferred or accrued as regulatory assets or regulatory liabilities on the balance sheet. Regulatory assets representincurred costs that have been deferred because it is probable they will be recovered from customers through future rates. Regulatory liabilities represent obligations to make refunds to
customers for previous collections, or represent amounts collected in advance of incurring an expense. The effects of applying these regulatory accounting principles to Idaho Power's
operations are discussed in more detail in Note 3 - "Regulatory Matters."operations are discussed in more detail in Note 3 - "Regulatory Matters."

System of Accounts

The accounting records of Idaho Power conform to the Uniform System of Accounts prescribed by the FERC and adopted by the public utility commissions of Idaho, Oregon, and
Wyoming.

Cash and Cash Equivalents

Cash and cash equivalents include cash on-hand and highly liquid temporary investments that mature within 90 days of the date of acquisition.

Receivables and Allowance for Uncollectible Accounts

Customer receivables are recorded at the invoiced amounts and do not bear interest. A late payment fee of one percent per month may be assessed on account balances after 30 days.
An allowance is recorded for potential uncollectible accounts. The measurement of expected credit losses on Idaho Power accounts receivable is based on historical experience,
current economic conditions, and forecasted information that may affect collections on the outstanding balance. Generally, this includes adjustments based upon a combination of
historical write-off experience, aging of accounts receivable, an analysis of specific customer accounts, and an evaluation of whether there are current or forecasted economic
conditions that might cause variation in collection from the historical experience. Adjustments are charged to income. Customer accounts receivable balances that remain outstanding
after reasonable collection efforts are written off.

The following table provides a rollforward of the allowance for uncollectible accounts related to customer receivables (in thousands of dollars):

Year Ended
December 31,
2022 2021
Balance at beginning of period $ 4,499 $ 4,766
Additions to the allowance 3,265 2,017
Write-offs, net of recoveries (2,730) (2,284)
Balance at end of period $ 5,034 $ 4,499
Allowance for uncollectible accounts as a percentage of customer receivables 4.2 % 5.4 %

Other receivables are also reviewed for impairment periodically, based upon transaction-specific facts. When it is probable that Idaho Power will be unable to collect all amounts due
according to the contractual terms of the agreement, an allowance is established for the estimated uncollectible portion of the receivable and charged to income.

There were no impaired receivables without related allowances at December 31, 2022 and 2021. Once a receivable is determined to be impaired, any further interest income
recognized is fully reserved.

Derivative Financial Instruments

Financial instruments such as commodity futures, forwards, options, and swaps are used to manage exposure to commodity price risk in the electricity and natural gas markets. All
derivative instruments are recognized as either assets or liabilities at fair value on the balance sheet unless they are designated as normal purchases and normal sales. With the
exception of forward contracts for the purchase of natural gas for use at Idaho Power's natural gas generation facilities and a nominal number of power transactions, Idaho Power's
physical forward contracts are designated as normal purchases and normal sales. Because of Idaho Power's regulatory accounting mechanisms, Idaho Power records the unrealized
changes in fair value of derivative instruments related to power supply as regulatory assets or liabilities.

Revenues

Operating revenues are generally recorded when service is rendered or energy is delivered to customers. Idaho Power accrues estimated unbilled revenues for electric services delivered
to customers but not yet billed at year-end. Idaho Power does not report any collections of franchise fees and similar taxes related to energy consumption on the income statement. In
addition, regulatory mechanisms in place in Idaho and Oregon affect the reported amount of revenue. The effects of applying these regulatory mechanisms are discussed in more detail
in Note 4 - "Revenues."

Property, Plant and Equipment and Depreciation

The cost of utility plant in service represents the original cost of contracted services, direct labor and material, allowance for funds used during construction (AFUDC), and indirect
charges for engineering, supervision, and similar overhead items. Repair and maintenance costs associated with planned major maintenance are expensed as the costs are incurred, as
are maintenance and repairs of property and replacements and renewals of items determined to be less than units of property. For utility property replaced or renewed, the original cost
plus removal cost less salvage is charged to accumulated provision for depreciation, while the cost of related replacements and renewals is added to property, plant and equipment.

All utility plant in service is depreciated using the straight-line method at rates approved by regulatory authorities. Annual depreciation provisions as a percent of average depreciable
utility plant in service approximated 2.7 percent in 2022 and 2.9 percent in 2021.

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 balance sheets. If the project becomes probable of being abandoned, these costs are expensed in the period such determination is
made. Idaho Power may seek recovery of these costs in customer rates, although there can be no guarantee such recovery would be granted.

Long-lived assets are periodically reviewed for impairment when events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the sum of
the undiscounted expected future cash flows from an asset is less than the carrying value of the asset, impairment is recognized in the financial statements. There were no material
impairments of long-lived assets in 2022 and 2021.

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 property through increased revenues resulting from a
higher rate base and higher depreciation expense. The component of AFUDC attributable to borrowed funds is included as a reduction to total interest expense. Idaho Power's
weighted-average monthly AFUDC rate was 7.4 percent for 2022 and 7.5 percent for 2021.

Income Taxes

Idaho Power accounts for income taxes under the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax
consequences of events that have been included in the financial statements. Under this method (commonly referred to as normalized accounting), deferred tax assets and liabilities are
determined based on the differences between the financial statements and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are
expected to reverse. In general, deferred income tax expense or benefit for a reporting period is recognized as the change in deferred tax assets and liabilities from the beginning to the
end of the period. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date unless Idaho Power's
primary regulator, the Idaho Public Utilities Commission (IPUC), orders direct deferral of the effect of the change in tax rates over a longer period of time.

Consistent with orders and directives of the IPUC, unless contrary to applicable income tax guidance, Idaho Power does not record deferred income tax expense or benefit for certain
operations are discussed in more detail in Note 3 - "Regulatory Matters." System of Accounts The accounting records of Idaho Power conform to the Uniform System of Accounts prescribed by the FERC and adopted by the public utility commissions of Idaho, Oregon, andWyoming. Cash and Cash Equivalents Cash and cash equivalents include cash on-hand and highly liquid temporary investments that mature within 90 days of the date of acquisition. Receivables and Allowance for Uncollectible Accounts Customer receivables are recorded at the invoiced amounts and do not bear interest. A late payment fee of one percent per month may be assessed on account balances after 30 days.An allowance is recorded for potential uncollectible accounts. The measurement of expected credit losses on Idaho Power accounts receivable is based on historical experience,current economic conditions, and forecasted information that may affect collections on the outstanding balance. Generally, this includes adjustments based upon a combination ofhistorical write-off experience, aging of accounts receivable, an analysis of specific customer accounts, and an evaluation of whether there are current or forecasted economicconditions that might cause variation in collection from the historical experience. Adjustments are charged to income. Customer accounts receivable balances that remain outstandingafter reasonable collection efforts are written off. The following table provides a rollforward of the allowance for uncollectible accounts related to customer receivables (in thousands of dollars): Year EndedDecember 31, 2022 2021Balance at beginning of period $ 4,499 $ 4,766Additions to the allowance 3,265 2,017Write-offs, net of recoveries (2,730) (2,284)Balance at end of period $ 5,034 $ 4,499Allowance for uncollectible accounts as a percentage of customer receivables 4.2 % 5.4 % Other receivables are also reviewed for impairment periodically, based upon transaction-specific facts. When it is probable that Idaho Power will be unable to collect all amounts dueaccording 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, 2022 and 2021. Once a receivable is determined to be impaired, any further interest incomerecognized is fully reserved. Derivative Financial Instruments Financial instruments such as commodity futures, forwards, options, and swaps are used to manage exposure to commodity price risk in the electricity and natural gas markets. Allderivative instruments are recognized as either assets or liabilities at fair value on the balance sheet unless they are designated as normal purchases and normal sales. With theexception of forward contracts for the purchase of natural gas for use at Idaho Power's natural gas generation facilities and a nominal number of power transactions, Idaho Power'sphysical forward contracts are designated as normal purchases and normal sales. Because of Idaho Power's regulatory accounting mechanisms, Idaho Power records the unrealizedchanges in fair value of derivative instruments related to power supply as regulatory assets or liabilities. Revenues Operating revenues are generally recorded when service is rendered or energy is delivered to customers. Idaho Power accrues estimated unbilled revenues for electric services deliveredto 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. Inaddition, 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 detailin Note 4 - "Revenues." Property, Plant and Equipment and Depreciation The cost of utility plant in service represents the original cost of contracted services, direct labor and material, allowance for funds used during construction (AFUDC), and indirectcharges for engineering, supervision, and similar overhead items. Repair and maintenance costs associated with planned major maintenance are expensed as the costs are incurred, asare maintenance and repairs of property and replacements and renewals of items determined to be less than units of property. For utility property replaced or renewed, the original costplus removal cost less salvage is charged to accumulated provision for depreciation, while the cost of related replacements and renewals is added to property, plant and equipment. All utility plant in service is depreciated using the straight-line method at rates approved by regulatory authorities. Annual depreciation provisions as a percent of average depreciableutility plant in service approximated 2.7 percent in 2022 and 2.9 percent in 2021. 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, areclassified as construction work in progress on the balance sheets. If the project becomes probable of being abandoned, these costs are expensed in the period such determination ismade. Idaho Power may seek recovery of these 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 ofthe undiscounted expected future cash flows from an asset is less than the carrying value of the asset, impairment is recognized in the financial statements. There were no materialimpairments of long-lived assets in 2022 and 2021. 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 property through increased revenues resulting from ahigher rate base and higher depreciation expense. The component of AFUDC attributable to borrowed funds is included as a reduction to total interest expense. Idaho Power'sweighted-average monthly AFUDC rate was 7.4 percent for 2022 and 7.5 percent for 2021. Income Taxes Idaho Power accounts for income taxes under the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future taxconsequences of events that have been included in the financial statements. Under this method (commonly referred to as normalized accounting), deferred tax assets and liabilities aredetermined 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 areexpected 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 theend of the period. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date unless Idaho Power's
primary regulator, the Idaho Public Utilities Commission (IPUC), orders direct deferral of the effect of the change in tax rates over a longer period of time.

Consistent with orders and directives of the IPUC, unless contrary to applicable income tax guidance, Idaho Power does not record deferred income tax expense or benefit for certainConsistent with orders and directives of the IPUC, unless contrary to applicable income tax guidance, Idaho Power does not record deferred income tax expense or benefit for certain
income tax temporary differences and instead recognizes the tax impact currently (commonly referred to as flow-through accounting) for rate making and financial reporting.
Therefore, Idaho Power's effective income tax rate is impacted as these differences arise and reverse. Idaho Power recognizes such adjustments as regulatory assets or liabilities if it is
probable that such amounts will be recovered from or returned to customers in future rates.

Idaho Power use judgment, estimation, and historical data in developing the provision for income taxes and the reporting of tax-related assets and liabilities, including development
of current year tax depreciation, capitalized repair costs, capitalized overheads, and other items. Income taxes can be impacted by changes in tax laws and regulations, interpretations
by taxing authorities, changes to accounting guidance, and actions by federal or state public utility regulators. Actual income taxes could vary from estimated amounts and may result
in favorable or unfavorable impacts to net 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 its plant assets for the
difference between income tax depreciation and book depreciation used for financial statement purposes. Deferred income taxes are recorded for other temporary differences unless
accounted for using flow-through.

Investment tax credits earned on regulated assets are deferred and amortized to income over the estimated service lives of the related properties.

Income taxes are discussed in more detail in Note 2 - "Income Taxes."

Other Accounting Policies

Debt discount, expense, and premium are deferred and amortized over the terms of the respective debt issuances. Losses on reacquired debt and associated costs are amortized over the
life of the associated replacement debt, as allowed under regulatory accounting.

New and Recently Adopted Accounting Pronouncements

There have been no recently issued accounting pronouncements that have had or are expected to have a material impact on Idaho Power's financial statements.

Subsequent Events

Management has evaluated the impact of events occurring after December 31, 2022, up to February 16, 2023, the date that Idaho Power Company's U.S. GAAP financial statements
were issued and has updated such evaluation for disclosure purposes through April 14, 2023. These financial statements include all necessary adjustments and disclosures resulting
from these evaluations.

2. INCOME TAXES

A reconciliation between the statutory federal income tax rate and the effective tax rate is as follows:

2022 2021
(thousands of dollars)
Federal income tax expense at 21% statutory rate $ 61,623 $ 58,857
Change in taxes resulting from:
Equity earnings of subsidiary companies (1,844)(1,888)
AFUDC (10,752)(9,141)
Capitalized interest 1,633 1,077
Investment tax credits (3,119)(2,866)
Removal costs (4,900)(3,302)
Capitalized overhead costs (3,150)(8,190)
Capitalized repair costs (19,320)(17,430)
State income taxes, net of federal benefit 18,352 11,633
Depreciation 11,897 14,233
Excess deferred income tax reversal (11,405)(8,958)
Income tax return adjustments (2,034)2,690
Other, net 1,596 329
Total income tax expense $ 38,577 $ 37,044
Effective tax rate 13.1%13.2%

The items comprising income tax expense are as follows: 2022 2021
(thousands of dollars)
Income taxes currently payable:
Federal $ 33,056 $ 34,574
State 11,715 12,932
Total 44,771 47,506
Income taxes deferred:
Federal (9,818)(16,999)
State (2,202)(5,295)
Total (12,020)(22,294)
Investment tax credits:
Deferred 8,945 14,698
Restored (3,119)(2,866)
Total 5,826 11,832
Total income tax expense $ 38,577 $ 37,044

The components of the net deferred tax liability are as
follows: 2022 2021
(thousands of dollars)

Deferred tax assets:
Regulatory liabilities $ 94,946 $ 96,880
Deferred compensation 24,495 23,333
Deferred revenue 53,418 48,318
Consistent with orders and directives of the IPUC, unless contrary to applicable income tax guidance, Idaho Power does not record deferred income tax expense or benefit for certainincome tax temporary differences and instead recognizes the tax impact currently (commonly referred to as flow-through accounting) for rate making and financial reporting.Therefore, Idaho Power's effective income tax rate is impacted as these differences arise and reverse. Idaho Power recognizes such adjustments as regulatory assets or liabilities if it isprobable that such amounts will be recovered from or returned to customers in future rates. Idaho Power use judgment, estimation, and historical data in developing the provision for income taxes and the reporting of tax-related assets and liabilities, including developmentof current year tax depreciation, capitalized repair costs, capitalized overheads, and other items. Income taxes can be impacted by changes in tax laws and regulations, interpretationsby 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 resultin 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 its plant assets for thedifference between income tax depreciation and book depreciation used for financial statement purposes. Deferred income taxes are recorded for other temporary differences unlessaccounted for using flow-through. Investment tax credits earned on regulated assets are deferred and amortized to income over the estimated service lives of the related properties. Income taxes are discussed in more detail in Note 2 - "Income Taxes." Other Accounting Policies Debt discount, expense, and premium are deferred and amortized over the terms of the respective debt issuances. Losses on reacquired debt and associated costs are amortized over thelife of the associated replacement debt, as allowed under regulatory accounting. New and Recently Adopted Accounting Pronouncements There have been no recently issued accounting pronouncements that have had or are expected to have a material impact on Idaho Power's financial statements. Subsequent Events Management has evaluated the impact of events occurring after December 31, 2022, up to February 16, 2023, the date that Idaho Power Company's U.S. GAAP financial statementswere issued and has updated such evaluation for disclosure purposes through April 14, 2023. These financial statements include all necessary adjustments and disclosures resultingfrom these evaluations. 2. INCOME TAXES A reconciliation between the statutory federal income tax rate and the effective tax rate is as follows: 2022 2021 (thousands of dollars)Federal income tax expense at 21% statutory rate $ 61,623 $ 58,857Change in taxes resulting from: Equity earnings of subsidiary companies (1,844)(1,888) AFUDC (10,752)(9,141) Capitalized interest 1,633 1,077 Investment tax credits (3,119)(2,866) Removal costs (4,900)(3,302) Capitalized overhead costs (3,150)(8,190) Capitalized repair costs (19,320)(17,430) State income taxes, net of federal benefit 18,352 11,633 Depreciation 11,897 14,233 Excess deferred income tax reversal (11,405)(8,958) Income tax return adjustments (2,034)2,690 Other, net 1,596 329Total income tax expense $ 38,577 $ 37,044 Effective tax rate 13.1%13.2% The items comprising income tax expense are as follows: 2022 2021 (thousands of dollars)Income taxes currently payable: Federal $ 33,056 $ 34,574 State 11,715 12,932 Total 44,771 47,506Income taxes deferred: Federal (9,818)(16,999) State (2,202)(5,295) Total (12,020)(22,294)Investment tax credits: Deferred 8,945 14,698 Restored (3,119)(2,866) Total 5,826 11,832Total income tax expense $ 38,577 $ 37,044 The components of the net deferred tax liability are asfollows: 2022 2021 (thousands of dollars) Deferred tax assets:
Regulatory liabilities $ 94,946 $ 96,880
Deferred compensation 24,495 23,333
Deferred revenue 53,418 48,318 Deferred revenue 53,418 48,318
Tax credits 44,727 35,781
Retirement benefits 38,687 110,997
Other 10,133 9,379
Total 266,406 324,688
Deferred tax liabilities:
Property, plant and equipment 249,452 272,530
Regulatory assets 739,689 721,276
Power cost adjustment 33,116 9,015
Retirement benefits 80,777 138,154
Other 49,322 40,533
Total 1,152,356 1,181,508

Net deferred tax liabilities $ 885,950 $ 856,820

The components of the net deferred tax liability are as follows (in thousands):

IDACORP's tax allocation agreement provides that each member of its consolidated group compute its income taxes on a separate company basis. Amounts payable or refundable are
settled through IDACORP and are reported as taxes accrued or income taxes receivable, respectively, on the balance sheets of Idaho Power. See Note 1 - "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 2022 and prior tax years. Idaho Power recognizes interest accrued related to unrecognized tax benefits as
interest expense and penalties as other expense.

Idaho Power is subject to examination by its major tax jurisdictions - United States federal and the State of Idaho. The open tax years for examination are 2020-2022 for federal and
2016-2022 for Idaho. The Idaho State Tax Commission began its examination of the 2016-2018 tax years in March of 2020. In May 2009, IDACORP formally entered the U.S. Internal
Revenue Service (IRS) Compliance Assurance Process (CAP) program for its 2009 tax year and has remained in the CAP program for all subsequent years. The CAP program provides
for Internal Revenue Service (IRS) examination and issue resolution throughout the current year with the objective of return filings containing no contested items. IDACORP was in
the bridge phase of CAP for both the 2020 and 2021 tax years. The IRS moved IDACORP from the bridge phase of CAP to the maintenance phase for the 2022 tax year.

Excess Deferred Income Taxes

Following the enactment of income tax reform in 2017, Idaho Power was required to remeasure its deferred tax assets and liabilities at the new federal corporate income tax rate which
resulted in lower net deferred tax liabilities and the establishment of a net regulatory liability for its depreciation-related excess deferred income taxes (EDIT). Idaho Power's deferred
taxes for depreciation-related temporary differences on its public utility property are subject to the normalization method of accounting. As provided in the 2017 income tax reform
statute, the normalization method requires the use of either the average rate assumption method (ARAM) or the alternative method for the reversal of the EDIT. In 2021, Idaho Power
began using the alternative method for the EDIT reversal pursuant to the interpretation of an Internal Revenue Service revenue procedure and series of related private letter rulings.
The alternative method results in the ratable return of the EDIT to customers over the remaining regulatory lives of Idaho Power's plant assets. For fiscal years 2018-2020, the ARAM
method was used to reverse the EDIT.

Inflation Reduction Act

On August 16, 2022, the Inflation Reduction Act of 2022 (the 2022 IRA) was signed into law. The 2022 IRA provides for, among other things, numerous renewable energy tax credits,
for example: extension of the current investment (ITC) and production (PTC) tax credits, a new ITC for standalone energy storage, application of the PTC to solar, transition to a
technology-neutral ITC and PTC after 2024 and created a transferability option that allows credits to be sold to an unrelated taxpayer. The 2022 IRA modifies the calculation of most
of the energy tax credits by introducing the concept of a "base credit" (e.g., 6 percent ITC) and a "bonus credit" (e.g., an additional 24 percent ITC) if certain wage and apprenticeship
requirements are met in the construction and ongoing maintenance of the renewable energy facilities. Additionally, the 2022 IRA also established a 15 percent alternative minimum
tax for C-corporations with an average financial statement income of more than $1 billion for the previous three taxable years. Idaho Power is not subject to the alternative minimum
tax.

3. REGULATORY MATTERS

Idaho Power's financial statements reflect the effects of the different ratemaking principles followed by the jurisdictions regulating Idaho Power. Included below is a summary of Idaho
Power's regulatory assets and liabilities, as well as a discussion of notable regulatory matters.

Regulatory Assets and Liabilities

The application of accounting principles related to regulated operations sometimes results in Idaho Power recording some expenses and revenues in a different period than when an
unregulated enterprise would record those expenses and revenues. Regulatory assets represent incurred costs that have been deferred because it is probable they will be recovered from
customers through future rates. Regulatory liabilities represent obligations to make refunds to customers for previous collections, or represent amounts collected in advance of
incurring an expense.

The following table presents a summary of Idaho Power's regulatory assets and liabilities (in thousands of dollars):
As of December 31, 2022
Remaining
Amortization
Period
Earning a
Return(1)
Not Earning
a Return
Total as of December 31,
Description 2022 2021
Regulatory Assets:
Income taxes(2) $ $ 739,689 $ 739,689 $ 721,276
Unfunded postretirement benefits(3) 70,254 70,254 315,011
Pension expense deferrals(4) 220,648 28,855 249,503 234,437
Energy efficiency program costs(5) 3,767 3,767 7,622
Power supply costs(6) 2023-2024 145,321 (16,012) 129,309 33,623
Fixed cost adjustment(6) 2023-2024 24,859 17,042 41,901 54,944
North Valmy plant settlements(6) 2023-2028 90,747 90,747 97,852
Jim Bridger plant settlement(6) 2023-2030 76,392 4,139 80,531
Asset retirement obligations(7) 28,780 28,780 22,585
Wildfire Mitigation Plan deferral(6) 27,078 27,078 6,075
Deferred revenue 53,418 48,318 Tax credits 44,727 35,781 Retirement benefits 38,687 110,997 Other 10,133 9,379 Total 266,406 324,688Deferred tax liabilities: Property, plant and equipment 249,452 272,530 Regulatory assets 739,689 721,276 Power cost adjustment 33,116 9,015 Retirement benefits 80,777 138,154 Other 49,322 40,533 Total 1,152,356 1,181,508 Net deferred tax liabilities $ 885,950 $ 856,820 The components of the net deferred tax liability are as follows (in thousands): IDACORP's tax allocation agreement provides that each member of its consolidated group compute its income taxes on a separate company basis. Amounts payable or refundable aresettled through IDACORP and are reported as taxes accrued or income taxes receivable, respectively, on the balance sheets of Idaho Power. See Note 1 - "Summary of SignificantAccounting 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 2022 and prior tax years. Idaho Power recognizes interest accrued related to unrecognized tax benefits asinterest expense and penalties as other expense. Idaho Power is subject to examination by its major tax jurisdictions - United States federal and the State of Idaho. The open tax years for examination are 2020-2022 for federal and2016-2022 for Idaho. The Idaho State Tax Commission began its examination of the 2016-2018 tax years in March of 2020. In May 2009, IDACORP formally entered the U.S. InternalRevenue Service (IRS) Compliance Assurance Process (CAP) program for its 2009 tax year and has remained in the CAP program for all subsequent years. The CAP program providesfor Internal Revenue Service (IRS) examination and issue resolution throughout the current year with the objective of return filings containing no contested items. IDACORP was inthe bridge phase of CAP for both the 2020 and 2021 tax years. The IRS moved IDACORP from the bridge phase of CAP to the maintenance phase for the 2022 tax year. Excess Deferred Income Taxes Following the enactment of income tax reform in 2017, Idaho Power was required to remeasure its deferred tax assets and liabilities at the new federal corporate income tax rate whichresulted in lower net deferred tax liabilities and the establishment of a net regulatory liability for its depreciation-related excess deferred income taxes (EDIT). Idaho Power's deferredtaxes for depreciation-related temporary differences on its public utility property are subject to the normalization method of accounting. As provided in the 2017 income tax reformstatute, the normalization method requires the use of either the average rate assumption method (ARAM) or the alternative method for the reversal of the EDIT. In 2021, Idaho Powerbegan using the alternative method for the EDIT reversal pursuant to the interpretation of an Internal Revenue Service revenue procedure and series of related private letter rulings.The alternative method results in the ratable return of the EDIT to customers over the remaining regulatory lives of Idaho Power's plant assets. For fiscal years 2018-2020, the ARAMmethod was used to reverse the EDIT. Inflation Reduction Act On August 16, 2022, the Inflation Reduction Act of 2022 (the 2022 IRA) was signed into law. The 2022 IRA provides for, among other things, numerous renewable energy tax credits,for example: extension of the current investment (ITC) and production (PTC) tax credits, a new ITC for standalone energy storage, application of the PTC to solar, transition to atechnology-neutral ITC and PTC after 2024 and created a transferability option that allows credits to be sold to an unrelated taxpayer. The 2022 IRA modifies the calculation of mostof the energy tax credits by introducing the concept of a "base credit" (e.g., 6 percent ITC) and a "bonus credit" (e.g., an additional 24 percent ITC) if certain wage and apprenticeshiprequirements are met in the construction and ongoing maintenance of the renewable energy facilities. Additionally, the 2022 IRA also established a 15 percent alternative minimumtax for C-corporations with an average financial statement income of more than $1 billion for the previous three taxable years. Idaho Power is not subject to the alternative minimumtax. 3. REGULATORY MATTERS Idaho Power's financial statements reflect the effects of the different ratemaking principles followed by the jurisdictions regulating Idaho Power. Included below is a summary of IdahoPower's 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 expenses and revenues in a different period than when anunregulated enterprise would record those expenses and revenues. Regulatory assets represent incurred costs that have been deferred because it is probable they will be recovered fromcustomers through future rates. Regulatory liabilities represent obligations to make refunds to customers for previous collections, or represent amounts collected in advance ofincurring an expense. The following table presents a summary of Idaho Power's regulatory assets and liabilities (in thousands of dollars): As of December 31, 2022 RemainingAmortizationPeriod Earning aReturn(1) Not Earninga Return Total as of December 31,Description 2022 2021Regulatory Assets: Income taxes(2) $ $ 739,689 $ 739,689 $ 721,276Unfunded postretirement benefits(3) 70,254 70,254 315,011Pension expense deferrals(4) 220,648 28,855 249,503 234,437Energy efficiency program costs(5) 3,767 3,767 7,622Power supply costs(6) 2023-2024 145,321 (16,012) 129,309 33,623Fixed cost adjustment(6) 2023-2024 24,859 17,042 41,901 54,944North Valmy plant settlements(6) 2023-2028 90,747 90,747 97,852
Jim Bridger plant settlement(6) 2023-2030 76,392 4,139 80,531
Asset retirement obligations(7) 28,780 28,780 22,585
Wildfire Mitigation Plan deferral(6) 27,078 27,078 6,075Wildfire Mitigation Plan deferral(6) 27,078 27,078 6,075
Long-term service agreement 2023-2043 13,363 8,751 22,114 23,273
Other 2023-2056 2,790 15,498 18,288 17,050
Total $ 577,887 $ 924,074 $ 1,501,961 $ 1,533,748
Regulatory Liabilities:
Income taxes(8) $ $ 94,946 $ 94,946 $ 96,880
Depreciation-related excess deferred income
taxes(9) 158,634 158,634 170,039
Energy efficiency program costs(5) 154 154
Settlement agreement sharing mechanism(6) 2023 569
Mark-to-market liabilities 59,544 59,544 8,581
Tax reform accrual for future
amortization(10) 32,793 32,793 24,522
Other 6,553 5,077 11,630 10,498
Total $ 165,341 $ 192,360 $ 357,701 $ 311,087

(1) Earning a return includes either interest or a return on the investment as a component of rate base at the allowed rate of return.
(2) Represents flow-through income tax accounting differences which have a corresponding deferred tax liability disclosed in Note 2 - "Income Taxes."
(3) Represents the unfunded obligation of Idaho Power's pension and postretirement benefit plans, which are discussed in Note 10 - "Benefit Plans."
(4) Idaho Power records a regulatory asset for the difference between net periodic pension cost and pension cost considered for rate-making purposes relating to Idaho Power's defined benefit pension plan. In its
Idaho jurisdiction, Idaho Power's inclusion of pension costs for the establishment of retail rates is based upon contributions made to the pension plan. This regulatory asset account represents the difference
between cumulative cash contributions and amounts collected in rates. Deferred costs are amortized into expense as the amounts are provided for in Idaho retail revenues.
(5) The energy efficiency asset and liability represent the separate Idaho and Oregon jurisdiction balances at December 31, 2022.
(6) This item is discussed in more detail in this Note 3 - "Regulatory Matters."
(7) Asset retirement obligations and removal costs are discussed in Note 12 - "Asset Retirement Obligations (ARO)."
(8) Represents the tax gross-up related to the depreciation-related excess deferred income taxes and investment tax credits included in this table and has a corresponding deferred tax asset disclosed in Note 2 -
"Income Taxes."
(9) In 2017, income tax reform reduced deferred income tax assets and liabilities. For depreciation-related temporary differences under the normalized tax accounting method, the resulting excess deferred taxes
will flow back to customers ratably over the remaining regulatory lives of Idaho Power's plant assets under the alternative method provided in the statute.
(10) Represents amount accrued under the May 2018 Idaho Tax Reform Settlement Stipulation (described below) for the future amortization of existing or future unspecified regulatory deferrals that would
otherwise be a future liability recoverable from Idaho customers.

Idaho Power's regulatory assets and liabilities are typically amortized over the period in which they are reflected in customer rates. In the event that recovery of Idaho Power's costs
through rates becomes unlikely or uncertain, regulatory accounting would no longer apply to some or all of Idaho Power's operations and the items above may represent stranded
investments. If not allowed full recovery of these items, Idaho Power would be required to write off the applicable portion, which could have a materially adverse financial impact.

Power Cost Adjustment Mechanisms and Deferred Power Supply Costs

In both its Idaho and Oregon jurisdictions, Idaho Power's power cost adjustment mechanisms address the volatility of power supply costs and provide for annual adjustments to the
rates charged to its retail customers. The power cost adjustment mechanisms compare Idaho Power's actual net power supply costs (primarily fuel and purchased power less wholesale
energy sales) against net power supply costs being recovered in Idaho Power's retail rates. Under the power cost adjustment mechanisms, certain differences between actual net power
supply costs 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 the levels of Idaho Power's own hydroelectric generation, changes in contracted power purchase prices and volumes, changes in
wholesale market prices and transaction volumes, and changes in fuel prices.

Idaho Jurisdiction Power Cost Adjustment Mechanism: In the Idaho jurisdiction, the annual power cost adjustment (PCA) 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 balancing component that trues up the difference between the
previous year's actual net power supply costs and the costs collected in the previous year's forecast component. The latter component ensures that, over time, the actual collection or
refund of net power supply costs matches the amounts authorized. The PCA mechanism includes:

a cost or benefit sharing ratio that allocates the deviations in net power supply expenses between customers (95 percent) and Idaho Power (5 percent), with the exceptions of
expenses associated with PURPA power purchases and demand response incentive payments, which are allocated 100 percent to customers; and
a sales-based adjustment intended to ensure that power supply expense recovery resulting solely from sales volume changes does not distort the results of the mechanism.

The Idaho deferral period or Idaho-jurisdiction PCA year runs from April 1 through March 31. Amounts deferred during the PCA year are primarily recovered or refunded during the
subsequent June 1 through May 31 period.

The table below summarizes the three most recent Idaho-jurisdiction PCA rate adjustments, which also include non-PCA-related rate adjustments as ordered by the IPUC:
Effective Date
$ Change
(millions) Notes
June 1, 2022

$ 94.9

The $94.9 million increase in PCA rates reflects a forecasted reduction in low-cost
hydroelectric generation as well as higher costs associated with market energy prices and
natural gas prices. The rate also reflects $0.6 million of 2021 earnings shared with
customers under the May 2018 Idaho Tax Reform Settlement Stipulation described below.
June 1, 2021

$ 39.1

The net increase in PCA rates reflects a forecasted reduction in low-cost hydroelectric
generation as well as higher costs associated with forecasted PURPA power purchases. The
net increase in PCA revenues also reflects a smaller credit to customers through the true-up
component.

Oregon Jurisdiction Power Cost Adjustment Mechanism: Idaho Power's power cost recovery mechanism in Oregon has two components: an annual power cost update (APCU) and a
power cost adjustment mechanism (PCAM). The APCU allows Idaho Power to reestablish its Oregon base net power supply costs annually, separate from a general rate case, and to
forecast net power supply costs for the upcoming water year. The PCAM is a true-up filed annually in February. The filing calculates the deviation between actual net power supply
expenses incurred for the preceding calendar year and the net power supply expenses recovered through the APCU for the same period. Actual 2022 Oregon-jurisdiction power supply
costs exceeded the amount recovered through the APCU, resulting in a $1.1 million deferral of costs for future recovery. Oregon jurisdiction power supply cost changes during 2021
did not have a material impact on Idaho Power's financial statements.

Notable Idaho Base Rate Adjustments

Idaho base rates were most recently established through a general rate case in 2012, and adjusted in 2014, 2017, 2018, and 2019.

Wildfire Mitigation Plan deferral(6) 27,078 27,078 6,075Long-term service agreement 2023-2043 13,363 8,751 22,114 23,273Other 2023-2056 2,790 15,498 18,288 17,050Total $ 577,887 $ 924,074 $ 1,501,961 $ 1,533,748Regulatory Liabilities: Income taxes(8) $ $ 94,946 $ 94,946 $ 96,880Depreciation-related excess deferred incometaxes(9) 158,634 158,634 170,039Energy efficiency program costs(5) 154 154 Settlement agreement sharing mechanism(6) 2023 569Mark-to-market liabilities 59,544 59,544 8,581Tax reform accrual for futureamortization(10) 32,793 32,793 24,522Other 6,553 5,077 11,630 10,498Total $ 165,341 $ 192,360 $ 357,701 $ 311,087 (1) Earning a return includes either interest or a return on the investment as a component of rate base at the allowed rate of return.(2) Represents flow-through income tax accounting differences which have a corresponding deferred tax liability disclosed in Note 2 - "Income Taxes."(3) Represents the unfunded obligation of Idaho Power's pension and postretirement benefit plans, which are discussed in Note 10 - "Benefit Plans."(4) Idaho Power records a regulatory asset for the difference between net periodic pension cost and pension cost considered for rate-making purposes relating to Idaho Power's defined benefit pension plan. In itsIdaho jurisdiction, Idaho Power's inclusion of pension costs for the establishment of retail rates is based upon contributions made to the pension plan. This regulatory asset account represents the differencebetween cumulative cash contributions and amounts collected in rates. Deferred costs are amortized into expense as the amounts are provided for in Idaho retail revenues.(5) The energy efficiency asset and liability represent the separate Idaho and Oregon jurisdiction balances at December 31, 2022.(6) This item is discussed in more detail in this Note 3 - "Regulatory Matters."(7) Asset retirement obligations and removal costs are discussed in Note 12 - "Asset Retirement Obligations (ARO)."(8) Represents the tax gross-up related to the depreciation-related excess deferred income taxes and investment tax credits included in this table and has a corresponding deferred tax asset disclosed in Note 2 -"Income Taxes."(9) In 2017, income tax reform reduced deferred income tax assets and liabilities. For depreciation-related temporary differences under the normalized tax accounting method, the resulting excess deferred taxeswill flow back to customers ratably over the remaining regulatory lives of Idaho Power's plant assets under the alternative method provided in the statute.(10) Represents amount accrued under the May 2018 Idaho Tax Reform Settlement Stipulation (described below) for the future amortization of existing or future unspecified regulatory deferrals that wouldotherwise be a future liability recoverable from Idaho customers. Idaho Power's regulatory assets and liabilities are typically amortized over the period in which they are reflected in customer rates. In the event that recovery of Idaho Power's coststhrough 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 strandedinvestments. If not allowed full recovery of these items, Idaho Power would be required to write off the applicable portion, which could have a materially adverse financial impact. 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 therates charged to its retail customers. The power cost adjustment mechanisms compare Idaho Power's actual net power supply costs (primarily fuel and purchased power less wholesaleenergy sales) against net power supply costs being recovered in Idaho Power's retail rates. Under the power cost adjustment mechanisms, certain differences between actual net powersupply 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 powersupply costs deferred primarily result from changes in the levels of Idaho Power's own hydroelectric generation, changes in contracted power purchase prices and volumes, changes inwholesale market prices and transaction volumes, and changes in fuel prices. Idaho Jurisdiction Power Cost Adjustment Mechanism: In the Idaho jurisdiction, the annual power cost adjustment (PCA) consists of (a) a forecast component, based on a forecast ofnet power supply costs in the coming year as compared with net power supply costs included in base rates; and (b) a balancing component that trues up the difference between theprevious year's actual net power supply costs and the costs collected in the previous year's forecast component. The latter component ensures that, over time, the actual collection orrefund of net power supply costs matches the amounts authorized. The PCA mechanism includes: a cost or benefit sharing ratio that allocates the deviations in net power supply expenses between customers (95 percent) and Idaho Power (5 percent), with the exceptions ofexpenses associated with PURPA power purchases and demand response incentive payments, which are allocated 100 percent to customers; and a sales-based adjustment intended to ensure that power supply expense recovery resulting solely from sales volume changes does not distort the results of the mechanism. The Idaho deferral period or Idaho-jurisdiction PCA year runs from April 1 through March 31. Amounts deferred during the PCA year are primarily recovered or refunded during thesubsequent June 1 through May 31 period. The table below summarizes the three most recent Idaho-jurisdiction PCA rate adjustments, which also include non-PCA-related rate adjustments as ordered by the IPUC:Effective Date $ Change(millions) NotesJune 1, 2022 $ 94.9 The $94.9 million increase in PCA rates reflects a forecasted reduction in low-costhydroelectric generation as well as higher costs associated with market energy prices andnatural gas prices. The rate also reflects $0.6 million of 2021 earnings shared withcustomers under the May 2018 Idaho Tax Reform Settlement Stipulation described below.June 1, 2021 $ 39.1 The net increase in PCA rates reflects a forecasted reduction in low-cost hydroelectricgeneration as well as higher costs associated with forecasted PURPA power purchases. Thenet increase in PCA revenues also reflects a smaller credit to customers through the true-upcomponent. Oregon Jurisdiction Power Cost Adjustment Mechanism: Idaho Power's power cost recovery mechanism in Oregon has two components: an annual power cost update (APCU) and apower 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 toforecast net power supply costs for the upcoming water year. The PCAM is a true-up filed annually in February. The filing calculates the deviation between actual net power supplyexpenses incurred for the preceding calendar year and the net power supply expenses recovered through the APCU for the same period. Actual 2022 Oregon-jurisdiction power supplycosts exceeded the amount recovered through the APCU, resulting in a $1.1 million deferral of costs for future recovery. Oregon jurisdiction power supply cost changes during 2021did not have a material impact on Idaho Power's financial statements.
Notable Idaho Base Rate Adjustments

Idaho base rates were most recently established through a general rate case in 2012, and adjusted in 2014, 2017, 2018, and 2019.

January 2012 and June 2014 Idaho Base Rate Adjustments: Effective January 1, 2012, Idaho Power implemented new Idaho base rates resulting from IPUC approval of a settlement
stipulation that provided for a 7.86 percent authorized overall rate of return on an Idaho-jurisdiction rate base of approximately $2.36 billion. The settlement stipulation resulted in a
4.07 percent, or $34.0 million, overall increase in Idaho Power's annual Idaho-jurisdiction base rate revenues. Idaho base rates were subsequently adjusted again in 2012, in
connection with Idaho Power's completion of the Langley Gulch power plant. In June 2012, the IPUC issued an order approving a $58.1 million increase in annual Idaho-jurisdiction
base rates, effective July 1, 2012. The order also provided for a $335.9 million increase in Idaho rate base. Neither the settlement stipulation nor the IPUC orders adjusting base rates
specified an authorized rate of return on equity or imposed a moratorium on Idaho Power filing a general rate case at a future date.

The IPUC issued a March 2014 order approving Idaho Power's request for an increase in the normalized or "base level" net power supply expense to be used to update base rates and in
the determination of the PCA rate that became effective June 1, 2014.

May 2018 Idaho Tax Reform Settlement Stipulation: In December 2017, the Tax Cuts and Jobs Act was signed into law, which, among other things, lowered the corporate federal
income tax rate from 35 percent to 21 percent and modified or eliminated certain federal income tax deductions for corporations. In March 2018, Idaho House Bill 463 was signed into
law reducing the Idaho state corporate income tax rate from 7.4 percent to 6.925 percent.

In May 2018, the IPUC issued an order approving a settlement stipulation (May 2018 Idaho Tax Reform Settlement Stipulation) related to income tax reform. Beginning June 1, 2018,
the settlement stipulation provided an annual (a) $18.7 million reduction to Idaho customer base rates and (b) $7.4 million amortization of existing regulatory deferrals for specified
items or future amortization of other existing or future unspecified regulatory deferrals that would otherwise be a future regulatory asset recoverable from Idaho customers. The May
2018 Idaho Tax Reform Settlement Stipulation also provided for the indefinite extension, with modifications, of a previous settlement stipulation beyond its termination date of
December 31, 2019.

The May 2018 settlement stipulation provides Idaho Power the ability to earn a minimum Idaho-Jurisdiction return on year-end equity (Idaho ROE) of 9.4 percent by amortizing up to
$25 million of additional ADITC in any calendar year, so long as the cumulative amount of additional accumulated deferred investment tax credits (ADITC) used does not exceed $45
million; however, Idaho Power may seek approval from the IPUC to replenish the total amount of additional ADITC it is permitted to amortize and if there are no remaining amounts of
additional ADITC authorized to be amortized, the remainder of the revenue sharing provisions below would not be applicable until additional ADITC is replenished.

If Idaho Power's annual Idaho ROE in any year exceeds 10.0 percent, the amount of earnings exceeding 10.0 percent and up to and including 10.5 percent will be allocated 80 percent
to Idaho Power's Idaho customers as a rate reduction to be effective at the time of the subsequent year's PCA, and 20 percent to Idaho Power.

If Idaho Power's annual Idaho ROE in any year exceeds 10.5 percent, the amount of earnings exceeding a 10.5 percent Idaho ROE will be allocated 55 percent to Idaho Power's Idaho
customers as a rate reduction to be effective at the time of the subsequent year's PCA, 25 percent to Idaho Power's Idaho customers in the form of a reduction to the pension regulatory
asset balancing account (to reduce the amount to be collected in the future from Idaho customers) and 20 percent to Idaho Power.

In the event the IPUC approves a change to Idaho Power's allowed annual Idaho ROE as part of a general rate case proceeding effective on or after January 1, 2020, the Idaho ROE
thresholds will be adjusted on a prospective basis as follows: (a) the Idaho ROE under which Idaho Power will be permitted to amortize an additional amount of ADITC will be set at
95 percent of the newly authorized Idaho ROE, (b) sharing with customers on an 80 percent basis as a customer rate reduction will begin at the newly authorized Idaho ROE, and (c)
sharing with customers on an 80 percent basis but allocated 55 percent to a rate reduction, and 25 percent to a pension expense deferral regulatory asset, will begin at 105 percent of
the newly authorized Idaho ROE.

The May 2018 Idaho Tax Reform Settlement Stipulation did not impose a moratorium on Idaho Power filing a general rate case or other form of rate proceeding in Idaho during its
respective term.

In 2022, Idaho Power recorded no provision against current revenue for sharing with customers or additional amortization of ADITC, as its full-year Idaho ROE was between 9.4
percent and 10.0 percent. In 2021, Idaho Power recorded a $0.6 million provision against current revenue for sharing with customers, as its Idaho ROE exceeded 10.0 percent.
Accordingly, at December 31, 2022, the full $45 million of additional ADITC remained available for future use under the terms of the May 2018 Idaho Tax Reform Settlement
Stipulation.

Valmy Base Rate Adjustment Settlement Stipulations: Idaho Power has settlement stipulations in place in Idaho and Oregon related to the planned early retirement of both units of its
jointly-owned North Valmy coal-fired power plant. Idaho Power ceased coal-fired operations at unit 1 in 2019, as planned, and plans to cease coal-fired operations at unit 2 in 2025.
Both commissions have approved this plan. The IPUC-approved settlement stipulation provides for (1) accelerated depreciation for the North Valmy plant to allow the coal-related
plant assets to be fully depreciated and recovered by December 31, 2028, (2) Idaho Power to use prudent and commercially reasonable efforts to end its participation in coal-fired
operations at North Valmy as described above, (3) a balancing account to track the incremental costs, benefits, and required regulatory accounting associated with ceasing
participation in coal-fired operations at the North Valmy plant, and (4) increased customer rates related to the associated incremental annual levelized revenue requirement. If actual
costs incurred differ from forecasted amounts included in the settlement stipulation, collection or refund of any differences would be subject to regulatory approval.

Jim Bridger Power Plant Rate Base Adjustment and Recovery: In June 2022, the IPUC issued an order approving, with modifications, Idaho Power's amended application requesting
authorization to (1) accelerate depreciation for the Jim Bridger plant to allow the coal-related plant assets to be fully depreciated and recovered by December 31, 2030, (2) establish a
balancing account to track the incremental costs, benefits, and required regulatory accounting associated with ceasing participation in coal-fired operations at the Jim Bridger plant,
and (3) increase customer rates related to the associated incremental annual levelized revenue requirement (Bridger Order).

The Bridger Order allows for regulatory accounting entries and establishes balancing accounts (recorded as regulatory assets or liabilities on Idaho Power's balance sheets) to track
differences between amounts recovered in rates and actual incremental costs and benefits associated with Idaho Power's cessation of coal-fired operations at the Jim Bridger plant. The
incremental costs and benefits include the revenue requirement associated with the incremental Jim Bridger plant coal-related investments made from 2012 through the end of 2020,
forecasted coal-related investments, and near-term decommissioning costs, offset by other operations and maintenance (O&M) cost savings. The Bridger Order deemed all coal-related
investments at the Jim Bridger plant from 2012 through 2020 to be prudent for recovery. In the Bridger Order, the IPUC reduced Idaho Power's requested rate increase from 2.1 percent
in its amended filing to 1.5 percent, a reduction from a requested $27.1 million to $18.8 million annually. The Bridger Order provides that any uncollected amount resulting from the
reduction in the rate increase will be recorded in the balancing account for future recovery with no carrying charge. Idaho Power anticipates making future filings with the IPUC that
may result in periodic adjustments to rates to true up variances between revenue collections and actual revenue requirement amounts.

The Bridger Order allows Idaho Power to earn a return on and recover through 2030 the net book value of coal-related assets at the Jim Bridger plant as of December 31, 2020, as well
as forecasted coal-related investments, which resulted in Idaho Power's deferral of certain depreciation expense during the full year of 2022. The deferral and impacts of the Bridger
Order resulted in an increase in net income for 2022 of approximately $20 million.

Other Notable Idaho Regulatory Matters

Fixed Cost Adjustment: The Idaho jurisdiction fixed cost adjustment (FCA) mechanism, applicable to Idaho residential and small commercial customers, is designed to remove a
portion of Idaho Power's financial disincentive to invest in energy efficiency programs by separating (or decoupling) the recovery of fixed costs from the variable kilowatt-hour (kWh)
charge and linking it instead to a set amount per customer. Under Idaho Power's current rate design, recovery of a portion of fixed costs is included in the variable kWh charge, which
may result in over-collection or under-collection of fixed costs. To return over-collection to customers or to collect under-collection from customers, the FCA mechanism allows Idaho
Power to accrue, or defer, the difference between the authorized fixed-cost recovery amount per customer and the actual fixed costs per customer recovered by Idaho Power during the
year. The IPUC has discretion to cap the annual increase in the FCA recovery at 3 percent of base revenue, with any excess deferred for collection in a subsequent year.

The following table summarizes FCA amounts approved for collection in the prior three FCA years:
FCA Year Period Rates in Effect
Annual Amount
(in millions)
2021 June 1, 2022-May 31, 2023 $35.2
2020 June 1, 2021-May 31, 2022 $38.3
2019 June 1, 2020-May 31, 2021 $35.5

January 2012 and June 2014 Idaho Base Rate Adjustments: Effective January 1, 2012, Idaho Power implemented new Idaho base rates resulting from IPUC approval of a settlementstipulation that provided for a 7.86 percent authorized overall rate of return on an Idaho-jurisdiction rate base of approximately $2.36 billion. The settlement stipulation resulted in a4.07 percent, or $34.0 million, overall increase in Idaho Power's annual Idaho-jurisdiction base rate revenues. Idaho base rates were subsequently adjusted again in 2012, inconnection with Idaho Power's completion of the Langley Gulch power plant. In June 2012, the IPUC issued an order approving a $58.1 million increase in annual Idaho-jurisdictionbase rates, effective July 1, 2012. The order also provided for a $335.9 million increase in Idaho rate base. Neither the settlement stipulation nor the IPUC orders adjusting base ratesspecified an authorized rate of return on equity or imposed a moratorium on Idaho Power filing a general rate case at a future date. The IPUC issued a March 2014 order approving Idaho Power's request for an increase in the normalized or "base level" net power supply expense to be used to update base rates and inthe determination of the PCA rate that became effective June 1, 2014. May 2018 Idaho Tax Reform Settlement Stipulation: In December 2017, the Tax Cuts and Jobs Act was signed into law, which, among other things, lowered the corporate federalincome tax rate from 35 percent to 21 percent and modified or eliminated certain federal income tax deductions for corporations. In March 2018, Idaho House Bill 463 was signed intolaw reducing the Idaho state corporate income tax rate from 7.4 percent to 6.925 percent. In May 2018, the IPUC issued an order approving a settlement stipulation (May 2018 Idaho Tax Reform Settlement Stipulation) related to income tax reform. Beginning June 1, 2018,the settlement stipulation provided an annual (a) $18.7 million reduction to Idaho customer base rates and (b) $7.4 million amortization of existing regulatory deferrals for specifieditems or future amortization of other existing or future unspecified regulatory deferrals that would otherwise be a future regulatory asset recoverable from Idaho customers. The May2018 Idaho Tax Reform Settlement Stipulation also provided for the indefinite extension, with modifications, of a previous settlement stipulation beyond its termination date ofDecember 31, 2019. The May 2018 settlement stipulation provides Idaho Power the ability to earn a minimum Idaho-Jurisdiction return on year-end equity (Idaho ROE) of 9.4 percent by amortizing up to$25 million of additional ADITC in any calendar year, so long as the cumulative amount of additional accumulated deferred investment tax credits (ADITC) used does not exceed $45million; however, Idaho Power may seek approval from the IPUC to replenish the total amount of additional ADITC it is permitted to amortize and if there are no remaining amounts ofadditional ADITC authorized to be amortized, the remainder of the revenue sharing provisions below would not be applicable until additional ADITC is replenished. If Idaho Power's annual Idaho ROE in any year exceeds 10.0 percent, the amount of earnings exceeding 10.0 percent and up to and including 10.5 percent will be allocated 80 percentto Idaho Power's Idaho customers as a rate reduction to be effective at the time of the subsequent year's PCA, and 20 percent to Idaho Power. If Idaho Power's annual Idaho ROE in any year exceeds 10.5 percent, the amount of earnings exceeding a 10.5 percent Idaho ROE will be allocated 55 percent to Idaho Power's Idahocustomers as a rate reduction to be effective at the time of the subsequent year's PCA, 25 percent to Idaho Power's Idaho customers in the form of a reduction to the pension regulatoryasset balancing account (to reduce the amount to be collected in the future from Idaho customers) and 20 percent to Idaho Power. In the event the IPUC approves a change to Idaho Power's allowed annual Idaho ROE as part of a general rate case proceeding effective on or after January 1, 2020, the Idaho ROEthresholds will be adjusted on a prospective basis as follows: (a) the Idaho ROE under which Idaho Power will be permitted to amortize an additional amount of ADITC will be set at95 percent of the newly authorized Idaho ROE, (b) sharing with customers on an 80 percent basis as a customer rate reduction will begin at the newly authorized Idaho ROE, and (c)sharing with customers on an 80 percent basis but allocated 55 percent to a rate reduction, and 25 percent to a pension expense deferral regulatory asset, will begin at 105 percent ofthe newly authorized Idaho ROE. The May 2018 Idaho Tax Reform Settlement Stipulation did not impose a moratorium on Idaho Power filing a general rate case or other form of rate proceeding in Idaho during itsrespective term. In 2022, Idaho Power recorded no provision against current revenue for sharing with customers or additional amortization of ADITC, as its full-year Idaho ROE was between 9.4percent and 10.0 percent. In 2021, Idaho Power recorded a $0.6 million provision against current revenue for sharing with customers, as its Idaho ROE exceeded 10.0 percent.Accordingly, at December 31, 2022, the full $45 million of additional ADITC remained available for future use under the terms of the May 2018 Idaho Tax Reform SettlementStipulation. Valmy Base Rate Adjustment Settlement Stipulations: Idaho Power has settlement stipulations in place in Idaho and Oregon related to the planned early retirement of both units of itsjointly-owned North Valmy coal-fired power plant. Idaho Power ceased coal-fired operations at unit 1 in 2019, as planned, and plans to cease coal-fired operations at unit 2 in 2025.Both commissions have approved this plan. The IPUC-approved settlement stipulation provides for (1) accelerated depreciation for the North Valmy plant to allow the coal-relatedplant assets to be fully depreciated and recovered by December 31, 2028, (2) Idaho Power to use prudent and commercially reasonable efforts to end its participation in coal-firedoperations at North Valmy as described above, (3) a balancing account to track the incremental costs, benefits, and required regulatory accounting associated with ceasingparticipation in coal-fired operations at the North Valmy plant, and (4) increased customer rates related to the associated incremental annual levelized revenue requirement. If actualcosts incurred differ from forecasted amounts included in the settlement stipulation, collection or refund of any differences would be subject to regulatory approval. Jim Bridger Power Plant Rate Base Adjustment and Recovery: In June 2022, the IPUC issued an order approving, with modifications, Idaho Power's amended application requestingauthorization to (1) accelerate depreciation for the Jim Bridger plant to allow the coal-related plant assets to be fully depreciated and recovered by December 31, 2030, (2) establish abalancing account to track the incremental costs, benefits, and required regulatory accounting associated with ceasing participation in coal-fired operations at the Jim Bridger plant,and (3) increase customer rates related to the associated incremental annual levelized revenue requirement (Bridger Order). The Bridger Order allows for regulatory accounting entries and establishes balancing accounts (recorded as regulatory assets or liabilities on Idaho Power's balance sheets) to trackdifferences between amounts recovered in rates and actual incremental costs and benefits associated with Idaho Power's cessation of coal-fired operations at the Jim Bridger plant. Theincremental costs and benefits include the revenue requirement associated with the incremental Jim Bridger plant coal-related investments made from 2012 through the end of 2020,forecasted coal-related investments, and near-term decommissioning costs, offset by other operations and maintenance (O&M) cost savings. The Bridger Order deemed all coal-relatedinvestments at the Jim Bridger plant from 2012 through 2020 to be prudent for recovery. In the Bridger Order, the IPUC reduced Idaho Power's requested rate increase from 2.1 percentin its amended filing to 1.5 percent, a reduction from a requested $27.1 million to $18.8 million annually. The Bridger Order provides that any uncollected amount resulting from thereduction in the rate increase will be recorded in the balancing account for future recovery with no carrying charge. Idaho Power anticipates making future filings with the IPUC thatmay result in periodic adjustments to rates to true up variances between revenue collections and actual revenue requirement amounts. The Bridger Order allows Idaho Power to earn a return on and recover through 2030 the net book value of coal-related assets at the Jim Bridger plant as of December 31, 2020, as wellas forecasted coal-related investments, which resulted in Idaho Power's deferral of certain depreciation expense during the full year of 2022. The deferral and impacts of the BridgerOrder resulted in an increase in net income for 2022 of approximately $20 million. Other Notable Idaho Regulatory Matters Fixed Cost Adjustment: The Idaho jurisdiction fixed cost adjustment (FCA) mechanism, applicable to Idaho residential and small commercial customers, is designed to remove aportion of Idaho Power's financial disincentive to invest in energy efficiency programs by separating (or decoupling) the recovery of fixed costs from the variable kilowatt-hour (kWh)charge and linking it instead to a set amount per customer. Under Idaho Power's current rate design, recovery of a portion of fixed costs is included in the variable kWh charge, whichmay result in over-collection or under-collection of fixed costs. To return over-collection to customers or to collect under-collection from customers, the FCA mechanism allows IdahoPower 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 theyear. The IPUC has discretion to cap the annual increase in the FCA recovery at 3 percent of base revenue, with any excess deferred for collection in a subsequent year. The following table summarizes FCA amounts approved for collection in the prior three FCA years:FCA Year Period Rates in Effect Annual Amount(in millions)2021 June 1, 2022-May 31, 2023 $35.2
2020 June 1, 2021-May 31, 2022 $38.3
2019 June 1, 2020-May 31, 2021 $35.5

Wildfire Mitigation Cost Recovery: In June 2021, the IPUC authorized Idaho Power to defer for future amortization incremental O&M and depreciation expense for certain capital
investments necessary to implement Idaho Power's Wildfire Mitigation Plan (WMP). The IPUC also authorized Idaho Power to record these deferred expenses as a regulatory asset until
Idaho Power can request amortization of the deferred costs in a future IPUC proceeding, at which time the IPUC will have the opportunity to review actual costs and determine the
amount of prudently incurred costs that Idaho Power can recover through retail rates. In its 2021 application with the IPUC, Idaho Power projected spending approximately $47
million in incremental wildfire mitigation-related O&M and roughly $35 million in wildfire mitigation system-hardening incremental capital expenditures over a five-year period.
The IPUC authorized a deferral period of five years, or until rates go into effect from Idaho Power's next general rate case, whichever is first. As of December 31, 2022, Idaho Power's
deferral of Idaho-jurisdiction costs related to the WMP was $27.1 million.

During the 2021 and 2022 wildfire seasons, Idaho Power identified needs for expanded mitigation measures by gaining additional insights and knowledge on wildfires and wildfire
mitigation activities. In October 2022, Idaho Power filed an updated WMP with the IPUC along with an application requesting authorization to defer an estimated $16 million of
newly identified incremental costs expected to be incurred between 2022 and 2025 associated with expanded wildfire mitigation efforts. As of the date of this report, the application
with the IPUC is pending.

Notable Oregon Regulatory Matters

Oregon Base Rate Changes: Oregon base rates were most recently established in a general rate case in 2012. In February 2012, the Public Utility Commission of Oregon (OPUC)
issued an order approving a settlement stipulation that provided for a $1.8 million base rate increase, a return on equity of 9.9 percent, and an overall rate of return of 7.757 percent in
the Oregon jurisdiction. New rates in conformity with the settlement stipulation were effective March 1, 2012. Subsequently, in September 2012, the OPUC issued an order approving
an approximately $3.0 million increase in annual Oregon jurisdiction base rates, effective October 1, 2012, for inclusion of the Langley Gulch power plant in Idaho Power's Oregon
rate base. Additionally, in October 2020, the OPUC approved an increase in Oregon customer rates of $0.4 million annually associated with amortization of deferred Langley Gulch
power plant revenue requirement variances, effective November 1, 2020, through October 31, 2024.

In May 2018, the OPUC issued an order approving a settlement stipulation that provides for an annual $1.5 million reduction to Oregon customer base rates beginning June 1, 2018
through May 31, 2020, related to income tax reform. In May 2020, the OPUC issued an order to approve the quantification of $1.5 million in annualized Oregon jurisdictional
benefits associated with federal and state income tax changes resulting from tax reform and adjusting customer rates to reflect this amount, effective June 1, 2020, until its next general
rate case or other proceeding where the tax-related revenue requirement components are reflected in rates.

The OPUC has also approved settlement stipulations that provide for the accelerated cost recovery of jointly-owned North Valmy unit 1 through 2019 and unit 2 through 2025. The
net rate impact of the Oregon settlement stipulations is immaterial.

Federal Regulatory Matters - 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 actual financial and
operational data Idaho Power files with the FERC and allows Idaho Power to recover costs associated with its transmission system. Idaho Power's OATT rates submitted to the FERC in
Idaho Power's three most recent annual OATT Final Informational Filings were as follows:
Applicable Period
OATT Rate (per
kW-year)
October 1, 2022 to September 30, 2023 $ 31.42
October 1, 2021 to September 30, 2022 $ 31.19
October 1, 2020 to September 30, 2021 $ 29.95

Idaho Power's current OATT rate is based on a net annual transmission revenue requirement of $132.7 million, which represents the OATT formulaic determination of Idaho Power's net
cost of providing OATT-based transmission service.

4. REVENUES

Revenues from Contracts with Customers

Revenues from contracts with customers are primarily related to Idaho Power's regulated 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. Idaho Power assesses revenues on a contract-by-contract basis to determine the nature, amount, timing,
and uncertainty, if any, of revenues being recognized.

Retail Revenues: Idaho Power's retail revenues primarily relate to the sale of electricity to customers based on regulated tariff-based prices. Idaho Power recognizes retail revenues in
amounts for which it has the right to invoice the customer in the period when energy is delivered or services are provided to customers. The total energy price generally has a fixed
component related to having service available and a usage-based component related to the demand, delivery, and consumption of energy. The revenues recognized reflect the
consideration Idaho Power expects to be entitled to in exchange for energy and services. Retail customers are classified as residential, commercial, industrial, or irrigation.
Approximately 95 percent of Idaho Power's retail revenue originates from customers located in Idaho, with the remainder originating from customers located in Oregon. Idaho Power's
retail customer rates are based on 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 typically the primary causes of fluctuations in retail revenue from period to period. The primary influences on changes in
customer demand for electricity are weather, economic conditions (including growth in the number of Idaho Power customers), and energy efficiency. Idaho Power's utility revenues
are not earned evenly during the year.

Retail revenues are billed monthly based on meter readings taken throughout the month. Payments for amounts billed are generally due from the customer within 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.

Residential Customers: Idaho Power's energy sales to residential customers typically peak during the summer cooling season and winter heating season. Extreme temperatures increase
sales to residential customers who use electricity for cooling and heating, compared with normal temperatures. Idaho Power's rate structure provides for higher rates during the summer
when overall system loads are at their highest, and includes tiers such that rates increase as a customer's consumption level increases. These seasonal and tiered rate structures
contribute to the seasonal fluctuations in revenues and earnings. Economic and demographic conditions can also affect residential customer demand; strong job growth and
population growth in Idaho Power's service area have led to higher customer growth in recent years. Residential demand is also impacted by energy efficiency initiatives. Idaho
Power's FCA mechanism mitigates some of the fluctuations caused by weather and energy efficiency initiatives.

Commercial Customers: Most businesses are included in Idaho Power's commercial customer class, as are small industrial companies, and public street and highway lighting accounts.
Idaho Power's commercial customers are less influenced by weather conditions than residential customers, although weather does still affect commercial customer energy use.
Economic conditions, including manufacturing activity levels, and energy efficiency initiatives also affect energy use of commercial customers.

Industrial Customers: Industrial customers consist of large industrial companies, including special contract customers. Energy use of industrial customers is primarily driven by
economic conditions, with weather having little impact on this customer class.

Irrigation Customers: Irrigation customers use electricity to operate irrigation pumps, primarily during the agricultural growing season. The amount and timing of precipitation as well
as temperature levels affect the timing and amounts of sales to irrigation customers, with increased precipitation during the agricultural growing season generally resulting in
decreased sales.

Provision for Sharing: Idaho Power has regulatory settlement stipulations in Idaho that provide for the potential sharing between Idaho Power and its Idaho customers of Idaho-
jurisdictional earnings in excess of 10.0 percent of Idaho ROE. Based on full-year 2022 Idaho ROE, Idaho Power recorded no provision against current revenues for sharing of
earnings with customers for 2022. Idaho Power recorded $0.6 million of sharing of earnings with customers during 2021. The regulatory settlement stipulations are described further in
Note 3 - "Regulatory Matters."
Wildfire Mitigation Cost Recovery: In June 2021, the IPUC authorized Idaho Power to defer for future amortization incremental O&M and depreciation expense for certain capitalinvestments necessary to implement Idaho Power's Wildfire Mitigation Plan (WMP). The IPUC also authorized Idaho Power to record these deferred expenses as a regulatory asset untilIdaho Power can request amortization of the deferred costs in a future IPUC proceeding, at which time the IPUC will have the opportunity to review actual costs and determine theamount of prudently incurred costs that Idaho Power can recover through retail rates. In its 2021 application with the IPUC, Idaho Power projected spending approximately $47million in incremental wildfire mitigation-related O&M and roughly $35 million in wildfire mitigation system-hardening incremental capital expenditures over a five-year period.The IPUC authorized a deferral period of five years, or until rates go into effect from Idaho Power's next general rate case, whichever is first. As of December 31, 2022, Idaho Power'sdeferral of Idaho-jurisdiction costs related to the WMP was $27.1 million. During the 2021 and 2022 wildfire seasons, Idaho Power identified needs for expanded mitigation measures by gaining additional insights and knowledge on wildfires and wildfiremitigation activities. In October 2022, Idaho Power filed an updated WMP with the IPUC along with an application requesting authorization to defer an estimated $16 million ofnewly identified incremental costs expected to be incurred between 2022 and 2025 associated with expanded wildfire mitigation efforts. As of the date of this report, the applicationwith the IPUC is pending. Notable Oregon Regulatory Matters Oregon Base Rate Changes: Oregon base rates were most recently established in a general rate case in 2012. In February 2012, the Public Utility Commission of Oregon (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 inthe Oregon jurisdiction. New rates in conformity with the settlement stipulation were effective March 1, 2012. Subsequently, in September 2012, the OPUC issued an order approvingan approximately $3.0 million increase in annual Oregon jurisdiction base rates, effective October 1, 2012, for inclusion of the Langley Gulch power plant in Idaho Power's Oregonrate base. Additionally, in October 2020, the OPUC approved an increase in Oregon customer rates of $0.4 million annually associated with amortization of deferred Langley Gulchpower plant revenue requirement variances, effective November 1, 2020, through October 31, 2024. In May 2018, the OPUC issued an order approving a settlement stipulation that provides for an annual $1.5 million reduction to Oregon customer base rates beginning June 1, 2018through May 31, 2020, related to income tax reform. In May 2020, the OPUC issued an order to approve the quantification of $1.5 million in annualized Oregon jurisdictionalbenefits associated with federal and state income tax changes resulting from tax reform and adjusting customer rates to reflect this amount, effective June 1, 2020, until its next generalrate case or other proceeding where the tax-related revenue requirement components are reflected in rates. The OPUC has also approved settlement stipulations that provide for the accelerated cost recovery of jointly-owned North Valmy unit 1 through 2019 and unit 2 through 2025. Thenet rate impact of the Oregon settlement stipulations is immaterial. Federal Regulatory Matters - 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 actual financial andoperational data Idaho Power files with the FERC and allows Idaho Power to recover costs associated with its transmission system. Idaho Power's OATT rates submitted to the FERC inIdaho Power's three most recent annual OATT Final Informational Filings were as follows:Applicable Period OATT Rate (perkW-year)October 1, 2022 to September 30, 2023 $ 31.42October 1, 2021 to September 30, 2022 $ 31.19October 1, 2020 to September 30, 2021 $ 29.95 Idaho Power's current OATT rate is based on a net annual transmission revenue requirement of $132.7 million, which represents the OATT formulaic determination of Idaho Power's netcost of providing OATT-based transmission service. 4. REVENUES Revenues from Contracts with Customers Revenues from contracts with customers are primarily related to Idaho Power's regulated tariff-based sales of energy or related services. Generally, tariff-based sales do not involve awritten contract, but are classified as revenues from contracts with customers. Idaho Power assesses revenues on a contract-by-contract basis to determine the nature, amount, timing,and uncertainty, if any, of revenues being recognized. Retail Revenues: Idaho Power's retail revenues primarily relate to the sale of electricity to customers based on regulated tariff-based prices. Idaho Power recognizes retail revenues inamounts for which it has the right to invoice the customer in the period when energy is delivered or services are provided to customers. The total energy price generally has a fixedcomponent related to having service available and a usage-based component related to the demand, delivery, and consumption of energy. The revenues recognized reflect theconsideration Idaho Power expects to be entitled to in exchange for energy and services. Retail customers are classified as residential, commercial, industrial, or irrigation.Approximately 95 percent of Idaho Power's retail revenue originates from customers located in Idaho, with the remainder originating from customers located in Oregon. Idaho Power'sretail 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 andOPUC. Changes in rates and changes in customer demand are typically the primary causes of fluctuations in retail revenue from period to period. The primary influences on changes incustomer demand for electricity are weather, economic conditions (including growth in the number of Idaho Power customers), and energy efficiency. Idaho Power's utility revenuesare 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-endand estimated rates. Residential Customers: Idaho Power's energy sales to residential customers typically peak during the summer cooling season and winter heating season. Extreme temperatures increasesales 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 summerwhen 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 structurescontribute to the seasonal fluctuations in revenues and earnings. Economic and demographic conditions can also affect residential customer demand; strong job growth andpopulation growth in Idaho Power's service area have led to higher customer growth in recent years. Residential demand is also impacted by energy efficiency initiatives. IdahoPower's FCA mechanism mitigates some of the fluctuations caused by weather and energy efficiency initiatives. Commercial Customers: Most businesses are included in Idaho Power's commercial customer class, as are small industrial companies, and public street and highway lighting accounts.Idaho Power's commercial customers are less influenced by weather conditions than residential customers, although weather does still affect commercial customer energy use.Economic conditions, including manufacturing activity levels, and energy efficiency initiatives also affect energy use of commercial customers. Industrial Customers: Industrial customers consist of large industrial companies, including special contract customers. Energy use of industrial customers is primarily driven byeconomic conditions, with weather having little 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 wellas temperature levels affect the timing and amounts of sales to irrigation customers, with increased precipitation during the agricultural growing season generally resulting indecreased sales.
Provision for Sharing: Idaho Power has regulatory settlement stipulations in Idaho that provide for the potential sharing between Idaho Power and its Idaho customers of Idaho-
jurisdictional earnings in excess of 10.0 percent of Idaho ROE. Based on full-year 2022 Idaho ROE, Idaho Power recorded no provision against current revenues for sharing of
earnings with customers for 2022. Idaho Power recorded $0.6 million of sharing of earnings with customers during 2021. The regulatory settlement stipulations are described further in
Note 3 - "Regulatory Matters."Note 3 - "Regulatory Matters."

Wholesale Energy Sales: As a public utility under the Federal Power Act (FPA), Idaho Power has the authority to charge market-based rates for wholesale energy sales under its FERC
tariff. Idaho Power's wholesale electricity sales are primarily to utilities and power marketers and are predominantly short-term and consist of a single performance obligation satisfied
as energy is transferred to the counterparty. 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 and demand at the time when those resources are available. A reduction in any of those factors may lead to lower wholesale
energy sales.

Transmission Wheeling-Related Revenues: As a public utility under the FPA, Idaho Power has the authority to provide cost-based wholesale and retail access transmission services
under its OATT. Services under the OATT are offered on a nondiscriminatory basis such that all potential customers have an equal opportunity to access the transmission system. Idaho
Power's transmission revenue is primarily related to third parties reserving capacity on Idaho Power's transmission system to transmit electricity through Idaho Power's service area.
Reservations are predominantly short-term contracts or on-demand when available, but may be part of a long-term capacity contract. Transmission wheeling-related revenues consist
of a single performance obligation satisfied as capacity on Idaho Power's transmission system is provided to the third party. Transmission wheeling-related revenues are affected by
changes in Idaho Power's OATT rate and customer demand. Demand for transmission services can be affected by regional market factors, such as loads and generation of utilities in
Idaho Power's region.

Energy Efficiency Program Revenues: Idaho Power collects most of its energy efficiency program costs through an energy efficiency rider on customer bills. The rider collections are
deferred until expenditures are incurred. Energy efficiency program expenditures funded through the rider are reported as an operating expense with an equal amount recognized in
revenues, resulting in no net impact on earnings. Fewer energy efficiency projects were completed in 2021 and 2022 due mostly to impacts of the COVID-19 public health crisis and
other economic conditions which decreased energy efficiency program revenues compared with prior years. The cumulative variance between expenditures and amounts collected
through the rider is recorded as a regulatory asset or liability. A liability balance indicates that Idaho Power has collected more than it has spent, and an asset balance indicates that
Idaho Power has spent more than it has collected. At December 31, 2022, Idaho Power's energy efficiency rider balances were a $3.8 million regulatory asset in the Idaho jurisdiction
and a $0.2 million regulatory liability 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 an additional regulatory mechanism, the Idaho FCA
mechanism, which may increase or decrease tariff-based customer rates. The Idaho FCA mechanism is described in Note 3 - "Regulatory Matters." The FCA mechanism revenues
include only the initial recognition of FCA revenues when they meet the regulator-specified conditions for recognition. Revenue from contracts with customers excludes the portion
of the tariff price representing FCA revenues that Idaho Power initially recorded in prior periods when revenues met regulator-specified conditions. When Idaho Power includes those
amounts in the price of utility service and billed to customers, Idaho Power records such amounts as recovery of the associated regulatory asset or liability and not as revenues.

Derivative revenues include gains from settled electricity swaps and sales of electricity under forward sales contracts that are bundled with renewable energy credits. Related to these
forward sales, Idaho Power simultaneously enters into forward purchases of electricity for the same quantity at the same location, which are recorded in purchased power on the
statements of income. For more information on settled electricity swaps, see Note 14 - "Derivative Financial Instruments."

5. LONG-TERM DEBT

The following table summarizes Idaho Power's long-term debt at December 31 (in thousands of dollars):
2022 2021
First mortgage bonds:
2.50% Series due 2023 $ 75,000 $ 75,000
1.90% Series due 2030 80,000 80,000
6.00% Series due 2032 100,000 100,000
4.99% Series due 2032 23,000
5.50% Series due 2033 70,000 70,000
5.50% Series due 2034 50,000 50,000
5.875% Series due 2034 55,000 55,000
5.30% Series due 2035 60,000 60,000
6.30% Series due 2037 140,000 140,000
6.25% Series due 2037 100,000 100,000
4.85% Series due 2040 100,000 100,000
4.30% Series due 2042 75,000 75,000
5.06% Series due 2042 25,000
4.00% Series due 2043 75,000 75,000
3.65% Series due 2045 250,000 250,000
4.05% Series due 2046 120,000 120,000
4.20% Series due 2048 450,000 450,000
Total first mortgage bonds 1,848,000 1,800,000
Pollution control revenue bonds:
1.45% Series due 2024(1) 49,800 49,800
1.70% Series due 2026(1) 116,300 116,300
Variable Rate Series 2000 (redeemed in 2022) 4,360
Total pollution control revenue bonds 166,100 170,460
Floating Rate Term Loan Facility due 2024 150,000
American Falls Variable Rate bond guarantee due 2025 19,885 19,885
Unamortized premium/discount 24,770 25,637
Total Idaho Power outstanding debt(2) 2,208,755 2,015,982

(1) Humboldt County and Sweetwater County Pollution Control Revenue Bonds are secured by the first mortgage bonds, bringing the total first mortgage bonds outstanding at December 31, 2022, to $2.014
billion.
(2) At December 31, 2022 and 2021, the overall effective cost rate of Idaho Power's outstanding debt was 4.60 percent and 4.40 percent, respectively.

At December 31, 2022, the maturities for the aggregate amount of Idaho Power long-term debt outstanding were as follows (in thousands of dollars):
2023 2024 2025 2026 2027 Thereafter
Note 3 - "Regulatory Matters." Wholesale Energy 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 FERCtariff. Idaho Power's wholesale electricity sales are primarily to utilities and power marketers and are predominantly short-term and consist of a single performance obligation satisfiedas energy is transferred to the counterparty. Idaho Power's wholesale energy sales depend largely on the availability of generation resources in excess of the amount necessary to servecustomer loads as well as adequate market power prices and demand at the time when those resources are available. A reduction in any of those factors may lead to lower wholesaleenergy sales. Transmission Wheeling-Related Revenues: As a public utility under the FPA, Idaho Power has the authority to provide cost-based wholesale and retail access transmission servicesunder its OATT. Services under the OATT are offered on a nondiscriminatory basis such that all potential customers have an equal opportunity to access the transmission system. IdahoPower's transmission revenue is primarily related to third parties reserving capacity on Idaho Power's transmission system to transmit electricity through Idaho Power's service area.Reservations are predominantly short-term contracts or on-demand when available, but may be part of a long-term capacity contract. Transmission wheeling-related revenues consistof a single performance obligation satisfied as capacity on Idaho Power's transmission system is provided to the third party. Transmission wheeling-related revenues are affected bychanges in Idaho Power's OATT rate and customer demand. Demand for transmission services can be affected by regional market factors, such as loads and generation of utilities inIdaho Power's region. Energy Efficiency Program Revenues: Idaho Power collects most of its energy efficiency program costs through an energy efficiency rider on customer bills. The rider collections aredeferred until expenditures are incurred. Energy efficiency program expenditures funded through the rider are reported as an operating expense with an equal amount recognized inrevenues, resulting in no net impact on earnings. Fewer energy efficiency projects were completed in 2021 and 2022 due mostly to impacts of the COVID-19 public health crisis andother economic conditions which decreased energy efficiency program revenues compared with prior years. The cumulative variance between expenditures and amounts collectedthrough the rider is recorded as a regulatory asset or liability. A liability balance indicates that Idaho Power has collected more than it has spent, and an asset balance indicates thatIdaho Power has spent more than it has collected. At December 31, 2022, Idaho Power's energy efficiency rider balances were a $3.8 million regulatory asset in the Idaho jurisdictionand a $0.2 million regulatory liability 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 an additional regulatory mechanism, the Idaho FCAmechanism, which may increase or decrease tariff-based customer rates. The Idaho FCA mechanism is described in Note 3 - "Regulatory Matters." The FCA mechanism revenuesinclude only the initial recognition of FCA revenues when they meet the regulator-specified conditions for recognition. Revenue from contracts with customers excludes the portionof the tariff price representing FCA revenues that Idaho Power initially recorded in prior periods when revenues met regulator-specified conditions. When Idaho Power includes thoseamounts in the price of utility service and billed to customers, Idaho Power records such amounts as recovery of the associated regulatory asset or liability and not as revenues. Derivative revenues include gains from settled electricity swaps and sales of electricity under forward sales contracts that are bundled with renewable energy credits. Related to theseforward sales, Idaho Power simultaneously enters into forward purchases of electricity for the same quantity at the same location, which are recorded in purchased power on thestatements of income. For more information on settled electricity swaps, see Note 14 - "Derivative Financial Instruments." 5. LONG-TERM DEBT The following table summarizes Idaho Power's long-term debt at December 31 (in thousands of dollars): 2022 2021First mortgage bonds: 2.50% Series due 2023 $ 75,000 $ 75,0001.90% Series due 2030 80,000 80,0006.00% Series due 2032 100,000 100,0004.99% Series due 2032 23,000 5.50% Series due 2033 70,000 70,0005.50% Series due 2034 50,000 50,0005.875% Series due 2034 55,000 55,0005.30% Series due 2035 60,000 60,0006.30% Series due 2037 140,000 140,0006.25% Series due 2037 100,000 100,0004.85% Series due 2040 100,000 100,0004.30% Series due 2042 75,000 75,0005.06% Series due 2042 25,000 4.00% Series due 2043 75,000 75,0003.65% Series due 2045 250,000 250,0004.05% Series due 2046 120,000 120,0004.20% Series due 2048 450,000 450,000Total first mortgage bonds 1,848,000 1,800,000Pollution control revenue bonds: 1.45% Series due 2024(1) 49,800 49,8001.70% Series due 2026(1) 116,300 116,300Variable Rate Series 2000 (redeemed in 2022) 4,360Total pollution control revenue bonds 166,100 170,460Floating Rate Term Loan Facility due 2024 150,000 American Falls Variable Rate bond guarantee due 2025 19,885 19,885Unamortized premium/discount 24,770 25,637Total Idaho Power outstanding debt(2) 2,208,755 2,015,982 (1) Humboldt County and Sweetwater County Pollution Control Revenue Bonds are secured by the first mortgage bonds, bringing the total first mortgage bonds outstanding at December 31, 2022, to $2.014billion.(2) At December 31, 2022 and 2021, the overall effective cost rate of Idaho Power's outstanding debt was 4.60 percent and 4.40 percent, respectively.

At December 31, 2022, the maturities for the aggregate amount of Idaho Power long-term debt outstanding were as follows (in thousands of dollars):
2023 2024 2025 2026 2027 Thereafter
$ 75,000 $ 199,800 $ 19,885 $ 116,300 $ $ 1,773,000

Long-Term Debt Issuances, Maturities, and Redemptions

On its balance sheet as of December 31, 2022, Idaho Power classified the $75 million in principal amount of 2.50% first mortgage bonds, Series I, maturing on April 1, 2023, as long-
term debt based upon Idaho Power's intent and ability to refinance the bonds on a long-term basis.

On December 22, 2022, Idaho Power entered into a Bond Purchase Agreement (Bond Purchase Agreement) with certain institutional purchasers relating to the sale by Idaho Power of
$170 million of first mortgage bonds secured medium-term-term notes, Series N (Series N Notes), as described in more detail below. At December 31, 2022, $48 million in principal
amount of Series N Notes had been issued and was outstanding.

On December 1, 2022, Idaho Power redeemed at par $4.36 million in principal amount of variable-rate pollution control revenue bonds due in 2027.

On March 4, 2022, Idaho Power entered into a floating rate term loan credit agreement (Term Loan Facility). The Term Loan Facility is a two-year senior unsecured term loan facility. It
provided for the issuance of loans not to exceed the aggregate principal amount of $150 million with a maturity date of March 4, 2024. The interest rates for the floating rate advances
under the Term Loan Facility were based on the highest of (1) the prime commercial lending rate of the lender acting as administrative agent, (2) the federal funds rate, plus 0.5
percent, (3) Term Secured Overnight Financing Rate administered by the Federal Reserve Bank of New York (SOFR) (as defined in the Term Loan Facility) for a one-month tenor that
is published by CME Group Benchmark Administration limited (or the successor administrator of such rate), plus 1 percent, and (4) zero percent. The interest rates for SOFR Advances
(as defined in the Term Loan Facility) were based on the Term SOFR rate for the borrower-selected period plus the Applicable Margin. The "Applicable Margin" is based on Idaho
Power's senior unsecured non-credit enhanced long-term indebtedness credit rating, as set forth on a schedule to the Term Loan Facility. At December 31, 2022, $150 million in
principal amount of one month term SOFR advances had been drawn and was outstanding on the Term Loan Facility. On March 31, 2023, Idaho Power repaid $100 million in
principal amount of one month term SOFR advances on the Term Loan Facility.

On March 14, 2023, Idaho Power issued $400,000,000 aggregate principal amount of 5.50% First Mortgage Bonds due 2053, Secured Medium-Term Notes, Series M.

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 May and June 2022, Idaho
Power received orders from the IPUC, OPUC, and WPSC authorizing the company to issue and sell from time to time up to $1.2 billion 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, 2025, subject to extensions upon request to the IPUC.
The OPUC's and WPSC's orders do not impose a time limitation for issuances, but the OPUC order does impose a number of other conditions, including a requirement that the interest
rates for the debt securities or first mortgage bonds fall within either (a) designated spreads over comparable U.S. Treasury rates or (b) a maximum interest rate limit of 8.0 percent. At
December 31, 2022, $1.15 billion remains available for debt issuance under the regulatory orders, prior to the commitment to draw the remaining $122 million of Series N Notes in
March 2023.

In May 2022, Idaho Power filed a shelf registration statement with the SEC, which became effective upon filing, for the offer and sale of an unspecified principal amount of its first
mortgage bonds. The issuance of first mortgage bonds requires that Idaho Power meet interest coverage and security provisions set forth in Idaho Power's Indenture of Mortgage and
Deed of Trust, dated as of October 1, 1937, as amended and supplemented from time to time (Indenture). Future issuances of first mortgage bonds are subject to satisfaction of
covenants and security provisions set forth in the Indenture, market conditions, regulatory authorizations, and covenants contained in other financing agreements.

In June 2022, Idaho Power entered into a selling agency agreement with six banks named in the agreement in
connection with the potential issuance and sale from time to time of up to $1.2 billion aggregate principal amount of first
mortgage bonds, secured medium term notes, Series M (Series M Notes), under Idaho Power's Indenture. Also in June 2022, Idaho Power entered into the Fiftieth Supplemental
Indenture, dated effective as of June 30, 2022, to the Indenture (Fiftieth Supplemental Indenture). The Fiftieth Supplemental Indenture provides for, among other items, the issuance of
up to $1.2 billion in aggregate principal amount of Series M Notes pursuant to the Indenture. In October 2022, Idaho Power entered into the Fifty-first Supplemental Indenture to
increase the limit of the amount of first mortgage bonds at any one time outstanding to $3.5 billion as provided in the Indenture. The amount issuable is also restricted by property,
earnings, and other provisions of the Indenture and supplemental indentures to the Indenture. The Indenture requires that Idaho Power's net earnings be at least twice the annual
interest requirements on all outstanding debt of equal or prior rank, including the bonds that Idaho Power may propose to issue. Under certain circumstances, the net earnings test does
not apply, including the issuance of refunding bonds to retire outstanding bonds that mature in less than two years or that are of an equal or higher interest rate, or prior lien bonds.

In December 2022, Idaho Power entered into the Bond Purchase Agreement with certain institutional purchasers, relating to the sale by Idaho Power of $170 million in aggregate
principal amount of Series N Notes. Also in December 2022, Idaho Power entered into the Fifty-second Supplemental Indenture, dated effective as of December 30, 2022, to the
Indenture (Fifty-second Supplemental Indenture). The Fifty-second Supplemental Indenture provides for, among other items, the issuance of Series N Notes pursuant to the Indenture.
The Series N Notes consist of:

$23 million in aggregate principal amount of Idaho Power's 4.99% first mortgage bonds due 2032, Series N Notes, Tranche 1 (Tranche 1 Bonds);
$25 million in aggregate principal amount of Idaho Power's 5.06% first mortgage bonds due 2042, Series N Notes, Tranche 2 (Tranche 2 Bonds);
$60 million in aggregate principal amount of Idaho Power's 5.06% first mortgage bonds due 2043, Series N Notes, Tranche 3 (Tranche 3 Bonds); and
$62 million in aggregate principal amount of Idaho Power's 5.20% first mortgage bonds due 2053, Series N Notes, Tranche 4 (Tranche 4 Bonds).

The Tranche 1 Bonds and Tranche 2 Bonds were issued on December 22, 2022, and Idaho Power Tranche 3 Bonds and Tranche 4 Bonds were issued on March 8, 2023, each under the
Indenture.

The mortgage of the Indenture secures all bonds issued under the Indenture equally and ratably, without preference, priority, or distinction. First mortgage bonds issued in the future
will also be secured by the mortgage of the Indenture. The lien constitutes a first mortgage on all the properties of Idaho Power, subject only to certain limited exceptions including
liens for taxes and assessments that are not delinquent and minor excepted encumbrances. Certain of the properties of Idaho Power are subject to easements, leases, contracts,
covenants, workmen's compensation awards, and similar encumbrances and minor defects common to properties. The mortgage of the Indenture does not create a lien on revenues or
profits, or notes or accounts receivable, contracts or choses in action, except as permitted by law during a completed default, securities, or cash, except when pledged, or merchandise
or equipment manufactured or acquired for resale. The mortgage of the Indenture creates a lien on the interest of Idaho Power in property subsequently acquired, other than excepted
property, subject to limitations in the case of consolidation, merger, or sale of all or substantially all of the assets of Idaho Power. The Indenture requires Idaho Power to spend or
appropriate 15 percent of its annual gross operating revenues for maintenance, retirement, or amortization of its properties. Idaho Power may, however, anticipate or make up these
expenditures or appropriations within the 5 years that immediately follow or precede a particular year.

As of December 31, 2022, the maximum amount of additional first mortgage bonds Idaho Power could issue, which excludes commitments to issue that have not already funded, is
approximately $1.5 billion, though as of the date of this report the amount is limited to the $1.15 billion amount authorized by the IPUC, OPUC, and WPSC. Separately, the Indenture
also limits the amount of additional first mortgage bonds that Idaho Power may issue to the sum of (a) the principal amount of retired first mortgage bonds and (b) 60 percent of total
unfunded property additions, as defined in the Indenture. As of December 31, 2022, Idaho Power could issue approximately $2.3 billion of additional first mortgage bonds based on
retired first mortgage bonds and total unfunded property additions.

6. COMMON STOCK

Idaho Power Common Stock

No contributions were made to Idaho Power in 2022 and 2021 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
$ 75,000 $ 199,800 $ 19,885 $ 116,300 $ $ 1,773,000 Long-Term Debt Issuances, Maturities, and Redemptions On its balance sheet as of December 31, 2022, Idaho Power classified the $75 million in principal amount of 2.50% first mortgage bonds, Series I, maturing on April 1, 2023, as long-term debt based upon Idaho Power's intent and ability to refinance the bonds on a long-term basis. On December 22, 2022, Idaho Power entered into a Bond Purchase Agreement (Bond Purchase Agreement) with certain institutional purchasers relating to the sale by Idaho Power of$170 million of first mortgage bonds secured medium-term-term notes, Series N (Series N Notes), as described in more detail below. At December 31, 2022, $48 million in principalamount of Series N Notes had been issued and was outstanding. On December 1, 2022, Idaho Power redeemed at par $4.36 million in principal amount of variable-rate pollution control revenue bonds due in 2027. On March 4, 2022, Idaho Power entered into a floating rate term loan credit agreement (Term Loan Facility). The Term Loan Facility is a two-year senior unsecured term loan facility. Itprovided for the issuance of loans not to exceed the aggregate principal amount of $150 million with a maturity date of March 4, 2024. The interest rates for the floating rate advancesunder the Term Loan Facility were based on the highest of (1) the prime commercial lending rate of the lender acting as administrative agent, (2) the federal funds rate, plus 0.5percent, (3) Term Secured Overnight Financing Rate administered by the Federal Reserve Bank of New York (SOFR) (as defined in the Term Loan Facility) for a one-month tenor thatis published by CME Group Benchmark Administration limited (or the successor administrator of such rate), plus 1 percent, and (4) zero percent. The interest rates for SOFR Advances(as defined in the Term Loan Facility) were based on the Term SOFR rate for the borrower-selected period plus the Applicable Margin. The "Applicable Margin" is based on IdahoPower's senior unsecured non-credit enhanced long-term indebtedness credit rating, as set forth on a schedule to the Term Loan Facility. At December 31, 2022, $150 million inprincipal amount of one month term SOFR advances had been drawn and was outstanding on the Term Loan Facility. On March 31, 2023, Idaho Power repaid $100 million inprincipal amount of one month term SOFR advances on the Term Loan Facility. On March 14, 2023, Idaho Power issued $400,000,000 aggregate principal amount of 5.50% First Mortgage Bonds due 2053, Secured Medium-Term Notes, Series M. 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 May and June 2022, IdahoPower received orders from the IPUC, OPUC, and WPSC authorizing the company to issue and sell from time to time up to $1.2 billion in aggregate principal amount of debt securitiesand first mortgage bonds, subject to conditions specified in the orders. Authority from the IPUC is effective through May 31, 2025, 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 interestrates for the debt securities or first mortgage bonds fall within either (a) designated spreads over comparable U.S. Treasury rates or (b) a maximum interest rate limit of 8.0 percent. AtDecember 31, 2022, $1.15 billion remains available for debt issuance under the regulatory orders, prior to the commitment to draw the remaining $122 million of Series N Notes inMarch 2023. In May 2022, Idaho Power filed a shelf registration statement with the SEC, which became effective upon filing, for the offer and sale of an unspecified principal amount of its firstmortgage bonds. The issuance of first mortgage bonds requires that Idaho Power meet interest coverage and security provisions set forth in Idaho Power's Indenture of Mortgage andDeed of Trust, dated as of October 1, 1937, as amended and supplemented from time to time (Indenture). Future issuances of first mortgage bonds are subject to satisfaction ofcovenants and security provisions set forth in the Indenture, market conditions, regulatory authorizations, and covenants contained in other financing agreements. In June 2022, Idaho Power entered into a selling agency agreement with six banks named in the agreement inconnection with the potential issuance and sale from time to time of up to $1.2 billion aggregate principal amount of firstmortgage bonds, secured medium term notes, Series M (Series M Notes), under Idaho Power's Indenture. Also in June 2022, Idaho Power entered into the Fiftieth SupplementalIndenture, dated effective as of June 30, 2022, to the Indenture (Fiftieth Supplemental Indenture). The Fiftieth Supplemental Indenture provides for, among other items, the issuance ofup to $1.2 billion in aggregate principal amount of Series M Notes pursuant to the Indenture. In October 2022, Idaho Power entered into the Fifty-first Supplemental Indenture toincrease the limit of the amount of first mortgage bonds at any one time outstanding to $3.5 billion as provided in the Indenture. The amount issuable is also restricted by property,earnings, and other provisions of the Indenture and supplemental indentures to the Indenture. The Indenture requires that Idaho Power's net earnings be at least twice the annualinterest requirements on all outstanding debt of equal or prior rank, including the bonds that Idaho Power may propose to issue. Under certain circumstances, the net earnings test doesnot 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. In December 2022, Idaho Power entered into the Bond Purchase Agreement with certain institutional purchasers, relating to the sale by Idaho Power of $170 million in aggregateprincipal amount of Series N Notes. Also in December 2022, Idaho Power entered into the Fifty-second Supplemental Indenture, dated effective as of December 30, 2022, to theIndenture (Fifty-second Supplemental Indenture). The Fifty-second Supplemental Indenture provides for, among other items, the issuance of Series N Notes pursuant to the Indenture.The Series N Notes consist of: $23 million in aggregate principal amount of Idaho Power's 4.99% first mortgage bonds due 2032, Series N Notes, Tranche 1 (Tranche 1 Bonds); $25 million in aggregate principal amount of Idaho Power's 5.06% first mortgage bonds due 2042, Series N Notes, Tranche 2 (Tranche 2 Bonds); $60 million in aggregate principal amount of Idaho Power's 5.06% first mortgage bonds due 2043, Series N Notes, Tranche 3 (Tranche 3 Bonds); and $62 million in aggregate principal amount of Idaho Power's 5.20% first mortgage bonds due 2053, Series N Notes, Tranche 4 (Tranche 4 Bonds). The Tranche 1 Bonds and Tranche 2 Bonds were issued on December 22, 2022, and Idaho Power Tranche 3 Bonds and Tranche 4 Bonds were issued on March 8, 2023, each under theIndenture. The mortgage of the Indenture secures all bonds issued under the Indenture equally and ratably, without preference, priority, or distinction. First mortgage bonds issued in the futurewill 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 includingliens for taxes and assessments that are not delinquent and minor excepted encumbrances. Certain of the properties of Idaho Power are subject to easements, leases, contracts,covenants, workmen's compensation awards, and similar encumbrances and minor defects common to properties. The mortgage of the Indenture does not create a lien on revenues orprofits, 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 merchandiseor 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 exceptedproperty, subject to limitations in the case of consolidation, merger, or sale of all or substantially all of the assets of Idaho Power. The Indenture requires Idaho Power to spend orappropriate 15 percent of its annual gross operating revenues for maintenance, retirement, or amortization of its properties. Idaho Power may, however, anticipate or make up theseexpenditures or appropriations within the 5 years that immediately follow or precede a particular year. As of December 31, 2022, the maximum amount of additional first mortgage bonds Idaho Power could issue, which excludes commitments to issue that have not already funded, isapproximately $1.5 billion, though as of the date of this report the amount is limited to the $1.15 billion amount authorized by the IPUC, OPUC, and WPSC. Separately, the Indenturealso limits the amount of additional first mortgage bonds that Idaho Power may issue to the sum of (a) the principal amount of retired first mortgage bonds and (b) 60 percent of totalunfunded property additions, as defined in the Indenture. As of December 31, 2022, Idaho Power could issue approximately $2.3 billion of additional first mortgage bonds based onretired first mortgage bonds and total unfunded property additions. 6. COMMON STOCK Idaho Power Common Stock
No contributions were made to Idaho Power in 2022 and 2021 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 orIdaho 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, 2022, the leverage ratio for Idaho Power was 46 percent. Based on
this restriction, Idaho Power's dividends were limited to $1.4 billion at December 31, 2022. There are additional facility covenants, subject to exceptions, that prohibit or restrict the
sale or disposition of property without consent and any agreements restricting dividend payments to IDACORP and Idaho Power from any material subsidiary. At December 31, 2022,
Idaho Power was in compliance with those covenants.

Idaho Power's Revised Policy and Code of Conduct relating to transactions between and among Idaho Power, IDACORP, and other affiliates, which was approved by the IPUC in April
2008, provides that Idaho Power will not pay any dividends to IDACORP that will reduce Idaho Power's common equity capital below 35 percent of its total adjusted capital without
IPUC approval. At December 31, 2022, Idaho Power's common equity capital was 55 percent of its total adjusted capital. Further, Idaho Power must obtain approval from the OPUC
before it can directly or indirectly loan funds or issue notes or give credit on its books to IDACORP.

Idaho Power's articles of incorporation contain restrictions on the payment of dividends on its common stock if preferred stock dividends are in arrears. As of the date of this report,
Idaho Power has no preferred stock outstanding.

In addition to contractual restrictions on the amount and payment of dividends, the FPA prohibits the payment of dividends from "capital accounts." The term "capital account" is
undefined in the FPA or its regulations, but Idaho Power does not believe the restriction would limit Idaho Power's ability to pay dividends out of current year earnings or retained
earnings.

In accordance with Section 10(d) of the Federal Power Act, Idaho Power has $13.3 million of amortization reserves established for certain of its licensed hydroelectric facilities.

7. SHARE-BASED COMPENSATION

Through its parent company IDACORP, Idaho Power has one share-based compensation plan the 2000 Long-Term Incentive and Compensation Plan (LTICP). The LTICP (for officers,
key employees, and directors) permits the grant of stock options, restricted stock and restricted stock units, performance shares and performance-based units, and several other types of
share-based awards. At December 31, 2022, the maximum number of shares available under the LTICP was 350,763.

Restricted Stock Unit and Performance-Based Unit Awards

Restricted stock unit awards have three-year vesting periods, entitle the recipients to dividend equivalents, and 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 unit awards have three-year vesting periods and do not have voting rights until the units are vested and settled in shares. Unvested awards are restricted as to
disposition, subject to forfeiture under certain circumstances, and subject to the attainment of specific performance conditions over the three-year vesting period. The performance
conditions are two equally-weighted metrics, cumulative earnings per share (CEPS) and total shareholder return (TSR) relative to a peer group. Depending on the level of attainment of
the performance conditions and the year issued, the final number of shares awarded can range from zero to 200 percent of the target award. Dividend equivalents 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 units and performance-based units award activity is presented below. Idaho Power unit amounts represent units of IDACORP:

Number of
Units
Weighted-
Average
Grant Date
Fair Value
Nonvested units at January 1, 2022 174,209 $ 99.61
Units granted 87,685 100.76
Units forfeited (8,144) 97.29
Units vested (65,934) 100.59
Nonvested units at December 31, 2022 187,816 $ 99.91

The total fair value of shares vested was $6.9 million in 2022 and $6.7 million in 2021. At December 31, 2022, Idaho Power had $8.3 million of total 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 shares of IDACORP are used for
these awards.

In 2022, a total of 12,021 shares of IDACORP common stock were awarded to directors of IDACORP and Idaho Power at an average grant date fair value of $103.95 per share. Directors
elected to defer receipt of 4,616 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 Idaho Power's compensation cost recognized in income and the tax benefits resulting from the LTICP (in thousands of dollars):

2022 2021
Compensation cost $ 10,204 $ 8,497
Income tax benefit 2,627 2,187

No equity compensation costs have been capitalized. These costs are primarily reported within "Other operations and maintenance" expense on the statements of income.

8. COMMITMENTS

Purchase Obligations

At December 31, 2022, Idaho Power had the following long-term commitments relating to purchases of energy, capacity, transmission rights, and fuel (in thousands of dollars):
2023 2024 2025 2026 2027 Thereafter
Cogeneration and power production $ 321,321 $ 327,054 $ 319,588 $ 319,852 $ 322,043 $ 2,597,922
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 orIdaho 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 consolidatedtotal capitalization, as defined therein, of no more than 65 percent at the end of each fiscal quarter. At December 31, 2022, the leverage ratio for Idaho Power was 46 percent. Based onthis restriction, Idaho Power's dividends were limited to $1.4 billion at December 31, 2022. There are additional facility covenants, subject to exceptions, that prohibit or restrict thesale or disposition of property without consent and any agreements restricting dividend payments to IDACORP and Idaho Power from any material subsidiary. At December 31, 2022,Idaho Power was in compliance with those covenants. Idaho Power's Revised Policy and Code of Conduct relating to transactions between and among Idaho Power, IDACORP, and other affiliates, which was approved by the IPUC in April2008, provides that Idaho Power will not pay any dividends to IDACORP that will reduce Idaho Power's common equity capital below 35 percent of its total adjusted capital withoutIPUC approval. At December 31, 2022, Idaho Power's common equity capital was 55 percent of its total adjusted capital. Further, Idaho Power must obtain approval from the OPUCbefore it can directly or indirectly loan funds or issue notes or give credit on its books to IDACORP. Idaho Power's articles of incorporation contain restrictions on the payment of dividends on its common stock if preferred stock dividends are in arrears. As of the date of this report,Idaho Power has no preferred stock outstanding. In addition to contractual restrictions on the amount and payment of dividends, the FPA prohibits the payment of dividends from "capital accounts." The term "capital account" isundefined 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 retainedearnings. In accordance with Section 10(d) of the Federal Power Act, Idaho Power has $13.3 million of amortization reserves established for certain of its licensed hydroelectric facilities. 7. SHARE-BASED COMPENSATION Through its parent company IDACORP, Idaho Power has one share-based compensation plan the 2000 Long-Term Incentive and Compensation Plan (LTICP). The LTICP (for officers,key employees, and directors) permits the grant of stock options, restricted stock and restricted stock units, performance shares and performance-based units, and several other types ofshare-based awards. At December 31, 2022, the maximum number of shares available under the LTICP was 350,763. Restricted Stock Unit and Performance-Based Unit Awards Restricted stock unit awards have three-year vesting periods, entitle the recipients to dividend equivalents, and units do not have voting rights until the units are vested and settled inshares. Unvested awards are restricted as to disposition and subject to forfeiture under certain circumstances. The fair value of these awards is based on the closing market price ofcommon stock on the grant date and is charged to compensation expense over the vesting period, reduced for any forfeitures during the vesting period. Performance-based unit awards have three-year vesting periods and do not have voting rights until the units are vested and settled in shares. Unvested awards are restricted as todisposition, subject to forfeiture under certain circumstances, and subject to the attainment of specific performance conditions over the three-year vesting period. The performanceconditions are two equally-weighted metrics, cumulative earnings per share (CEPS) and total shareholder return (TSR) relative to a peer group. Depending on the level of attainment ofthe performance conditions and the year issued, the final number of shares awarded can range from zero to 200 percent of the target award. Dividend equivalents are accrued during thevesting 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, reducedfor 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 thatincorporates 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 tocompensation 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 units and performance-based units award activity is presented below. Idaho Power unit amounts represent units of IDACORP: Number ofUnits Weighted-AverageGrant DateFair ValueNonvested units at January 1, 2022 174,209 $ 99.61Units granted 87,685 100.76Units forfeited (8,144) 97.29Units vested (65,934) 100.59Nonvested units at December 31, 2022 187,816 $ 99.91 The total fair value of shares vested was $6.9 million in 2022 and $6.7 million in 2021. At December 31, 2022, Idaho Power had $8.3 million of total unrecognized compensation costrelated to nonvested share-based compensation. These costs are expected to be recognized over a weighted-average period of 1.7 years. Original issue shares of IDACORP are used forthese awards. In 2022, a total of 12,021 shares of IDACORP common stock were awarded to directors of IDACORP and Idaho Power at an average grant date fair value of $103.95 per share. Directorselected to defer receipt of 4,616 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 Idaho Power's compensation cost recognized in income and the tax benefits resulting from the LTICP (in thousands of dollars): 2022 2021 Compensation cost $ 10,204 $ 8,497 Income tax benefit 2,627 2,187 No equity compensation costs have been capitalized. These costs are primarily reported within "Other operations and maintenance" expense on the statements of income. 8. COMMITMENTS Purchase Obligations

At December 31, 2022, Idaho Power had the following long-term commitments relating to purchases of energy, capacity, transmission rights, and fuel (in thousands of dollars):
2023 2024 2025 2026 2027 Thereafter
Cogeneration and power production $ 321,321 $ 327,054 $ 319,588 $ 319,852 $ 322,043 $ 2,597,922Cogeneration and power production $ 321,321 $ 327,054 $ 319,588 $ 319,852 $ 322,043 $ 2,597,922
Fuel 144,856 31,559 8,239 8,492 8,659 50,884

As of December 31, 2022, Idaho Power had 1,137 megawatt (MW) nameplate capacity of PURPA-related projects on-line, with an additional 75 MW nameplate capacity of projects
projected to be on-line by 2024. The power purchase contracts for these projects have original contract terms ranging from one to 35 years. Idaho Power's expenses associated with
PURPA-related projects were approximately $189 million in 2022 and $200 million in 2021.

In January 2023, Idaho Power entered into an additional new non-PURPA-qualifying solar facility power purchase contract, subject to regulatory approval, which increased Idaho
Power's contractual purchase obligations by approximately $228 million over the 25-year term of the contract. The facility is scheduled to be online in June 2024.

As of December 31, 2022, Idaho Power had a remaining $95 million commitment related to two contracts to acquire and own battery storage systems expected to be in service in 2023.
Also, in January 2023, Idaho Power entered into a commitment to acquire and own a 60 MW battery storage system for $129 million, due upon its expected completion in 2024.

Idaho Power also has the following long-term commitments (in thousands of dollars):
2023 2024 2025 2026 2027 Thereafter
Joint-operating agreement payments(1) $ 3,243 $ 3,243 $ 3,243 $ 3,243 $ 3,243 $ 16,217
Easements and other payments 2,075 2,119 2,163 2,209 2,255 12,005
Maintenance, service, and materials
agreements(1) 174,619 11,931 9,652 7,623 11,660 38,729
FERC and other industry-related fees(1) 17,402 15,619 15,562 15,839 15,348 75,272

(1) Approximately $34 million, $18 million, and $152 million of the obligations included in joint-operating agreement payments, maintenance, service, and materials agreements, and FERC and other industry-
related fees, respectively, have contracts that do not specify terms related to expiration. As these contracts are presumed to continue indefinitely, ten years of information, estimated based on current contract
terms, has been included in the table for presentation purposes.

Idaho Power's expense for operating leases was not material for the years ended 2022 and 2021.

Guarantees

Idaho Power guarantees its portion of reclamation activities and obligations at BCC, of which IERCo owns a one-third interest. This guarantee, which is renewed annually with the
Wyoming Department of Environmental Quality, was $48.2 million at December 31, 2022, representing IERCo's one-third share of BCC's total reclamation obligation of $144.7
million. BCC has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs. At December 31, 2022, the value of the reclamation trust fund was
$196.1 million. During 2022, the reclamation trust fund made $3.9 million of distributions for reclamation activity costs associated with the BCC surface mine. BCC periodically
assesses the adequacy of the reclamation trust fund and its estimate of future reclamation costs. To ensure that the reclamation trust fund maintains adequate reserves, 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 enter into financial agreements and power purchase and sale agreements that include indemnification provisions relating to various forms of claims or liabilities that may
arise from the transactions contemplated by these agreements. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall
maximum amount of the obligation under such indemnification provisions cannot be reasonably estimated. Idaho Power periodically evaluates the likelihood of incurring costs under
such indemnities based on their historical experience and the evaluation of the specific indemnities. As of December 31, 2022, management believes the likelihood is remote that
Idaho Power would be required to perform under such indemnification provisions or otherwise incur any significant losses with respect to such indemnification obligations. Idaho
Power has not recorded any liability on its balance sheets with respect to these indemnification obligations.

9. CONTINGENCIES

Idaho Power has in the past and expect in the future to become involved in various claims, controversies, disputes, and other contingent matters, some of which involve litigation and
regulatory or other contested proceedings. The ultimate resolution and outcome of litigation and regulatory proceedings is inherently difficult to determine, particularly where (a) the
remedies or penalties sought are indeterminate, (b) the proceedings are in the early stages or the substantive issues have not been well developed, or (c) the matters involve complex or
novel legal theories or a large number 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. If the loss contingency at issue is not both probable and
reasonably estimable, Idaho Power does not establish an accrual and the matter will continue to be monitored for any developments that would make the loss contingency both
probable and reasonably estimable. As of the date of this report, Idaho Power's accruals for loss contingencies are not material to its financial statements as a whole; however, future
accruals could be material in a given period. Idaho Power's determination is based on currently available information, and estimates presented in financial statements and other
financial disclosures involve significant judgment and may be subject to significant uncertainty. For matters that affect Idaho Power's operations, Idaho Power intends to seek, to the
extent permissible and appropriate, recovery through the ratemaking process of costs incurred, although there is no assurance that such recovery would be granted.

Idaho Power is party to legal claims and legal, tax, and regulatory actions and proceedings in the ordinary course of business and, as noted above, record an accrual for associated loss
contingencies when they are probable and reasonably estimable. In connection with its utility operations, Idaho Power is subject to claims by individuals, entities, and governmental
agencies for damages for alleged personal injury, property damage, and economic losses, relating to the company's provision of electric service and the operation of its generation,
transmission, and distribution facilities. Some of those claims relate to electrical contacts, service quality, property damage, and wildfires. In recent years, utilities in the western
United States have been subject to significant liability for personal injury, loss of life, property damage, trespass, and economic losses, and in some cases, punitive damages and
criminal charges, associated with wildfires that originated from utility property, most commonly transmission and distribution lines. Idaho Power has also regularly received claims by
governmental agencies and private landowners for damages for fires allegedly originating from Idaho Power's transmission and distribution system. As of the date of this report, Idaho
Power believes that resolution of existing claims will not have a material adverse effect on its financial statements.

Idaho Power is also actively monitoring various pending environmental regulations and executive orders related to environmental matters that may have a significant impact on its
future operations. Given uncertainties regarding the outcome, timing, and compliance plans for these environmental matters, Idaho Power is unable to estimate the financial impact of
these regulations.

10. BENEFIT PLANS

Idaho Power sponsors defined benefit and other postretirement benefit plans that cover the majority of its employees. Idaho Power also sponsors a defined contribution 401(k)
employee savings plan and provides certain post-employment benefits.

Pension Plans

Idaho Power has pension plans-a noncontributory defined 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 Security Plan for Senior Management Employees II (together, SMSP). Idaho Power also has a nonqualified
defined benefit pension plan for directors that was frozen in 2002. Remaining vested benefits from that plan are included with the SMSP in the disclosures below. The benefits under
these plans are based on years of service and the employee's final average earnings.

The following table summarizes the changes in benefit obligations and plan assets of these plans (in thousands of dollars):
Pension Plan SMSP
2022 2021 2022 2021
Cogeneration and power production $ 321,321 $ 327,054 $ 319,588 $ 319,852 $ 322,043 $ 2,597,922Fuel 144,856 31,559 8,239 8,492 8,659 50,884 As of December 31, 2022, Idaho Power had 1,137 megawatt (MW) nameplate capacity of PURPA-related projects on-line, with an additional 75 MW nameplate capacity of projectsprojected to be on-line by 2024. The power purchase contracts for these projects have original contract terms ranging from one to 35 years. Idaho Power's expenses associated withPURPA-related projects were approximately $189 million in 2022 and $200 million in 2021. In January 2023, Idaho Power entered into an additional new non-PURPA-qualifying solar facility power purchase contract, subject to regulatory approval, which increased IdahoPower's contractual purchase obligations by approximately $228 million over the 25-year term of the contract. The facility is scheduled to be online in June 2024. As of December 31, 2022, Idaho Power had a remaining $95 million commitment related to two contracts to acquire and own battery storage systems expected to be in service in 2023.Also, in January 2023, Idaho Power entered into a commitment to acquire and own a 60 MW battery storage system for $129 million, due upon its expected completion in 2024. Idaho Power also has the following long-term commitments (in thousands of dollars): 2023 2024 2025 2026 2027 ThereafterJoint-operating agreement payments(1) $ 3,243 $ 3,243 $ 3,243 $ 3,243 $ 3,243 $ 16,217Easements and other payments 2,075 2,119 2,163 2,209 2,255 12,005Maintenance, service, and materialsagreements(1) 174,619 11,931 9,652 7,623 11,660 38,729FERC and other industry-related fees(1) 17,402 15,619 15,562 15,839 15,348 75,272 (1) Approximately $34 million, $18 million, and $152 million of the obligations included in joint-operating agreement payments, maintenance, service, and materials agreements, and FERC and other industry-related fees, respectively, have contracts that do not specify terms related to expiration. As these contracts are presumed to continue indefinitely, ten years of information, estimated based on current contractterms, has been included in the table for presentation purposes. Idaho Power's expense for operating leases was not material for the years ended 2022 and 2021. Guarantees Idaho Power guarantees its portion of reclamation activities and obligations at BCC, of which IERCo owns a one-third interest. This guarantee, which is renewed annually with theWyoming Department of Environmental Quality, was $48.2 million at December 31, 2022, representing IERCo's one-third share of BCC's total reclamation obligation of $144.7million. BCC has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs. At December 31, 2022, the value of the reclamation trust fund was$196.1 million. During 2022, the reclamation trust fund made $3.9 million of distributions for reclamation activity costs associated with the BCC surface mine. BCC periodicallyassesses the adequacy of the reclamation trust fund and its estimate of future reclamation costs. To ensure that the reclamation trust fund maintains adequate reserves, BCC has theability 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-tonsurcharge, the estimated fair value of this guarantee is minimal. Idaho Power enter into financial agreements and power purchase and sale agreements that include indemnification provisions relating to various forms of claims or liabilities that mayarise from the transactions contemplated by these agreements. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overallmaximum amount of the obligation under such indemnification provisions cannot be reasonably estimated. Idaho Power periodically evaluates the likelihood of incurring costs undersuch indemnities based on their historical experience and the evaluation of the specific indemnities. As of December 31, 2022, management believes the likelihood is remote thatIdaho Power would be required to perform under such indemnification provisions or otherwise incur any significant losses with respect to such indemnification obligations. IdahoPower has not recorded any liability on its balance sheets with respect to these indemnification obligations. 9. CONTINGENCIES Idaho Power has in the past and expect in the future to become involved in various claims, controversies, disputes, and other contingent matters, some of which involve litigation andregulatory or other contested proceedings. The ultimate resolution and outcome of litigation and regulatory proceedings is inherently difficult to determine, particularly where (a) theremedies 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 ornovel legal theories or a large number of parties. In accordance with applicable accounting guidance, Idaho Power, as applicable, establishes an accrual for legal proceedings whenthose matters proceed to a stage where they present loss contingencies that are both probable and reasonably estimable. If the loss contingency at issue is not both probable andreasonably 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 bothprobable and reasonably estimable. As of the date of this report, Idaho Power's accruals for loss contingencies are not material to its financial statements as a whole; however, futureaccruals could be material in a given period. Idaho Power's determination is based on currently available information, and estimates presented in financial statements and otherfinancial disclosures involve significant judgment and may be subject to significant uncertainty. For matters that affect Idaho Power's operations, Idaho Power intends to seek, to theextent 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, tax, and regulatory actions and proceedings in the ordinary course of business and, as noted above, record an accrual for associated losscontingencies when they are probable and reasonably estimable. In connection with its utility operations, Idaho Power is subject to claims by individuals, entities, and governmentalagencies for damages for alleged personal injury, property damage, and economic losses, relating to the company's provision of electric service and the operation of its generation,transmission, and distribution facilities. Some of those claims relate to electrical contacts, service quality, property damage, and wildfires. In recent years, utilities in the westernUnited States have been subject to significant liability for personal injury, loss of life, property damage, trespass, and economic losses, and in some cases, punitive damages andcriminal charges, associated with wildfires that originated from utility property, most commonly transmission and distribution lines. Idaho Power has also regularly received claims bygovernmental agencies and private landowners for damages for fires allegedly originating from Idaho Power's transmission and distribution system. As of the date of this report, IdahoPower believes that resolution of existing claims will not have a material adverse effect on its financial statements. Idaho Power is also actively monitoring various pending environmental regulations and executive orders related to environmental matters that may have a significant impact on itsfuture operations. Given uncertainties regarding the outcome, timing, and compliance plans for these environmental matters, Idaho Power is unable to estimate the financial impact ofthese regulations. 10. BENEFIT PLANS Idaho Power sponsors defined benefit and other postretirement benefit plans that cover the majority of its employees. Idaho Power also sponsors a defined contribution 401(k)employee savings plan and provides certain post-employment benefits. Pension Plans Idaho Power has pension plans-a noncontributory defined benefit pension plan (pension plan) and two nonqualified defined benefit pension plans for certain senior managementemployees called the Security Plan for Senior Management Employees I and Security Plan for Senior Management Employees II (together, SMSP). Idaho Power also has a nonqualifieddefined benefit pension plan for directors that was frozen in 2002. Remaining vested benefits from that plan are included with the SMSP in the disclosures below. The benefits under
these plans are based on years of service and the employee's final average earnings.

The following table summarizes the changes in benefit obligations and plan assets of these plans (in thousands of dollars):
Pension Plan SMSP
2022 2021 2022 2021 2022 2021 2022 2021

Change in projected benefit obligation:
Benefit obligation at January 1 $ 1,346,530 $ 1,337,395 $ 133,012 $ 134,791
Service cost 52,025 54,202 1,185 813
Interest cost 39,670 37,317 3,897 3,557
Actuarial (gain) loss (438,297) (35,833) (32,009) 33
Benefits paid (46,159) (46,551) (6,109) (6,182)
Projected benefit obligation at December 31 953,769 1,346,530 99,976 133,012
Change in plan assets:
Fair value at January 1 984,464 871,603
Actual return on plan assets (138,577) 119,412
Employer contributions 40,000 40,000
Benefits paid (46,159) (46,551)
Fair value at December 31 839,728 984,464
Funded status at end of year $ (114,041) $ (362,066) $ (99,976) $ (133,012)

Amounts recognized in accumulated other comprehensive
income consist of:

Net loss $ 83,263 $ 322,908 $ 15,127 $ 51,365
Prior service cost 37 43 2,408 2,687
Subtotal 83,300 322,951 17,535 54,052
Less amount recorded as regulatory asset(1) (83,300) (322,951)
Net amount recognized in accumulated other comprehensive
income $ $ $ 17,535 $ 54,052
Accumulated benefit obligation $ 837,377 $ 1,120,036 $ 93,995 $ 121,591

(1) Changes in the funded status of the pension plan that would be recorded in accumulated other comprehensive income for an unregulated entity are recorded as a regulatory asset for Idaho Power as Idaho
Power believes it is probable that an amount equal to the regulatory asset will be collected through the setting of future rates.

The actuarial gains reflected in the benefit obligations for the pension and SMSP plans in 2022 are due primarily to increases in the assumed discount rates of both plans from
December 31, 2021, to December 31, 2022. The actuarial gains reflected in the benefit obligations for the pension and SMSP plans in 2021 are due primarily to increases in the
assumed discount rates of both plans from December 31, 2020 to December 31, 2021. For more information on discount rates, see "Plan Assumptions" below in this Note 10.

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 $134.2 million and $117.1 million at December 31, 2022 and
2021, respectively.

The following table shows the components of net periodic pension cost for these plans (in thousands of dollars). For purposes of calculating the expected return on plan assets, the
market-related value of assets is equal to the fair value of the assets.
Pension Plan SMSP
2022 2021 2022 2021
Service cost $ 52,025 $ 54,202 $ 1,185 $ 813
Interest cost 39,670 37,317 3,897 3,557
Expected return on assets (72,348) (64,090)
Amortization of net loss 12,273 23,796 4,229 4,205
Amortization of prior service cost 6 6 279 296
Net periodic pension cost 31,626 51,231 9,590 8,871
Regulatory deferral of net periodic pension cost(1) (30,197) (48,962)
Previously deferred pension cost recognized(1) 17,154 17,154
Net periodic pension cost recognized for financial reporting(1)
(2) $ 18,583 $ 19,423 $ 9,590 $ 8,871

(1) Net periodic pension costs for the pension plan are recognized for financial reporting based upon the authorization of each regulatory jurisdiction in which Idaho Power operates. Under IPUC order, the Idaho
portion of net periodic pension cost is recorded as a regulatory asset and is recognized in the income statement as those costs are recovered through rates.

The following table shows the components of other comprehensive income (loss) for the plans (in thousands of dollars):
Pension Plan SMSP
2022 2021 2022 2021
Actuarial (loss) gain during the year $ 227,372 $ 91,156 $ 32,009 $ (33)
Plan amendment service cost
Reclassification adjustments for:
Amortization of net (gain) loss 12,273 23,796 4,229 4,205
Amortization of prior service cost 6 6 279 296
2022 2021 2022 2021 Change in projected benefit obligation: Benefit obligation at January 1 $ 1,346,530 $ 1,337,395 $ 133,012 $ 134,791Service cost 52,025 54,202 1,185 813Interest cost 39,670 37,317 3,897 3,557Actuarial (gain) loss (438,297) (35,833) (32,009) 33Benefits paid (46,159) (46,551) (6,109) (6,182)Projected benefit obligation at December 31 953,769 1,346,530 99,976 133,012Change in plan assets: Fair value at January 1 984,464 871,603 Actual return on plan assets (138,577) 119,412 Employer contributions 40,000 40,000 Benefits paid (46,159) (46,551) Fair value at December 31 839,728 984,464 Funded status at end of year $ (114,041) $ (362,066) $ (99,976) $ (133,012) Amounts recognized in accumulated other comprehensiveincome consist of: Net loss $ 83,263 $ 322,908 $ 15,127 $ 51,365Prior service cost 37 43 2,408 2,687Subtotal 83,300 322,951 17,535 54,052Less amount recorded as regulatory asset(1) (83,300) (322,951) Net amount recognized in accumulated other comprehensiveincome $ $ $ 17,535 $ 54,052Accumulated benefit obligation $ 837,377 $ 1,120,036 $ 93,995 $ 121,591 (1) Changes in the funded status of the pension plan that would be recorded in accumulated other comprehensive income for an unregulated entity are recorded as a regulatory asset for Idaho Power as IdahoPower believes it is probable that an amount equal to the regulatory asset will be collected through the setting of future rates. The actuarial gains reflected in the benefit obligations for the pension and SMSP plans in 2022 are due primarily to increases in the assumed discount rates of both plans fromDecember 31, 2021, to December 31, 2022. The actuarial gains reflected in the benefit obligations for the pension and SMSP plans in 2021 are due primarily to increases in theassumed discount rates of both plans from December 31, 2020 to December 31, 2021. For more information on discount rates, see "Plan Assumptions" below in this Note 10. 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 investmentsin marketable securities and corporate-owned life insurance. The recorded value of these investments was approximately $134.2 million and $117.1 million at December 31, 2022 and2021, respectively. The following table shows the components of net periodic pension cost for these plans (in thousands of dollars). For purposes of calculating the expected return on plan assets, themarket-related value of assets is equal to the fair value of the assets. Pension Plan SMSP 2022 2021 2022 2021 Service cost $ 52,025 $ 54,202 $ 1,185 $ 813 Interest cost 39,670 37,317 3,897 3,557 Expected return on assets (72,348) (64,090) Amortization of net loss 12,273 23,796 4,229 4,205 Amortization of prior service cost 6 6 279 296 Net periodic pension cost 31,626 51,231 9,590 8,871 Regulatory deferral of net periodic pension cost(1) (30,197) (48,962) Previously deferred pension cost recognized(1) 17,154 17,154 Net periodic pension cost recognized for financial reporting(1)(2) $ 18,583 $ 19,423 $ 9,590 $ 8,871 (1) Net periodic pension costs for the pension plan are recognized for financial reporting based upon the authorization of each regulatory jurisdiction in which Idaho Power operates. Under IPUC order, the Idahoportion of net periodic pension cost is recorded as a regulatory asset and is recognized in the income statement as those costs are recovered through rates. The following table shows the components of other comprehensive income (loss) for the plans (in thousands of dollars): Pension Plan SMSP 2022 2021 2022 2021
Actuarial (loss) gain during the year $ 227,372 $ 91,156 $ 32,009 $ (33)
Plan amendment service cost
Reclassification adjustments for:
Amortization of net (gain) loss 12,273 23,796 4,229 4,205
Amortization of prior service cost 6 6 279 296 Amortization of prior service cost 6 6 279 296
Adjustment for deferred tax effects (61,686) (29,590) (9,399) (1,150)
Adjustment due to the effects of regulation (177,965) (85,368)
Other comprehensive income (loss)
recognized related to pension benefit
plans $ $ $ 27,118 $ 3,318

The following table summarizes the expected future benefit payments of these plans (in thousands of dollars):
2023 2024 2025 2026 2027 2026-2030
Pension Plan $ 47,477 $ 48,972 $ 50,666 $ 52,490 $ 54,209 $ 298,823
SMSP 6,514 6,558 6,656 6,695 6,725 35,197

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 2022 and 2021, Idaho Power elected to contribute more than the minimum required amounts in order to bring the
pension plan to a more funded position, to reduce future required contributions, and to reduce Pension Benefit Guaranty Corporation premiums. As of the date of this report, Idaho
Power has no estimated minimum required contributions to the pension plan for 2023. Depending on market conditions and cash flow considerations in 2023, Idaho Power could
contribute up to $40 million to the pension plan during 2023 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 postretirement benefit plan (consisting of health care and death benefits) that covers all employees who were enrolled in the active-employee
group plan at the time of retirement as well as their spouses and qualifying dependents. Retirees hired on or after January 1, 1999, have access to the standard medical option at full
cost, with no contribution by Idaho Power. Benefits for employees who retire after December 31, 2002, are limited to a fixed amount, which has limited the growth 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):
2022 2021
Change in accumulated benefit obligation:
Benefit obligation at January 1 $ 74,075 $ 80,952
Service cost 1,071 1,063
Interest cost 2,112 2,059
Actuarial gain (21,845) (5,805)
Benefits paid(1) (4,379) (4,194)
Plan amendments 8,065
Benefit obligation at December 31 59,099 74,075
Change in plan assets:
Fair value of plan assets at January 1 41,464 41,311
Actual return on plan assets (6,586) 6,308
Employer contributions(1) (1,934) (1,961)
Benefits paid(1) (4,379) (4,194)
Fair value of plan assets at December 31 28,565 41,464
Funded status at end of year (included in noncurrent liabilities) $ (30,534) $ (32,611)

(1) Contributions and benefits paid are each net of $2.9 million and $3.0 million of plan participant contributions for 2022 and 2021, respectively.

Amounts recognized in accumulated other comprehensive income consist of the following (in thousands of dollars):
2022 2021
Net gain $ (20,896) $ (8,020)
Prior service cost 7,849 80
Subtotal (13,047) (7,940)
Less amount recognized in regulatory assets 13,047 7,940
Net amount recognized in accumulated other comprehensive income $ $

The net periodic postretirement benefit cost was as follows (in thousands of dollars):

2022 2021
Service cost $ 1,071 $ 1,063
Interest cost 2,112 2,059
Expected return on plan assets (2,351) (2,395)
Immediate recognition of loss from temporary deviation(1) 4,736
Amortization of net loss (31)
Amortization of prior service cost 295 47
Net periodic postretirement benefit cost $ 1,096 $ 5,510

(1) In 2021, a loss associated with a temporary deviation from the cost-sharing provisions of the substantive plan was recognized on the statements of income.

Amortization of prior service cost 6 6 279 296 Adjustment for deferred tax effects (61,686) (29,590) (9,399) (1,150) Adjustment due to the effects of regulation (177,965) (85,368) Other comprehensive income (loss)recognized related to pension benefitplans $ $ $ 27,118 $ 3,318 The following table summarizes the expected future benefit payments of these plans (in thousands of dollars): 2023 2024 2025 2026 2027 2026-2030Pension Plan $ 47,477 $ 48,972 $ 50,666 $ 52,490 $ 54,209 $ 298,823SMSP 6,514 6,558 6,656 6,695 6,725 35,197 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 morethan the maximum amount deductible for income tax purposes. In 2022 and 2021, Idaho Power elected to contribute more than the minimum required amounts in order to bring thepension plan to a more funded position, to reduce future required contributions, and to reduce Pension Benefit Guaranty Corporation premiums. As of the date of this report, IdahoPower has no estimated minimum required contributions to the pension plan for 2023. Depending on market conditions and cash flow considerations in 2023, Idaho Power couldcontribute up to $40 million to the pension plan during 2023 in order to help balance the regulatory collection of these expenditures with the amount and timing of contributions andto mitigate the cost of being in an underfunded position. Postretirement Benefits Idaho Power maintains a defined benefit postretirement benefit plan (consisting of health care and death benefits) that covers all employees who were enrolled in the active-employeegroup 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 fullcost, with no contribution by Idaho Power. Benefits for employees who retire after December 31, 2002, are limited to a fixed amount, which has limited the growth of Idaho Power'sfuture obligations under this plan. The following table summarizes the changes in benefit obligation and plan assets (in thousands of dollars): 2022 2021Change in accumulated benefit obligation: Benefit obligation at January 1 $ 74,075 $ 80,952Service cost 1,071 1,063Interest cost 2,112 2,059Actuarial gain (21,845) (5,805)Benefits paid(1) (4,379) (4,194)Plan amendments 8,065 Benefit obligation at December 31 59,099 74,075Change in plan assets: Fair value of plan assets at January 1 41,464 41,311Actual return on plan assets (6,586) 6,308Employer contributions(1) (1,934) (1,961)Benefits paid(1) (4,379) (4,194)Fair value of plan assets at December 31 28,565 41,464Funded status at end of year (included in noncurrent liabilities) $ (30,534) $ (32,611) (1) Contributions and benefits paid are each net of $2.9 million and $3.0 million of plan participant contributions for 2022 and 2021, respectively. Amounts recognized in accumulated other comprehensive income consist of the following (in thousands of dollars): 2022 2021Net gain $ (20,896) $ (8,020)Prior service cost 7,849 80Subtotal (13,047) (7,940)Less amount recognized in regulatory assets 13,047 7,940Net amount recognized in accumulated other comprehensive income $ $ The net periodic postretirement benefit cost was as follows (in thousands of dollars): 2022 2021 Service cost $ 1,071 $ 1,063 Interest cost 2,112 2,059 Expected return on plan assets (2,351) (2,395) Immediate recognition of loss from temporary deviation(1) 4,736 Amortization of net loss (31)
Amortization of prior service cost 295 47
Net periodic postretirement benefit cost $ 1,096 $ 5,510

(1) In 2021, a loss associated with a temporary deviation from the cost-sharing provisions of the substantive plan was recognized on the statements of income.

The following table shows the components of other comprehensive income for the plan (in thousands of dollars):
2022 2021
Actuarial gain (loss) during the year $ 12,908 $ 9,718
Prior service cost arising during the year (8,065)
Reclassification adjustments for:
Amortization of net loss (31)
Immediate recognition of loss from temporary deviation(1) 4,736
Reclassification adjustments for amortization of prior service cost 295 47
Adjustment for deferred tax effects (1,315) (2,514)
Adjustment due to the effects of regulation (3,792) (11,987)
Other comprehensive income related to postretirement benefit plans $ $

(1) In 2021, a loss associated with a temporary deviation from the cost-sharing provisions of the substantive plan was recognized on the statements of income.

The following table summarizes the expected future benefit payments of the postretirement benefit plan (in thousands of dollars):
2023 2024 2025 2026 2027 2028-2032
Expected benefit payments $ 4,736 $ 4,864 $ 4,959 $ 4,860 $ 4,693 $ 21,912

Plan Assumptions

The following table sets forth the weighted-average assumptions used at the end of each year to determine benefit obligations for all Idaho Power-sponsored pension and
postretirement benefits plans:
Pension Plan SMSP
Postretirement
Benefits
2022 2021 2022 2021 2022 2021
Discount rate 5.45 % 3.05 % 5.50 % 3.00 % 5.45 % 2.95 %
Rate of compensation increase(1) 4.49 % 4.49 % 4.75 % 4.75 %
Medical trend rate 6.7 % 6.3 %
Dental trend rate 3.5 % 3.5 %
Measurement date 12/31/2022 12/31/2021 12/31/2022 12/31/2021 12/31/2022 12/31/2021

(1) The 2022 rate of compensation increase assumption for the pension plan includes an inflation component of 2.40% plus a 2.09% composite merit increase component that is based on employees' years of
service. Merit salary increases are assumed to be 8.0% for employees in their first year of service and scale down to 0.6% for employees in their fortieth year of service and beyond.

The following table sets forth the weighted-average assumptions used to determine net periodic benefit cost for all Idaho Power-sponsored pension and postretirement benefit plans:
Pension Plan SMSP
Postretirement
Benefits
2022 2021 2022 2021 2022 2021
Discount rate 3.05 % 2.80 % 3.00 % 2.70 % 2.95 % 2.70 %
Expected long-term rate of return
on assets 7.40 % 7.40 % 6.00 % 6.00 %
Rate of compensation increase 4.49 % 4.49 % 4.75 % 4.75 % %
Medical trend rate 5.8 % 6.3 %
Dental trend rate 3.5 % 3.5 %

The assumed health care cost trend rate used to measure the expected cost of health benefits covered by the postretirement plan was 5.8 percent in 2022 and is assumed to increase to
6.7 percent in 2023, 7.1 percent in 2024, decrease to 6.5 percent in 2025, and to gradually decrease to 3.8 percent by 2074. The assumed dental cost trend rate used to measure the
expected cost of dental benefits covered by the plan was 3.5 percent, or equal to the medical trend rate if lower, for all years.

Plan Assets

Pension Asset Allocation Policy: The target allocation and actual allocations at December 31, 2022, for the pension asset portfolio by asset class is set forth below:
Asset Class
Target
Allocation
Actual
Allocation
December 31,
2022
Debt securities 24 % 24 %
Equity securities 59 % 59 %
Real estate 9 % 10 %
Other plan assets 8 % 7 %
Total 100 % 100 %

Assets are rebalanced as necessary to keep the portfolio close to target allocations. The plan's principal investment objective is to maximize total return (defined as the sum of realized
interest and dividend income and realized and unrealized gain or loss in market price) consistent with prudent parameters of risk and the liability profile of the portfolio. Emphasis is
placed on preservation and growth of capital along with adequacy of cash flow sufficient to fund current and future payments to plan participants.

The three major goals in Idaho Power's asset allocation process are to:

The following table shows the components of other comprehensive income for the plan (in thousands of dollars): 2022 2021 Actuarial gain (loss) during the year $ 12,908 $ 9,718 Prior service cost arising during the year (8,065) Reclassification adjustments for: Amortization of net loss (31) Immediate recognition of loss from temporary deviation(1) 4,736 Reclassification adjustments for amortization of prior service cost 295 47 Adjustment for deferred tax effects (1,315) (2,514) Adjustment due to the effects of regulation (3,792) (11,987) Other comprehensive income related to postretirement benefit plans $ $ (1) In 2021, a loss associated with a temporary deviation from the cost-sharing provisions of the substantive plan was recognized on the statements of income. The following table summarizes the expected future benefit payments of the postretirement benefit plan (in thousands of dollars): 2023 2024 2025 2026 2027 2028-2032Expected benefit payments $ 4,736 $ 4,864 $ 4,959 $ 4,860 $ 4,693 $ 21,912 Plan Assumptions The following table sets forth the weighted-average assumptions used at the end of each year to determine benefit obligations for all Idaho Power-sponsored pension andpostretirement benefits plans: Pension Plan SMSP PostretirementBenefits 2022 2021 2022 2021 2022 2021Discount rate 5.45 % 3.05 % 5.50 % 3.00 % 5.45 % 2.95 %Rate of compensation increase(1) 4.49 % 4.49 % 4.75 % 4.75 % Medical trend rate 6.7 % 6.3 %Dental trend rate 3.5 % 3.5 %Measurement date 12/31/2022 12/31/2021 12/31/2022 12/31/2021 12/31/2022 12/31/2021 (1) The 2022 rate of compensation increase assumption for the pension plan includes an inflation component of 2.40% plus a 2.09% composite merit increase component that is based on employees' years ofservice. Merit salary increases are assumed to be 8.0% for employees in their first year of service and scale down to 0.6% for employees in their fortieth year of service and beyond. The following table sets forth the weighted-average assumptions used to determine net periodic benefit cost for all Idaho Power-sponsored pension and postretirement benefit plans: Pension Plan SMSP PostretirementBenefits 2022 2021 2022 2021 2022 2021 Discount rate 3.05 % 2.80 % 3.00 % 2.70 % 2.95 % 2.70 % Expected long-term rate of returnon assets 7.40 % 7.40 % 6.00 % 6.00 % Rate of compensation increase 4.49 % 4.49 % 4.75 % 4.75 % % Medical trend rate 5.8 % 6.3 % Dental trend rate 3.5 % 3.5 % The assumed health care cost trend rate used to measure the expected cost of health benefits covered by the postretirement plan was 5.8 percent in 2022 and is assumed to increase to6.7 percent in 2023, 7.1 percent in 2024, decrease to 6.5 percent in 2025, and to gradually decrease to 3.8 percent by 2074. The assumed dental cost trend rate used to measure theexpected cost of dental benefits covered by the plan was 3.5 percent, or equal to the medical trend rate if lower, for all years. Plan Assets Pension Asset Allocation Policy: The target allocation and actual allocations at December 31, 2022, for the pension asset portfolio by asset class is set forth below:Asset Class TargetAllocation ActualAllocationDecember 31,2022Debt securities 24 % 24 %Equity securities 59 % 59 %Real estate 9 % 10 %Other plan assets 8 % 7 %Total 100 % 100 %

Assets are rebalanced as necessary to keep the portfolio close to target allocations. The plan's principal investment objective is to maximize total return (defined as the sum of realized
interest and dividend income and realized and unrealized gain or loss in market price) consistent with prudent parameters of risk and the liability profile of the portfolio. Emphasis is
placed on preservation and growth of capital along with adequacy of cash flow sufficient to fund current and future payments to plan participants.

The three major goals in Idaho Power's asset allocation process are to:

determine if the investments have the potential to earn the rate of return assumed in the actuarial liability calculations;
match the cash flow needs of the plan. Idaho Power sets bond allocations sufficient to cover approximately five years of benefit payments. Idaho Power then utilizes growth
instruments (equities, real estate, venture capital) to fund the longer-term liabilities of the plan; and
maintain a prudent risk profile consistent with ERISA fiduciary standards.

Allowable plan investments include stocks and stock funds, investment-grade bonds and bond funds, real estate funds, private equity funds, and cash and cash equivalents. With the
exception of real estate holdings and private equity, investments must be readily marketable so that an entire holding can be disposed of quickly with only a minor effect upon market
price.

Rate-of-return projections for plan assets are based on historical risk/return relationships among asset classes. The primary measure is the historical risk premium each asset class has
delivered versus the yield on the Moody's Investors Service (Moody's) AA Corporate Bond Index. This historical risk premium is then added to the current yield on the Moody's AA
Corporate Bond Index. Additional analysis is performed to measure the expected range of returns, as well as worst-case and best-case scenarios. Based on the current interest rate
environment, current rate-of-return expectations are lower than the nominal returns generated over the past 30 years when interest rates were generally higher.

Idaho Power's asset modeling process also utilizes historical market returns to measure the portfolio's exposure to a "worst-case" market scenario, to determine how much performance
could vary from the expected "average" performance over various time periods. This "worst-case" modeling, in addition to cash flow matching and diversification by asset class and
investment style, provides the basis for managing the risk associated with investing portfolio assets.

Fair Value of Plan Assets: Idaho Power classifies its pension plan and postretirement benefit plan investments using the three-level fair value hierarchy described in Note 15 - "Fair
Value Measurements." The following table presents the fair value of the plans' investments by asset category (in thousands of dollars).
Level 1 Level 2 Level 3 Total
Assets at December 31, 2022
Cash and cash equivalents $ 11,679 $ $ $ 11,679
Intermediate bonds 33,305 166,530 199,835
Equity Securities: Large-Cap 85,617 85,617
Equity Securities: Mid-Cap 90,049 90,049
Equity Securities: Small-Cap 65,505 65,505
Equity Securities: Micro-Cap 33,438 33,438
Equity Securities: Global and International 52,876 52,876
Equity Securities: Emerging Markets 6,964 6,964
Plan assets measured at NAV (not subject to hierarchy disclosure)
Commingled Fund: Equity Securities: Global and International 117,631
Commingled Fund: Equity Securities: Emerging Markets 42,119
Real estate 83,676
Private market investments 50,339
Total $ 379,433 $ 166,530 $ $ 839,728
Postretirement plan assets(1) $ 2,009 $ 26,556 $ $ 28,565

Level 1 Level 2 Level 3 Total
Assets at December 31, 2021
Cash and cash equivalents $ 24,636 $ $ $ 24,636
Intermediate bonds 39,133 187,048 226,181
Equity Securities: Large-Cap 104,318 104,318
Equity Securities: Mid-Cap 113,621 113,621
Equity Securities: Small-Cap 85,244 85,244
Equity Securities: Micro-Cap 42,915 42,915
Equity Securities: Global and International 67,625 67,625
Equity Securities: Emerging Markets 7,393 7,393
Plan assets measured at NAV (not subject to hierarchy disclosure)
Commingled Fund: Equity Securities: Global and International 134,752
Commingled Fund: Equity Securities: Emerging Markets 47,332
Real estate 73,958
Private market investments 56,489
Total $ 484,885 $ 187,048 $ $ 984,464
Postretirement plan assets(1) $ 2,391 $ 39,073 $ $ 41,464

(1) The postretirement benefits assets are primarily life insurance contracts.

For the years ended December 31, 2022 and 2021, there were no material transfers into or out of Levels 1, 2, or 3.

Fair Value Measurement of Level 2 Plan assets and Plan assets measured at net asset value(NAV):

Level 2 Bonds: These investments represent United States government, agency bonds, and corporate bonds. The United States 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.

determine if the investments have the potential to earn the rate of return assumed in the actuarial liability calculations; match the cash flow needs of the plan. Idaho Power sets bond allocations sufficient to cover approximately five years of benefit payments. Idaho Power then utilizes growthinstruments (equities, real estate, venture capital) to fund the longer-term liabilities of the plan; and maintain a prudent risk profile consistent with ERISA fiduciary standards. Allowable plan investments include stocks and stock funds, investment-grade bonds and bond funds, real estate funds, private equity funds, and cash and cash equivalents. With theexception 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 marketprice. Rate-of-return projections for plan assets are based on historical risk/return relationships among asset classes. The primary measure is the historical risk premium each asset class hasdelivered versus the yield on the Moody's Investors Service (Moody's) AA Corporate Bond Index. This historical risk premium is then added to the current yield on the Moody's AACorporate Bond Index. Additional analysis is performed to measure the expected range of returns, as well as worst-case and best-case scenarios. Based on the current interest rateenvironment, current rate-of-return expectations are lower than the nominal returns generated over the past 30 years when interest rates were generally 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 performancecould 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 andinvestment style, provides the basis for managing the risk associated with investing portfolio assets. Fair Value of Plan Assets: Idaho Power classifies its pension plan and postretirement benefit plan investments using the three-level fair value hierarchy described in Note 15 - "FairValue Measurements." The following table presents the fair value of the plans' investments by asset category (in thousands of dollars). Level 1 Level 2 Level 3 TotalAssets at December 31, 2022 Cash and cash equivalents $ 11,679 $ $ $ 11,679Intermediate bonds 33,305 166,530 199,835Equity Securities: Large-Cap 85,617 85,617Equity Securities: Mid-Cap 90,049 90,049Equity Securities: Small-Cap 65,505 65,505Equity Securities: Micro-Cap 33,438 33,438Equity Securities: Global and International 52,876 52,876Equity Securities: Emerging Markets 6,964 6,964Plan assets measured at NAV (not subject to hierarchy disclosure) Commingled Fund: Equity Securities: Global and International 117,631Commingled Fund: Equity Securities: Emerging Markets 42,119Real estate 83,676Private market investments 50,339Total $ 379,433 $ 166,530 $ $ 839,728Postretirement plan assets(1) $ 2,009 $ 26,556 $ $ 28,565 Level 1 Level 2 Level 3 TotalAssets at December 31, 2021 Cash and cash equivalents $ 24,636 $ $ $ 24,636Intermediate bonds 39,133 187,048 226,181Equity Securities: Large-Cap 104,318 104,318Equity Securities: Mid-Cap 113,621 113,621Equity Securities: Small-Cap 85,244 85,244Equity Securities: Micro-Cap 42,915 42,915Equity Securities: Global and International 67,625 67,625Equity Securities: Emerging Markets 7,393 7,393Plan assets measured at NAV (not subject to hierarchy disclosure) Commingled Fund: Equity Securities: Global and International 134,752Commingled Fund: Equity Securities: Emerging Markets 47,332Real estate 73,958Private market investments 56,489Total $ 484,885 $ 187,048 $ $ 984,464Postretirement plan assets(1) $ 2,391 $ 39,073 $ $ 41,464 (1) The postretirement benefits assets are primarily life insurance contracts.
For the years ended December 31, 2022 and 2021, there were no material transfers into or out of Levels 1, 2, or 3.

Fair Value Measurement of Level 2 Plan assets and Plan assets measured at net asset value(NAV):

Level 2 Bonds: These investments represent United States government, agency bonds, and corporate bonds. The United States 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 Postretirement Asset: This asset represents an investment in a life insurance contract and is recorded at fair value, which is the cash surrender value, less any unpaid expenses.
The cash surrender value of this insurance contract is contractually equal to the insurance contract's proportionate share of the market value of an associated investment account held
by the insurer. The investments held by the insurer's investment account are all instruments traded on exchanges with readily determinable market prices.

Commingled Funds: These funds, made up of global, international and emerging markets equity securities are 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 funds have redemption limitations that permit monthly
redemption following notice requirements of 5 to 7 days.

Real Estate: Real estate holdings represent investments in open-end and closed-end commingled real estate funds. As the property interests held in these real estate funds are not
frequently traded, establishing the market value of the property interests held by the fund, and the resulting unit value of fund shareholders, is based on unobservable inputs including
property appraisals by the fund companies, property appraisals by independent appraisal firms, analysis of the replacement cost of the property, discounted cash flows generated by
property rents and changes in property values, and comparisons with sale prices of similar properties in similar markets. These real estate funds also furnish annual audited financial
statements that are also used to further validate the information provided. Redemptions on the open-end funds are generally available on a quarterly basis, with 10 to 35 days written
notice, depending on the individual fund. If the fund has sufficient liquidity, the redemption will be processed at the fund NAV or the fund's estimate of fair value at the end of the
quarter. If the fund does not have sufficient liquidity to honor the full redemption, the remainder will be set for redemption the following quarter on a pro-rata basis with other
redemption requests. This same process will repeat until the redemption request has been completed. To protect other fund holders, real estate funds have no duty to liquidate or
encumber funds to meet redemption requests. The closed-end funds are formed for a stated life of 7 to 10 years. The fund can be further extended with the approval of the limited
partners. There are generally no redemption rights associated with these funds. The limited partner must hold the fund for the life of the fund or find a third-party buyer.

Private Market Investments: Private market investments represent two categories: fund of hedge funds and venture capital funds. These funds are valued by the fund companies based
on the estimated fair values of the 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 full redemption, a reserve amount of 5% to 10% of the redemption amount
may be held in reserve until the audited financial statements of the fund are published. This allows the fund to adjust the redemption so that other fund holders are not adversely
impacted. Venture capital fund investments are valued by the fund companies based on estimated fair value of the underlying fund holdings divided by the fund shares outstanding.
Some venture capital investments have progressed to the point that they have readily available exchange-based market valuations. Early stage venture investments are valued based
on unobservable inputs including cost, operating results, discounted cash flows, the price of recent funding events, or pending offers from other viable entities. These private market
investments furnish annual audited financial statements that are also used to further validate the information provided. 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 one-year periods. The fund can be further extended with the approval of the limited partners. There are generally no redemption
rights associated with these funds. The limited partner must hold the fund for the life of the fund or find a third-party buyer.

Employee Savings Plan

Idaho Power has a defined contribution plan designed to comply with Section 401(k) of the Internal Revenue Code and that covers substantially all employees. Idaho Power matches
specified percentages of employee contributions to the plan. Matching annual contributions were approximately $8.8 million and $8.2 million in 2022 and 2021, respectively.

Post-employment Benefits

Idaho Power provides certain benefits to former or inactive employees, their beneficiaries, and covered dependents after employment but before retirement, in addition to the health
care benefits required under the Consolidated Omnibus Budget Reconciliation Act. These benefits include salary continuation, health care and life insurance for those employees
found to be disabled under Idaho Power's disability plans, and health care for surviving spouses and dependents. Idaho Power accrues a liability for such benefits. The post-
employment benefits included in other deferred credits on Idaho Power's balance sheets at both December 31, 2022 and 2021, were approximately $2 million.

11. PROPERTY, PLANT AND EQUIPMENT AND JOINTLY-OWNED PROJECTS

The following table presents the major classifications of Idaho Power's utility plant in service, annual depreciation provisions as a percent of average depreciable balance, and
accumulated provision for depreciation for the years ended December 31, 2022 and 2021 (in thousands of dollars):
2022 2021
Balance Avg Rate Balance Avg Rate
Production $ 2,700,494 2.89 % $ 2,597,285 3.15 %
Transmission 1,346,463 1.91 % 1,309,143 1.89 %
Distribution 2,192,135 2.15 % 2,058,819 2.25 %
General and Other 598,570 5.36 % 548,877 6.17 %
Total in service 6,837,662 2.66 % 6,514,124 2.85 %
Accumulated provision for depreciation (2,645,516) (2,483,621)
In service - net $ 4,192,146 $ 4,030,503

At December 31, 2022, Idaho Power's construction work in progress balance of $786.2 million included relicensing costs of $423.1 million for the HCC, Idaho Power's largest
hydropower complex. In 2022 and 2021, Idaho Power had IPUC authorization to include in its Idaho jurisdiction rates $6.5 million annually ($8.8 million when grossed-up for the
effect of income taxes) of AFUDC relating to the HCC relicensing project. Collecting these amounts will reduce the amount collected in the future once the HCC relicensing costs are
approved for recovery in base rates. At December 31, 2022, Idaho Power's provision for rate refund for collection of AFUDC relating to the HCC was $207.5 million.

Idaho Power's ownership interest in two jointly-owned generating facilities is included in the table above. Under the joint operating agreements for these facilities, each participating
utility is responsible for financing its share of construction, operating, and leasing costs. Idaho Power's proportionate share of operating expenses for each facility is included in the
Statements of Income. These jointly-owned facilities, including balance sheet amounts and the extent of Idaho Power's participation, were as follows at December 31, 2022 (in
thousands of dollars):
Name of Plant Location
Utility
Plant in
Service
Construction
Work in
Progress
Accumulated
Provision for
Depreciation Ownership % MW(1)(2)
Jim Bridger units 1-4 Rock Springs, WY $ 775,778 $ 19,258 $ 485,289 33 775
North Valmy unit 2(2) Winnemucca, NV 259,099 1,233 210,467 50 145

(1) Idaho Power's share of nameplate capacity.
(2) Pursuant to an agreement with NV Energy, Idaho Power's participation in coal-fired operations of North Valmy ended in December 2019 at unit 1 and is planned to end no later than the end of 2025 at unit 2.

IERCo, Idaho Power's wholly-owned subsidiary, is a joint venturer in BCC. Idaho Power's coal purchases from the joint venture were $60.4 million in 2022 and $59.7 million in 2021.

Idaho Power has contracts to purchase the energy from four PURPA qualifying facilities that are 50 percent owned by Ida-West. Idaho Power's power purchases from these facilities
Level 2 Postretirement Asset: This asset represents an investment in a life insurance contract and is recorded at fair value, which is the cash surrender value, less any unpaid expenses.The cash surrender value of this insurance contract is contractually equal to the insurance contract's proportionate share of the market value of an associated investment account heldby the insurer. The investments held by the insurer's investment account are all instruments traded on exchanges with readily determinable market prices. Commingled Funds: These funds, made up of global, international and emerging markets equity securities are measured at NAV, are not publicly traded, and therefore no publiclyquoted 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 valuesof 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 thecommingled funds divided by the number of fund shares outstanding for the respective fund. The investments in commingled funds have redemption limitations that permit monthlyredemption following notice requirements of 5 to 7 days. Real Estate: Real estate holdings represent investments in open-end and closed-end commingled real estate funds. As the property interests held in these real estate funds are notfrequently 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 includingproperty appraisals by the fund companies, property appraisals by independent appraisal firms, analysis of the replacement cost of the property, discounted cash flows generated byproperty rents and changes in property values, and comparisons with sale prices of similar properties in similar markets. These real estate funds also furnish annual audited financialstatements that are also used to further validate the information provided. Redemptions on the open-end funds are generally available on a quarterly basis, with 10 to 35 days writtennotice, depending on the individual fund. If the fund has sufficient liquidity, the redemption will be processed at the fund NAV or the fund's estimate of fair value at the end of thequarter. 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 otherredemption 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 orencumber funds to meet redemption requests. The closed-end funds are formed for a stated life of 7 to 10 years. The fund can be further extended with the approval of the limitedpartners. 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. Private Market Investments: Private market investments represent two categories: fund of hedge funds and venture capital funds. These funds are valued by the fund companies basedon 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 fundstrategies 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. Redemptionswill be processed at the quarterly NAV or fair value within 60 days following quarter end. In the event of a full redemption, a reserve amount of 5% to 10% of the redemption amountmay 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 adverselyimpacted. Venture capital fund investments are valued by the fund companies based on estimated fair value of the underlying fund holdings divided by the fund shares outstanding.Some venture capital investments have progressed to the point that they have readily available exchange-based market valuations. Early stage venture investments are valued basedon unobservable inputs including cost, operating results, discounted cash flows, the price of recent funding events, or pending offers from other viable entities. These private marketinvestments furnish annual audited financial statements that are also used to further validate the information provided. These funds are formed for a stated life of 10 to 15 years. Thegeneral partner can extend the fund life for 2 or 3 one-year periods. The fund can be further extended with the approval of the limited partners. There are generally no redemptionrights 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 Plan Idaho Power has a defined contribution plan designed to comply with Section 401(k) of the Internal Revenue Code and that covers substantially all employees. Idaho Power matchesspecified percentages of employee contributions to the plan. Matching annual contributions were approximately $8.8 million and $8.2 million in 2022 and 2021, respectively. Post-employment Benefits Idaho Power provides certain benefits to former or inactive employees, their beneficiaries, and covered dependents after employment but before retirement, in addition to the healthcare benefits required under the Consolidated Omnibus Budget Reconciliation Act. These benefits include salary continuation, health care and life insurance for those employeesfound 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 balance sheets at both December 31, 2022 and 2021, were approximately $2 million. 11. PROPERTY, PLANT AND EQUIPMENT AND JOINTLY-OWNED PROJECTS The following table presents the major classifications of Idaho Power's utility plant in service, annual depreciation provisions as a percent of average depreciable balance, andaccumulated provision for depreciation for the years ended December 31, 2022 and 2021 (in thousands of dollars): 2022 2021 Balance Avg Rate Balance Avg RateProduction $ 2,700,494 2.89 % $ 2,597,285 3.15 %Transmission 1,346,463 1.91 % 1,309,143 1.89 %Distribution 2,192,135 2.15 % 2,058,819 2.25 %General and Other 598,570 5.36 % 548,877 6.17 %Total in service 6,837,662 2.66 % 6,514,124 2.85 %Accumulated provision for depreciation (2,645,516) (2,483,621) In service - net $ 4,192,146 $ 4,030,503 At December 31, 2022, Idaho Power's construction work in progress balance of $786.2 million included relicensing costs of $423.1 million for the HCC, Idaho Power's largesthydropower complex. In 2022 and 2021, Idaho Power had IPUC authorization to include in its Idaho jurisdiction rates $6.5 million annually ($8.8 million when grossed-up for theeffect of income taxes) of AFUDC relating to the HCC relicensing project. Collecting these amounts will reduce the amount collected in the future once the HCC relicensing costs areapproved for recovery in base rates. At December 31, 2022, Idaho Power's provision for rate refund for collection of AFUDC relating to the HCC was $207.5 million. Idaho Power's ownership interest in two jointly-owned generating facilities is included in the table above. Under the joint operating agreements for these facilities, each participatingutility 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 theStatements of Income. These jointly-owned facilities, including balance sheet amounts and the extent of Idaho Power's participation, were as follows at December 31, 2022 (inthousands of dollars):Name of Plant Location UtilityPlant inService ConstructionWork inProgress AccumulatedProvision forDepreciation Ownership % MW(1)(2)Jim Bridger units 1-4 Rock Springs, WY $ 775,778 $ 19,258 $ 485,289 33 775North Valmy unit 2(2) Winnemucca, NV 259,099 1,233 210,467 50 145

(1) Idaho Power's share of nameplate capacity.
(2) Pursuant to an agreement with NV Energy, Idaho Power's participation in coal-fired operations of North Valmy ended in December 2019 at unit 1 and is planned to end no later than the end of 2025 at unit 2.

IERCo, Idaho Power's wholly-owned subsidiary, is a joint venturer in BCC. Idaho Power's coal purchases from the joint venture were $60.4 million in 2022 and $59.7 million in 2021.

Idaho Power has contracts to purchase the energy from four PURPA qualifying facilities that are 50 percent owned by Ida-West. Idaho Power's power purchases from these facilitiesIdaho Power has contracts to purchase the energy from four PURPA qualifying facilities that are 50 percent owned by Ida-West. Idaho Power's power purchases from these facilities
were $7.9 million in 2022 and $8.2 million in 2021.

12. ASSET RETIREMENT OBLIGATIONS (ARO)

The guidance relating to accounting for AROs requires that legal obligations associated with the retirement of property, plant, and equipment be recognized as a liability at fair value
when incurred and when a reasonable estimate of the fair value of the liability can be made. Under the guidance, when a liability is initially recorded, the entity increases the carrying
amount of the related long-lived asset to reflect the future retirement cost. Over time, the liability is accreted to its estimated settlement value and paid, and the capitalized cost is
depreciated over the useful life of the related asset. If, at the end of the asset's life, the recorded liability differs from the actual obligations paid, a gain or loss would be recognized. As
a rate-regulated entity, Idaho Power defers accretion, depreciation, and gains or losses as regulatory assets, as approved by the IPUC, until such asset retirement obligation costs are
included in customer rates for collection. The regulatory assets recorded under this order do not earn a return on investment.

Idaho Power's recorded AROs relate to the reclamation and removal costs at its jointly-owned coal-fired generation facilities.

Idaho Power also has additional AROs associated with its transmission system and generation facilities; however, due to the indeterminate removal date, the fair value of the
associated liabilities currently cannot be estimated and no amounts are recognized in the financial statements.

Idaho Power also collects removal costs in rates for certain assets that do not have associated AROs. Idaho Power is required to classify these removal costs as regulatory liabilities, see
Note 3 - "Regulatory Matters" for the removal costs recorded as regulatory liabilities on Idaho Power's balance sheets as of December 31, 2022 and 2021.

The following table presents the changes in the carrying amount of AROs (in thousands of dollars):
2022 2021
Balance at beginning of year $ 36,698 $ 27,691
Accretion expense 1,106 1,021
Revisions in estimated cash flows 1,412 9,415
Liability settled (1,659) (1,429)
Balance at end of year $ 37,557 $ 36,698

13. INVESTMENTS

The table below summarizes Idaho Power's investments as of December 31 (in thousands of dollars):
2022 2021
Idaho Power investments:
IERCO $ 14,692 $ 27,909
Exchange traded short-term bond funds and cash equivalents 33,687 54,078
Held-to-Maturity securities 30,475
Executive deferred compensation plan investments 442 353
Total Idaho Power investments 79,296 82,340
Investments in Equity Securities

Investments in equity securities are reported at fair value. Any unrealized gains or losses on equity securities are included in income. Unrealized gains and losses on equity securities
were immaterial at December 31, 2022 and 2021. The following table summarizes sales of equity securities (in thousands of dollars):
2022 2021
Proceeds from sales $ 63,857 $ 11,328
Gross realized gains from sales

Held-to-Maturity Securities

Idaho Power has a rabbi trust designated to provide funding for obligations related to the SMSP. During 2022, the rabbi trust purchased $31.2 million of held-to-maturity investments
in corporate fixed-income and asset-backed debt securities. Substantially all of these debt securities mature between 2027 and 2037. Held-to-maturity investments are carried at
amortized cost, reflecting Idaho Power's ability and intent to hold the securities to maturity. Held-to-maturity investments are adjusted for the amortization or accretion of premiums or
discounts, which are amortized or accreted over the life of the related held-to-maturity security. Such amortization and accretion are included in the "Other income, net" line in the
statements of income. Due to increases in market interest rates in 2022, all held-to-maturity securities were in a gross unrealized holding loss position totaling $5.0 million at
December 31, 2022. Based on ongoing credit evaluations of these holdings, Idaho Power does not expect payment defaults or delinquencies and has not recorded an allowance for
credit losses for these securities as of December 31, 2022.

14. DERIVATIVE FINANCIAL INSTRUMENTS

Commodity Price Risk

Idaho Power is exposed to market risk relating to electricity, natural gas, and other fuel commodity prices, all of which are heavily influenced by supply and demand. Market risk may
be influenced by market participants' nonperformance of their contractual obligations and commitments, which affects the supply of or demand for the commodity. Idaho Power uses
derivative instruments, such as physical and financial forward contracts, for both electricity and fuel to manage the risks relating to these commodity price exposures. The primary
objectives of Idaho Power's energy purchase and sale activity are to meet the demand of retail electric customers, maintain appropriate physical reserves to ensure reliability, and make
economic use of temporary surpluses that may develop.

All of Idaho Power's derivative instruments have been entered into for the purpose of securing energy resources for future periods or economically hedging forecasted purchases and
sales, though none of these instruments have been designated as cash flow hedges. Idaho Power offsets fair value amounts recognized on its balance sheet and applies collateral related
to derivative instruments executed with the same counterparty under the same master netting agreement. Idaho Power does not offset a counterparty's current derivative contracts with
the counterparty's long-term derivative contracts, although Idaho Power's master netting arrangements would allow current and long-term positions to be offset in the event of default.
Also, in the event of default, Idaho Power's master netting arrangements would allow for the offsetting of all transactions executed under the master netting arrangement. These types
of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, receivables and payables arising from settled positions, and other forms of non-
cash collateral (such as letters of credit). These types of transactions are excluded from the offsetting presented in the derivative fair value and offsetting table that follows.

The table below presents the gains and losses on derivatives not designated as hedging instruments for the years ended December 31, 2022 and 2021 (in thousands of dollars):
Gain/(Loss) on Derivatives
Idaho Power has contracts to purchase the energy from four PURPA qualifying facilities that are 50 percent owned by Ida-West. Idaho Power's power purchases from these facilitieswere $7.9 million in 2022 and $8.2 million in 2021. 12. ASSET RETIREMENT OBLIGATIONS (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 valuewhen incurred and when a reasonable estimate of the fair value of the liability can be made. Under the guidance, when a liability is initially recorded, the entity increases the carryingamount of the related long-lived asset to reflect the future retirement cost. Over time, the liability is accreted to its estimated settlement value and paid, and the capitalized cost isdepreciated over the useful life of the related asset. If, at the end of the asset's life, the recorded liability differs from the actual obligations paid, a gain or loss would be recognized. Asa rate-regulated entity, Idaho Power defers accretion, depreciation, and gains or losses as regulatory assets, as approved by the IPUC, until such asset retirement obligation costs areincluded in customer rates for collection. The regulatory assets recorded under this order do not earn a return on investment. Idaho Power's recorded AROs relate to the reclamation and removal costs at its jointly-owned coal-fired generation facilities. Idaho Power also has additional AROs associated with its transmission system and generation facilities; however, due to the indeterminate removal date, the fair value of theassociated liabilities currently cannot be estimated and no amounts are recognized in the financial statements. Idaho Power also collects removal costs in rates for certain assets that do not have associated AROs. Idaho Power is required to classify these removal costs as regulatory liabilities, seeNote 3 - "Regulatory Matters" for the removal costs recorded as regulatory liabilities on Idaho Power's balance sheets as of December 31, 2022 and 2021. The following table presents the changes in the carrying amount of AROs (in thousands of dollars): 2022 2021Balance at beginning of year $ 36,698 $ 27,691Accretion expense 1,106 1,021Revisions in estimated cash flows 1,412 9,415Liability settled (1,659) (1,429)Balance at end of year $ 37,557 $ 36,698 13. INVESTMENTS The table below summarizes Idaho Power's investments as of December 31 (in thousands of dollars): 2022 2021Idaho Power investments: IERCO $ 14,692 $ 27,909Exchange traded short-term bond funds and cash equivalents 33,687 54,078Held-to-Maturity securities 30,475 Executive deferred compensation plan investments 442 353Total Idaho Power investments 79,296 82,340Investments in Equity Securities Investments in equity securities are reported at fair value. Any unrealized gains or losses on equity securities are included in income. Unrealized gains and losses on equity securitieswere immaterial at December 31, 2022 and 2021. The following table summarizes sales of equity securities (in thousands of dollars): 2022 2021 Proceeds from sales $ 63,857 $ 11,328 Gross realized gains from sales Held-to-Maturity Securities Idaho Power has a rabbi trust designated to provide funding for obligations related to the SMSP. During 2022, the rabbi trust purchased $31.2 million of held-to-maturity investmentsin corporate fixed-income and asset-backed debt securities. Substantially all of these debt securities mature between 2027 and 2037. Held-to-maturity investments are carried atamortized cost, reflecting Idaho Power's ability and intent to hold the securities to maturity. Held-to-maturity investments are adjusted for the amortization or accretion of premiums ordiscounts, which are amortized or accreted over the life of the related held-to-maturity security. Such amortization and accretion are included in the "Other income, net" line in thestatements of income. Due to increases in market interest rates in 2022, all held-to-maturity securities were in a gross unrealized holding loss position totaling $5.0 million atDecember 31, 2022. Based on ongoing credit evaluations of these holdings, Idaho Power does not expect payment defaults or delinquencies and has not recorded an allowance forcredit losses for these securities as of December 31, 2022. 14. DERIVATIVE FINANCIAL INSTRUMENTS Commodity Price Risk Idaho Power is exposed to market risk relating to electricity, natural gas, and other fuel commodity prices, all of which are heavily influenced by supply and demand. Market risk maybe influenced by market participants' nonperformance of their contractual obligations and commitments, which affects the supply of or demand for the commodity. Idaho Power usesderivative instruments, such as physical and financial forward contracts, for both electricity and fuel to manage the risks relating to these commodity price exposures. The primaryobjectives of Idaho Power's energy purchase and sale activity are to meet the demand of retail electric customers, maintain appropriate physical reserves to ensure reliability, and makeeconomic use of temporary surpluses that may develop. All of Idaho Power's derivative instruments have been entered into for the purpose of securing energy resources for future periods or economically hedging forecasted purchases andsales, 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 relatedto derivative instruments executed with the same counterparty under the same master netting agreement. Idaho Power does not offset a counterparty's current derivative contracts with
the counterparty's long-term derivative contracts, although Idaho Power's master netting arrangements would allow current and long-term positions to be offset in the event of default.
Also, in the event of default, Idaho Power's master netting arrangements would allow for the offsetting of all transactions executed under the master netting arrangement. These types
of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, receivables and payables arising from settled positions, and other forms of non-
cash collateral (such as letters of credit). These types of transactions are excluded from the offsetting presented in the derivative fair value and offsetting table that follows.

The table below presents the gains and losses on derivatives not designated as hedging instruments for the years ended December 31, 2022 and 2021 (in thousands of dollars):
Gain/(Loss) on Derivatives Location of Realized Gain/(Loss) on
Derivatives Recognized in Income

Gain/(Loss) on Derivatives
Recognized in Income(1)
2022 2021
Financial swaps Operating revenues $ (6,249) $ 1,046
Financial swaps Purchased power 2,373 1,959
Financial swaps Fuel expense 68,489 12,180
Forward contracts Operating revenues 1,090 1,966
Forward contracts Purchased power (2,994) (1,099)
Forward contracts Fuel expense (136) (194)

(1) Excludes unrealized gains or losses on derivatives, which are recorded on the balance sheet as regulatory assets or regulatory liabilities.

Settlement gains and losses on electricity swap contracts are recorded on the income statement in operating revenues 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 O&M expense. See Note 15 - "Fair Value Measurements" for additional information concerning the determination of fair value for Idaho Power's assets and
liabilities from price risk management activities.

Credit Risk

At December 31, 2022, Idaho Power did not have material credit risk exposure from financial instruments, including derivatives. Idaho Power monitors credit risk exposure through
reviews of counterparty credit quality, corporate-wide counterparty credit exposure, and corporate-wide counterparty concentration levels. Idaho Power manages these risks by
establishing credit and concentration limits on transactions with counterparties and requiring contractual guarantees, cash deposits, or letters of credit from counterparties or their
affiliates, as deemed necessary. Idaho Power's physical power contracts are commonly under WSPP, Inc. agreements, physical gas contracts are usually under North American Energy
Standards Board contracts, and financial transactions are usually under International Swaps and Derivatives Association, Inc. contracts. These contracts typically contain adequate
assurance clauses requiring collateralization if a counterparty has debt that is downgraded below investment grade by at least one rating agency.

Credit-Contingent Features

Certain of Idaho Power's derivative instruments contain provisions that require Idaho Power's unsecured debt to maintain an investment grade credit rating from Moody's 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 31, 2022, was $15.7 million. Idaho Power did not post
any cash collateral related to this amount. If the credit-risk-related contingent features underlying these agreements were triggered on December 31, 2022, Idaho Power would have
been required to pay or post collateral to its counterparties up to an additional $66.1 million to cover open liability positions as well as completed transactions that have not yet been
paid.

Derivative Instrument Summary

The table below presents the fair values and locations of derivative instruments not designated as hedging instruments recorded on the balance sheets and reconciles the gross
amounts of derivatives recognized as assets and as liabilities to the net amounts presented in the balance sheets at December 31, 2022 and 2021 (in thousands of dollars):
Asset Derivatives Liability Derivatives

Balance Sheet
Location
Gross
Fair
Value
Amounts
Offset
Net
Assets
Gross
Fair
Value
Amounts
Offset
Net
Liabilities
December 31,
2022
Current:
Financial swaps Other current assets $ 72,548 $ (32,609)(1)$ 39,939 $ 13,982 $ (13,982) $
Financial swaps
Other current
liabilities 132 (132) 1,577 (132) 1,445
Forward
contracts Other current assets 400 400
Forward
contracts
Other current
liabilities 2,071 2,071
Long-term:
Financial swaps Other assets 622 (43) 579 43 (43)
Financial swaps Other liabilities 644 (644) 2,136 (644) 1,492
Forward
contracts Other liabilities 1,780 1,780
Total $ 74,346 $ (33,428) $ 40,918 $ 21,589 $ (14,801) $ 6,788

December 31,
2021
Current:
Financial swaps Other current assets $ 10,599 $ (4,893)(2)$ 5,706 $ 2,910 $ (2,910) $
Financial swaps
Other current
liabilities 20
20
Forward
contracts Other current assets 6 (4) 2
4
(4)
Forward
contracts
Other current
liabilities

1,970 1,970
Long-term:
Financial swaps Other assets 899 (9) 890 9 (9)
Financial swaps Other liabilities 14 14
Location of Realized Gain/(Loss) onDerivatives Recognized in Income Gain/(Loss) on DerivativesRecognized in Income(1) 2022 2021 Financial swaps Operating revenues $ (6,249) $ 1,046 Financial swaps Purchased power 2,373 1,959 Financial swaps Fuel expense 68,489 12,180 Forward contracts Operating revenues 1,090 1,966 Forward contracts Purchased power (2,994) (1,099) Forward contracts Fuel expense (136) (194) (1) Excludes unrealized gains or losses on derivatives, which are recorded on the balance sheet as regulatory assets or regulatory liabilities. Settlement gains and losses on electricity swap contracts are recorded on the income statement in operating revenues or purchased power depending on the forecasted position beingeconomically 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 derivativesare recorded in other O&M expense. See Note 15 - "Fair Value Measurements" for additional information concerning the determination of fair value for Idaho Power's assets andliabilities from price risk management activities. Credit Risk At December 31, 2022, Idaho Power did not have material credit risk exposure from financial instruments, including derivatives. Idaho Power monitors credit risk exposure throughreviews of counterparty credit quality, corporate-wide counterparty credit exposure, and corporate-wide counterparty concentration levels. Idaho Power manages these risks byestablishing credit and concentration limits on transactions with counterparties and requiring contractual guarantees, cash deposits, or letters of credit from counterparties or theiraffiliates, as deemed necessary. Idaho Power's physical power contracts are commonly under WSPP, Inc. agreements, physical gas contracts are usually under North American EnergyStandards Board contracts, and financial transactions are usually under International Swaps and Derivatives Association, Inc. contracts. These contracts typically contain adequateassurance clauses requiring collateralization if a counterparty has debt that is downgraded below investment grade by at least one rating agency. Credit-Contingent Features Certain of Idaho Power's derivative instruments contain provisions that require Idaho Power's unsecured debt to maintain an investment grade credit rating from Moody's 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 derivativeinstruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. The aggregatefair value of all derivative instruments with credit-risk-related contingent features that were in a liability position at December 31, 2022, was $15.7 million. Idaho Power did not postany cash collateral related to this amount. If the credit-risk-related contingent features underlying these agreements were triggered on December 31, 2022, Idaho Power would havebeen required to pay or post collateral to its counterparties up to an additional $66.1 million to cover open liability positions as well as completed transactions that have not yet beenpaid. 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 grossamounts of derivatives recognized as assets and as liabilities to the net amounts presented in the balance sheets at December 31, 2022 and 2021 (in thousands of dollars): Asset Derivatives Liability Derivatives Balance SheetLocation GrossFairValue AmountsOffset NetAssets GrossFairValue AmountsOffset NetLiabilities December 31,2022 Current: Financial swaps Other current assets $ 72,548 $ (32,609)(1)$ 39,939 $ 13,982 $ (13,982) $Financial swaps Other currentliabilities 132 (132) 1,577 (132) 1,445Forwardcontracts Other current assets 400 400 Forwardcontracts Other currentliabilities 2,071 2,071Long-term: Financial swaps Other assets 622 (43) 579 43 (43) Financial swaps Other liabilities 644 (644) 2,136 (644) 1,492Forwardcontracts Other liabilities 1,780 1,780Total $ 74,346 $ (33,428) $ 40,918 $ 21,589 $ (14,801) $ 6,788 December 31,2021 Current: Financial swaps Other current assets $ 10,599 $ (4,893)(2)$ 5,706 $ 2,910 $ (2,910) $Financial swaps Other currentliabilities 20 20Forward
contracts Other current assets 6 (4) 2
4
(4)
Forward
contracts
Other current
liabilities

1,970 1,970
Long-term:
Financial swaps Other assets 899 (9) 890 9 (9)
Financial swaps Other liabilities 14 14Financial swaps Other liabilities 14 14
Forward
contracts Other liabilities 3,743 3,743
Total $ 11,504 $ (4,906) $ 6,598 $ 8,670 $ (2,923) $ 5,747

(1) Current asset derivative amounts offset include $18.6 million of collateral payable at December 31, 2022.
(2) Current asset derivative amounts offset include $2.0 million of collateral payable at December 31, 2021.

The table below presents the volumes of derivative commodity forward contracts and swaps outstanding at December 31, 2022 and 2021 (in thousands of units):
December 31,
Commodity Units 2022 2021
Electricity purchases MWh 898 529
Electricity sales MWh 32 129
Natural gas purchases MMBtu 26,773 11,740
Natural gas sales MMBtu 310

15. FAIR VALUE MEASUREMENTS

Idaho Power has categorized its financial instruments into a three-level fair value hierarchy, based on the priority of the inputs to the valuation technique. The fair value hierarchy
gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). If the inputs used to
measure the financial instruments fall within different levels of the hierarchy, the categorization is based on the lowest level input that is significant to the fair value measurement of
the instrument.

Financial assets and liabilities recorded on the balance sheets are categorized based on the inputs to the valuation techniques as follows:

Level 1: Financial assets and liabilities whose values are based on unadjusted quoted prices for identical assets or liabilities in an active market that Idaho Power has the ability to
access.

Level 2: Financial assets and liabilities whose values are based on the following:
a) quoted prices for similar assets or liabilities in active markets;
b) quoted prices for identical or similar assets or liabilities in non-active markets;
c) pricing models whose inputs are observable for substantially the full term of the asset or liability; and
d) pricing models whose inputs are derived principally from or corroborated by observable market data through correlation or other means for substantially the full term
of the asset or liability.

Idaho Power Level 2 inputs for derivative instruments are based on quoted market prices adjusted for location using corroborated, observable market data.

Level 3: Financial assets and liabilities whose values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair
value measurement. These inputs reflect management's own assumptions about the assumptions a market participant would use in pricing the asset or liability.

Idaho Power's assessment of a particular input's significance to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their
placement within the fair value hierarchy. There were no transfers between levels or material changes in valuation techniques or inputs during the years ended December 31, 2022 and
2021.

The following table presents information about Idaho Power's assets and liabilities measured at fair value on a recurring basis as of December 31, 2022 and 2021 (in thousands of
dollars):
December 31, 2022 December 31, 2021
Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets:
Money market funds and commercial
paper
$ 34,468

$

$
$ 34,468
$ 10,393

$

$
$ 10,393
Derivatives 40,518 400 40,918 6,596 2 6,598
Equity securities 34,129 34,129 54,431 54,431
Liabilities:
Derivatives $ 2,937 $ 3,851 $ $ 6,788 $ 34 $ 5,713 $ $ 5,747

(1) Holding company only. Does not include amounts held by Idaho Power.

Idaho Power's derivatives are contracts entered into as part of its management of loads and resources. Electricity swap derivatives are valued on the Intercontinental Exchange with
quoted prices in an active market. Electricity forward contract derivatives are valued using a blend of two electricity exchanges, adjusted for location basis, as specified in the forward
contract. Natural gas and diesel derivatives are valued using New York Mercantile Exchange (NYMEX) and Intercontinental Exchange (ICE) pricing, adjusted for location basis,
which are also quoted under NYMEX and ICE pricing. Equity securities at Idaho Power consist of employee-directed investments related to an executive deferred compensation plan
and actively traded money market and exchange traded funds related to the SMSP. The investments are measured using quoted prices in active markets and are held in a rabbi trust.

The table below presents the carrying value and estimated fair value of financial instruments that are not reported at fair value, as of December 31, 2022 and 2021, using available
market information and appropriate valuation methodologies (in thousands).
December 31, 2022 December 31, 2021

Carrying
Amount
Estimated Fair
Value
Carrying
Amount
Estimated Fair
Value
(thousands of dollars)
Assets:
Held-to-maturity securities(1) $ 30,475 $ 25,452 $ $
Liabilities:
Financial swaps Other liabilities 14 14Forwardcontracts Other liabilities 3,743 3,743Total $ 11,504 $ (4,906) $ 6,598 $ 8,670 $ (2,923) $ 5,747 (1) Current asset derivative amounts offset include $18.6 million of collateral payable at December 31, 2022.(2) Current asset derivative amounts offset include $2.0 million of collateral payable at December 31, 2021. The table below presents the volumes of derivative commodity forward contracts and swaps outstanding at December 31, 2022 and 2021 (in thousands of units): December 31,Commodity Units 2022 2021Electricity purchases MWh 898 529Electricity sales MWh 32 129Natural gas purchases MMBtu 26,773 11,740Natural gas sales MMBtu 310 15. FAIR VALUE MEASUREMENTS Idaho Power has categorized its financial instruments into a three-level fair value hierarchy, based on the priority of the inputs to the valuation technique. The fair value hierarchygives 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 tomeasure 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 ofthe instrument. Financial assets and liabilities recorded on the balance sheets are categorized based on the inputs to the valuation techniques as follows: Level 1: Financial assets and liabilities whose values are based on unadjusted quoted prices for identical assets or liabilities in an active market that Idaho Power has the ability toaccess. Level 2: Financial assets and liabilities whose values are based on the following:a) quoted prices for similar assets or liabilities in active markets;b) quoted prices for identical or similar assets or liabilities in non-active markets;c) pricing models whose inputs are observable for substantially the full term of the asset or liability; andd) pricing models whose inputs are derived principally from or corroborated by observable market data through correlation or other means for substantially the full termof the asset or liability. Idaho Power Level 2 inputs for derivative instruments are based on quoted market prices adjusted for location using corroborated, observable market data. Level 3: Financial assets and liabilities whose values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fairvalue 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 theirplacement within the fair value hierarchy. There were no transfers between levels or material changes in valuation techniques or inputs during the years ended December 31, 2022 and2021. The following table presents information about Idaho Power's assets and liabilities measured at fair value on a recurring basis as of December 31, 2022 and 2021 (in thousands ofdollars): December 31, 2022 December 31, 2021 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 TotalAssets: Money market funds and commercialpaper $ 34,468 $ $ $ 34,468 $ 10,393 $ $ $ 10,393Derivatives 40,518 400 40,918 6,596 2 6,598Equity securities 34,129 34,129 54,431 54,431Liabilities: Derivatives $ 2,937 $ 3,851 $ $ 6,788 $ 34 $ 5,713 $ $ 5,747 (1) Holding company only. Does not include amounts held by Idaho Power. Idaho Power's derivatives are contracts entered into as part of its management of loads and resources. Electricity swap derivatives are valued on the Intercontinental Exchange withquoted prices in an active market. Electricity forward contract derivatives are valued using a blend of two electricity exchanges, adjusted for location basis, as specified in the forwardcontract. Natural gas and diesel derivatives are valued using New York Mercantile Exchange (NYMEX) and Intercontinental Exchange (ICE) pricing, adjusted for location basis,which are also quoted under NYMEX and ICE pricing. Equity securities at Idaho Power consist of employee-directed investments related to an executive deferred compensation planand actively traded money market and exchange traded funds related to the SMSP. The investments are measured using quoted prices in active markets and are held in a rabbi trust. The table below presents the carrying value and estimated fair value of financial instruments that are not reported at fair value, as of December 31, 2022 and 2021, using availablemarket information and appropriate valuation methodologies (in thousands).
December 31, 2022 December 31, 2021

Carrying
Amount
Estimated Fair
Value
Carrying
Amount
Estimated Fair
Value
(thousands of dollars)
Assets:
Held-to-maturity securities(1) $ 30,475 $ 25,452 $ $
Liabilities: Liabilities:
Long-term debt (including current
portion)(1) 2,194,145 1,953,470 2,000,640 2,381,172

(1) Held-to-maturity securities and long-term debt are categorized as Level 2 of the fair value hierarchy, as defined earlier in this Note 15 - "Fair Value Measurements."

Held-to-maturity securities are held in a rabbi trust and are generally valued using quoted prices, which may be in non-active markets. Long-term debt is not traded on an exchange
and is valued using quoted rates for similar debt in active markets. Carrying values for cash and cash equivalents, deposits, customer and other receivables, notes payable, accounts
payable, interest accrued, and taxes accrued approximate fair value.

16. CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME

Comprehensive income includes net income 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, 2022 and 2021 (in thousands of dollars). Items in parentheses indicate reductions to AOCI.
Year Ended December 31,
2022 2021
Defined benefit pension items
Balance at beginning of period $ (40,040) $ (43,358)
Other comprehensive income before reclassifications, net of tax of
$8,239, $(8), and $(3,488) 23,770 (25)
Amounts reclassified out of AOCI to net income, net of tax of $1,160,
$1,158, and $1,036 3,348 3,343
Net current-period other comprehensive income 27,118 3,318
Balance at end of period $ (12,922) $ (40,040)

The table below presents the effects on net income of amounts reclassified out of components of AOCI and the income statement location of those amounts reclassified during the
years ended December 31, 2022 and 2021 (in thousands of dollars). Items in parentheses indicate increases to net income.
Amount Reclassified from AOCI
Year Ended December 31,
2022 2021
Amortization of defined benefit pension items(1)
Prior service cost $ 279 $ 296
Net loss 4,229 4,205
Total before tax 4,508 4,501
Tax benefit(2) (1,160) (1,158)
Net of tax 3,348 3,343
Total reclassification for the period $ 3,348 $ 3,343

(1) Amortization of these items is included in "Other (income) expense, net" in the income statements of Idaho Power.
(2) The tax benefit is included in "Income tax expense" in the income statements of Idaho Power.

17. RELATED PARTY TRANSACTIONS

IDACORP: Idaho Power performs corporate functions such as financial, legal, and management services for IDACORP and its subsidiaries. Idaho Power charges IDACORP for the costs
of these services based on service agreements and other specifically identified costs. For these services, Idaho Power billed IDACORP $0.9 million in 2022 and $0.8 million in 2021.

At December 31, 2022 and 2021, Idaho Power had a $56.2 million and $2.0 million payable to IDACORP, respectively, which was included in its accounts payable to affiliates
balance on its balance sheets, primarily related to income tax payments.

Ida-West: Ida-West Energy Company (Ida-West) is a wholly-owned subsidiary of IDACORP and is an operator of small hydropower generation projects that satisfy the requirements of
the Public Utility Regulatory Policies Act of 1978. Idaho Power purchases all of the power generated by four of Ida-West's hydropower projects located in Idaho. Idaho Power
purchased $7.9 million in 2022 and $8.2 million in 2021 of power from Ida-West.

39
FERC FORM No. 1 (ED. 12-96)
Page 122-123
Liabilities: Long-term debt (including currentportion)(1) 2,194,145 1,953,470 2,000,640 2,381,172 (1) Held-to-maturity securities and long-term debt are categorized as Level 2 of the fair value hierarchy, as defined earlier in this Note 15 - "Fair Value Measurements." Held-to-maturity securities are held in a rabbi trust and are generally valued using quoted prices, which may be in non-active markets. Long-term debt is not traded on an exchangeand 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, accountspayable, interest accrued, and taxes accrued approximate fair value. 16. CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME Comprehensive income includes net income and amounts related to the SMSP. The table below presents changes in components of accumulated other comprehensive income (AOCI),net of tax, during the years ended December 31, 2022 and 2021 (in thousands of dollars). Items in parentheses indicate reductions to AOCI. Year Ended December 31, 2022 2021 Defined benefit pension items Balance at beginning of period $ (40,040) $ (43,358) Other comprehensive income before reclassifications, net of tax of$8,239, $(8), and $(3,488) 23,770 (25) Amounts reclassified out of AOCI to net income, net of tax of $1,160,$1,158, and $1,036 3,348 3,343 Net current-period other comprehensive income 27,118 3,318 Balance at end of period $ (12,922) $ (40,040) The table below presents the effects on net income of amounts reclassified out of components of AOCI and the income statement location of those amounts reclassified during theyears ended December 31, 2022 and 2021 (in thousands of dollars). Items in parentheses indicate increases to net income. Amount Reclassified from AOCI Year Ended December 31, 2022 2021 Amortization of defined benefit pension items(1) Prior service cost $ 279 $ 296 Net loss 4,229 4,205 Total before tax 4,508 4,501 Tax benefit(2) (1,160) (1,158) Net of tax 3,348 3,343 Total reclassification for the period $ 3,348 $ 3,343 (1) Amortization of these items is included in "Other (income) expense, net" in the income statements of Idaho Power.(2) The tax benefit is included in "Income tax expense" in the income statements of Idaho Power. 17. RELATED PARTY TRANSACTIONS IDACORP: Idaho Power performs corporate functions such as financial, legal, and management services for IDACORP and its subsidiaries. Idaho Power charges IDACORP for the costsof these services based on service agreements and other specifically identified costs. For these services, Idaho Power billed IDACORP $0.9 million in 2022 and $0.8 million in 2021. At December 31, 2022 and 2021, Idaho Power had a $56.2 million and $2.0 million payable to IDACORP, respectively, which was included in its accounts payable to affiliatesbalance on its balance sheets, primarily related to income tax payments. Ida-West: Ida-West Energy Company (Ida-West) is a wholly-owned subsidiary of IDACORP and is an operator of small hydropower generation projects that satisfy the requirements ofthe Public Utility Regulatory Policies Act of 1978. Idaho Power purchases all of the power generated by four of Ida-West's hydropower projects located in Idaho. Idaho Powerpurchased $7.9 million in 2022 and $8.2 million in 2021 of power from Ida-West. 39
FERC FORM No. 1 (ED. 12-96)
Page 122-123
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
Line
No.
Item
(a)
Unrealized Gains and
Losses on Available-For-
Sale Securities
(b)
Minimum Pension Liability
Adjustment (net amount)
(c)
Foreign Currency Hedges
(d)
Other Adjustments
(e)
Other Cash Flow
Hedges Interest Rate
Swaps
(f)
Other
Cash
Flow
Hedges
[Specify]
(g)
Totals for
each category
of items
recorded in
Account 219
(h)
Net Income
(Carried
Forward from
Page 116,
Line 78)
(i)
Total
Comprehensive
Income
(j)
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.
1 Balance of Account 219 at Beginning of
Preceding Year 0 0 0 (43,357,680)0 0 (43,357,680)
2
Preceding Quarter/Year to Date
Reclassifications from Account 219 to Net
Income
0 3,343,179 3,343,179
3 Preceding Quarter/Year to Date Changes in
Fair Value 0 (25,393)(25,393)
4 Total (lines 2 and 3)0 0 0 3,317,786 0 0 3,317,786 243,225,299 246,543,085
5 Balance of Account 219 at End of Preceding
Quarter/Year 0 0 0 (40,039,894)0 0 (40,039,894)
6 Balance of Account 219 at Beginning of
Current Year 0 0 0 (40,039,894)0 0 (40,039,894)
7 Current Quarter/Year to Date Reclassifications
from Account 219 to Net Income 3,347,820 3,347,820
8 Current Quarter/Year to Date Changes in Fair
Value 23,769,687 23,769,687
9 Total (lines 7 and 8)27,117,507 27,117,507 254,866,668 281,984,175
10 Balance of Account 219 at End of Current
Quarter/Year (12,922,387)(12,922,387)
FERC FORM No. 1 (NEW 06-02)
Page 122 (a)(b)
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Line
No.
Classification
(a)
Total Company For the Current
Year/Quarter Ended
(b)
Electric
(c)
Gas
(d)
Other (Specify)
(e)
Other (Specify)
(f)
Other
(Specify)
(g)
Common
(h)
1 UTILITY PLANT
2 In Service
3 Plant in Service (Classified)6,829,781,143 6,829,781,143
4 Property Under Capital Leases
5 Plant Purchased or Sold
6 Completed Construction not Classified
7 Experimental Plant Unclassified
8 Total (3 thru 7)6,829,781,143 6,829,781,143
9 Leased to Others
10 Held for Future Use 7,129,775 7,129,775
11 Construction Work in Progress 786,213,001 786,213,001
12 Acquisition Adjustments 750,894 750,894
13 Total Utility Plant (8 thru 12)7,623,874,813 7,623,874,813
14 Accumulated Provisions for Depreciation, Amortization,
& Depletion 2,645,515,886 2,645,515,886
15 Net Utility Plant (13 less 14)4,978,358,927 4,978,358,927
16 DETAIL OF ACCUMULATED PROVISIONS FOR
DEPRECIATION, AMORTIZATION AND DEPLETION
17 In Service:
18 Depreciation 2,606,079,117 2,606,079,117
19 Amortization and Depletion of Producing Natural Gas
Land and Land Rights
20 Amortization of Underground Storage Land and Land
Rights
21 Amortization of Other Utility Plant 39,329,141 39,329,141
22 Total in Service (18 thru 21)2,645,408,258 2,645,408,258
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 Amortization of Plant Acquisition Adjustment 107,628 107,628
33 Total Accum Prov (equals 14) (22,26,30,31,32)2,645,515,886 2,645,515,886
FERC FORM No. 1 (ED. 12-89)
Page 200-201
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106)
Line
No.
Account
(a)
Balance Beginning of Year
(b)
Additions
(c)
Retirements
(d)
Adjustments
(e)
Transfers
(f)
Balance at End
of Year
(g)
1 1. INTANGIBLE PLANT
2 (301) Organization 5,703 0 0 5,703
3 (302) Franchise and Consents 38,076,883 13,245,504 60,000 51,262,387
4 (303) Miscellaneous Intangible Plant 44,512,459 11,562,836 5,063,951 51,011,344
5 TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4)82,595,045 24,808,340 5,123,951 102,279,434
6 2. PRODUCTION PLANT
7 A. Steam Production Plant
8 (310) Land and Land Rights 1,722,421 0 0 1,722,421
9 (311) Structures and Improvements 120,945,901 440,961 190,815 121,196,047
10 (312) Boiler Plant Equipment 648,153,415 6,453,240 2,567,615 652,039,040
11 (313) Engines and Engine-Driven Generators 0 0 0 0
12 (314) Turbogenerator Units 140,615,651 921,808 467,428 141,070,031
13 (315) Accessory Electric Equipment 54,101,874 1,060,890 46,421 55,116,343
14 (316) Misc. Power Plant Equipment 19,152,496 1,114,801 71,135 20,196,162
15 (317) Asset Retirement Costs for Steam Production 26,540,204 1,696,397 0 28,236,601
16 TOTAL Steam Production Plant (Enter Total of lines 8
thru 15)1,011,231,962 11,688,097 3,343,414 1,019,576,645
17 B. Nuclear Production Plant
18 (320) Land and Land Rights 0 0 0 0
19 (321) Structures and Improvements 0 0 0 0
20 (322) Reactor Plant Equipment 0 0 0 0
21 (323) Turbogenerator Units 0 0 0 0
22 (324) Accessory Electric Equipment 0 0 0 0
23 (325) Misc. Power Plant Equipment 0 0 0 0
24 (326) Asset Retirement Costs for Nuclear Production 0 0 0 0
25 TOTAL Nuclear Production Plant (Enter Total of lines 18
thru 24)0 0 0 0
26 C. Hydraulic Production Plant
27 (330) Land and Land Rights 31,998,608 131,627 (74)32,130,309
28 (331) Structures and Improvements 245,328,748 6,666,971 301,234 251,694,485
29 (332) Reservoirs, Dams, and Waterways 300,891,768 6,487,198 583,337 306,795,629
30 (333) Water Wheels, Turbines, and Generators 340,646,213 27,548,722 4,481,039 363,713,896
31 (334) Accessory Electric Equipment 68,318,708 3,796,207 62,165 72,052,750
32 (335) Misc. Power Plant Equipment 29,253,215 2,157,348 183,778 31,226,785
33 (336) Roads, Railroads, and Bridges 14,790,198 0 0 14,790,198
34 (337) Asset Retirement Costs for Hydraulic Production 0 0 0 0
35 TOTAL Hydraulic Production Plant (Enter Total of lines
27 thru 34)1,031,227,458 46,788,073 5,611,479 1,072,404,052
36 D. Other Production Plant
37 (340) Land and Land Rights 2,699,794 0 0 2,699,794
38 (341) Structures and Improvements 154,588,980 138,061 116,559 154,610,482
39 (342) Fuel Holders, Products, and Accessories 10,446,262 (8,015)0 10,438,247
40 (343) Prime Movers 221,427,286 52,086,406 87,433 273,426,259
41 (344) Generators 66,678,480 0 0 66,678,480
42 (345) Accessory Electric Equipment 92,082,268 1,567,201 20,000 93,629,469
43 (346) Misc. Power Plant Equipment 6,902,185 218,977 90,948 7,030,214
44 (347) Asset Retirement Costs for Other Production 0 0 0 0
44.1 (348) Energy Storage Equipment - Production 0 0 0 0
45 TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44)554,825,255 54,002,630 314,940 608,512,945
46 TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and
45)2,597,284,675 112,478,800 9,269,833 2,700,493,642
47 3. Transmission Plant
48 (350) Land and Land Rights 39,616,968 861,425 0 40,478,393
48.1 (351) Energy Storage Equipment - Transmission 0 0 0 0
49 (352) Structures and Improvements 87,473,548 13,654,967 239,296 100,889,219
50 (353) Station Equipment 470,126,028 9,820,041 5,901,222 474,044,847
51 (354) Towers and Fixtures 231,330,644 1,489,893 21 232,820,516
52 (355) Poles and Fixtures 224,163,704 7,025,038 1,071,817 230,116,925
53 (356) Overhead Conductors and Devices 256,041,849 12,759,798 1,078,669 267,722,978
54 (357) Underground Conduit 0 0 0 0
55 (358) Underground Conductors and Devices 0 0 0 0
FERC FORM No. 1 (REV. 12-05)
Page 204-207
56 (359) Roads and Trails 390,266 0 0 390,266
57 (359.1) Asset Retirement Costs for Transmission Plant 0 0 0 0
58 TOTAL Transmission Plant (Enter Total of lines 48 thru
57)1,309,143,007 45,611,162 8,291,025 1,346,463,144
59 4. Distribution Plant
60 (360) Land and Land Rights 7,831,316 1,183,114 9,014,430
61 (361) Structures and Improvements 52,169,659 7,437,287 89,148 59,517,798
62 (362) Station Equipment 301,417,637 27,444,865 1,025,805 327,836,697
63 (363) Energy Storage Equipment – Distribution 0 0 0 0
64 (364) Poles, Towers, and Fixtures 307,123,822 24,352,937 5,112,755 326,364,004
65 (365) Overhead Conductors and Devices 152,118,967 9,698,160 2,216,147 159,600,980
66 (366) Underground Conduit 53,351,941 1,661,918 388,169 54,625,690
67 (367) Underground Conductors and Devices 313,609,491 20,773,802 2,779,803 331,603,490
68 (368) Line Transformers 683,919,398 54,687,299 8,151,503 730,455,194
69 (369) Services 66,365,371 2,887,786 139,422 69,113,735
70 (370) Meters 110,068,259 8,399,895 5,122,897 113,345,257
71 (371) Installations on Customer Premises 5,284,632 9,741 664,999 4,629,374
72 (372) Leased Property on Customer Premises 0 0 0 0
73 (373) Street Lighting and Signal Systems 5,558,315 1,834,687 1,364,380 6,028,622
74 (374) Asset Retirement Costs for Distribution Plant 0 0 0 0
75 TOTAL Distribution Plant (Enter Total of lines 60 thru 74)2,058,818,808 160,371,491 27,055,028 2,192,135,271
76 5. REGIONAL TRANSMISSION AND MARKET
OPERATION PLANT
77 (380) Land and Land Rights 0 0 0 0
78 (381) Structures and Improvements 0 0 0 0
79 (382) Computer Hardware 0 0 0 0
80 (383) Computer Software 0 0 0 0
81 (384) Communication Equipment 0 0 0 0
82 (385) Miscellaneous Regional Transmission and Market
Operation Plant 0 0 0 0
83 (386) Asset Retirement Costs for Regional Transmission
and Market Oper 0 0 0 0
84 TOTAL Transmission and Market Operation Plant (Total
lines 77 thru 83)0 0 0 0
85 6. General Plant
86 (389) Land and Land Rights 20,690,512 121,054 0 20,811,566
87 (390) Structures and Improvements 141,138,726 16,361,976 666,038 156,834,664
88 (391) Office Furniture and Equipment 43,003,684 4,776,572 5,338,812 42,441,444
89 (392) Transportation Equipment 109,292,064 13,877,749 8,298,323 114,871,490
90 (393) Stores Equipment 4,279,317 705,067 26,914 4,957,470
91 (394) Tools, Shop and Garage Equipment 12,357,084 2,864,098 163,826 15,057,356
92 (395) Laboratory Equipment 14,779,348 345,001 339,181 14,785,168
93 (396) Power Operated Equipment 23,927,370 3,661,745 1,189,910 26,399,205
94 (397) Communication Equipment 81,342,100 2,315,470 2,182,943 81,474,627
95 (398) Miscellaneous Equipment 10,209,853 1,079,480 512,671 10,776,662
96 SUBTOTAL (Enter Total of lines 86 thru 95)461,020,058 46,108,212 18,718,618 488,409,652
97 (399) Other Tangible Property 0 0 0 0
98 (399.1) Asset Retirement Costs for General Plant 0 0 0 0
99 TOTAL General Plant (Enter Total of lines 96, 97, and 98)461,020,058 46,108,212 18,718,618 488,409,652
100 TOTAL (Accounts 101 and 106)6,508,861,593 389,378,005 68,458,455 6,829,781,143
101 (102) Electric Plant Purchased (See Instr. 8)0 0 0 0
102 (Less) (102) Electric Plant Sold (See Instr. 8)0 0 0 0
103 (103) Experimental Plant Unclassified 0 0 0 0
104 TOTAL Electric Plant in Service (Enter Total of lines 100
thru 103)6,508,861,593 389,378,005 68,458,455 6,829,781,143
FERC FORM No. 1 (REV. 12-05)
Page 204-207
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106)
Line
No.
Account
(a)
Balance Beginning of Year
(b)
Additions
(c)
Retirements
(d)
Adjustments
(e)
Transfers
(f)
Balance at End
of Year
(g)
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
ELECTRIC PLANT HELD FOR FUTURE USE (Account 105)
Line
No.
Description and Location of Property
(a)
Date Originally Included in This Account
(b)
Date Expected to be used in Utility Service
(c)
Balance at End of Year
(d)
1 Land and Rights:
2 Distribution Lines (a)(f)25,581
3 Distribution Stations (b)(g)1,379,097
4 Line #854 500 Kv 03/31/2009 12/31/2030 308,066
5 Pallette Junction Substation 03/15/2021 12/31/2028 748,482
6 Production (c)(h)104,155
7
8 Transmission Stations (d)(i)349,831
9 Midpoint Transmission Station 12/15/2022 06/30/2027 851,271
10 Line #853 500 Kv 12/16/2011 12/31/2026 332,747
11
12
13 Transmission Lines (e)(j)68,592
14 McDermott Substation 10/26/2022 06/30/2026 1,330,604
15 Farmway Station 12/22/2022 06/30/2028 934,174
21 Other Property:
22 Transmission Stations (k)(m)199,069
23 Distribution Stations (l)(n)54,561
24 Underground Vault, Blaine County 08/30/2016 12/31/2024 443,545
47 TOTAL 7,129,775
FERC FORM No. 1 (ED. 12-96)
Page 214
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
FOOTNOTE DATA
(a) Concept: ElectricPlantPropertyClassifiedAsHeldForFutureUseOriginalDate
Various dates
(b) Concept: ElectricPlantPropertyClassifiedAsHeldForFutureUseOriginalDate
Various dates
(c) Concept: ElectricPlantPropertyClassifiedAsHeldForFutureUseOriginalDate
Various dates
(d) Concept: ElectricPlantPropertyClassifiedAsHeldForFutureUseOriginalDate
Various dates
(e) Concept: ElectricPlantPropertyClassifiedAsHeldForFutureUseOriginalDate
Various dates
(f) Concept: ElectricPlantPropertyClassifiedAsHeldForFutureUseExpectedUseInServiceDate
Various dates
(g) Concept: ElectricPlantPropertyClassifiedAsHeldForFutureUseExpectedUseInServiceDate
Various dates
(h) Concept: ElectricPlantPropertyClassifiedAsHeldForFutureUseExpectedUseInServiceDate
Various dates
(i) Concept: ElectricPlantPropertyClassifiedAsHeldForFutureUseExpectedUseInServiceDate
Various dates
(j) Concept: ElectricPlantPropertyClassifiedAsHeldForFutureUseExpectedUseInServiceDate
Various dates
(k) Concept: ElectricPlantPropertyClassifiedAsHeldForFutureUseOriginalDate
Various dates
(l) Concept: ElectricPlantPropertyClassifiedAsHeldForFutureUseOriginalDate
Various dates
(m) Concept: ElectricPlantPropertyClassifiedAsHeldForFutureUseExpectedUseInServiceDate
Various dates
(n) Concept: ElectricPlantPropertyClassifiedAsHeldForFutureUseExpectedUseInServiceDate
Various dates
FERC FORM No. 1 (ED. 12-96)
Page 214
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)
Line No.Description of Project
(a)
Construction work in progress - Electric (Account 107)
(b)
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.
1 ROLLUP RELIC COST BROWNLEE 164,734,553
2 ROLLUP RELIC COST HELLS CANYON 112,035,786
3 ROLLUP RELIC COST OXBOW 52,280,601
4 GATEWAY WEST 500KV LINE 51,928,790
5 HELLS CANYON RELICENSING OUTSI 45,561,460
6 HMWY220002- 2021 RFP NEW ENERG 38,187,611
7 B2H PERMITTING 11/1/2011 & FOR 30,688,666
8 BMSU220002 - BESS 40MW INSTALL 15,966,928
9 BRIDGER 2017C100 CCR JB FGD PO 14,304,848
10 BOARDMAN - HEMINGWAY 500 KV LI 12,561,091
11 WQ HCC401 CERTIFICATION OPS AN 12,293,446
12 HCC WATERSHED ENHANCEMENT PROG 10,855,410
13 LEGAL DEPT. LABOR FOR RELICENS 7,982,437
14 LOWER SALMON UNIT 3 REFURB 7,639,825
15 BROWNLEE SECURITY FENCE 7,388,119
16 LTP - MAJOR INSPECTION W/UPGRA 6,580,985
17 BULL TROUT PROGRAM - ADMINISTR 6,519,335
18 OXBOW HATCHERY RENOVATION 6,371,132
19 AFPR TURBINE GENERATOR REFURB 5,965,271
20 REL-HCC OREGON REAUTHORIZATION 5,852,153
21 HELLS CANYON GENERATOR REFURBI 5,367,765
22 B2H TLINE CONSTRUCTION COSTS 4,647,786
23 HC SEDIMENT PROGRAMS 4,336,302
24 FALL CHINOOK PROGRAM - REDD SU 4,012,058
25 REPORTING MODEL FOR SNAKE RIVE 3,783,710
26 WDRI-KCHM NEW 138KV 3,673,176
27 T423190001-REBUILD FROM HGTN T 3,407,416
28 BLPR190001 - SWITCHYARD PERIME 3,126,196
29 WESR220001 - ADD 2MW BATTERY S 2,833,620
30 COMMON ASSET: MPSN 500KV FENCE 2,779,925
31 HELLS CANYON SPARE GENERATOR C 2,418,137
32 AFPR PLANT CONTROLS MODERNIZAT 2,237,310
33 OXBOW SPILLWAY REHABILITATION 2,089,681
34 BOBN200005 - STATION PERIMETER 2,088,253
35 B2H TLINE PRE-CONSTRUCTION COS 2,032,262
36 HMWY 80MW ENERGY STORAGE PROJE 1,943,687
37 ELMR220001 - ADD 4MW BATTERY S 1,925,124
38 T426 KING-DALE-HUNT-ADELAIDE-L 1,895,823
39 COMMON ASSET: MPSN 345KV FENCE 1,865,842
40 REPLACE UNIT 8320 WITH 8524 -1,850,352
41 LSPR LOCAL SERVICE UPGRADE PHA 1,773,649
42 FILR220001 - ADD 2MW BATTERY S 1,629,078
43 SDI CARD REPLACEMENTS 2021 1,572,772
44 HYDA REPLACE 103Z AND 104X WIT 1,503,496
45 SIMPLOT POC. NEW COOLING POND,1,430,487
46 JOINT ASSET: RPL MPSN C506 SER 1,400,998
47 AFPR UNIT 3 REWIND 1,340,662
48 FALL CHINOOK PROGRAM - ENTRAPM 1,322,081
49 SH-16 RELOCATION - LINE 465 1,300,727
50 BLACK MESA GINT#557- STATIONS 1,287,146
51 HDSP190001 - NEW UG CABLE TO D 1,283,986
52 GRID MOD SINGLE VENDOR PLATFOR 1,265,524
53 RELOCATE SKWY-014 FOR HWY 20/2 1,238,180
54 B2H- BPA STEPDOWN STATION 1,204,145
55 AMITY DISTRIBUTION CENTER 1,195,196
56 MLBA220001 - ADD 2MW BATTERY S 1,193,589
57 DALE220001 - BOVARIUS - IPC CO 1,170,299
FERC FORM No. 1 (ED. 12-87)
Page 216
58 B2H: RIGHTS OF WAY 1,168,493
59 HCPR190001 - UNIT#1 PLANT MODE 1,166,243
60 HELLS CANYON NOAA BIOLOGICAL A 1,116,013
61 CHQ EXTERIOR GRANITE REPLACEME 1,087,245
62 HCC MERCURY NUMERIC MODEL DEVE 1,015,629
63 OTHER MINOR PROJECTS UNDER $1,000,000 83,534,491
43 Total 786,213,001
FERC FORM No. 1 (ED. 12-87)
Page 216
CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)
Line No.Description of Project
(a)
Construction work in progress - Electric (Account 107)
(b)
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT (Account 108)
Line
No.
Item
(a)
Total (c + d + e)
(b)
Electric Plant in Service
(c)
Electric Plant Held for Future Use
(d)
Electric Plant Leased To Others
(e)
Section A. Balances and Changes During Year
1 Balance Beginning of Year 2,444,332,482 2,444,332,482 0
2 Depreciation Provisions for Year, Charged to
3 (403) Depreciation Expense 162,962,070 162,962,070
4 (403.1) Depreciation Expense for Asset Retirement Costs
5 (413) Exp. of Elec. Plt. Leas. to Others
6 Transportation Expenses-Clearing 6,270,493 6,270,493
7 Other Clearing Accounts
8 Other Accounts (Specify, details in footnote):
9.1 Fuel Stock 49,844 49,844
10 TOTAL Deprec. Prov for Year (Enter Total of lines 3 thru 9)169,282,407 169,282,407
11 Net Charges for Plant Retired:
12 Book Cost of Plant Retired (63,334,577)(63,334,577)
13 Cost of Removal (23,331,082)(23,331,082)
14 Salvage (Credit)8,038,085 8,038,085
15 TOTAL Net Chrgs. for Plant Ret. (Enter Total of lines 12 thru 14)(78,627,574)(78,627,574)
16 Other Debit or Cr. Items (Describe, details in footnote):
17.1 (a)
Depreciation Adjustments 71,091,802 71,091,802
18 Book Cost or Asset Retirement Costs Retired
19 Balance End of Year (Enter Totals of lines 1, 10, 15, 16, and 18)2,606,079,117 2,606,079,117
Section B. Balances at End of Year According to Functional Classification
20 Steam Production 692,080,427 692,080,427
21 Nuclear Production
22 Hydraulic Production-Conventional 499,216,642 499,216,642
23 Hydraulic Production-Pumped Storage
24 Other Production 163,174,993 163,174,993
25 Transmission 417,316,596 417,316,596
26 Distribution 698,514,955 698,514,955
27 Regional Transmission and Market Operation
28 General 135,775,504 135,775,504
29 TOTAL (Enter Total of lines 20 thru 28)2,606,079,117 2,606,079,117
FERC FORM No. 1 (REV. 12-05)
Page 219
FOOTNOTE DATA
(a) Concept: OtherAdjustmentsToAccumulatedDepreciationDescription
Valmy depreciation adjustments (ID Order No. 33771 and OR Order No. 17-235), Bridger depreciation adjustments (ID Order No. 35423), Wildfire Mitigation depreciation adjustments (ID Order No. 35077), and CIAC and Asset Retirement Obligation activity.
FERC FORM No. 1 (REV. 12-05)
Page 219
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1)
Line
No.
Description of Investment
(a)
Date Acquired
(b)
Date of Maturity
(c)
Amount of Investment at
Beginning of Year
(d)
Equity in Subsidiary Earnings
of Year
(e)
Revenues
for Year
(f)
Amount of
Investment
at End of
Year
(g)
Gain or
Loss from
Investment
Disposed
of
(h)
1 Common Stock 02/01/1974 500 500
2 Capital Contributions 2,462,593 2,462,593
3 Equity in Earnings 25,446,384 8,782,042 22,000,000 12,228,426
42 Total Cost of Account 123.1 $Total 27,909,477 8,782,042 22,000,000 14,691,519 0
FERC FORM No. 1 (ED. 12-89)
Page 224-225
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
MATERIALS AND SUPPLIES
Line
No.
Account
(a)
Balance Beginning of Year
(b)
Balance End of Year
(c)
Department or Departments which Use Material
(d)
1 Fuel Stock (Account 151)18,045,117 14,760,362
2 Fuel Stock Expenses Undistributed (Account 152)0 1,691
3 Residuals and Extracted Products (Account 153)
4 Plant Materials and Operating Supplies (Account 154)
5 Assigned to - Construction (Estimated)
6 Assigned to - Operations and Maintenance
7 Production Plant (Estimated)15,670,182 14,645,220
8 Transmission Plant (Estimated)11,778,851 15,826,350
9 Distribution Plant (Estimated)44,464,177 59,743,149
10 Regional Transmission and Market Operation Plant (Estimated)
11 Assigned to - Other (provide details in footnote)1,416,614 (a)1,656,595
12 TOTAL Account 154 (Enter Total of lines 5 thru 11)73,329,824 91,871,314
13 Merchandise (Account 155)
14 Other Materials and Supplies (Account 156)0 0
15 Nuclear Materials Held for Sale (Account 157) (Not applic to Gas Util)
16 Stores Expense Undistributed (Account 163)4,221,832 589,580
17
18
19
20 TOTAL Materials and Supplies 95,596,773 107,222,947
FERC FORM No. 1 (REV. 12-05)
Page 227
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
FOOTNOTE DATA
(a) Concept: PlantMaterialsAndOperatingSuppliesOther
This amount represents miscellaneous inventory that is not yet assigned to a particular function.
FERC FORM No. 1 (REV. 12-05)
Page 227
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
Transmission Service and Generation Interconnection Study Costs
Line
No.
Description
(a)
Costs Incurred During Period
(b)
Account Charged
(c)
Reimbursements Received During the Period
(d)
Account Credited With
Reimbursement
(e)
1 Transmission Studies
2 GREAT BASIN (GBT) SWIP-NORTH TRANSMISSION STUDY 29,077 186623 (a)0 186623
3 PWX LTF PTP 94688523 STUDY 0 186623 9,118 186623
4 PWX LTF PTP 94688524 STUDY 0 186623 9,426 186623
5 BPAP LTF PTP 94946026 STUDY 0 186623 19,546 186623
6 BPAP LTF PTP 94946039 STUDY 0 186623 (260)186623
7 BPAP 91629500 BIENNIAL REASSESSMENT 361 186623 (833)186623
8 BPAP 91629850 BIENNIAL REASSESSMENT 361 186623 (833)186623
9 MEAI LTF PTP 95956232 STUDY 237 186623 (237)186623
10 UAMP LTF PTP 95937484 STUDY 2,520 186623 (2,520)186623
11 VTOL LTF PTP 96153227 STUDY 513 186623 (513)186623
12 MCPI LTF PTP 96350733 STUDY 209 186623 (209)186623
13 BPA LTF PTP 96484930 STUDY 3,101 186623 (3,101)186623
14 BPA LTF PTP 97456622 STUDY 6,368 186623 (11,353)186623
15 PWX 92502052 CF BIENNIAL REASSESSMENT 273 186623 0 186623
16 PWX 92502053 CF BIENNIAL REASSESSMENT 273 186623 (273)186623
17 BPA LTF PTP 97887976 STUDY 1,142 186623 (10,000)186623
18 PWX LTF PTP B2H STUDIES 435 186623 (80,000)186623
19 PAC LTF PTP 98184887 STUDY 0 186623 (10,000)186623
20 Total 44,870 (82,042)
21 Generation Studies
22 BLACK MESA ENERGY #557 (807)186623 0 186623
23 BENNETT SOLAR 1 #551 34 186623 132,113 186623
24 PLEASANT VALLEY SOLAR #568 8,609 186623 81,043 186623
25 MOON CRATER SOLAR #57 0 186623 0 186623
26 MAGIC VALLEY ENERGY #572 1,140 186623 83,164 186623
27 ARCO WIND 2 #580 42,444 186623 (64,759)186623
28 MAGIC VALLEY WIND (2) #581 751 186623 86,885 186623
29 PEASANT VALLEY SOLAR (2) #587 4,173 186623 93,436 186623
30 APPALOOSA WIND & SOLAR #1 400MW 83,646 186623 (62,974)186623
31 FRANKLIN SOLAR #549 7,409 186623 81,080 186623
32 WOOD CREEK RANCH #578 114 186623 38,643 186623
33 PILLAR FALLS HYDRO #601 0 186623 (3,524)186623
34 CRIMSON ORCHARD #604 240MW 18,393 186623 (53,630)186623
35 SOUTH BENNETT #605 240MW 8,014 186623 (52,621)186623
36 JACKALOPE 1 #607 300 MW 6,564 186623 (77,718)186623
37 JACKALOPE 2 #608 300 MW 2,700 186623 (53,479)186623
38 JACKALOPE 2 #609 300 MW 2,790 186623 (53,450)186623
39 LANGLEY GULCH EXPANSION II 610 5,107 186623 (5,300)186623
40 OLD OREGON TRAIL PV3 #613 18,101 186623 (64,529)186623
41 SALMON FALLS WIND #614 10,409 186623 (38,603)186623
42 JUNIPER GULCH #617 (395)186623 20,000 186623
43 SALMON FALLS WIND 2 #616 7,702 186623 (41,810)186623
44 FILR ENERGY STORAGE #618 2,339 186623 (3,802)186623
45 HMWY ENERGY STORAGE #619 6,050 186623 (8,358)186623
46 BENNETT MOUNTAIN EXPANSION #620 4,368 186623 (6,183)186623
47 DANSKIN EXPANSION #621 3,781 186623 (5,693)186623
48 OWYHEE PUMPED STORAGE #622 20,043 186623 (108,919)186623
49 MOSBY BUTTE SOLAR #623 19,979 186623 (103,789)186623
50 GEM VALE 1 #624 15,310 186623 (91,470)186623
51 GEM VALE 2 #625 9,207 186623 (91,144)186623
52 MLBA ENERGY STORAGE #627 847 186623 (3,396)186623
53 ELMR ENERGY STORAGE #626 1,989 186623 (1,989)186623
54 WESR ENERGY STORAGE #628 4,790 186623 (4,790)186623
55 HMWY ENERGY STORAGE 2 #629 15,000 186623 0 186623
56 ELKO COUNTY SOLAR 1 GI #630 21,557 186623 (117,645)186623
57 JUNIPER GULCH #631 3,667 186623 (3,667)186623
58 WILSON #632 10,650 186623 (129,288)186623
59 GATHER #633 24,327 186623 (135,626)186623
FERC FORM No. 1 (NEW. 03-07)
Page 231
60 HMWY ENERGY STORAGE EXPANSION #634 11,424 186623 0 186623
61 TAURUS WIND #635 11,727 186623 (151,786)186623
62 SOLES REST #636 9,357 186623 (62,198)186623
63 HPVY ENERGY STORAGE #638 4,751 186623 0 186623
64 BOBN ENERGY STORAGE 1 #639 4,624 186623 0 186623
65 BOBN ENERGY STORAGE 2 #640 2,855 186623 0 186623
66 AMERICAN FALLS ESC #641 7,223 186623 (104,888)186623
67 LAVA #642 4,238 186623 (4,238)186623
68 SHOESTRING #643 4,155 186623 (152,010)186623
69 OPAL #644 4,846 186623 (4,846)186623
70 HASSELBACK #645 3,879 186623 (3,879)186623
71 JASPER #646 6,723 186623 (152,749)186623
72 HASHBROWN #647 6,417 186623 (151,957)186623
73 MOON CRATER II #648 28,179 186623 (145,663)186623
74 ARCHWAY SOLAR PAC C1-44 555 186623 (555)186623
75 VIZCAYA GI PROJECT #649 5,956 186623 (160,000)186623
76 DRAGONFLY GI PROJECT #650 5,685 186623 (160,000)186623
77 ARROWROCK PROJECT EXPANSION #651 2,014 186623 (2,014)186623
78 MAGIC VALLEY ENERGY STORAGE GI PROJECT #652 9,533 186623 (53,485)186623
79 BURBANK SOLAR GI PROJECT #653 170 186623 (170)186623
80 PINGREE SOLAR GI PROJECT #654 3,928 186623 (70,000)186623
81 BEAR LAKE GI PROJECT #655 4,571 186623 (70,000)186623
82 RED BRIDGE SOLAR & STORAGE GI PROJECT #656 3,355 186623 (53,182)186623
83 KUNA STORAGE GI PROJECT #657 3,714 186623 (52,227)186623
84 BLUEBUNCH SOLAR 1 GI PROJECT #658 6,256 186623 (52,143)186623
85 FALCON GI PROJECT #659 10,110 186623 (70,000)186623
86 FITZ GI PROJECT #660 2,658 186623 (70,000)186623
87 JACQUELINE GI PROJECT #661 3,881 186623 (70,000)186623
88 OLNEY GI PROJECT #662 7,291 186623 (70,000)186623
89 VIZCAYA 230KV GI PROJECT #663 3,547 186623 (53,427)186623
90 DAN ANDREWS (CASCARA) GI #664 3,801 186623 (3,801)186623
91 BLACKS CREEK EC GI PROJECT #665 6,879 186623 (60,000)186623
92 POWERS BUTTE EC GI PROJECT #666 6,613 186623 (60,000)186623
93 MARTHA FIELDS EC I GI PROJECT #667 5,589 186623 (70,000)186623
94 MARTHA FIELDS EC II GI PROJECT #668 4,079 186623 (70,000)186623
95 BRIDGERS PVS GI PROJECT #669 4,640 186623 (60,000)186623
96 FLATIRON HILLS WIND I GI PROJECT #670 1,082 186623 (20,000)186623
97 KIMAMA FLATTS SOLAR GI PROJECT #671 3,113 186623 (20,000)186623
98 EDEN WEST SOLAR GI PROJECT #672 1,583 186623 (20,000)186623
99 EDEN NORTH SOLAR GI PROJECT #673 311 186623 (10,305)186623
100 KUNA MATATA SOLAR GI PROJECT #674 1,674 186623 (20,000)186623
101 OMG WIND GI PROJECT #675 64 186623 (10,059)186623
102 OMG WIND II GI PROJECT #676 64 186623 (10,059)186623
103 BEAR DEN SOLAR 1 GI PROJECT #677 258 186623 (20,000)186623
104 SOUTH FALLS GI PROJECT #678 3,993 186623 (20,000)186623
105 SOUTH HILLS SOLAR GI PROJECT #680 2,049 186623 (10,000)186623
106 BEAR DEN SOLAR II GI PROJECT #682 64 186623 (20,000)186623
107 MOON CRATER SOLAR GI PROJECT #573 0 186623 (20,000)186623
108 BRIDGERS PVS 2 GI PROJECT #683 186 186623 (10,000)186623
109 JTA SOLAR 138KV GI PROJECT #684 0 186623 (20,000)186623
110 JTA SOLAR 345KV GI PROJECT #685 357 186623 (20,000)186623
111 MOONSTONE SOLAR GI PROJECT #686 99 186623 (10,000)186623
112 BOISE BENCH GRID GI PROJECT #688 0 186623 (20,000)186623
113 DOVE SPRINGS SOLAR GI PROJECT #689 0 186623 (10,000)186623
114 RUGG SPRINGS SOLAR GI PROJECT #690 0 186623 (20,000)186623
115 RUGG SPRINGS WIND GI PROJECT #691 0 186623 (20,000)186623
116 MARLIN SOLAR GI PROJECT #692 0 186623 (20,000)186623
117 RIGGS SOLAR GI PROJECT #693 0 186623 (20,000)186623
118 SANTIAGO SOLAR GI PROJECT #694 0 186623 (20,000)186623
119 KCE ID 1 GI PROJECT #696 0 186623 (20,000)186623
120 KCE ID 2 GI PROJECT #697 0 186623 (20,000)186623
Transmission Service and Generation Interconnection Study Costs
Line
No.
Description
(a)
Costs Incurred During Period
(b)
Account Charged
(c)
Reimbursements Received During the Period
(d)
Account Credited With
Reimbursement
(e)
FERC FORM No. 1 (NEW. 03-07)
Page 231
121 KCE ID 3 GI PROJECT #698 0 186623 (20,000)186623
39 Total 620,922 (3,487,433)
40 Grand Total 665,792 (3,569,475)
FERC FORM No. 1 (NEW. 03-07)
Page 231
Transmission Service and Generation Interconnection Study Costs
Line
No.
Description
(a)
Costs Incurred During Period
(b)
Account Charged
(c)
Reimbursements Received During the Period
(d)
Account Credited With
Reimbursement
(e)
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
FOOTNOTE DATA
(a) Concept: StudyCostsReimbursements
FERC FORM No. 1 (NEW. 03-07)
Page 231
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
OTHER REGULATORY ASSETS (Account 182.3)
CREDITS CREDITS
Line
No.
Description and Purpose of Other Regulatory Assets
(a)
Balance at Beginning of Current
Quarter/Year
(b)
Debits
(c)
Written off During
Quarter/Year Account
Charged
(d)
Written off During the Period Amount
(e)
Balance at end of Current
Quarter/Year
(f)
1 Fixed Cost Adjustment (FCA) (182302)35,057,904 24,888,143 1823 35,086,973 24,859,074
2 IPUC Order Pending (Amort period 06/23 thru 05/24)0 0
3 COVID Incremental Expenses-ID (182303)460,869 460,869
4 IPUC Order #34718 0 0
5 Arrearage Management Program-OR (182304)348,448 160,227 401 203,262 305,413
6 OPUC Order #20-377 0 0
7 (a)
AOCI Impact of Unfunded Pension Liability (7,939,709)2283 5,107,010 (13,046,719)
8 IPUC Order #30256 (182320)0 0
9 FCA Calendar Mo Adjustment (182308)2,516,250 400 1,198,543 1,317,707
10 Prior Year FCA (182309)0 35,203,248 400 19,479,022 15,724,226
11 IPUC Order pending (Amort period 06/23 thru 05/24)0 0
12 Prior Year FCA (182309)17,370,069 400 17,370,069 0
13 IPUC Order #35056 (Amort period 06/21 thru 05/22)0 0
14 AOCI Impact of Unfunded Pension Liability 322,950,830 2283 239,650,511 83,300,319
15 IPUC Order #30256 (182320)0 0
16 Deferred Pension Expense Net of Contributions 36,814,433 30,216,172 1823 38,175,484 28,855,121
17 IPUC Order #30333 (182321)0 0
18 FAS 109 Unfunded (182322)492,298,472 33,770,791 526,069,263
19 Accum Deferred Income Noncurrent 0 0
20 Idaho Pension Cash - IPUC Order #32248 (182327)197,622,560 40,215,563 Various 17,189,701 220,648,422
21 Amort period 06/11 thru indefinite 0 0
22 Mark- to Market Short Term (182330)1,989,711 1,526,238 3,515,949
23 Oregon Pension Expense Capitalized (182339)6,671,905 548,669 4073 219,696 7,000,878
24 OPUC Order #10-064 0 0
25 Asset Retirement Obligations (182341)22,585,175 6,213,088 Various 17,881 28,780,382
26 IPUC Order #29414; OPUC Order #04-585 0 0
27 RA-Hells Canyon-Baker Co (182360)313,506 313,506
28 IPUC Order #33948 0 0
29 Oregon Corporate Activity Tax (182355)403,124 318,244 Various 287,113 434,255
30 OPUC Order #20-397 0 0
31 Oregon Community Solar (182378)170,108 49,177 219,285
32 OPUC Order #16-410 0 0
33 Intervenor Funding-Idaho (182387)288,063 2,893 290,956
34 Multiple IPUC Orders 0 0
35 RA-CONTRA-DEF INC TAX (182389)228,977,480 282 15,357,707 213,619,773
36 Langley Revenue Accrual (182398)1,090,075 25,953 4073 369,171 746,857
37 OPUC Order #12-226 0 0
38 RA-OR LANGLEY REV INT RES (182399)(165,052)58,254 (106,798)
39 Siemens Long Term Deferred Rate Base (182410)9,043,980 4073 431,487 8,612,493
40 IPUC Order #33420 (Amort period 01/16 thru 12/43)0 0
41 Siemens Long Term Deferred Rate Based (182411)13,495,438 4073 643,866 12,851,572
42 IPUC Order #33420 (Amort period 01/16 thru 12/43)0 0
43 Siemens Long Term Deferred Rate Base (182412)375,476 28,584 4073 44,047 360,013
44 OPUC Order #15-387 (Amort period 01/16 thru 12/36)0 0
45 Siemens Long Term Deferred Rate Based (182413)550,421 4073 39,316 511,105
46 OPUC Order #15-387 (Amort period 01/16 thru 12/36)0 0
47 Siemens Long Term Interest Reserve (182414)(192,880)4190 28,584 (221,464)
48 Valmy O&M ID (182432)1,615,696 2,248,512 3,864,208
49 IPUC Order #33771 0 0
50 Valmy Acctg Adj ID (182435)96,525,981 400 8,215,668 88,310,313
51 IPUC Order #33771 0 0
52 Valmy Decomm Oregon (182436)410,843 20,813 400 237,503 194,153
53 OPUC Order #17-235 (Amort period 06/17 thru 12/25)0 0
54 Idaho DSM Rider 6,937,705 31,709,598 Various 34,879,984 3,767,319
55 IPUC Order#28661 0 0
56 (b)
Oregon DSM Rider 683,983 254 683,983 0
57 OPUC Advice #05-03 0 0
FERC FORM No. 1 (REV. 02-04)
Page 232
58 COVID Incremental Expenses-OR (182305)214,563 522 401 151,349 63,736
59 OPUC Order #20-377 0 0
60 PCA Deferral Idaho-Current Year (multiple 182 accounts)33,654,425 118,514,787 Various 23,929,706 128,239,506
61 IPUC Order Pending (Amort period 06/22 thru 05/23)0 0
62 Mark-to-Market Long Term (182333)3,757,552 244 485,557 3,271,995
63 (c)
ID Valmy Collections (182430)(700,830)400 920,556 (1,621,386)
64 IPUC Order #33771 0 0
65 Wildfire Mitigation-ID (182310)6,075,024 21,003,203 27,078,227
66 IPUC Order #35077 0 0
67 Cloud Computing (182315)1,408,857 496,710 4073 288,649 1,616,918
68 IPUC Order #34707 0 0
69 Bridger Decommissioning (multiple 182 accounts)0 87,872,194 Various 7,341,031 80,531,163
70 IPUC Order #35423
71 Oregon PCAM (182384)0 1,120,595 1,120,595
72 OPUC Order pending
73 Minor items (4)67,066 136,787 Various 102,151 101,702
44 TOTAL 1,533,747,521 436,348,965 468,135,580 1,501,960,906
FERC FORM No. 1 (REV. 02-04)
Page 232
OTHER REGULATORY ASSETS (Account 182.3)
CREDITS CREDITS
Line
No.
Description and Purpose of Other Regulatory Assets
(a)
Balance at Beginning of Current
Quarter/Year
(b)
Debits
(c)
Written off During
Quarter/Year Account
Charged
(d)
Written off During the Period Amount
(e)
Balance at end of Current
Quarter/Year
(f)
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
FOOTNOTE DATA
(a) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Regulatory Asset is in a credit position, but is netted with the other Postretirement regulatory accounts for presentation as a net Regulatory Asset on the year-end financial statements.
(b) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
During 2022, this balance was reclassed from a Regulatory Asset to a Regulatory Liability for financial statement presentation.
(c) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets
Regulatory asset is in a credit position, but it is netted against other Valmy related regulatory asset accounts for a net Regulatory Asset on the year-end financial statements.
FERC FORM No. 1 (REV. 02-04)
Page 232
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
MISCELLANEOUS DEFFERED DEBITS (Account 186)
CREDITS CREDITS
Line
No.
Description of Miscellaneous Deferred Debits
(a)
Balance at Beginning of Year
(b)
Debits
(c)
Credits Account
Charged
(d)
Credits Amount
(e)
Balance at End of Year
(f)
1 Prepaid Credit Facility (186025)887,985 224,530 Various 258,555 853,960
2 Amortization period 12/19-12/26
3 Prepaid Services (LT) (186052)3,061,848 Various 315,389 2,746,459
4 Amortization periods - multiple
5 Workers Compensation (186121)934,717 401 91,672 843,045
6 Prepaid ROW (LT) (186160)486,954 401 43,902 443,052
7 Amortization periods - multiple
8 CARB Inventory (186650)494,947 460,594 242 153,304 802,237
9 Coal Royalties/Fly Ash (186709)961,328 151 247,311 714,017
10 Stable Value Life Inv (186719)57,237,164 6,728,655 63,965,819
11 Security Plan Net Insurance Asset 186720 5,787,637 94,626 4262 223,760 5,658,503
12 Retiree Medical-COLI (186726)4,318,015 165,903 4262 164,161 4,319,757
13 American Falls Water Rts (186727)3,212,861 401 1,042,009 2,170,852
14 Amortization period 01/06-02/25
15 American Falls Bond Refi (186770)151,998 401 47,999 103,999
16 Amortization period 12/09-02/25
17 Regulatory Reserves (186800)(2,116,034)Various 2,344,834 (4,460,868)
18 Minor Items (6)17,530 6,939,330 Various 6,708,797 248,063
47 Miscellaneous Work in Progress
48 Deferred Regulatroy Comm. Expenses (See pages 350 - 351)
49 TOTAL 75,436,950 78,408,895
FERC FORM No. 1 (ED. 12-94)
Page 233
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
ACCUMULATED DEFERRED INCOME TAXES (Account 190)
Line No.Description and Location
(a)
Balance at Beginning of Year
(b)
Balance at End of Year
(c)
1 Electric
2 Unrealized Loss on Investments 1,287 259
3 Tax Reform Regulatory Stipulation 6,460,884 8,440,979
4 Postretirement Benefits 500,537 396,050
5 Deferred Idaho ITC 28,267,325 35,334,005
6 USBR-American Falls O&M Costs Settlement 118,624 28,489
7 Non-VEBA Pension and Benefits Non-VEBA Pension and Benefits (699,431)(804,568)
8 Executive Deferred Compensation 52,084 90,889
9 Stock Based Compensation 2,956,484 3,184,240
10 Pension Expense-Oregon 4,173,591 4,456,667
11 Asset Retirement Obligation (ARO)1,578,325 1,533,029
12 Incentive Deferral-Profit Sharing-Not in Rates 3,705,325 3,882,562
13 Employer FICA Tax Deferral-CARES Act 1,126,180
14 Rate Case Disallowance 1,039,418 963,150
15 Revenue Sharing 146,402 146,402
16 Customer Advances 1,753,689 2,563,899
17 Covid Deferral 49,900
18 Bridger Revenue Deferral 960,590 1,114,435
19 OR Reconnect Fees Adv 2,841 3,262
20 Prov for Rate Refund-HC Relicensing (AFUDC)48,318,135 53,417,595
21 Soft Cap Battery Reserve 720,720
22 VEBA-Post Retirement Benefits 11,242,321 12,042,335
7 Other (a)192,659,208 117,542,752
8 TOTAL Electric (Enter Total of lines 2 thru 7)304,363,819 245,107,051
9 Gas
15 Other
16 TOTAL Gas (Enter Total of lines 10 thru 15)0
17.1 (b)
Other Non Electric (See footnote)20,324,309 21,298,737
17 Other (Specify)
18 TOTAL (Acct 190) (Total of lines 8, 16 and 17)324,688,128 266,405,788
FERC FORM NO. 1 (ED. 12-88)
Page 234
Notes
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
FOOTNOTE DATA
(a) Concept: AccumulatedDeferredIncomeTaxes
Line No.: 7
Pension-FAS 158 83,910,187 21,441,502
Regulatory Liability-FAS 109 96,879,711 94,945,955
Minimum Pension Liability 13,912,991 4,513,521
Postretirement Plan-FAS 158 (2,043,681)(3,358,226)
Total Other 192,659,208 117,542,752
(b) Concept: DescriptionOfAccumulatedDeferredIncomeTax
Line No.: 17
CIAC as Taxable inc Closed to nonutility Plant 0 78,534
Senior Management Security Plan 20,324,309 21,220,203
Total Non Electric 20,324,309 21,298,737
FERC FORM NO. 1 (ED. 12-88)
Page 234
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
CAPITAL STOCKS (Account 201 and 204)
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)
Outstanding per Bal. Sheet (Total
amount outstanding without
reduction for amounts held by
respondent) Shares
(e)
Outstanding per Bal. Sheet
(Total amount outstanding
without reduction for amounts
held by respondent) Amount
(f)
1 Common Stock (Account 201)
2 Account 201
3 Common Stock all of which is held by 50,000,000 2.5 39,150,812 97,877,030
4 IdaCorp, Inc. and not traded
5 Account 204 - None
14 Total 50,000,000 39,150,812 97,877,030
15 Preferred Stock (Account 204)
16
17
18
19 Total 0
1 Capital Stock (Accounts 201 and 204) - Data Conversion
2
3
4
5 Total
FERC FORM NO. 1 (ED. 12-91)
Page 250-251
CAPITAL STOCKS (Account 201 and 204)
Line
No.
Held by Respondent As Reacquired Stock (Acct 217)
Shares
(g)
Held by Respondent As Reacquired Stock (Acct 217) Cost
(h)
Held by Respondent In Sinking and Other Funds Shares
(i)
Held by Respondent In Sinking and Other Funds Amount
(j)
1
2
3
4
5
14
15
16
17
18
19
1
2
3
4
5
FERC FORM NO. 1 (ED. 12-91)
Page 250-251
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
2023-04-13
Year/Period of Report
End of: 2022/ Q4
Other Paid-in Capital
Line No.Item
(a)
Amount
(b)
1 Donations Received from Stockholders (Account 208)
2 Beginning Balance Amount 0
3 Increases (Decreases) from Sales of Donations Received from Stockholders
4 Ending Balance Amount
5 Reduction in Par or Stated Value of Capital Stock (Account 209)
6 Beginning Balance Amount 0
7 Increases (Decreases) Due to Reductions in Par or Stated Value of Capital Stock
8 Ending Balance Amount
9 Gain or Resale or Cancellation of Reacquired Capital Stock (Account 210)
10 Beginning Balance Amount 0
11 Increases (Decreases) from Gain or Resale or Cancellation of Reacquired Capital Stock
12 Ending Balance Amount
13 Miscellaneous Paid-In Capital (Account 211)
14 Beginning Balance Amount 0
15 Increases (Decreases) Due to Miscellaneous Paid-In Capital
16 Ending Balance Amount
17 Historical Data - Other Paid in Capital
18 Beginning Balance Amount 0
19 Increases (Decreases) in Other Paid-In Capital
20 Ending Balance Amount
40 Total 0
FERC FORM No. 1 (ED. 12-87)
Page 253
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
CAPITAL STOCK EXPENSE (Account 214)
Line No.Class and Series of Stock
(a)
Balance at End of Year
(b)
1 Common Stock 2,096,925
22 TOTAL 2,096,925
FERC FORM No. 1 (ED. 12-87)
Page 254b
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
LONG-TERM DEBT (Account 221, 222, 223 and 224)
Line
No.
Class and Series of Obligation, Coupon Rate (For new
issue, give commission Authorization numbers and dates)
(a)
Related Account
Number
(b)
Principal Amount of Debt Issued
(c)
Total Expense, Premium or
Discount
(d)
Total Expense
(e)
Total Premium
(f)
Total
Discount
(g)
1 Bonds (Account 221)
2 4.00% Series due 2043 221101 75,000,000 742,017 194,250
3 2.50% Series due 2023 221102 75,000,000 648,267 374,250
4 3.65% Series Due 2045 221107 250,000,000 2,559,510 1,715,000
5 (a)
4.20% Series Due 2048 221110 450,000,000 4,629,516 (31,654,900)814,000
6 4.99% PRP Due 2032 221111 23,000,000 75,000
7 5.06% PRP Due 2042 221112 25,000,000 76,304
8 5.875% Series due 2034 221116 55,000,000 585,759 748,000
9 6.00% Series due 2032 221133 100,000,000 1,191,216 544,000
10 5.30% Series Due 2035 221134 60,000,000 3,849,739 408,600
11 5.50% Series due 2033 221135 70,000,000 728,701 36,400
12 6.30% Series due 2037 221141 140,000,000 1,500,031 278,600
13 6.25% Series due 2037 221142 100,000,000 1,227,490 268,000
14 5.50% Series due 2034 221145 50,000,000 524,419 383,500
15 4.85% Series Due 2040 221146 100,000,000 1,284,871 170,000
16 4.30% Series Due 2042 221147 75,000,000 802,240 49,500
17 4.05% Series Due 2046 221148 120,000,000 1,311,383 309,600
18 1.90% Series Due 2030 221149 80,000,000 980,949 328,000
19 Port of Morrow Variable due 2027 221311 4,360,000 0
20 Humboldt 1.45 % Variable due 2024 221325 49,800,000 396,278
21 Sweetwater 1.7% Variable due 2026 221335 116,300,000 908,982
22 Subtotal 2,018,460,000 24,022,672 (31,654,900)6,621,700
23 Reacquired Bonds (Account 222)
24
25
26
27 Subtotal
28 Advances from Associated Companies (Account 223)
29
30
31
32 Subtotal
33 Other Long Term Debt (Account 224)
34 Bond Guarantee - American Falls 224200 19,885,000
35 Multi Year Note 224015 (b)150,000,000
36 Subtotal 169,885,000 0 0 0
33 TOTAL 2,188,345,000
FERC FORM No. 1 (ED. 12-96)
Page 256-257
LONG-TERM DEBT (Account 221, 222, 223 and 224)
Line
No.
Nominal Date of Issue
(h)
Date of Maturity
(i)
AMORTIZATION PERIOD Date From
(j)
AMORTIZATION PERIOD Date To
(k)
Outstanding (Total amount outstanding
without reduction for amounts held by
respondent)
(l)
Interest for Year Amount
(m)
1
2 04/08/2013 04/01/2043 04/08/2013 04/01/2043 75,000,000 3,000,000
3 04/08/2013 04/01/2023 04/08/2013 04/01/2023 75,000,000 1,875,000
4 03/06/2015 03/01/2045 03/06/2015 03/01/2045 250,000,000 9,125,000
5 03/16/2018 03/01/2048 03/16/2018 03/01/2048 450,000,000 18,900,000
6 12/22/2022 12/22/2032 12/22/2022 12/22/2032 23,000,000 28,693
7 12/22/2022 12/22/2042 12/22/2022 12/22/2042 25,000,000 31,625
8 08/16/2004 08/15/2034 08/16/2004 08/15/2034 55,000,000 3,231,250
9 11/15/2002 11/15/2032 11/15/2002 11/15/2032 100,000,000 6,000,000
10 08/26/2005 08/15/2035 08/26/2005 08/15/2035 60,000,000 3,180,000
11 05/13/2003 04/01/2033 05/13/2003 04/01/2033 70,000,000 3,850,000
12 06/22/2007 06/15/2037 06/22/2007 06/15/2037 140,000,000 8,820,000
13 10/18/2007 10/15/2037 10/18/2007 10/15/2037 100,000,000 6,250,000
14 03/26/2004 03/15/2034 03/26/2004 03/15/2034 50,000,000 2,750,000
15 08/30/2010 08/15/2040 08/30/2010 08/15/2040 100,000,000 4,850,000
16 04/13/2012 04/01/2042 04/13/2012 04/01/2042 75,000,000 3,225,000
17 03/10/2016 03/01/2046 03/10/2016 03/01/2046 120,000,000 4,860,000
18 06/22/2020 07/15/2030 06/22/2020 07/15/2030 80,000,000 1,520,000
19 05/17/2000 02/01/2027 05/17/2000 02/01/2027 0 53,813
20 08/21/2019 12/01/2024 08/21/2019 12/01/2024 49,800,000 722,100
21 08/21/2019 07/15/2026 08/21/2019 07/15/2026 116,300,000 1,977,100
22 2,014,100,000 84,249,581
23
24
25
26
27 0
28
29
30
31
32
33
34 04/26/2000 02/01/2025 04/26/2000 02/01/2025 19,885,000
35 03/04/2022 03/04/2024 03/04/2022 03/04/2024 150,000,000 3,009,161
36 169,885,000 3,009,161
33 2,183,985,000 87,258,742
FERC FORM No. 1 (ED. 12-96)
Page 256-257
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
FOOTNOTE DATA
(a) Concept: ClassAndSeriesOfObligationCouponRateDescription
Additional $230 million of 4.20% bonds due 3-1-2048 issued on 4-3-2020 with a premium of $31,654,900, bringing 4.20% series outstanding to $450 million.
(b) Concept: OtherLongTermDebtPrincipalAmountIssued
Multi year note: $50 million, issued 03-04-2022, due 03-04-2024
Multi year note: $100 million, issued 05-24-2022, due 03-04-2024
FERC FORM No. 1 (ED. 12-96)
Page 256-257
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
RECONCILIATION OF REPORTED NET INCOME WITH TAXABLE INCOME FOR FEDERAL INCOME TAXES
Line No.Particulars (Details)
(a)
Amount
(b)
1 Net Income for the Year (Page 117)254,866,668
2 Reconciling Items for the Year
3
4 Taxable Income Not Reported on Books
5 CONSTRUCTION ADVANCES 3,858,140
6 AVOIDED COST 7,774,547
7 CIAC - TAXABLE - ACCT 107 37,083,411
8 ENGINEERING FEES - TAXABLE - ACCT 107 80,497
9 BOARDMAN DECOMMISSION 465,904
10 VALMY SETTLEMENT ADJUSTMENT 6,436,592
9 Deductions Recorded on Books Not Deducted for Return
10 BAD DEBT EXPENSE 529,661
11 GAIN/LOSS ON REACQUIRED DEBT 273,234
12 VACATION ACCRUAL 1,761,221
13 COVID DEFERRAL ORD 34718 193,862
14 STOCK BASED COMPENSATION 2,611,006
15 FIXED COST ADJUSTMENT 13,043,217
16 PENSION EXPENSES - OREGON 1,099,750
17 ASSET RETIREMENT OBLIGATION (ARO)27,141
18 INCENTIVE DEFERRAL-PROFIT SHARING-NOT IN RATES 1,733,563
19 VALMY DEPRECIATION ADJUSTMENT 4,129,844
20 TAX REFORM REGULATORY STIPULATION 7,692,680
21 NON-DEDUCTIBLE POLITICAL EXPENSES 1,049,277
22 SMSP - NET 3,480,553
23 FINES & PENALTIES - OPERATING 2,019,200
24 PROV FOR RATE REFUND - HC RELICENSING (AFUDC)19,811,422
25 SOFT CAP BATTERY RESERVE 2,800,000
26 VEBA - POST RETIREMENT BENEFITS 3,108,060
27 DEPR TIMING DIFF - OPERATING - FEDERAL 187,668,672
28 CONSERVATION EXPENSES 4,286,340
29 GAIN/LOSS ON REACQUIRED DEBT 2,542,672
30 SOFTWARE - LABOR CONSTS DEDUCTED - ACCT 107 6,249,864
31 IPCO-162(m) $1M THRESHOLD 4,325,405
32 VALMY1 BOOK BASIS ADJUSTMENT 3,081,950
33 TOTAL FEDERAL & STATE TAXES DEDUCTED ON BOOKS 38,577,316
14 Income Recorded on Books Not Included in Return
15 SMSP - INSURANCE COSTS 6,823,106
16 REVERSE EQUITY EARNINGS OF SUBSIDIARIES 8,782,042
17 ALLOWANCE FOR OFUDC 37,285,494
18 ALLOWANCE FOR BFUDC 13,914,276
19 SMSP - INSURANCE PROCEEDS 119,851
19 Deductions on Return Not Charged Against Book Income
20 INJURIES AND DAMAGES 893,854
21 263A CAPITALIZED OVERHEADS 15,000,000
22 PENSION EXPENSE 24,886,366
23 PCA EXPENSE DEFERRAL 94,703,645
24 WILDFIRE MITIGATION 35077 DEFERRAL 18,095,358
25 AMORTIZATION OF ACCOUNT 181 293,633
26 OREGON - PCAM 1,068,787
27 INCENTIVE DEFERRAL - CRI & RELIABILITY-INCLUDED IN RATES 205,479
28 EMPLOYER FICA TAX DEFERRAL - CARES ACT 4,375,214
29 BRIDGER DEFRECIATION ADJUST - 283 37,722,674
30 STOCK BASED COMP - STOCK 151,605
31 REMOVAL COSTS 23,331,082
32 RELICENSING - LABOR COSTS DEDUCTED - ACCT 107 2,479,000
33 REPAIRS DEDUCTION 92,000,000
34 PREPAID INSURANCE & OTHER EXPENSES 104,500
35 STOCK BASED COMP - DIVIDENDS 616,140
36 OR CAT 296,388
37 STATE INCOME TAX DEDUCTED ON FEDERAL RETURN 14,020,477
FERC FORM NO. 1 (ED. 12-96)
Page 261
27 Federal Tax Net Income 225,492,698
28 Show Computation of Tax:
29 TENATIVE FEDERAL TAX @ 21%47,353,467
FERC FORM NO. 1 (ED. 12-96)
Page 261
RECONCILIATION OF REPORTED NET INCOME WITH TAXABLE INCOME FOR FEDERAL INCOME TAXES
Line No.Particulars (Details)
(a)
Amount
(b)
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
TAXES ACCRUED, PREPAID AND CHARGES DURING YEAR
BALANCE AT
BEGINNING
OF YEAR
BALANCE
AT
BEGINNING
OF YEAR
Line
No.
Kind of Tax (See Instruction 5)
(a)
Type of Tax
(b)
State
(c)
Tax Year
(d)
Taxes
Accrued
(Account 236)
(e)
Prepaid
Taxes
(Include in
Account
165)
(f)
1 Federal Income Tax (12,063,192)0
2 State Income Tax Idaho (3,811,564)0
3 State Income Tax Oregon 51,958 0
4 Other (a)
Income Tax Other 223,606 0
5 Subtotal Income Tax (15,599,192)0
6 Federal (b)
Other Taxes 4,271,242 0
7 Other (c)
Other Taxes Other 10,726 0
8 Subtotal Other Taxes 4,281,968 0
9 State (d)
Other State Tax Oregon 0 28,500
10 State (e)
Other State Tax Oregon 0 1,022
11 State (f)
Other State Tax Idaho 0 0
12 State (g)
Other State Tax Idaho 108,388 0
13 State (h)
Other State Tax Idaho 11,088 0
14 Subtotal Other State Tax 119,476 29,522
15 State (i)
Other License And Fees Tax Idaho 0 0
16 State (j)
Other License And Fees Tax Wyoming 0 0
17 Subtotal Other License And Fees Tax 0 0
18 Federal Unemployment Tax (1,974)0
19 State Unemployment Tax Idaho (2,289)0
20 State Unemployment Tax Oregon 0 0
21 Subtotal Unemployment Tax (4,263)0
22 State Property Tax Idaho 8,567,240 0
23 State Property Tax Oregon 0 2,579,143
24 State Property Tax Montana 221,345 0
25 State Property Tax Nevada 0 174,947
26 State Property Tax Wyoming 658,375 0
27 State Property Tax Washington 6,689 0
28 Subtotal Property Tax 9,453,649 2,754,090
29 State Franchise Tax Oregon 190,135 0
30 Subtotal Franchise Tax 190,135 0
31 Other Payroll Tax Other 0 0
32 Subtotal Payroll Tax 0 0
40 TOTAL (1,558,227)2,783,612
FERC FORM NO. 1 (ED. 12-96)
Page 262-263
TAXES ACCRUED, PREPAID AND CHARGES DURING YEAR
BALANCE AT END OF YEAR BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED
Line
No.
Taxes Charged During Year
(g)
Taxes Paid During Year
(h)
Adjustments
(i)
Taxes Accrued (Account 236)
(j)
Prepaid Taxes (Included in Account
165)
(k)
Electric (Account 408.1, 409.1)
(l)
1 42,613,732 42,545,362 0 (11,994,822)0 32,286,828
2 11,070,359 8,623,327 0 (1,364,532)0 10,931,530
3 909,272 444,400 0 516,830 0 880,742
4 30,853 12,212 0 242,247 0 29,177
5 54,624,216 51,625,301 0 (12,600,277)0 44,128,277
6 18,219,357 22,606,418 0 (115,819)0 18,219,357
7 0 171,279 91,194 (69,359)0 0
8 18,219,357 22,777,697 91,194 (185,178)0 18,219,357
9 290,260 337,332 75,572 0 0 290,260
10 1,858 1,671 0 0 835 0
11 2,616,251 2,616,251 0 0 0 2,616,251
12 1,162,897 1,190,847 0 80,438 0 1,162,897
13 34,888 28,697 0 17,279 0 0
14 4,106,154 4,174,798 75,572 97,717 835 4,069,408
15 150 150 0 0 0 150
16 4,090 4,090 0 0 0 4,090
17 4,240 4,240 0 0 0 4,240
18 94,333 94,585 0 (2,226)0 94,333
19 199,146 198,423 0 (1,566)0 199,146
20 45,401 45,160 0 241 0 45,401
21 338,880 338,168 0 (3,551)0 338,880
22 16,540,555 17,841,653 0 7,266,142 0 16,539,256
23 5,321,584 5,483,025 0 0 2,740,584 5,007,521
24 473,595 458,439 0 236,501 0 473,595
25 321,605 293,316 0 0 146,658 321,605
26 1,391,819 1,354,285 0 695,909 0 1,391,819
27 4,069 5,379 0 5,379 0 4,069
28 24,053,227 25,436,097 0 8,203,931 2,887,242 23,737,865
29 890,161 851,102 (292)228,902 0 890,161
30 890,161 851,102 (292)228,902 0 890,161
31 (18,558,238)0 18,558,238 0 0 (18,558,238)
32 (18,558,238)0 18,558,238 0 0 (18,558,238)
40 83,677,997 105,207,403 18,724,712 (4,258,456)2,888,077 72,829,950
FERC FORM NO. 1 (ED. 12-96)
Page 262-263
TAXES ACCRUED, PREPAID AND CHARGES DURING YEAR
DISTRIBUTION OF TAXES CHARGED DISTRIBUTION OF TAXES CHARGED DISTRIBUTION OF TAXES CHARGED
Line No.Extraordinary Items (Account 409.3)
(m)
Adjustment to Ret. Earnings (Account 439)
(n)
Other
(o)
1 0 0 10,326,904
2 0 0 138,829
3 0 0 28,530
4 0 0 1,677
5 0 0 10,495,940
6 0 0 0
7 0 0 0
8 0 0 0
9 0 0 0
10 0 0 1,858
11 0 0 0
12 0 0 0
13 0 0 34,888
14 0 0 36,746
15 0 0 0
16 0 0 0
17 0 0 0
18 0 0 0
19 0 0 0
20 0 0 0
21 0 0 0
22 0 0 1,299
23 0 0 314,062
24 0 0 0
25 0 0 0
26 0 0 0
27 0 0 0
28 0 0 315,361
29 0 0 0
30 0 0 0
31 0 0 0
32 0 0 0
40 0 0 10,848,047
FERC FORM NO. 1 (ED. 12-96)
Page 262-263
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
FOOTNOTE DATA
(a) Concept: TypeOfTax
Other States Income
(b) Concept: TypeOfTax
Social Security (FOAB)
(c) Concept: TypeOfTax
Canada GST Tax
(d) Concept: TypeOfTax
Regulatory Commission
(e) Concept: TypeOfTax
Non-Operating Property
(f) Concept: TypeOfTax
Regulatory Commission
(g) Concept: TypeOfTax
kwh
(h) Concept: TypeOfTax
Non-Operating
(i) Concept: TypeOfTax
Business License - Sho Ban
(j) Concept: TypeOfTax
Corporate License
FERC FORM NO. 1 (ED. 12-96)
Page 262-263
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255)
Deferred for Year Deferred for Year Allocations to Current
Year's Income Allocations to Current Year's Income
Line
No.
Account Subdivisions
(a)
Balance at Beginning of Year
(b)
Account No.
(c)
Amount
(d)
Account No.
(e)
Amount
(f)
1 Electric Utility
2 0.03 0
3 0.04 162,595 411.401 54,038
4 0.07
5 0.10 9,902,512 411.401 1,352,747
6 Other - Federal 24,455,018 333,433
7 Other - State 74,939,541 411.402 8,945,164 411.402 1,379,206
8 TOTAL Electric (Enter Total of lines 2 thru 7)109,459,666 8,945,164 3,119,424
9 Other (List separately and show 3%, 4%, 7%, 10% and TOTAL)
10 0.11 997,108 411.401 21,551
11 0.30 23,457,910 411.401 411.401 311,882
47 OTHER TOTAL 24,455,018 333,433
48 GRAND TOTAL 109,459,666
FERC FORM NO. 1 (ED. 12-89)
Page 266-267
ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255)
Line
No.
Adjustments
(g)
Balance at End of Year
(h)
Average Period of Allocation to Income
(i)
ADJUSTMENT EXPLANATION
(j)
1
2
3 108,557 3.01
4
5 8,549,765 7.32
6 24,121,585 75.21
7 82,505,500 54.34
8 0 115,285,407
9
10 975,557 46.27
11 23,146,028 75.21
47 24,121,585
48 115,285,406
FERC FORM NO. 1 (ED. 12-89)
Page 266-267
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
OTHER DEFERRED CREDITS (Account 253)
DEBITS DEBITS
Line
No.
Description and Other Deferred Credits
(a)
Balance at Beginning of Year
(b)
Contra Account
(c)
Amount
(d)
Credits
(e)
Balance at End of Year
(f)
1 PTP Transmission Deposits 253201 3,676,661 131 447,091 3,683,938 6,913,508
2 FTV Dark Fiber Rental 253202 66,666 400 66,666 0
3 Amortization period 03/98-02/23 0 0
4 Cogen Deposits 253360 147,000 147,000
5 Sho-Ban Scholarships 253480 97,500 242 15,000 82,500
6 Amortization period 01/05-12/27 0 0
7 Operations Accruals 253550 298,121 131 52,351 675,303 921,073
8 Postretirement Benefits 253960 1,538,657 401 90,302 1,628,959
9 Directors Deferred Compensation 3,230,565 3230565 311,682 253,497 3,172,380
10 253970-253999 0 0
47 TOTAL 9,055,170 892,790 4,703,040 12,865,420
FERC FORM NO. 1 (ED. 12-94)
Page 269
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
ACCUMULATED DEFERRED INCOME TAXES - OTHER PROPERTY (Account 282)
CHANGES DURING YEAR CHANGES DURING YEAR CHANGES DURING YEAR CHANGES DURING YEAR
Line
No.
Account
(a)
Balance at Beginning of Year
(b)
Amounts Debited to Account 410.1
(c)
Amounts Credited to Account 411.1
(d)
Amounts Debited to Account 410.2
(e)
Amounts Credited to Account
411.2
(f)
1 Account 282
2 Electric 268,007,852 3,055,469 37,538,689 0 0
3 Gas 0
4 Other (Specify)0
5 Total (Total of lines 2 thru 4)(a)268,007,852 3,055,469 37,538,689 0 0
6 0
7 Other - Regulatory Asset for Income Taxes (b)721,275,952
8 Like Kind Exchange - Reclass Non-Rate Base 4,522,631
9 TOTAL Account 282 (Total of Lines 5 thru 8)993,806,435 3,055,469 37,538,689 0 0
10 Classification of TOTAL
11 Federal Income Tax 790,831,352 2,980,972 37,309,587
12 State Income Tax 202,975,084 74,497 229,102
13 Local Income Tax 0
FERC FORM NO. 1 (ED. 12-96)
Page 274-275
ACCUMULATED DEFERRED INCOME TAXES - OTHER PROPERTY (Account 282)
ADJUSTMENTS ADJUSTMENTS ADJUSTMENTS ADJUSTMENTS
Debits Debits Credits Credits
Line
No.
Account Credited
(g)
Amount
(h)
Account Debited
(i)
Amount
(j)
Balance at End of Year
(k)
1
2 0 282/254 11,626,332 245,150,964
3 0
4 0
5 0 11,626,332 245,150,964
6 0
7 182 18,413,085 739,689,037
8 282 221,698 4,300,933
9 221,698 30,039,417 989,140,934
10
11 182/254 28,427,815 784,930,552
12 182 1,389,901 204,210,380
13
FERC FORM NO. 1 (ED. 12-96)
Page 274-275
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
FOOTNOTE DATA
(a) Concept: AccumulatedDeferredIncomeTaxesOtherProperty
2022 Changes during Year Adjustments Debits Adjustments Credits 2022
Beginning DR to CR to DR to CR to Acct.Acct.Ending
Line Account Balance 410.1 411.1 410.2 411.2 credited Amount debited Amount Balance
No.(a)b c d e f g h i j k
Line 2:Depreciation Timing Diff-Operating 440,440,535.25 2,949,725.26 29,734,203.14 0.00 0.00 0.00 0.00 413,656,057.37
Like Kind Exchange - Reclass Non-Rate Base (4,522,631.00)0.00 0.00 282111 221,698.00 (4,300,933.00)
Excess Deferred Tax on Depreciation (Reg Liab)(170,038,676.70)0.00 0.00 254967 11,404,633.10 (158,634,043.60)
4013 CIAC-Taxable-Acct 107 (11,756,879.40)1,109,993.85 7,787,516.31 (18,434,401.86)
4021 Engineering Fees-Taxable-Acct 107 (923,195.38)0.00 16,970.10 (940,165.48)
8059 Software-Labor Costs Deducted-Acct 107 1,461,305.79 (1,461,305.79)0.00 (0.00)
8072 Intangible-Labor Costs Deducted-Acct 107 13,347,393.57 457,056.39 0.00 13,804,449.96
TOTAL Line 2 268,007,852.13 3,055,469.71 37,538,689.55 0.00 0.00 0.00 11,626,331.10 245,150,963.39
(b) Concept: AccumulatedDeferredIncomeTaxesOtherProperty
2022 Changes during Year Adjustments Debits Adjustments Credits 2022
Beginning DR to CR to DR to CR to Acct.Acct.Ending
Line Account Balance 410.1 411.1 410.2 411.2 credited Amount debited Amount Balance
No.(a)b c d e f g h i j k
Line 7:
282135 ADIT-FAS109 Unfnd-State 199,465,124.45 182 1,389,900.99 200,855,025.44
282136 ADIT-FAS109 Unfnd-Fed 292,833,347.19 182 32,380,890.10 325,214,237.29
282137 ADIT-Contra-Def Inc Tax 228,977,480.07 182 (15,357,706.84)213,619,773.23
TOTAL Line 7 721,275,951.71 0.00 0.00 0.00 0.00 0.00 18,413,084.25 739,689,035.96
FERC FORM NO. 1 (ED. 12-96)
Page 274-275
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
ACCUMULATED DEFERRED INCOME TAXES - OTHER (Account 283)
CHANGES DURING YEAR CHANGES DURING YEAR CHANGES DURING YEAR CHANGES DURING YEAR
Line
No.
Account
(a)
Balance at Beginning of Year
(b)
Amounts Debited to Account 410.1
(c)
Amounts Credited to Account 411.1
(d)
Amounts Debited to Account 410.2
(e)
Amounts Credited to Account
411.2
(f)
1 Account 283
2 Electric
3 (a)
Other Electric 105,676,238 47,093,684 7,915,413
4 (b)
Other 81,866,507
9 TOTAL Electric (Total of lines 3 thru 8)187,542,745 47,093,684 7,915,413
10 Gas
11
12
13
14
15
16
17 TOTAL Gas (Total of lines 11 thru 16)
18 TOTAL Other (c)159,064 590 218,217
19 TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18)187,701,809 47,093,684 7,915,413 590 218,217
20 Classification of TOTAL
21 Federal Income Tax 143,971,522 36,116,135 6,061,728 453 167,351
22 State Income Tax 43,730,287 10,977,549 1,853,685 138 50,867
23 Local Income Tax
NOTES
FERC FORM NO. 1 (ED. 12-96)
Page 276-277
ACCUMULATED DEFERRED INCOME TAXES - OTHER (Account 283)
ADJUSTMENTS ADJUSTMENTS ADJUSTMENTS ADJUSTMENTS
Debits Debits Credits Credits
Line
No.
Account Credited
(g)
Amount
(h)
Account Debited
(i)
Amount
(j)
Balance at End of Year
(k)
1
2
3 190 16,464 190 352,814 145,190,859
4 190 (63,783,229)18,083,278
9 16,464 (63,430,415)163,274,137
10
11
12
13
14
15
16
17
18 (58,563)
19 16,464 (63,430,415)163,215,574
20
21 190 (48,915,344)124,943,687
22 190 (14,867,886)37,935,536
23
NOTES
FERC FORM NO. 1 (ED. 12-96)
Page 276-277
FOOTNOTE DATA
(a) Concept: DescriptionOfAccumulatedDeferredIncomeTaxOther
2022 Changes during Year Adjustments Debits Adjustments Credits 2022
Beginning DR to CR to DR to CR to Acct.Acct.Ending
Line Account Balance 410.1 411.1 410.2 411.2 credited Amount debited Amount Balance
No.(a)b c d e f g h i j k
Line 3:
4024 Renewable Energy Certificates (REC) Sales 1,013,088.05 0.00 177,441.01 835,647.04
4501 Royalty Income 211,113.32 36,332.52 0.00 247,445.84
5008 Gain/Loss on Reacquired Debt 282,499.87 0.00 70,330.42 212,169.45
5023 Pension Expense 56,287,372.02 6,405,750.62 0.00 62,693,122.64
5035 PCA Expense 9,014,690.86 24,376,718.23 276,042.97 33,115,366.12
5040 Covid Deferral (336,349.21)0.00 0.00 190 16,464.65 190 352,813.86 (0.00)
5045 Wildfire Mitigation 35077 Deferral 5,940,335.63 0.00 5,940,335.63
5057 Intervenor Funding Orders 80,767.23 7,955.46 0.00 88,722.69
5058 Fixed Cost Adjustment 14,142,642.98 0.26 3,357,324.06 10,785,319.18
5060 Oregon PCAM 3,969.90 275,105.77 12,069.23 267,006.44
5062 2011 LIDAR Surveys Deferral 11,223.64 0.00 11,223.66 (0.02)
5066 Boardman Decommission (322,383.21)0.00 119,923.68 (442,306.89)
5074 Valmy Settlement Adjustment 4,970,336.35 0.00 1,656,778.78 3,313,557.57
5075 EIM Deferral 2,557.01 0.00 2,557.00 0.01
5077 Valmy Depreciation Adjustment 17,808,796.62 0.00 1,063,021.84 16,745,774.78
5079 Community Solar Deferral 30,530.47 13,255.33 0.00 43,785.80
5081 EIM PCA Offset Estimate 0.00 24,096.77 (24,096.77)
5082 Bridger Depreciation Adjust - 283 9,709,816.28 0.00 9,709,816.28
7013 Langley Revenue Accrual 308,638.04 0.00 70,537.12 238,100.92
8020 Conservation Expenses 1,731,839.20 0.26 1,103,303.92 628,535.54
8081 Siemens LTP Contract 110,489.23 17,213.63 0.00 127,702.86
8082 Prepaid Credit Facility 97,661.18 27,619.53 0.00 125,280.71
8083 Siemens OR DRB Interest Reserve (41,993.80)0.00 7,653.52 (49,647.32)
8704 Boardman Removal Costs 163,583.11 279,084.40 0.00 442,667.51
8706 OR Annual Reg Exp 6,290.60 4,496.52 0.00 10,787.12
N/A Oregon CAT Deferral 98,875.00 0.00 (36,892.00)135,767.00
TOTAL Line 3 105,676,238.46 47,093,684.44 7,915,411.98 0.00 0.00 16,464.65 352,813.86 145,190,860.13
(b) Concept: DescriptionOfAccumulatedDeferredIncomeTaxOther
2022 Changes during Year Adjustments Debits Adjustments Credits 2022
Beginning DR to CR to DR to CR to Acct.Acct.Ending
Line Account Balance 410.1 411.1 410.2 411.2 credited Amount debited Amount Balance
No.(a)b c d e f g h i j k
Line 4:Pension-FAS 158 83,910,187.47 190 (62,468,685.40)21,441,502.07
Postretirement Plan-FAS 158 (2,043,681.19)190 (1,314,544.40)(3,358,225.59)
TOTAL Line 4 81,866,506.28 0.00 0.00 0.00 0.00 0.00 (63,783,229.80)18,083,276.48
(c) Concept: AccumulatedDeferredIncomeTaxesOther
2022 Changes during Year Adjustments Debits Adjustments Credits 2022
Beginning DR to CR to DR to CR to Acct.Acct.Ending
Line Account Balance 410.1 411.1 410.2 411.2 credited Amount debited Amount Balance
No.(a)b c d e f g h i j k
Line 18:
5503 EDC-Unrealized Gain/Loss From Rabbit Trust 11,918.91 584.81 0.00 12,503.72
5517 SMSP-Unrealized Gain/Loss From Rabbi Trust 146,887.63 0.00 218,217.55 (71,329.92)
8504 Oregon Non-Op Prop Tax Adj 257.66 5.41 0.00 263.07
TOTAL Line 18 159,064.20 0.00 0.00 590.22 218,217.55 0.00 0.00 (58,563.13)
FERC FORM NO. 1 (ED. 12-96)
Page 276-277
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
OTHER REGULATORY LIABILITIES (Account 254)
DEBITS DEBITS
Line
No.
Description and Purpose of Other Regulatory Liabilities
(a)
Balance at Beginning of Current
Quarter/Year
(b)
Account Credited
(c)
Amount
(d)
Credits
(e)
Balance at End of Current
Quarter/Year
(f)
1 Market to Market Short Term (254001)7,691,029 51,274,705 58,965,734
2 IPUC Order #28661 0 0
3 Oregon Solar Rider (254005)190,798 401 11,909 108,284 287,173
4 OPUC Order #10-198 0 0
5 BPA Credit Residential Idaho (254401)1,135,564 142 15,856,445 16,742,534 2,021,653
6 OPUC Advice #15-13 0 0
7 BPA Credit Residential Oregon (254402)140,030 142 622,434 573,650 91,246
8 OPUC Advice #15-11 0 0
9 BPA Credit Farm Idaho (254403)300,180 142 2,047,759 2,533,914 786,335
10 OPUC Advice #15-13 0 0
11 BPA Credit Farm Oregon (254404)150,481 142 175,393 144,024 119,112
12 OPUC Advice #15-11 0 0
13 Idaho Tax Settlement (254451)24,522,500 7,692,680 32,215,180
14 IPUC Order #34071 0 0
15 Oregon Tax Settlement (254452)578,057 578,057
16 OPUC Order #18-199 0 0
17 Bridger Depreciation (254800)4,329,583 400 1,044,197 619,349 3,904,735
18 OPUC Order #12-296 0 0
19 RL-WAQC CRYOVR (254901)893,485 401 72,236 350,155 1,171,404
20 Revenue Sharing (254101)568,771 1823 568,771 0 0
21 Unfunded Accum Def Income Tax (254966)37,940,907 Various 329,578 2,348,896 39,960,225
22 RL-DEF INC TAX-ARAM (254967)170,038,677 282 11,404,633 158,634,044
23 RL-DEF INC TAX-ARAM GROSS-UP (254968)58,938,803 190 3,953,074 54,985,729
24 (a)
Boardman Decommissioning 2,766,950 Various 1,522,090 1,987,994 3,232,854
25 OPUC Order #12-235, IPUC Order #32457 0 0
26 Market-to-Market Short Term (254203)890,345 175 311,907 578,438
27 Oregon DSM Rider (254202)0 Various 1,301,657 1,455,709 154,052
28 OPUC Advice #05-03 0
29 Minor items (1)12,674 Various 2,038 14,712
41 TOTAL 311,088,834 39,222,083 85,833,932 357,700,683
FERC FORM NO. 1 (REV 02-04)
Page 278
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
FOOTNOTE DATA
(a) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities
The Boardman Decommissioning is composed of multiple accounts aggregated into one line for clean presentation in the year-end financial statements.
FERC FORM NO. 1 (REV 02-04)
Page 278
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
Electric Operating Revenues
Line
No.
Title of Account
(a)
Operating Revenues Year to Date
Quarterly/Annual
(b)
Operating Revenues Previous
year (no Quarterly)
(c)
MEGAWATT HOURS SOLD Year to
Date Quarterly/Annual
(d)
MEGAWATT HOURS SOLD
Amount Previous year (no
Quarterly)
(e)
AVG.NO. CUSTOMERS PER
MONTH Current Year (no
Quarterly)
(f)
AVG.NO.
CUSTOMERS
PER MONTH
Previous
Year (no
Quarterly)
(g)
1 Sales of Electricity
2 (440) Residential Sales 647,174,173 584,718,584 6,056,124 5,644,996 512,803 499,216
3 (442) Commercial and Industrial Sales
4 Small (or Comm.) (See Instr. 4)517,216,222 481,561,025 6,230,687 6,261,255 94,237 92,932
5 Large (or Ind.) (See Instr. 4)218,518,077 196,176,848 3,509,694 3,471,486 126 127
6 (444) Public Street and Highway Lighting 4,035,747 3,946,139 25,950 28,062 4,431 4,118
7 (445) Other Sales to Public Authorities
8 (446) Sales to Railroads and Railways
9 (448) Interdepartmental Sales
10 TOTAL Sales to Ultimate Consumers 1,386,944,219 1,266,402,596 15,822,455 15,405,799 611,597 596,393
11 (447) Sales for Resale 145,798,279 90,426,613 1,318,132 1,339,089
12 TOTAL Sales of Electricity 1,532,742,498 1,356,829,209 17,140,587 16,744,888 611,597 596,393
13 (Less) (449.1) Provision for Rate Refunds 8,780,127 9,348,898
14 TOTAL Revenues Before Prov. for Refunds 1,523,962,371 1,347,480,311 17,140,587 16,744,888 611,597 596,393
15 Other Operating Revenues
16 (450) Forfeited Discounts
17 (451) Miscellaneous Service Revenues (a)4,936,204 (c)4,655,727
18 (453) Sales of Water and Water Power
19 (454) Rent from Electric Property 18,827,074 18,384,621
20 (455) Interdepartmental Rents
21 (456) Other Electric Revenues (b)34,010,537 (d)30,722,858
22 (456.1) Revenues from Transmission of Electricity of
Others 60,797,833 54,924,770
23 (457.1) Regional Control Service Revenues
24 (457.2) Miscellaneous Revenues
25 Other Miscellaneous Operating Revenues
26 TOTAL Other Operating Revenues 118,571,648 108,687,976
27 TOTAL Electric Operating Revenues 1,642,534,019 1,456,168,287
Line12, column (b) includes $ 10,163,761 of unbilled revenues.
Line12, column (d) includes 43,833 MWH relating to unbilled revenues
FERC FORM NO. 1 (REV. 12-05)
Page 300-301
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
FOOTNOTE DATA
(a) Concept: MiscellaneousServiceRevenues
This amount consists of:
Service Establishment/Connection Charges: $4,305,005
(Includes late and after hour charges)
Misc. Under $250,000: $631,199
(b) Concept: OtherElectricRevenue
This amount consists of:
DSM Activity: $33,197,113
Alternate Distribution Services: $813,619
Misc. Under $250,000: ($195.00)
(c) Concept: MiscellaneousServiceRevenues
This amount consists of:
Service Establishment/Connection Charges $ 4,231,000
(Includes late and after hour charges)
Misc. Under $250,000 424,727
Total Account 451 $ 4,655,727
(d) Concept: OtherElectricRevenue
This amount consists of:
DSM Activity $ 29,920,448
Alternate distribution Service 802,320
Misc. Under $250,000 90
Total Account 456 $ 30,722,858
FERC FORM NO. 1 (REV. 12-05)
Page 300-301
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
Line
No.
Number and Title of Rate Schedule
(a)
MWh Sold
(b)
Revenue
(c)
Average Number of Customers
(d)
KWh of Sales Per Customer
(e)
Revenue Per KWh Sold
(f)
1 01 RESIDENTIAL 5,936,371 645,478,203 500,657 11,857.1617 0.1087
2 03 Residential Master Meter 5,216 540,908 19 274,526.3158 0.1037
3 04 Residential EW 0 0 0
4 05 Residential TOD 18,088 1,894,809 980 18,457.1429 0.1048
5 06 Residential On-Site Generation 60,920 6,993,531 11,147 5,465.1476 0.1148
6 15 Dusk to Dawn Light 1,611 646,096 0 0.4011
7 Other 0 (14,858,671)0
41 TOTAL Billed Residential Sales 6,022,206 640,694,876 512,803 11,743.7027 0.1064
42 TOTAL Unbilled Rev. (See Instr. 6)33,918 6,479,297 0.191
43 TOTAL 6,056,124 647,174,173 512,803 11,809.8451 0.1069
FERC FORM NO. 1 (ED. 12-95)
Page 304
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
Line
No.
Number and Title of Rate Schedule
(a)
MWh Sold
(b)
Revenue
(c)
Average Number of Customers
(d)
KWh of Sales Per Customer
(e)
Revenue Per KWh Sold
(f)
1 07 General Service 162,424 21,325,804 32,358 5,019.5933 0.1313
2 08 General Service On-Site Generation 157 23,049 65 2,415.3846 0.1468
3 09P General Service 638,610 45,239,977 290 2,202,103.4483 0.0708
4 09S General Service 3,443,534 275,351,853 38,310 89,886.035 0.08
5 09T General Service 9,999 706,357 5 1,999,800 0.0706
6 15 Dusk to Dawn Light 2,814 754,238 0 0.268
7 24S Irrigation & Pump 1,949,766 172,140,765 21,995 88,645.8741 0.0883
8 24T Irrigation & Pump 0 0 0
9 40 General Service 13,586 1,223,882 1,214 11,191.1038 0.0901
41 TOTAL Billed Small or Commercial 6,220,890 516,765,925 94,237 66,013.2432 0.0831
42 TOTAL Unbilled Rev. Small or Commercial (See Instr. 6)9,797 450,297 0.046
43 TOTAL Small or Commercial 6,230,687 517,216,222 94,237 66,117.2045 0.083
FERC FORM NO. 1 (ED. 12-95)
Page 304
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
Line
No.
Number and Title of Rate Schedule
(a)
MWh Sold
(b)
Revenue
(c)
Average Number of Customers
(d)
KWh of Sales Per Customer
(e)
Revenue Per KWh Sold
(f)
1 19P Uniform Rate 2,419,263 153,066,982 119 20,329,941.1765 0.0633
2 19S Uniform Rate 2,393 176,980 1 2,393,000 0.074
3 19T Uniform Rate 141,257 9,352,581 3 47,085,666.6667 0.0662
4 Special Contracts 946,593 53,926,970 3 315,531,000 0.057
5 Other 0 (1,225,863)0
41 TOTAL Billed Large (or Ind.) Sales 3,509,506 215,297,650 126 27,853,222.2222 0.0613
42 TOTAL Unbilled Rev. Large (or Ind.) (See Instr. 6)188 3,220,427 17.1299
43 TOTAL Large (or Ind.)3,509,694 218,518,077 126 27,854,714.2857 0.0623
FERC FORM NO. 1 (ED. 12-95)
Page 304
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
Line
No.
Number and Title of Rate Schedule
(a)
MWh Sold
(b)
Revenue
(c)
Average Number of Customers
(d)
KWh of Sales Per Customer
(e)
Revenue Per KWh Sold
(f)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41 TOTAL Billed Commercial and Industrial Sales
42 TOTAL Unbilled Rev. (See Instr. 6)
43 TOTAL
FERC FORM NO. 1 (ED. 12-95)
Page 304
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
Line
No.
Number and Title of Rate Schedule
(a)
MWh Sold
(b)
Revenue
(c)
Average Number of Customers
(d)
KWh of Sales Per Customer
(e)
Revenue Per KWh Sold
(f)
1 40 General Service 787 72,991 493 1,596.3489 0.0927
2 41 Municipal Lighting (A,B,C)22,263 3,742,827 3,152 7,063.1345 0.1681
3 42 Signal Lighting 2,970 204,808 786 3,778.626 0.069
4 Other 0 1,381 0
41 TOTAL Billed Public Street and Highway Lighting 26,020 4,022,007 4,431 5,872.2636 0.1546
42 TOTAL Unbilled Rev. (See Instr. 6)(70)13,740 (0.1963)
43 TOTAL 25,950 4,035,747 4,431 5,856.4658 0.1555
FERC FORM NO. 1 (ED. 12-95)
Page 304
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
Line
No.
Number and Title of Rate Schedule
(a)
MWh Sold
(b)
Revenue
(c)
Average Number of Customers
(d)
KWh of Sales Per Customer
(e)
Revenue Per KWh Sold
(f)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41 TOTAL Billed Provision For Rate Refunds
42 TOTAL Unbilled Rev. (See Instr. 6)0 0
43 TOTAL 8,780,127
FERC FORM NO. 1 (ED. 12-95)
Page 304
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
Line
No.
Number and Title of Rate Schedule
(a)
MWh Sold
(b)
Revenue
(c)
Average Number of Customers
(d)
KWh of Sales Per Customer
(e)
Revenue Per KWh Sold
(f)
41 TOTAL Billed - All Accounts 15,778,622 1,376,780,458 611,597 25,799.0507 0.0873
42 TOTAL Unbilled Rev. (See Instr. 6) - All Accounts 43,833 10,163,761 0.2319
43 TOTAL - All Accounts 15,822,455 1,386,944,219 611,597 25,870.7204 0.0877
FERC FORM NO. 1 (ED. 12-95)
Page 304
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
SALES FOR RESALE (Account 447)
ACTUAL DEMAND (MW)ACTUAL DEMAND (MW)
Line
No.
Name of Company or Public Authority (Footnote Affiliations)
(a)
Statistical Classification
(b)
FERC Rate Schedule or
Tariff Number
(c)
Average Monthly Billing Demand (MW)
(d)
Average Monthly NCP Demand
(e)
Average Monthly CP Demand
(f)
1 3PR Trading Inc SF WSPP
2 ADM Investor Services, Inc.(a)
OS WSPP
3 AmpRenew Offtake 1 LLC (b)
OS OATT
4 Avangrid Renewables, LLC (c)
OS OATT
5 AVANGRID RENEWABLES, LLC SF WSPP
6 Avista Corp.SF WSPP
7 Avista Corp. - WWP Div.(d)
OS OATT
8 Black Hills Power Inc.(e)
OS OATT
9 Black Hills Power Inc.SF WSPP
10 Bonneville Power Administration (f)
OS OATT
11 Bonneville Power Administration SF WSPP
12 BP Energy Company SF WSPP
13 Brookfield Renewable Trading and Marketing LP (g)
OS OATT
14 Brookfield Renewable Trading and Marketing LP SF WSPP
15 California Independent System Operator (h)
OS CAISO
16 Calpine Energy Solutions LLC SF WSPP
17 Chelan Co PUD SF WSPP
18 Citigroup Energy Inc.SF ISDA
19 Clatskanie PUD SF WSPP
20 Clean Power Alliance of Southern California SF WSPP
21 ConocoPhillips Company (i)
OS OATT
22 ConocoPhillips Company SF WSPP
23 CP Energy Marking Inc (j)
OS OATT
24 DTE Energy Trading, Inc.SF WSPP
25 Dynasty Power Inc.(k)
OS OATT
26 Dynasty Power Inc.SF WSPP
27 EDF Trading North America, LLC (l)
OS OATT
28 EDF Trading North America, LLC SF WSPP
29 Energy Keepers, Inc SF WSPP
30 Energy Keepers, Inc.(m)
OS OATT
31 Eugene Water & Electric Board SF WSPP
32 Guzman Energy Group LLC (n)
OS OATT
33 Guzman Energy Group LLC SF WSPP
34 Macquarie Energy LLC (o)
OS OATT
35 Macquarie Energy LLC SF WSPP
36 MAG Energy Solutions (p)
OS OATT
37 Mercuria Energy America, LLC (q)
OS OATT
38 Morgan Stanley Capital Group Inc.(r)
OS OATT
39 Morgan Stanley Capital Group Inc.SF ISDA
40 Nevada Power Company, dba NV Energy (s)
OS OATT
41 Nevada Power Company, dba NV Energy SF WSPP
42 NextEra Energy Marketing, LLC SF WSPP
43 NorthWestern Energy (t)
OS OATT
44 NorthWestern Energy SF WSPP
45 PacifiCorp Inc.(u)
OS T-7
46 PacifiCorp Inc.(v)
OS WSPP
47 PacifiCorp Inc.SF WSPP
48 PacifiCorp Inc.(w)
OS OATT
49 Portland General Electric Company (x)
OS OATT
50 Portland General Electric Company SF WSPP
FERC FORM NO. 1 (ED. 12-90)
Page 310-311
51 Powerex Corp.(y)
OS OATT
52 Powerex Corp.SF WSPP
53 Public Service Company of Colorado SF WSPP
54 Puget Sound Energy, Inc.SF WSPP
55 Rainbow Energy Marketing Corporation (z)
OS OATT
56 Rainbow Energy Marketing Corporation SF WSPP
57 Seattle City Light SF WSPP
58 Shell Energy North America (US), L.P.(aa)
OS OATT
59 Shell Energy North America (US), L.P.SF WSPP
60 Sierra Pacific Power Co., dba NV Energy (ab)
OS T-7
61 Sierra Pacific Power Co., dba NV Energy (ac)
OS WSPP
62 Snohomish County PUD SF WSPP
63 Tenaska Power Services Co.(ad)
OS OATT
64 Tenaska Power Services Co.SF WSPP
65 The Energy Authority, Inc.(ae)
OS OATT
66 The Energy Authority, Inc.SF WSPP
67 TransAlta Energy Marketing (U.S.) Inc.(af)
OS OATT
68 TransAlta Energy Marketing (U.S.) Inc.SF WSPP
69 Transmission Penalty Distribution (ag)
OS -
70 Utah Associated Municipal Power Systems (ah)
OS OATT
71 Utah Associated Municipal Power Systems SF WSPP
72 Vitol Inc.(ai)
OS OATT
73 Vitol Inc.SF WSPP
74 Western Area Power Administration (WACM)(aj)
OS T-7
75 Western Area Power Administration (WACM)(ak)
OS WSPP
15 Subtotal - RQ
16 Subtotal-Non-RQ
17 Total
FERC FORM NO. 1 (ED. 12-90)
Page 310-311
SALES FOR RESALE (Account 447)
ACTUAL DEMAND (MW)ACTUAL DEMAND (MW)
Line
No.
Name of Company or Public Authority (Footnote Affiliations)
(a)
Statistical Classification
(b)
FERC Rate Schedule or
Tariff Number
(c)
Average Monthly Billing Demand (MW)
(d)
Average Monthly NCP Demand
(e)
Average Monthly CP Demand
(f)
SALES FOR RESALE (Account 447)
REVENUE REVENUE REVENUE
Line
No.
Megawatt Hours Sold
(g)
Demand Charges ($)
(h)
Energy Charges ($)
(i)
Other Charges ($)
(j)
Total ($) (h+i+j)
(k)
1 436,400 0 54,269,328 0 54,269,328
2 0 0 0 (6,248,728)(6,248,728)
3 0 0 0 6,185 6,185
4 0 0 0 39,459 39,459
5 13,566 0 638,390 0 638,390
6 3,961 0 607,595 0 607,595
7 0 0 0 6,421 6,421
8 0 0 0 (52)(52)
9 1,205 0 10,118 0 10,118
10 0 0 0 7,277,315 7,277,315
11 65,744 0 8,642,246 0 8,642,246
12 8,201 0 2,341,257 0 2,341,257
13 0 0 0 1,355 1,355
14 76 0 17,040 0 17,040
15 25,069 0 10,004,984 0 10,004,984
16 75 0 8,987 0 8,987
17 6,424 0 295,642 0 295,642
18 11,600 0 233,074 0 233,074
19 537 0 36,255 0 36,255
20 116,600 0 12,213,130 0 12,213,130
21 0 0 0 1,528 1,528
22 72,309 0 13,846,247 0 13,846,247
23 0 0 0 1,453 1,453
24 233,600 0 13,180,770 0 13,180,770
25 0 0 0 511,764 511,764
26 43 0 5,022 0 5,022
27 0 0 0 1,524 1,524
28 576 0 2,904 0 2,904
29 236 0 19,072 0 19,072
30 0 0 0 32,390 32,390
31 2,302 0 158,003 0 158,003
32 0 0 0 26,990 26,990
33 165 0 3,565 0 3,565
34 0 0 0 152,603 152,603
35 310 0 21,021 0 21,021
36 0 0 0 281,341 281,341
37 0 0 0 140,937 140,937
38 0 0 0 1,477,668 1,477,668
39 5,719 0 394,295 0 394,295
40 0 0 0 (27,716)(27,716)
41 1,671 0 87,016 0 87,016
42 500 0 24,320 0 24,320
43 0 0 0 333 333
44 2,391 0 263,500 0 263,500
45 17 0 0 359 359
46 38 0 0 3,136 3,136
47 2,804 0 158,695 0 158,695
48 0 0 0 5,668,022 5,668,022
49 0 0 0 85,153 85,153
50 27,931 0 1,402,557 0 1,402,557
51 0 0 0 1,991,580 1,991,580
52 2,241 0 42,288 0 42,288
53 3,635 0 1,018,514 0 1,018,514
54 6,654 0 628,401 0 628,401
55 0 0 0 218,998 218,998
56 2,250 0 81,339 0 81,339
57 1,761 0 151,515 0 151,515
58 0 0 0 949,702 949,702
59 32,094 0 1,956,792 0 1,956,792
60 21 0 0 1,744 1,744
61 3 0 0 230 230
FERC FORM NO. 1 (ED. 12-90)
Page 310-311
62 460 0 26,525 0 26,525
63 0 0 0 219,151 219,151
64 7,966 467,630 0 467,630
65 0 0 0 413,332 413,332
66 4,300 271,610 0 271,610
67 0 0 0 142,809 142,809
68 7,515 675,251 0 675,251
69 0 0 0 11,935 11,935
70 0 0 0 17,573 17,573
71 50 2,000 0 2,000
72 0 0 0 91,674 91,674
73 208,750 0 8,063,885 0 8,063,885
74 210 0 0 15,117 15,117
75 152 0 0 14,211 14,211
15 0
16 1,318,132 0 132,270,783 13,527,496 145,798,279
17 1,318,132 0 132,270,783 13,527,496 145,798,279
FERC FORM NO. 1 (ED. 12-90)
Page 310-311
SALES FOR RESALE (Account 447)
REVENUE REVENUE REVENUE
Line
No.
Megawatt Hours Sold
(g)
Demand Charges ($)
(h)
Energy Charges ($)
(i)
Other Charges ($)
(j)
Total ($) (h+i+j)
(k)
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
FOOTNOTE DATA
(a) Concept: StatisticalClassificationCode
ADM Investor Services, Inc Futures Account Document, dated May 6, 2015
(b) Concept: StatisticalClassificationCode
Financial Transmission Losses
(c) Concept: StatisticalClassificationCode
Financial Transmission Losses
(d) Concept: StatisticalClassificationCode
Financial Transmission Losses
(e) Concept: StatisticalClassificationCode
Financial Transmission Losses
(f) Concept: StatisticalClassificationCode
Financial Transmission Losses
(g) Concept: StatisticalClassificationCode
Financial Transmission Losses
(h) Concept: StatisticalClassificationCode
Includes actual billing and estimate accrual
(i) Concept: StatisticalClassificationCode
Financial Transmission Losses
(j) Concept: StatisticalClassificationCode
Financial Transmission Losses
(k) Concept: StatisticalClassificationCode
Financial Transmission Losses
(l) Concept: StatisticalClassificationCode
Financial Transmission Losses
(m) Concept: StatisticalClassificationCode
Financial Transmission Losses
(n) Concept: StatisticalClassificationCode
Financial Transmission Losses
(o) Concept: StatisticalClassificationCode
Financial Transmission Losses
(p) Concept: StatisticalClassificationCode
Financial Transmission Losses
(q) Concept: StatisticalClassificationCode
Financial Transmission Losses
(r) Concept: StatisticalClassificationCode
Financial Transmission Losses
(s) Concept: StatisticalClassificationCode
Financial Transmission Losses
(t) Concept: StatisticalClassificationCode
Financial Transmission Losses
(u) Concept: StatisticalClassificationCode
Spinning or Operating Reserves
(v) Concept: StatisticalClassificationCode
Spinning or Operating Reserves
(w) Concept: StatisticalClassificationCode
Financial Transmission Losses
(x) Concept: StatisticalClassificationCode
Financial Transmission Losses
(y) Concept: StatisticalClassificationCode
Financial Transmission Losses
(z) Concept: StatisticalClassificationCode
Financial Transmission Losses
(aa) Concept: StatisticalClassificationCode
Financial Transmission Losses
(ab) Concept: StatisticalClassificationCode
Spinning or Operating Reserves
(ac) Concept: StatisticalClassificationCode
Spinning or Operating Reserves
(ad) Concept: StatisticalClassificationCode
Financial Transmission Losses
(ae) Concept: StatisticalClassificationCode
Financial Transmission Losses
(af) Concept: StatisticalClassificationCode
Financial Transmission Losses
(ag) Concept: StatisticalClassificationCode
Transmission penalty distribution credits
(ah) Concept: StatisticalClassificationCode
Financial Transmission Losses
(ai) Concept: StatisticalClassificationCode
Financial Transmission Losses
(aj) Concept: StatisticalClassificationCode
Spinning or Operating Reserves
(ak) Concept: StatisticalClassificationCode
Spinning or Operating Reserves
FERC FORM NO. 1 (ED. 12-90)
Page 310-311
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
Line No.Account
(a)
Amount for Current Year
(b)
Amount for Previous Year (c)
(c)
1 1. POWER PRODUCTION EXPENSES
2 A. Steam Power Generation
3 Operation
4 (500) Operation Supervision and Engineering 632,248 900,983
5 (501) Fuel 105,551,917 95,323,833
6 (502) Steam Expenses 9,298,487 9,231,056
7 (503) Steam from Other Sources 0 0
8 (Less) (504) Steam Transferred-Cr.0 0
9 (505) Electric Expenses 1,128,466 1,282,126
10 (506) Miscellaneous Steam Power Expenses 8,586,281 8,485,407
11 (507) Rents 229,461 216,915
12 (509) Allowances 0 0
13 TOTAL Operation (Enter Total of Lines 4 thru 12)125,426,860 115,440,320
14 Maintenance
15 (510) Maintenance Supervision and Engineering (238,936)(1,754)
16 (511) Maintenance of Structures 2,540,010 1,278,996
17 (512) Maintenance of Boiler Plant 8,774,081 8,910,438
18 (513) Maintenance of Electric Plant 2,306,519 2,692,331
19 (514) Maintenance of Miscellaneous Steam Plant 9,592,111 8,056,749
20 TOTAL Maintenance (Enter Total of Lines 15 thru 19)22,973,785 20,936,760
21 TOTAL Power Production Expenses-Steam Power (Enter Total of Lines 13 & 20)148,400,645 136,377,080
22 B. Nuclear Power Generation
23 Operation
24 (517) Operation Supervision and Engineering 0 0
25 (518) Fuel 0 0
26 (519) Coolants and Water 0 0
27 (520) Steam Expenses 0 0
28 (521) Steam from Other Sources 0 0
29 (Less) (522) Steam Transferred-Cr.0 0
30 (523) Electric Expenses 0 0
31 (524) Miscellaneous Nuclear Power Expenses 0 0
32 (525) Rents 0 0
33 TOTAL Operation (Enter Total of lines 24 thru 32)0 0
34 Maintenance
35 (528) Maintenance Supervision and Engineering 0 0
36 (529) Maintenance of Structures 0 0
37 (530) Maintenance of Reactor Plant Equipment 0 0
38 (531) Maintenance of Electric Plant 0 0
39 (532) Maintenance of Miscellaneous Nuclear Plant 0 0
40 TOTAL Maintenance (Enter Total of lines 35 thru 39)0 0
41 TOTAL Power Production Expenses-Nuclear. Power (Enter Total of lines 33 & 40)0 0
42 C. Hydraulic Power Generation
43 Operation
44 (535) Operation Supervision and Engineering 5,758,397 5,427,508
45 (536) Water for Power 6,627,500 5,677,053
46 (537) Hydraulic Expenses 18,433,658 16,085,623
47 (538) Electric Expenses 1,959,732 1,781,395
48 (539) Miscellaneous Hydraulic Power Generation Expenses 5,131,196 4,915,529
49 (540) Rents 303,402 306,561
50 TOTAL Operation (Enter Total of Lines 44 thru 49)38,213,885 34,193,669
51 C. Hydraulic Power Generation (Continued)
52 Maintenance
53 (541) Mainentance Supervision and Engineering 110,982 134,378
54 (542) Maintenance of Structures 932,291 993,194
55 (543) Maintenance of Reservoirs, Dams, and Waterways 454,092 596,164
56 (544) Maintenance of Electric Plant 2,611,843 2,630,296
57 (545) Maintenance of Miscellaneous Hydraulic Plant 3,919,209 3,066,271
58 TOTAL Maintenance (Enter Total of lines 53 thru 57)8,028,417 7,420,303
59 TOTAL Power Production Expenses-Hydraulic Power (Total of Lines 50 & 58)46,242,302 41,613,972
60 D. Other Power Generation
FERC FORM NO. 1 (ED. 12-93)
Page 320-323
61 Operation
62 (546) Operation Supervision and Engineering 627,106 590,913
63 (547) Fuel 124,658,377 85,225,955
64 (548) Generation Expenses 4,902,489 4,772,834
64.1 (548.1) Operation of Energy Storage Equipment
65 (549) Miscellaneous Other Power Generation Expenses 9,124 1,475,129
66 (550) Rents 0 0
67 TOTAL Operation (Enter Total of Lines 62 thru 67)130,197,096 92,064,831
68 Maintenance
69 (551) Maintenance Supervision and Engineering 0 0
70 (552) Maintenance of Structures 159,030 163,959
71 (553) Maintenance of Generating and Electric Plant 927,810 72,744
71.1 (553.1) Maintenance of Energy Storage Equipment
72 (554) Maintenance of Miscellaneous Other Power Generation Plant 6,730,627 2,184,732
73 TOTAL Maintenance (Enter Total of Lines 69 thru 72)7,817,467 2,421,435
74 TOTAL Power Production Expenses-Other Power (Enter Total of Lines 67 & 73)138,014,563 94,486,266
75 E. Other Power Supply Expenses
76 (555) Purchased Power 533,032,204 386,658,508
76.1 (555.1) Power Purchased for Storage Operations
77 (556) System Control and Load Dispatching 0 355
78 (557) Other Expenses (94,515,705)(44,579,887)
79 TOTAL Other Power Supply Exp (Enter Total of Lines 76 thru 78)438,516,499 342,078,976
80 TOTAL Power Production Expenses (Total of Lines 21, 41, 59, 74 & 79)771,174,009 614,556,294
81 2. TRANSMISSION EXPENSES
82 Operation
83 (560) Operation Supervision and Engineering 3,193,933 2,899,726
85 (561.1) Load Dispatch-Reliability 20,864 38,058
86 (561.2) Load Dispatch-Monitor and Operate Transmission System 2,721,791 2,930,439
87 (561.3) Load Dispatch-Transmission Service and Scheduling 1,175,087 871,560
88 (561.4) Scheduling, System Control and Dispatch Services 18,769 12,934
89 (561.5) Reliability, Planning and Standards Development 0 0
90 (561.6) Transmission Service Studies 0 76,035
91 (561.7) Generation Interconnection Studies 124,783 103,680
92 (561.8) Reliability, Planning and Standards Development Services 1,314,282 1,266,365
93 (562) Station Expenses 2,788,678 3,030,864
93.1 (562.1) Operation of Energy Storage Equipment
94 (563) Overhead Lines Expenses 1,121,678 1,055,067
95 (564) Underground Lines Expenses 0
96 (565) Transmission of Electricity by Others 11,322,964 7,022,556
97 (566) Miscellaneous Transmission Expenses 8 0
98 (567) Rents 4,855,402 4,568,113
99 TOTAL Operation (Enter Total of Lines 83 thru 98)28,658,239 23,875,397
100 Maintenance
101 (568) Maintenance Supervision and Engineering 206,814 184,291
102 (569) Maintenance of Structures 43,860 0
103 (569.1) Maintenance of Computer Hardware 40,374 39,953
104 (569.2) Maintenance of Computer Software 1,795,651 1,461,285
105 (569.3) Maintenance of Communication Equipment 27,750 27,006
106 (569.4) Maintenance of Miscellaneous Regional Transmission Plant 0 0
107 (570) Maintenance of Station Equipment 2,611,391 1,774,304
107.1 (570.1) Maintenance of Energy Storage Equipment
108 (571) Maintenance of Overhead Lines 2,274,243 1,126,974
109 (572) Maintenance of Underground Lines 0 0
110 (573) Maintenance of Miscellaneous Transmission Plant 5,113 2,545
111 TOTAL Maintenance (Total of Lines 101 thru 110)7,005,196 4,616,358
112 TOTAL Transmission Expenses (Total of Lines 99 and 111)35,663,435 28,491,755
113 3. REGIONAL MARKET EXPENSES
114 Operation
115 (575.1) Operation Supervision
116 (575.2) Day-Ahead and Real-Time Market Facilitation
117 (575.3) Transmission Rights Market Facilitation
118 (575.4) Capacity Market Facilitation
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
Line No.Account
(a)
Amount for Current Year
(b)
Amount for Previous Year (c)
(c)
FERC FORM NO. 1 (ED. 12-93)
Page 320-323
119 (575.5) Ancillary Services Market Facilitation
120 (575.6) Market Monitoring and Compliance
121 (575.7) Market Facilitation, Monitoring and Compliance Services 686,880 732,683
122 (575.8) Rents
123 Total Operation (Lines 115 thru 122)686,880 732,683
124 Maintenance
125 (576.1) Maintenance of Structures and Improvements
126 (576.2) Maintenance of Computer Hardware
127 (576.3) Maintenance of Computer Software
128 (576.4) Maintenance of Communication Equipment
129 (576.5) Maintenance of Miscellaneous Market Operation Plant
130 Total Maintenance (Lines 125 thru 129)0
131 TOTAL Regional Transmission and Market Operation Expenses (Enter Total of Lines 123 and 130)686,880 732,683
132 4. DISTRIBUTION EXPENSES
133 Operation
134 (580) Operation Supervision and Engineering 5,911,141 4,083,135
135 (581) Load Dispatching 5,170,071 4,899,999
136 (582) Station Expenses 1,862,473 1,579,041
137 (583) Overhead Line Expenses 5,421,238 4,854,331
138 (584) Underground Line Expenses 4,717,552 4,573,059
138.1 (584.1) Operation of Energy Storage Equipment
139 (585) Street Lighting and Signal System Expenses 44,756 561
140 (586) Meter Expenses 5,719,569 5,014,025
141 (587) Customer Installations Expenses 1,095,297 1,011,897
142 (588) Miscellaneous Expenses 4,687,903 4,109,601
143 (589) Rents 741,341 439,479
144 TOTAL Operation (Enter Total of Lines 134 thru 143)35,371,341 30,565,128
145 Maintenance
146 (590) Maintenance Supervision and Engineering 11,968 10,926
147 (591) Maintenance of Structures 0 0
148 (592) Maintenance of Station Equipment 4,120,742 4,077,874
148.1 (592.2) Maintenance of Energy Storage Equipment
149 (593) Maintenance of Overhead Lines 21,931,803 17,694,888
150 (594) Maintenance of Underground Lines 751,577 597,945
151 (595) Maintenance of Line Transformers 94,087 57,820
152 (596) Maintenance of Street Lighting and Signal Systems 204,924 263,541
153 (597) Maintenance of Meters 862,000 841,948
154 (598) Maintenance of Miscellaneous Distribution Plant 123,766 98,043
155 TOTAL Maintenance (Total of Lines 146 thru 154)28,100,867 23,642,985
156 TOTAL Distribution Expenses (Total of Lines 144 and 155)63,472,208 54,208,113
157 5. CUSTOMER ACCOUNTS EXPENSES
158 Operation
159 (901) Supervision 845,854 841,926
160 (902) Meter Reading Expenses 1,819,788 1,871,924
161 (903) Customer Records and Collection Expenses 15,041,848 14,000,067
162 (904) Uncollectible Accounts 3,069,311 2,363,140
163 (905) Miscellaneous Customer Accounts Expenses (3,030)423
164 TOTAL Customer Accounts Expenses (Enter Total of Lines 159 thru 163)20,773,771 19,077,480
165 6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
166 Operation
167 (907) Supervision 1,009,780 793,300
168 (908) Customer Assistance Expenses 40,483,172 36,468,097
169 (909) Informational and Instructional Expenses 295,103 294,369
170 (910) Miscellaneous Customer Service and Informational Expenses 746,645 850,624
171 TOTAL Customer Service and Information Expenses (Total Lines 167 thru 170)42,534,700 38,406,390
172 7. SALES EXPENSES
173 Operation
174 (911) Supervision 0 0
175 (912) Demonstrating and Selling Expenses 0 0
176 (913) Advertising Expenses 0 0
177 (916) Miscellaneous Sales Expenses 0 0
178 TOTAL Sales Expenses (Enter Total of Lines 174 thru 177)0 0
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
Line No.Account
(a)
Amount for Current Year
(b)
Amount for Previous Year (c)
(c)
FERC FORM NO. 1 (ED. 12-93)
Page 320-323
179 8. ADMINISTRATIVE AND GENERAL EXPENSES
180 Operation
181 (920) Administrative and General Salaries 95,790,672 87,358,103
182 (921) Office Supplies and Expenses 15,137,531 14,005,146
183 (Less) (922) Administrative Expenses Transferred-Credit 35,131,943 32,764,226
184 (923) Outside Services Employed 8,733,229 7,828,424
185 (924) Property Insurance 3,925,608 3,571,061
186 (925) Injuries and Damages 6,544,597 6,484,661
187 (926) Employee Pensions and Benefits 54,443,509 56,595,140
188 (927) Franchise Requirements 0 0
189 (928) Regulatory Commission Expenses 6,545,806 6,675,237
190 (929) (Less) Duplicate Charges-Cr.0 0
191 (930.1) General Advertising Expenses 491,473 381,688
192 (930.2) Miscellaneous General Expenses 4,378,924 4,090,496
193 (931) Rents 0 0
194 TOTAL Operation (Enter Total of Lines 181 thru 193)160,859,406 154,225,730
195 Maintenance
196 (935) Maintenance of General Plant 7,877,237 7,816,747
197 TOTAL Administrative & General Expenses (Total of Lines 194 and 196)168,736,643 162,042,477
198 TOTAL Electric Operation and Maintenance Expenses (Total of Lines 80, 112, 131, 156, 164, 171, 178, and
197)1,103,041,646 917,515,192
FERC FORM NO. 1 (ED. 12-93)
Page 320-323
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
Line No.Account
(a)
Amount for Current Year
(b)
Amount for Previous Year (c)
(c)
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
PURCHASED POWER (Account 555)
Actual Demand (MW)Actual Demand (MW)
Line
No.
Name of Company or Public Authority (Footnote Affiliations)
(a)
Statistical Classification
(b)
Ferc Rate Schedule or
Tariff Number
(c)
Average Monthly Billing Demand
(MW)
(d)
Average Monthly NCP Demand
(e)
Average Monthly CP Demand
(f)
MegaWatt Hours
Purchased
(Excluding for
Energy Storage)
(g)
1 American Falls Solar, LLC LU 41,139
2 American Falls Solar II, LLC LU 42,465
3 Allan Ravenscroft/Malad River LU -953
4 Baker City Hydro LU 780
5 Bannock County Landfill LU 12,107
6 Bennett Creek Wind Farm LU 33,040
7 Benson Creek Windfarm LU 28,582
8 Black Canyon Bliss Hydro LU -134
9 Blind Canyon LU -4,135
10 Branchflower - Trout Company LU -589
11 Burley Butte Wind Park LU 56,529
12 CAFCO Idaho Refuse Management LLC - SISW LFGE LU -18,124
13 Camp Reed Wind Park LU 63,865
14 Cassia Wind Farm LLC LU 17,562
15 CCP OR Tenant 1, LLC
16 Grove Solar Center, LLC LU 13,057
17 Hyline Solar Center, LLC LU 19,458
18 Open Range Solar Center, LLC LU 22,041
19 Railroad Solar Center, LLC LU 9,977
20 Thunderegg Solar Center, LLC LU 21,411
21 Vale Air Solar Center, LLC LU 21,460
22 Central Rivers Power US LLC
23 Barber Dam LU 4,276
24 Dietrich Drop LU 13,430
25 Lowline #2 LU 7,841
26 City of Hailey LU -148
27 City of Pocatello LU -1,467
28 Clear Springs Trout LU -3,313
29 Clifton E. Jenson - Birch Creek LU -337
30 Cold Springs Windfarm LU -49,343
31 College of Southern Idaho - Pristine Springs #1 LU -837
32 College of Southern Idaho - Pristine Springs #3 LU -1,690
33 Crystal Springs LU -7,426
34 Curry Cattle Company LU -487
35 Cycle Horseshoe Bend Wind LU -23,232
36 David R Snedigar LU -1,079
37 Desert Meadow Windfarm LU -54,380
38 Durbin Creek Windfarm LU 24,646
39 Eightmile Hydro Project LU -975
40 Enerparc Solar Development LLC
41 Baker Solar Center LU 32,603
42 Brush Solar LU 6,316
43 Morgan Solar LU 6,912
44 Ontario Solar Center LU 7,019
45 Vale I Solar LU 5,820
46 Faulkner Ranch LU -2,920
47 Fisheries Development LU -423
48 Fossil Gulch Wind LU -23,673
49 Hidden Hollow Landfill Gas LU -22,881
50 Golden Valley Wind Park LU -29,985
51 Grand View PV Solar Two LU -176,143
52 Hammett Hill Windfarm LU -55,288
53 Hazelton B (a)
LU -20,864
54 High Mesa Wind Project (b)
LU -82,005
55 H.K. Hydro Mud Creek S & S LU -1,303
56 Horseshoe Bend Hydro LU -38,575
57 Hot Springs Wind Farm LU 33,398
FERC FORM NO. 1 (ED. 12-90)
Page 326-327
58 Hydroland LU
59 Elk Creek Hydro LU 2,497
60 Rock Creek #2 LU -2,522
61 ID Solar 1 LU 94,009
62 Idaho Winds - Sawtooth Wind Project LU -55,154
63 J R Simplot Co.LU -50,510
64 J.M. Miller/Sahko Hydro LU 978
65 Jett Creek Windfarm LU 26,370
66 John R LeMoyne LU -654
67 Kootenai Electric Cooperative - Fighting Creek LU -11,706
68 Koosh Inc. Geo Bon #2 LU -2,684
69 Koyle Small Hydro LU -2,440
70 Lateral #10 LU -4,168
71 Lemhi Hydro Power Co.- Schaffner LU -944
72 Lime Wind Energy LU 5,489
73 Little Mac Power Co./Cedar Draw LU -3,698
74 Little Wood River Irrigation District LU -3,868
75 Mainline Windfarm LU -53,971
76 Marco Ranches LU -2,300
77 Marysville Hydro Partners- Falls River (c)
LU -38,748
78 McCollum Enterprises -Canyon Springs LU -603
79 MC6 Hydro LU -6,880
80 Milner Dam Wind Park LU 51,350
81 Mountain Home Solar I, LLC LU 42,238
82 Mud Creek White Hydro, Inc LU -300
83 Murphy Flat Power, LLC LU 37,965
84 North Gooding Main Hydro LU -3,718
85 North Side Energy Company Inc
86 Bypass LU -25,507
87 Hazelton A LU -21,850
88 Head of U Canal Project LU -4,303
89 Orchard Ranch Solar, LLC LU 44,678
90 Oregon Trail Wind Park LU 34,657
91 Owyhee Irrigation District
92 Mitchell Butte LU -2,663
93 Owyhee Dam Cspp LU -10,766
94 Tunnel #1 LU -3,528
95 Payne's Ferry Wind Park LU 61,191
96 Pico Energy, LLC LU 6,959
97 Pigeon Cove LU -6,557
98 Pilgrim Stage Station Wind Park LU 31,351
99 Prospector Windfarm LU 26,674
100 Reynolds Irrigation LU -776
101 Richard Kaster
102 Box Canyon LU -1,835
103 Briggs Creek LU -3,666
104 Riverside Hydro - Mora Drop LU 3,781
105 Riverside Investments
106 Arena Drop LU 1,345
107 Fargo Drop Hydroelectric LU 2,817
108 Rockland Wind Farm (d)
LU 234,455
109 Ryegrass Windfarm LU 51,222
110 Salmon Falls Wind LU 57,373
111 Shingle Creek LU -1,007
112 Shorock Hydro Inc.
113 Rock Creek #1 LU 9,033
114 Shoshone CSPP LU -1,015
115 Shoshone #2 LU -2,182
116 Simcoe Solar, LLC LU 46,188
PURCHASED POWER (Account 555)
Actual Demand (MW)Actual Demand (MW)
Line
No.
Name of Company or Public Authority (Footnote Affiliations)
(a)
Statistical Classification
(b)
Ferc Rate Schedule or
Tariff Number
(c)
Average Monthly Billing Demand
(MW)
(d)
Average Monthly NCP Demand
(e)
Average Monthly CP Demand
(f)
MegaWatt Hours
Purchased
(Excluding for
Energy Storage)
(g)
FERC FORM NO. 1 (ED. 12-90)
Page 326-327
117 Snake River Pottery LU -407
118 South Forks Joint Venture-Lowline Canal (e)
LU -22,289
119 Tamarack Energy Partnership LU -19,460
120 Tasco - Nampa (f)
OS -6
121 Tasco - Twin Falls (g)
OS 0
122 Thousand Springs Wind Park LU 30,190
123 Tiber Montana LLC - Tiber Dam LU 24,887
124 Tuana Gulch Wind Park LU 28,279
125 Tuana Springs Expansion (h)
LU 67,722
126 Twin Falls Energy-Lowline Midway Hydro LU 5,107
127 Two Ponds Windfarm LU -55,928
128 White Water Ranch LU -664
129 William Arkoosh-Littlewood River Ranch I LU -1,531
130 William Arkoosh- Littlewood River Ranch II LU 3,124
131 Willow Spring Windfarm LU 28,880
132 Wilson Power Company (i)
LU -24,292
133 Wood Hydro
134 Black Canyon #3 LU 255
135 Jim Knight LU 1,129
136 Magic Reservoir LU -0
137 Mile 28 LU 4,867
138 Sagebrush LU 1,677
139 Yahoo Creek Wind Park LU 59,438
140 Scheduling Deviation (j)
OS 4,547
141 3PR Trading Inc SF WSPP 102,956
142 ADM Investor Services, Inc.(k)
OS WSPP 0
143 AVANGRID RENEWABLES, LLC (l)
OS WSPP 7
144 AVANGRID RENEWABLES, LLC SF WSPP 199,920
145 Avista Corp.(m)
OS WSPP 45
146 Avista Corp.(n)
OS WSPP 0
147 Avista Corp.SF WSPP 9,051
148 Bonneville Power Administration (o)
OS WSPP 175
149 Bonneville Power Administration (p)
OS WSPP 0
150 Bonneville Power Administration SF WSPP 115,734
151 Bonneville Power Administration (Transmission)(q)
OS WSPP 105
152 BP Energy Company SF WSPP 597,850
153 Brookfield Renewable Trading and Marketing LP SF WSPP 8,200
154 California Independent System Operator (r)
SF CAISO 1,394,230
155 Calpine Energy Solutions LLC SF WSPP 3,600
156 Chelan Co PUD (s)
EX WSPP 6
157 Chelan Co PUD SF WSPP 397,275
158 Citigroup Energy Inc.SF WSPP 305,600
159 Clatskanie PUD SF WSPP 253
160 Clatskanie PUD SF WSPP 121
161 Clean Power Alliance of Southern California SF WSPP 593
162 ConocoPhillips Company SF WSPP 16,405
163 Constellation Energy Generation, LLC SF WSPP 2,600
164 DTE Energy Trading, Inc.SF WSPP (30)
165 Dynasty Power Inc.SF WSPP 8,197
166 EDF Trading North America, LLC SF WSPP 1,200
167 El Paso Electric Company SF WSPP 6,000
168 Energy Keepers, Inc SF WSPP 4,440
169 Grant CO Public Utility District #2 -- Electric System (t)
OS WSPP 17
170 Gridforce Energy Management, LLC (u)
OS WSPP 10
PURCHASED POWER (Account 555)
Actual Demand (MW)Actual Demand (MW)
Line
No.
Name of Company or Public Authority (Footnote Affiliations)
(a)
Statistical Classification
(b)
Ferc Rate Schedule or
Tariff Number
(c)
Average Monthly Billing Demand
(MW)
(d)
Average Monthly NCP Demand
(e)
Average Monthly CP Demand
(f)
MegaWatt Hours
Purchased
(Excluding for
Energy Storage)
(g)
FERC FORM NO. 1 (ED. 12-90)
Page 326-327
171 Jackpot Solar LU -6,114
172 Macquarie Energy LLC OS ISDA 0
173 Macquarie Energy LLC SF ISDA 2,200
174 Morgan Stanley Capital Group Inc.SF WSPP 11,127
175 Neal Hot Springs Unit #1 LU -178,844
176 Nevada Power Company, dba NV Energy (v)
OS WSPP 0
177 Nevada Power Company, dba NV Energy SF WSPP 11,881
178 NextEra Energy Marketing, LLC SF WSPP 6,200
179 NorthWestern Energy SF WSPP 205
180 NorthWestern Energy (Transmission)
(w)
OS WSPP 0
181 NorthWestern Energy (Transmission)(x)
OS WSPP 35
182 Oregon Solar Customers (y)
OS -700
183 PacifiCorp (z)
OS WSPP 267
184 PacifiCorp SF WSPP 12,200
185 PacifiCorp Inc.(aa)
OS WSPP 0
186 Portland General Electric Company (ab)
OS WSPP 70
187 Portland General Electric Company SF WSPP 7,303
188 Powerex Corp.(ac)
OS 354
189 Powerex Corp.SF WSPP 193,713
190 Public Service Company of Colorado SF WSPP 67,250
191 Puget Sound Energy, Inc.
(ad)
OS WSPP 75
192 Puget Sound Energy, Inc.SF WSPP 78,425
193 Raft River Energy I LLC LU -91,433
194 Salt River Project SF WSPP 3,600
195 Seattle City Light (ae)
OS WSPP 24
196 Seattle City Light SF WSPP 5,800
197 Shell Energy North America (US), L.P.SF WSPP 159,655
198 Sierra Pacific Power Co., dba NV Energy (af)
OS WSPP 344
199 Sierra Pacific Power Co., dba NV Energy (ag)
OS WSPP 0
200 Tacoma Power (ah)
OS WSPP 10
201 Tacoma Power SF WSPP 4,000
202 Telocaset Wind Power Partners LLC LU APP-A 294,788
203 Tenaska Power Services Co.SF WSPP 10,063
204 The Energy Authority, Inc.SF WSPP 6,963
205 TransAlta Energy Marketing (U.S.) Inc.SF WSPP 63,766
206 Vitol Inc.SF WSPP 2,296
207 Western Area Power Administration (WACM)(ai)
OS WSPP 178
208 PacifiCorp Inc.(aj)
EX -
209 Sierra Pacific Power Co., dba NV Energy (ak)
EX -
210 Clatskanie PUD (al)
EX 153
211 Acctg Valuation of Clatskanie PUD (am)
EX 0
212 Demand Response Avoided Energy (an)
OS -0
15 TOTAL 7,150,708
FERC FORM NO. 1 (ED. 12-90)
Page 326-327
PURCHASED POWER (Account 555)
Actual Demand (MW)Actual Demand (MW)
Line
No.
Name of Company or Public Authority (Footnote Affiliations)
(a)
Statistical Classification
(b)
Ferc Rate Schedule or
Tariff Number
(c)
Average Monthly Billing Demand
(MW)
(d)
Average Monthly NCP Demand
(e)
Average Monthly CP Demand
(f)
MegaWatt Hours
Purchased
(Excluding for
Energy Storage)
(g)
PURCHASED POWER (Account 555)
POWER EXCHANGES POWER EXCHANGES COST/SETTLEMENT OF POWER COST/SETTLEMENT OF POWER COST/SETTLEMENT OF POWER COST/SETTLEMENT
OF POWER
Line
No.
MegaWatt Hours Purchased for
Energy Storage
(h)
MegaWatt Hours Received
(i)
MegaWatt Hours Delivered
(j)
Demand Charges ($)
(k)
Energy Charges ($)
(l)
Other Charges ($)
(m)
Total (k+l+m) of
Settlement ($)
(n)
1 2,517,359 2,517,359
2 2,497,144 2,497,144
3 56,006 56,006
4 55,459 55,459
5 903,735 903,735
6 2,385,646 2,385,646
7 1,948,524 1,948,524
8 7,452 7,452
9 258,317 258,317
10 29,506 29,506
11 3,696,957 3,696,957
12 690,319 690,319
13 5,274,082 5,274,082
14 1,099,291 1,099,291
15 0
16 957,781 957,781
17 1,435,522 1,435,522
18 1,626,814 1,626,814
19 734,187 734,187
20 1,581,144 1,581,144
21 1,579,297 1,579,297
22 0
23 225,950 225,950
24 766,597 766,597
25 437,183 437,183
26 6,428 6,428
27 56,391 56,391
28 219,281 219,281
29 18,853 18,853
30 4,189,375 4,189,375
31 49,298 49,298
32 99,052 99,052
33 369,145 369,145
34 40,354 40,354
35 1,463,898 1,463,898
36 61,201 61,201
37 4,630,073 4,630,073
38 1,685,476 1,685,476
39 63,127 63,127
40 0
41 1,388,009 1,388,009
42 194,173 194,173
43 211,801 211,801
44 198,274 198,274
45 178,176 178,176
46 214,113 214,113
47 26,681 26,681
48 1,587,979 1,587,979
49 1,664,304 1,664,304
50 1,962,014 1,962,014
51 11,050,418 11,050,418
52 4,721,313 4,721,313
53 1,588,492 1,588,492
54 4,580,493 (11,610)4,568,883
55 85,437 85,437
56 2,917,828 2,917,828
57 2,399,319 2,399,319
58 0
59 77,340 77,340
60 135,248 135,248
FERC FORM NO. 1 (ED. 12-90)
Page 326-327
61 5,473,385 5,473,385
62 5,119,205 5,119,205
63 2,507,581 2,507,581
64 46,537 46,537
65 1,794,138 1,794,138
66 38,355 38,355
67 1,030,116 1,030,116
68 143,401 143,401
69 152,729 152,729
70 195,808 195,808
71 46,299 46,299
72 464,877 464,877
73 208,755 208,755
74 177,648 177,648
75 4,592,340 4,592,340
76 128,657 128,657
77 2,717,072 2,717,072
78 39,773 39,773
79 247,754 247,754
80 3,344,523 3,344,523
81 2,076,600 2,076,600
82 14,752 14,752
83 2,396,161 2,396,161
84 328,383 328,383
85 0
86 1,389,125 1,389,125
87 2,087,276 2,087,276
88 451,364 451,364
89 2,695,983 2,695,983
90 2,271,498 2,271,498
91 0
92 81,337 81,337
93 271,088 271,088
94 120,462 120,462
95 5,048,578 5,048,578
96 289,304 289,304
97 374,049 374,049
98 2,071,521 2,071,521
99 1,812,263 1,812,263
100 41,066 41,066
101 0
102 120,091 120,091
103 215,764 215,764
104 237,908 237,908
105 0
106 119,417 119,417
107 176,964 176,964
108 17,267,246 (10,845)17,256,401
109 4,359,948 4,359,948
110 3,762,412 3,762,412
111 63,497 63,497
112 0
113 588,121 588,121
114 70,684 70,684
115 162,367 162,367
116 2,939,152 2,939,152
117 21,306 21,306
118 1,720,981 1,720,981
119 1,164,789 1,164,789
120 598 598
PURCHASED POWER (Account 555)
POWER EXCHANGES POWER EXCHANGES COST/SETTLEMENT OF POWER COST/SETTLEMENT OF POWER COST/SETTLEMENT OF POWER COST/SETTLEMENT
OF POWER
Line
No.
MegaWatt Hours Purchased for
Energy Storage
(h)
MegaWatt Hours Received
(i)
MegaWatt Hours Delivered
(j)
Demand Charges ($)
(k)
Energy Charges ($)
(l)
Other Charges ($)
(m)
Total (k+l+m) of
Settlement ($)
(n)
FERC FORM NO. 1 (ED. 12-90)
Page 326-327
121 0 0
122 1,975,067 1,975,067
123 1,663,259 1,663,259
124 1,857,813 1,857,813
125 4,600,497 (22,301)4,578,196
126 320,666 320,666
127 4,767,349 4,767,349
128 39,093 39,093
129 67,513 67,513
130 260,661 260,661
131 1,983,928 1,983,928
132 1,851,080 1,851,080
133 0
134 20,915 20,915
135 77,725 77,725
136 0 0
137 366,191 366,191
138 105,284 105,284
139 4,897,683 4,897,683
140 0
141 0 0 0 21,991,759 0 21,991,759
142 0 0 0 (2,356,741)(2,356,741)
143 0 0 0 0 709 709
144 0 0 0 15,651,243 0 15,651,243
145 0 0 0 0 5,652 5,652
146 0 0 0 0 1,505,309 1,505,309
147 0 0 0 684,178 0 684,178
148 0 0 0 0 8,645 8,645
149 0 0 0 0 542,967 542,967
150 0 0 0 10,826,591 0 10,826,591
151 0 0 0 0 23,307 23,307
152 0 0 0 60,670,559 0 60,670,559
153 0 0 0 881,178 0 881,178
154 0 0 0 56,982,328 0 56,982,328
155 0 0 0 478,936 0 478,936
156 0 0 0 0 684 684
157 0 0 0 33,456,516 0 33,456,516
158 0 0 0 12,278,306 0 12,278,306
159 0 0 0 37,771 0 37,771
160 0 0 0 8,974 0 8,974
161 0 0 0 105,557 0 105,557
162 0 0 0 891,110 0 891,110
163 0 0 0 117,800 0 117,800
164 0 0 0 (1,473)0 (1,473)
165 0 0 0 1,017,914 0 1,017,914
166 0 0 0 262,284 0 262,284
167 0 0 0 353,928 0 353,928
168 0 0 0 739,986 0 739,986
169 0 0 0 0 1,730 1,730
170 0 0 0 0 1,290 1,290
171 0 0 0 150,018 0 150,018
172 0 0 0 (16,200)(16,200)
173 0 0 0 173,850 0 173,850
174 0 0 0 839,903 0 839,903
175 0 0 0 21,640,640 0 21,640,640
176 0 0 0 0 5,515 5,515
177 0 0 0 569,561 0 569,561
178 0 0 0 237,118 0 237,118
179 0 0 0 4,715 0 4,715
180 0 0 0 0 15,524 15,524
PURCHASED POWER (Account 555)
POWER EXCHANGES POWER EXCHANGES COST/SETTLEMENT OF POWER COST/SETTLEMENT OF POWER COST/SETTLEMENT OF POWER COST/SETTLEMENT
OF POWER
Line
No.
MegaWatt Hours Purchased for
Energy Storage
(h)
MegaWatt Hours Received
(i)
MegaWatt Hours Delivered
(j)
Demand Charges ($)
(k)
Energy Charges ($)
(l)
Other Charges ($)
(m)
Total (k+l+m) of
Settlement ($)
(n)
FERC FORM NO. 1 (ED. 12-90)
Page 326-327
181 0 0 0 0 3,031 3,031
182 0 0 0 0 50,703 50,703
183 0 0 0 0 33,185 33,185
184 0 0 0 540,824 0 540,824
185 0 0 0 0 925,598 925,598
186 0 0 0 0 9,469 9,469
187 0 0 0 1,007,316 0 1,007,316
188 283,200 283,200
189 0 0 0 23,130,347 0 23,130,347
190 0 0 0 8,545,876 0 8,545,876
191 0 0 0 0 9,956 9,956
192 0 0 0 11,157,828 0 11,157,828
193 0 0 0 6,529,708 0 6,529,708
194 0 0 0 323,200 0 323,200
195 0 0 0 0 2,211 2,211
196 0 0 0 276,992 0 276,992
197 0 0 0 10,425,147 0 10,425,147
198 0 0 0 0 29,625 29,625
199 0 0 0 0 31,045 31,045
200 0 0 0 0 1,306 1,306
201 0 0 0 188,352 0 188,352
202 0 0 0 20,849,137 0 20,849,137
203 0 0 0 1,447,101 0 1,447,101
204 0 0 0 654,216 0 654,216
205 0 0 0 8,333,906 0 8,333,906
206 0 0 0 211,943 0 211,943
207 0 0 0 0 17,452 17,452
208 0 124,135 0
209 0 1,676 0
210 53,368 25,600 0
211 0 0 (76,051)(76,051)
212 0 0 8,311,328 8,311,328
15 0 53,368 151,411 0 523,989,711 9,042,493 533,032,204
FERC FORM NO. 1 (ED. 12-90)
Page 326-327
PURCHASED POWER (Account 555)
POWER EXCHANGES POWER EXCHANGES COST/SETTLEMENT OF POWER COST/SETTLEMENT OF POWER COST/SETTLEMENT OF POWER COST/SETTLEMENT
OF POWER
Line
No.
MegaWatt Hours Purchased for
Energy Storage
(h)
MegaWatt Hours Received
(i)
MegaWatt Hours Delivered
(j)
Demand Charges ($)
(k)
Energy Charges ($)
(l)
Other Charges ($)
(m)
Total (k+l+m) of
Settlement ($)
(n)
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
FOOTNOTE DATA
(a) Concept: StatisticalClassificationCode
Ida West, a subsidiary of IdaCorp (Idaho Power Company's parent company), has partial ownership of these projects.
(b) Concept: StatisticalClassificationCode
Mechanical Availability Guarantee Damages
(c) Concept: StatisticalClassificationCode
Ida West, a subsidiary of IdaCorp (Idaho Power Company's parent company), has partial ownership of these projects.
(d) Concept: StatisticalClassificationCode
Mechanical Availability Guarantee Damages
(e) Concept: StatisticalClassificationCode
Ida West, a subsidiary of IdaCorp (Idaho Power Company's parent company), has partial ownership of these projects.
(f) Concept: StatisticalClassificationCode
Non Firm Purchases
(g) Concept: StatisticalClassificationCode
Non Firm Purchases
(h) Concept: StatisticalClassificationCode
Mechanical Availability Guarantee Damages
(i) Concept: StatisticalClassificationCode
Ida West, a subsidiary of IdaCorp (Idaho Power Company's parent company), has partial ownership of these projects.
(j) Concept: StatisticalClassificationCode
Difference between booked and scheduled energy
(k) Concept: StatisticalClassificationCode
ADM Investor Services, Inc Futures Account Document, dated May 6, 2015
(l) Concept: StatisticalClassificationCode
Spinning or Operating Reserves
(m) Concept: StatisticalClassificationCode
Spinning or Operating Reserves
(n) Concept: StatisticalClassificationCode
Financial Transmission Losses
(o) Concept: StatisticalClassificationCode
Spinning or Operating Reserves
(p) Concept: StatisticalClassificationCode
Financial Transmission Losses
(q) Concept: StatisticalClassificationCode
Spinning or Operating Reserves
(r) Concept: StatisticalClassificationCode
Includes actual billing and estimate accrual
(s) Concept: StatisticalClassificationCode
Spinning or Operating Reserves
(t) Concept: StatisticalClassificationCode
Spinning or Operating Reserves
(u) Concept: StatisticalClassificationCode
Spinning or Operating Reserves
(v) Concept: StatisticalClassificationCode
Financial Transmission Losses
(w) Concept: StatisticalClassificationCode
Financial Transmission Losses
(x) Concept: StatisticalClassificationCode
Spinning or Operating Reserves
(y) Concept: StatisticalClassificationCode
Schedule 88 Oregon Solar
(z) Concept: StatisticalClassificationCode
Spinning or Operating Reserves
(aa) Concept: StatisticalClassificationCode
Financial Transmission Losses
(ab) Concept: StatisticalClassificationCode
Spinning or Operating Reserves
(ac) Concept: StatisticalClassificationCode
Non Firm Purchases
(ad) Concept: StatisticalClassificationCode
Spinning or Operating Reserves
(ae) Concept: StatisticalClassificationCode
Spinning or Operating Reserves
(af) Concept: StatisticalClassificationCode
Spinning or Operating Reserves
(ag) Concept: StatisticalClassificationCode
Financial Transmission Losses
(ah) Concept: StatisticalClassificationCode
Spinning or Operating Reserves
(ai) Concept: StatisticalClassificationCode
Spinning or Operating Reserves
(aj) Concept: StatisticalClassificationCode
Physical Transmission Losses
(ak) Concept: StatisticalClassificationCode
Physical Transmission Losses
(al) Concept: StatisticalClassificationCode
Energy exchange between Clatskanie PUD and Idaho Power Company at Arrowrock Dam
(am) Concept: StatisticalClassificationCode
Energy exchange between Clatskanie PUD and Idaho Power Company at Arrowrock Dam
(an) Concept: StatisticalClassificationCode
Incentive program for customers to reduce demand during peak hours
FERC FORM NO. 1 (ED. 12-90)
Page 326-327
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")
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
Classification
(d)
Ferc Rate Schedule
of Tariff Number
(e)
Point of Receipt
(Substation or
Other
Designation)
(f)
Point of
Delivery
(Substation or
Other
Designation)
(g)
1 (a)
Bonneville Power Administration - OTEC Bonneville Power Administration Oregon Trails Electric Co-op FNO (i)
9
2 (b)
Bonneville Power Administration - USBR Bonneville Power Administration United States Bureau of Reclamation FNO 9
3 (c)
Bonneville Power Administration - PF Bonneville Power Administration Priority Firm Customers FNO 9
4 (d)
Milner Irrigation District United States Bureau of Reclamation Milner Irrigation District OLF (j)
Legacy
Minidoka,
Idaho
Various in
Idaho
5 (e)
Shell Energy North America (US), L.P.Seattle City Light Bonneville Power Administration OS (k)
4
6 (f)
PacifiCorp PacifiCorp West PacifiCorp West FNO 9
7 (g)
United States Bureau of Indian Affairs Bonneville Power Administration United States Bureau of Indian Affairs OS Legacy LaGrande,
Oregon
Various in
Idaho
8
(h)
Cycle Horseshoe Bend Wind, LLC PacifiCorp East PacifiCorp East OS
(l)
5/6 BRDY IPCOEAST
9 Cycle Horseshoe Bend Wind, LLC PacifiCorp East PacifiCorp East OS 5/6 JEFF IPCOEAST
10 Tenaska Power Services OS 5/6
11 AmpRenew Offtake I LLC OS 5/6
12 Vitol Inc.OS 5/6
13 PacifiCorp Inc.PacifiCorp East Bonneville Power Administration LFP (m)
7/8 BORA LAGRANDE
14 PacifiCorp Inc.PacifiCorp East PacifiCorp West LFP 7/8 KPRT HURR
15 PacifiCorp Inc.PacifiCorp East PacifiCorp West LFP 7/8 BORA HURR
16 Shell Energy North America (US), L.P.Idaho Power Company Bonneville Power Administration LFP 7/8 LYPK LAGRANDE
17 Bonneville Power Administration PacifiCorp West PacifiCorp East LFP 7/8 M500 KPRT
18 Bonneville Power Administration PacifiCorp West PacifiCorp East LFP 7/8 SMLK KPRT
19 Mercuria Energy America, LLC NorthWestern/PacifiCorp East Sierra Pacific Power LFP 7/8 BPAT.NWMT M345
20 Powerex Corporation Avista PacifiCorp East LFP 7/8 LOLO BORA
21 Powerex Corporation PacifiCorp East PacifiCorp East LFP 7/8 JEFF BORA
22 Vitol Inc.Idaho Power Company Sierra Pacific Power LFP 7/8 MDSK M345
23 AmpRenew Offtake I LLC Idaho Power Company Sierra Pacific Power LFP 7/8 MDSK M345
24 Adapture Renewables, LLC (Baker Solar Center)NF (n)
11
25 Avangrid Renewables, LLC PacifiCorp East Bonneville Power Administration NF 7/8 BORA LAGRANDE
26 Avangrid Renewables, LLC Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE BORA
27 Avangrid Renewables, LLC Bonneville Power Administration Sierra Pacific Power NF 7/8 LAGRANDE M345
28 Avangrid Renewables, LLC Avista PacifiCorp East NF 7/8 LOLO BORA
29 Avangrid Renewables, LLC Avista Sierra Pacific Power NF 7/8 LOLO M345
30 Avangrid Renewables, LLC Sierra Pacific Power Bonneville Power Administration NF 7/8 M345 LAGRANDE
31 Avangrid Renewables, LLC PacifiCorp West PacifiCorp East NF 7/8 SMLK BORA
32 Avangrid Renewables, LLC PacifiCorp West Sierra Pacific Power NF 7/8 SMLK M345
33 Avista Corporation PacifiCorp East Avista NF 7/8 JBSN LOLO
34 Avista Corporation Bonneville Power Administration Sierra Pacific Power NF 7/8 LAGRANDE M345
35 Avista Corporation Avista PacifiCorp East NF 7/8 LOLO BORA
36 Avista Corporation Avista PacifiCorp East NF 7/8 LOLO BRDY
37 Avista Corporation Avista Sierra Pacific Power NF 7/8 LOLO M345
38 Avista Corporation Sierra Pacific Power Avista NF 7/8 M345 LOLO
39 Avista Corporation Idaho Power Company PacifiCorp East NF 7/8 WALLAWALLA BORA
40 Avista Corporation Idaho Power Company Sierra Pacific Power NF 7/8 WALLAWALLA M345
41 Benson Creek Windfarm, LLC NF 11
42 Black Hills Power NorthWestern/PacifiCorp East PacifiCorp East NF 7/8 BPAT.NWMT JBSN
43 Bonneville Power Administration NorthWestern/PacifiCorp East PacifiCorp East NF 7/8 BPAT.NWMT ANTE
44 Bonneville Power Administration NorthWestern/PacifiCorp East Bonneville Power Administration NF 7/8 BPAT.NWMT BPASID
45 Bonneville Power Administration NorthWestern/PacifiCorp East Bonneville Power Administration NF 7/8 BPAT.NWMT LAGRANDE
46 Bonneville Power Administration NorthWestern/PacifiCorp East Sierra Pacific Power NF 7/8 BPAT.NWMT M345
47 Bonneville Power Administration PacifiCorp East Bonneville Power Administration NF 7/8 BRDY LAGRANDE
48 Bonneville Power Administration PacifiCorp East Sierra Pacific Power NF 7/8 BRDY M345
49 Bonneville Power Administration PacifiCorp East Bonneville Power Administration NF 7/8 KPRT BPASID
50 Bonneville Power Administration Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE BORA
51 Bonneville Power Administration Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE BRDY
52 Bonneville Power Administration Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE KPRT
53 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration NF 7/8 LAGRANDE LAGRANDE
54 Bonneville Power Administration Bonneville Power Administration Sierra Pacific Power NF 7/8 LAGRANDE M345
FERC FORM NO. 1 (ED. 12-90)
Page 328-330
55 Bonneville Power Administration Avista PacifiCorp East NF 7/8 LOLO BORA
56 Bonneville Power Administration Avista PacifiCorp East NF 7/8 LOLO KPRT
57 Bonneville Power Administration Avista Bonneville Power Administration NF 7/8 LOLO LAGRANDE
58 Bonneville Power Administration Avista Sierra Pacific Power NF 7/8 LOLO M345
59 Bonneville Power Administration Sierra Pacific Power PacifiCorp East NF 7/8 M345 KPRT
60 Bonneville Power Administration PacifiCorp West Bonneville Power Administration NF 7/8 M500 LAGRANDE
61 Bonneville Power Administration PacifiCorp West PacifiCorp East NF 7/8 SMLK BORA
62 Bonneville Power Administration PacifiCorp West Bonneville Power Administration NF 7/8 SMLK BPASID
63 Bonneville Power Administration PacifiCorp West PacifiCorp East NF 7/8 SMLK BRDY
64 Bonneville Power Administration PacifiCorp West Bonneville Power Administration NF 7/8 SMLK LAGRANDE
65 Bonneville Power Administration PacifiCorp West Sierra Pacific Power NF 7/8 SMLK M345
66 Bonneville Power Administration NF 11
67 CCP OR Tenant 1, LLC (Thunderegg Solar Center)NF 11
68 Durbin Creek Windfarm, LLC NF 11
69 Brookfield Renewable Trading & Marketing NorthWestern/PacifiCorp East PacifiCorp East NF 7/8 BPAT.NWMT BRDY
70 Brookfield Renewable Trading & Marketing PacifiCorp East Idaho Power Company NF 7/8 BRDY IPCO
71 ConocoPhillips Company Bonneville Power Administration Sierra Pacific Power NF 7/8 LAGRANDE M345
72 ConocoPhillips Company Avista PacifiCorp East NF 7/8 LOLO BORA
73 ConocoPhillips Company Sierra Pacific Power Bonneville Power Administration NF 7/8 M345 LAGRANDE
74 ConocoPhillips Company PacifiCorp West PacifiCorp East NF 7/8 M500 BORA
75 CP Energy Marketing (US) Inc.NorthWestern/PacifiCorp East Sierra Pacific Power NF 7/8 BPAT.NWMT M345
76 CP Energy Marketing (US) Inc.PacifiCorp East Sierra Pacific Power NF 7/8 JBSN M345
77 CP Energy Marketing (US) Inc.PacifiCorp East PacifiCorp East NF 7/8 JEFF GSHN
78 CP Energy Marketing (US) Inc.PacifiCorp East Sierra Pacific Power NF 7/8 JEFF M345
79 Dynasty Power Inc.PacifiCorp East NorthWestern/PacifiCorp East NF 7/8 BORA AVAT.NWMT
80 Dynasty Power Inc.PacifiCorp East NorthWestern/PacifiCorp East NF 7/8 BORA BPAT.NWMT
81 Dynasty Power Inc.PacifiCorp East PacifiCorp West NF 7/8 BORA H500
82 Dynasty Power Inc.PacifiCorp East PacifiCorp West NF 7/8 BORA HURR
83 Dynasty Power Inc.PacifiCorp East Bonneville Power Administration NF 7/8 BORA LAGRANDE
84 Dynasty Power Inc.PacifiCorp East Avista NF 7/8 BORA LOLO
85 Dynasty Power Inc.PacifiCorp East Sierra Pacific Power NF 7/8 BORA M345
86 Dynasty Power Inc.NorthWestern/PacifiCorp East PacifiCorp East NF 7/8 BPAT.NWMT BORA
87 Dynasty Power Inc.NorthWestern/PacifiCorp East PacifiCorp East NF 7/8 BPAT.NWMT BRDY
88 Dynasty Power Inc.NorthWestern/PacifiCorp East Sierra Pacific Power NF 7/8 BPAT.NWMT M345
89 Dynasty Power Inc.PacifiCorp East NorthWestern/PacifiCorp East NF 7/8 BRDY BPAT.NWMT
90 Dynasty Power Inc.PacifiCorp West PacifiCorp East NF 7/8 HURR BORA
91 Dynasty Power Inc.PacifiCorp West Sierra Pacific Power NF 7/8 HURR M345
92 Dynasty Power Inc.PacifiCorp West PacifiCorp West NF 7/8 HURR POP
93 Dynasty Power Inc.PacifiCorp East NorthWestern/PacifiCorp East NF 7/8 JBSN AVAT.NWMT
94 Dynasty Power Inc.PacifiCorp East PacifiCorp East NF 7/8 JBSN BORA
95 Dynasty Power Inc.PacifiCorp East PacifiCorp East NF 7/8 JBSN BRDY
96 Dynasty Power Inc.PacifiCorp East Idaho Power Company NF 7/8 JBSN IPCO
97 Dynasty Power Inc.PacifiCorp East Bonneville Power Administration NF 7/8 JBSN LAGRANDE
98 Dynasty Power Inc.PacifiCorp East Sierra Pacific Power NF 7/8 JBSN M345
99 Dynasty Power Inc.PacifiCorp East PacifiCorp West NF 7/8 JBSN POP
100 Dynasty Power Inc.PacifiCorp East PacifiCorp East NF 7/8 JEFF BRDY
101 Dynasty Power Inc.Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE BORA
102 Dynasty Power Inc.Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE BRDY
103 Dynasty Power Inc.Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE JBSN
104 Dynasty Power Inc.Bonneville Power Administration Sierra Pacific Power NF 7/8 LAGRANDE M345
105 Dynasty Power Inc.Bonneville Power Administration PacifiCorp West NF 7/8 LAGRANDE POP
106 Dynasty Power Inc.Avista PacifiCorp East NF 7/8 LOLO BORA
107 Dynasty Power Inc.Sierra Pacific Power PacifiCorp East NF 7/8 M345 BORA
108 Dynasty Power Inc.Sierra Pacific Power PacifiCorp East SFP 7/8 M345 BORA
109 Dynasty Power Inc.Sierra Pacific Power NorthWestern/PacifiCorp East NF 7/8 M345 BPAT.NWMT
110 Dynasty Power Inc.Sierra Pacific Power PacifiCorp East NF 7/8 M345 BRDY
111 Dynasty Power Inc.Sierra Pacific Power Idaho Power Company NF 7/8 M345 IPCO
112 Dynasty Power Inc.Sierra Pacific Power Bonneville Power Administration NF 7/8 M345 LAGRANDE
113 Dynasty Power Inc.Sierra Pacific Power Bonneville Power Administration SFP 7/8 M345 LAGRANDE
114 Dynasty Power Inc.Sierra Pacific Power Avista NF 7/8 M345 LOLO
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")
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
Classification
(d)
Ferc Rate Schedule
of Tariff Number
(e)
Point of Receipt
(Substation or
Other
Designation)
(f)
Point of
Delivery
(Substation or
Other
Designation)
(g)
FERC FORM NO. 1 (ED. 12-90)
Page 328-330
115 Dynasty Power Inc.PacifiCorp West NorthWestern/PacifiCorp East NF 7/8 POP AVAT.NWMT
116 Dynasty Power Inc.PacifiCorp West Bonneville Power Administration NF 7/8 POP LAGRANDE
117 Dynasty Power Inc.PacifiCorp West PacifiCorp East NF 7/8 SMLK BORA
118 Dynasty Power Inc.PacifiCorp West PacifiCorp East SFP 7/8 SMLK BORA
119 Dynasty Power Inc.PacifiCorp West PacifiCorp East NF 7/8 SMLK JBSN
120 Dynasty Power Inc.PacifiCorp West Sierra Pacific Power NF 7/8 SMLK M345
121 Dynasty Power Inc.PacifiCorp West Sierra Pacific Power SFP 7/8 SMLK M345
122 Dynasty Power Inc.Idaho Power Company PacifiCorp East NF 7/8 WALLAWALLA BORA
123 Dynasty Power Inc.Idaho Power Company PacifiCorp East NF 7/8 WALLAWALLA BRDY
124 Dynasty Power Inc.Idaho Power Company Sierra Pacific Power NF 7/8 WALLAWALLA M345
125 Dynasty Power Inc.Idaho Power Company Sierra Pacific Power SFP 7/8 WALLAWALLA M345
126 EDF Trading North America, LLC PacifiCorp East PacifiCorp East SFP 7/8 BORA BRDY
127 EDF Trading North America, LLC PacifiCorp East NorthWestern/PacifiCorp East NF 7/8 GSHN BPAT.NWMT
128 Energy Keepers, Inc.PacifiCorp East NorthWestern/PacifiCorp East NF 7/8 BORA BPAT.NWMT
129 Energy Keepers, Inc.PacifiCorp East Bonneville Power Administration NF 7/8 BORA LAGRANDE
130 Energy Keepers, Inc.PacifiCorp East Bonneville Power Administration SFP 7/8 BORA LAGRANDE
131 Energy Keepers, Inc.PacifiCorp East NorthWestern/PacifiCorp East NF 7/8 BRDY BPAT.NWMT
132 Energy Keepers, Inc.PacifiCorp East Sierra Pacific Power NF 7/8 BRDY M345
133 Energy Keepers, Inc.PacifiCorp East Sierra Pacific Power SFP 7/8 BRDY M345
134 Energy Keepers, Inc.PacifiCorp East PacifiCorp West NF 7/8 BRDY POP
135 Energy Keepers, Inc.PacifiCorp East PacifiCorp East NF 7/8 JBSN BRDY
136 Energy Keepers, Inc.PacifiCorp East PacifiCorp East NF 7/8 JEFF BRDY
137 Energy Keepers, Inc.PacifiCorp East Sierra Pacific Power NF 7/8 JEFF M345
138 Energy Keepers, Inc.PacifiCorp East Sierra Pacific Power SFP 7/8 JEFF M345
139 Energy Keepers, Inc.Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE BRDY
140 Energy Keepers, Inc.Avista PacifiCorp East NF 7/8 LOLO BRDY
141 Energy Keepers, Inc.Sierra Pacific Power NorthWestern/PacifiCorp East NF 7/8 M345 BPAT.NWMT
142 Energy Keepers, Inc.Sierra Pacific Power NorthWestern/PacifiCorp East SFP 7/8 M345 BPAT.NWMT
143 Energy Keepers, Inc.Sierra Pacific Power Bonneville Power Administration SFP 7/8 M345 LAGRANDE
144 Energy Keepers, Inc.PacifiCorp West PacifiCorp East NF 7/8 SMLK BRDY
145 Energy Keepers, Inc.Idaho Power Company Avista NF 7/8 WALLAWALLA LOLO
146 Energy Keepers, Inc.Idaho Power Company Sierra Pacific Power NF 7/8 WALLAWALLA M345
147 Grove Solar Center, LLC NF 11
148 Guzman Energy Group LLC NorthWestern/PacifiCorp East PacifiCorp East NF 7/8 AVAT.NWMT BRDY
149 Guzman Energy Group LLC PacifiCorp East NorthWestern/PacifiCorp East NF 7/8 BORA BPAT.NWMT
150 Guzman Energy Group LLC PacifiCorp East PacifiCorp West NF 7/8 BORA HURR
151 Guzman Energy Group LLC PacifiCorp East Bonneville Power Administration NF 7/8 BORA LAGRANDE
152 Guzman Energy Group LLC PacifiCorp East Bonneville Power Administration SFP 7/8 BORA LAGRANDE
153 Guzman Energy Group LLC PacifiCorp East Avista NF 7/8 BORA LOLO
154 Guzman Energy Group LLC PacifiCorp East Sierra Pacific Power NF 7/8 BORA M345
155 Guzman Energy Group LLC PacifiCorp East PacifiCorp West NF 7/8 BORA M500
156 Guzman Energy Group LLC NorthWestern/PacifiCorp East PacifiCorp East NF 7/8 BPAT.NWMT BRDY
157 Guzman Energy Group LLC NorthWestern/PacifiCorp East Sierra Pacific Power NF 7/8 BPAT.NWMT M345
158 Guzman Energy Group LLC PacifiCorp East NorthWestern/PacifiCorp East NF 7/8 BRDY AVAT.NWMT
159 Guzman Energy Group LLC PacifiCorp East NorthWestern/PacifiCorp East NF 7/8 BRDY BPAT.NWMT
160 Guzman Energy Group LLC PacifiCorp East NorthWestern/PacifiCorp East SFP 7/8 BRDY BPAT.NWMT
161 Guzman Energy Group LLC PacifiCorp East PacifiCorp East NF 7/8 BRDY GSHN
162 Guzman Energy Group LLC PacifiCorp East PacifiCorp East SFP 7/8 BRDY JBSN
163 Guzman Energy Group LLC PacifiCorp East Bonneville Power Administration NF 7/8 BRDY LAGRANDE
164 Guzman Energy Group LLC PacifiCorp East Avista NF 7/8 BRDY LOLO
165 Guzman Energy Group LLC PacifiCorp East NorthWestern/PacifiCorp East NF 7/8 JBSN BPAT.NWMT
166 Guzman Energy Group LLC PacifiCorp East PacifiCorp East NF 7/8 JBSN BRDY
167 Guzman Energy Group LLC PacifiCorp East PacifiCorp West NF 7/8 JBSN POP
168 Guzman Energy Group LLC PacifiCorp East PacifiCorp East NF 7/8 JEFF BORA
169 Guzman Energy Group LLC PacifiCorp East Sierra Pacific Power NF 7/8 JEFF M345
170 Guzman Energy Group LLC Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE BORA
171 Guzman Energy Group LLC Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE BRDY
172 Guzman Energy Group LLC Bonneville Power Administration Sierra Pacific Power NF 7/8 LAGRANDE M345
173 Guzman Energy Group LLC Avista PacifiCorp East NF 7/8 LOLO BORA
174 Guzman Energy Group LLC Avista PacifiCorp East NF 7/8 LOLO BRDY
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")
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
Classification
(d)
Ferc Rate Schedule
of Tariff Number
(e)
Point of Receipt
(Substation or
Other
Designation)
(f)
Point of
Delivery
(Substation or
Other
Designation)
(g)
FERC FORM NO. 1 (ED. 12-90)
Page 328-330
175 Guzman Energy Group LLC Avista PacifiCorp East NF 7/8 LOLO JBSN
176 Guzman Energy Group LLC Avista Sierra Pacific Power NF 7/8 LOLO M345
177 Guzman Energy Group LLC Sierra Pacific Power NorthWestern/PacifiCorp East NF 7/8 M345 BPAT.NWMT
178 Guzman Energy Group LLC Sierra Pacific Power Bonneville Power Administration NF 7/8 M345 LAGRANDE
179 Guzman Energy Group LLC PacifiCorp West PacifiCorp East NF 7/8 M500 BORA
180 Guzman Energy Group LLC PacifiCorp West PacifiCorp East NF 7/8 POP BRDY
181 Guzman Energy Group LLC PacifiCorp West PacifiCorp East SFP 7/8 POP BRDY
182 Guzman Energy Group LLC PacifiCorp West Bonneville Power Administration NF 7/8 POP LAGRANDE
183 Guzman Energy Group LLC PacifiCorp West PacifiCorp East NF 7/8 SMLK BRDY
184 Guzman Energy Group LLC PacifiCorp West Sierra Pacific Power NF 7/8 SMLK M345
185 Guzman Energy Group LLC Idaho Power Company PacifiCorp East NF 7/8 WALLAWALLA BORA
186 Guzman Energy Group LLC Idaho Power Company Sierra Pacific Power NF 7/8 WALLAWALLA M345
187 Idaho Wind Partners 1, LLC (Camp Reed Wind Park)NF 11
188 Idaho Wind Partners 1, LLC (Milner Dam Wind)NF 11
189 Idaho Wind Partners 1, LLC (Oregon Trail Wind Park)NF 11
190 Idaho Wind Partners 1, LLC (Payne's Ferry Wind
Park)NF 11
191 Idaho Wind Partners 1, LLC (Thousand Springs Wind
Park)NF 11
192 Idaho Wind Partners 1, LLC (Tuana Gulch Wind
Park)NF 11
193 Idaho Wind Partners 1, LLC (Yahoo Creek Wind
Park)NF 11
194 Idaho Winds LLC (Sawtooth Wind Project)NF 11
195 Jett Creek Windfarm, LLC NF 11
196 Lime Wind LLC NF 11
197 Macquarie Energy, LLC PacifiCorp East PacifiCorp East SFP 7/8 BORA BRDY
198 Macquarie Energy, LLC PacifiCorp East Bonneville Power Administration NF 7/8 BORA LAGRANDE
199 Macquarie Energy, LLC PacifiCorp East Bonneville Power Administration SFP 7/8 BORA LAGRANDE
200 Macquarie Energy, LLC PacifiCorp East Sierra Pacific Power NF 7/8 BORA M345
201 Macquarie Energy, LLC NorthWestern/PacifiCorp East Sierra Pacific Power NF 7/8 BPAT.NWMT M345
202 Macquarie Energy, LLC PacifiCorp East PacifiCorp East NF 7/8 BRDY BORA
203 Macquarie Energy, LLC PacifiCorp East Sierra Pacific Power NF 7/8 BRDY M345
204 Macquarie Energy, LLC PacifiCorp East Sierra Pacific Power SFP 7/8 BRDY M345
205 Macquarie Energy, LLC PacifiCorp East NorthWestern/PacifiCorp East NF 7/8 JBSN AVAT.NWMT
206 Macquarie Energy, LLC PacifiCorp East NorthWestern/PacifiCorp East NF 7/8 JBSN BPAT.NWMT
207 Macquarie Energy, LLC PacifiCorp East PacifiCorp East NF 7/8 JBSN BRDY
208 Macquarie Energy, LLC PacifiCorp East Bonneville Power Administration NF 7/8 JBSN LAGRANDE
209 Macquarie Energy, LLC PacifiCorp East Sierra Pacific Power NF 7/8 JBSN M345
210 Macquarie Energy, LLC PacifiCorp East Sierra Pacific Power SFP 7/8 JBSN M345
211 Macquarie Energy, LLC Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE BRDY
212 Macquarie Energy, LLC Bonneville Power Administration Sierra Pacific Power NF 7/8 LAGRANDE M345
213 Macquarie Energy, LLC Avista Sierra Pacific Power NF 7/8 LOLO M345
214 Macquarie Energy, LLC Sierra Pacific Power NorthWestern/PacifiCorp East NF 7/8 M345 AVAT.NWMT
215 Macquarie Energy, LLC Sierra Pacific Power NorthWestern/PacifiCorp East SFP 7/8 M345 AVAT.NWMT
216 Macquarie Energy, LLC Sierra Pacific Power PacifiCorp East NF 7/8 M345 BORA
217 Macquarie Energy, LLC Sierra Pacific Power NorthWestern/PacifiCorp East NF 7/8 M345 BPAT.NWMT
218 Macquarie Energy, LLC Sierra Pacific Power NorthWestern/PacifiCorp East SFP 7/8 M345 BPAT.NWMT
219 Macquarie Energy, LLC Sierra Pacific Power PacifiCorp East NF 7/8 M345 BRDY
220 Macquarie Energy, LLC Sierra Pacific Power PacifiCorp East SFP 7/8 M345 BRDY
221 Macquarie Energy, LLC Sierra Pacific Power Bonneville Power Administration NF 7/8 M345 LAGRANDE
222 Macquarie Energy, LLC Sierra Pacific Power Bonneville Power Administration SFP 7/8 M345 LAGRANDE
223 Macquarie Energy, LLC Sierra Pacific Power Avista NF 7/8 M345 LOLO
224 Macquarie Energy, LLC NorthWestern/PacifiCorp East Sierra Pacific Power NF 7/8 MLCK M345
225 Macquarie Energy, LLC PacifiCorp West Sierra Pacific Power NF 7/8 SMLK M345
226 Mag Energy Solutions NorthWestern/PacifiCorp East Sierra Pacific Power NF 7/8 AVAT.NWMT M345
227 Mag Energy Solutions NorthWestern/PacifiCorp East Sierra Pacific Power SFP 7/8 AVAT.NWMT M345
228 Mag Energy Solutions Idaho Power Company PacifiCorp East NF 7/8 BGSY JEFF
229 Mag Energy Solutions NorthWestern/PacifiCorp East Sierra Pacific Power NF 7/8 BPAT.NWMT M345
230 Mag Energy Solutions NorthWestern/PacifiCorp East Sierra Pacific Power SFP 7/8 BPAT.NWMT M345
231 Mag Energy Solutions PacifiCorp East Sierra Pacific Power SFP 7/8 BRDY M345
232 Mag Energy Solutions PacifiCorp East Sierra Pacific Power NF 7/8 JBSN M345
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")
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
Classification
(d)
Ferc Rate Schedule
of Tariff Number
(e)
Point of Receipt
(Substation or
Other
Designation)
(f)
Point of
Delivery
(Substation or
Other
Designation)
(g)
FERC FORM NO. 1 (ED. 12-90)
Page 328-330
233 Mag Energy Solutions PacifiCorp East Sierra Pacific Power NF 7/8 JEFF M345
234 Mag Energy Solutions PacifiCorp East Sierra Pacific Power SFP 7/8 JEFF M345
235 Mag Energy Solutions Sierra Pacific Power PacifiCorp East NF 7/8 M345 GSHN
236 Mercuria Energy America, LLC PacifiCorp East PacifiCorp East SFP 7/8 BRDY ANTE
237 Mercuria Energy America, LLC PacifiCorp East PacifiCorp East NF 7/8 BRDY JBSN
238 Mercuria Energy America, LLC PacifiCorp East Sierra Pacific Power NF 7/8 BRDY M345
239 Mercuria Energy America, LLC PacifiCorp East PacifiCorp East NF 7/8 JBSN BRDY
240 Mercuria Energy America, LLC PacifiCorp East PacifiCorp East SFP 7/8 JBSN BRDY
241 Mercuria Energy America, LLC PacifiCorp East Sierra Pacific Power NF 7/8 JBSN M345
242 Mercuria Energy America, LLC PacifiCorp East Sierra Pacific Power SFP 7/8 JBSN M345
243 Mercuria Energy America, LLC Avista NorthWestern/PacifiCorp East NF 7/8 LOLO BPAT.NWMT
244 Mercuria Energy America, LLC Sierra Pacific Power PacifiCorp East NF 7/8 M345 BRDY
245 Mercuria Energy America, LLC Sierra Pacific Power PacifiCorp West NF 7/8 M345 H500
246 Mercuria Energy America, LLC PacifiCorp West NorthWestern/PacifiCorp East NF 7/8 POP BPAT.NWMT
247 Morgan Stanley Capital Group. Inc.NorthWestern/PacifiCorp East Sierra Pacific Power NF 7/8 AVAT.NWMT M345
248 Morgan Stanley Capital Group. Inc.NorthWestern/PacifiCorp East Sierra Pacific Power SFP 7/8 AVAT.NWMT M345
249 Morgan Stanley Capital Group. Inc.PacifiCorp East NorthWestern/PacifiCorp East NF 7/8 BORA BPAT.NWMT
250 Morgan Stanley Capital Group. Inc.PacifiCorp East PacifiCorp East SFP 7/8 BORA BRDY
251 Morgan Stanley Capital Group. Inc.PacifiCorp East PacifiCorp West NF 7/8 BORA H500
252 Morgan Stanley Capital Group. Inc.PacifiCorp East PacifiCorp East SFP 7/8 BORA JBSN
253 Morgan Stanley Capital Group. Inc.PacifiCorp East Bonneville Power Administration NF 7/8 BORA LAGRANDE
254 Morgan Stanley Capital Group. Inc.PacifiCorp East Bonneville Power Administration SFP 7/8 BORA LAGRANDE
255 Morgan Stanley Capital Group. Inc.PacifiCorp East Avista NF 7/8 BORA LOLO
256 Morgan Stanley Capital Group. Inc.PacifiCorp East Avista SFP 7/8 BORA LOLO
257 Morgan Stanley Capital Group. Inc.PacifiCorp East Sierra Pacific Power NF 7/8 BORA M345
258 Morgan Stanley Capital Group. Inc.PacifiCorp East Sierra Pacific Power SFP 7/8 BORA M345
259 Morgan Stanley Capital Group. Inc.NorthWestern/PacifiCorp East PacifiCorp East SFP 7/8 BPAT.NWMT BORA
260 Morgan Stanley Capital Group. Inc.NorthWestern/PacifiCorp East PacifiCorp East NF 7/8 BPAT.NWMT BRDY
261 Morgan Stanley Capital Group. Inc.NorthWestern/PacifiCorp East PacifiCorp East SFP 7/8 BPAT.NWMT BRDY
262 Morgan Stanley Capital Group. Inc.NorthWestern/PacifiCorp East Sierra Pacific Power NF 7/8 BPAT.NWMT M345
263 Morgan Stanley Capital Group. Inc.NorthWestern/PacifiCorp East Sierra Pacific Power SFP 7/8 BPAT.NWMT M345
264 Morgan Stanley Capital Group. Inc.PacifiCorp East NorthWestern/PacifiCorp East NF 7/8 BRDY AVAT.NWMT
265 Morgan Stanley Capital Group. Inc.PacifiCorp East PacifiCorp East NF 7/8 BRDY BORA
266 Morgan Stanley Capital Group. Inc.PacifiCorp East PacifiCorp East SFP 7/8 BRDY BORA
267 Morgan Stanley Capital Group. Inc.PacifiCorp East NorthWestern/PacifiCorp East NF 7/8 BRDY BPAT.NWMT
268 Morgan Stanley Capital Group. Inc.PacifiCorp East Bonneville Power Administration NF 7/8 BRDY LAGRANDE
269 Morgan Stanley Capital Group. Inc.PacifiCorp East Avista NF 7/8 BRDY LOLO
270 Morgan Stanley Capital Group. Inc.PacifiCorp East Sierra Pacific Power NF 7/8 BRDY M345
271 Morgan Stanley Capital Group. Inc.PacifiCorp East Sierra Pacific Power SFP 7/8 BRDY M345
272 Morgan Stanley Capital Group. Inc.PacifiCorp East PacifiCorp East NF 7/8 JBSN BORA
273 Morgan Stanley Capital Group. Inc.PacifiCorp East PacifiCorp East SFP 7/8 JBSN BORA
274 Morgan Stanley Capital Group. Inc.PacifiCorp East Sierra Pacific Power NF 7/8 JBSN M345
275 Morgan Stanley Capital Group. Inc.PacifiCorp East PacifiCorp East NF 7/8 JEFF BORA
276 Morgan Stanley Capital Group. Inc.PacifiCorp East PacifiCorp East SFP 7/8 JEFF BORA
277 Morgan Stanley Capital Group. Inc.PacifiCorp East Bonneville Power Administration NF 7/8 JEFF LAGRANDE
278 Morgan Stanley Capital Group. Inc.PacifiCorp East Sierra Pacific Power NF 7/8 JEFF M345
279 Morgan Stanley Capital Group. Inc.PacifiCorp East Sierra Pacific Power SFP 7/8 JEFF M345
280 Morgan Stanley Capital Group. Inc.Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE BORA
281 Morgan Stanley Capital Group. Inc.Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE BRDY
282 Morgan Stanley Capital Group. Inc.Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE JEFF
283 Morgan Stanley Capital Group. Inc.Bonneville Power Administration Sierra Pacific Power NF 7/8 LAGRANDE M345
284 Morgan Stanley Capital Group. Inc.Avista PacifiCorp East NF 7/8 LOLO BORA
285 Morgan Stanley Capital Group. Inc.Avista PacifiCorp East NF 7/8 LOLO BRDY
286 Morgan Stanley Capital Group. Inc.Avista Sierra Pacific Power NF 7/8 LOLO M345
287 Morgan Stanley Capital Group. Inc.Idaho Power Company Bonneville Power Administration NF 7/8 LYPK LAGRANDE
288 Morgan Stanley Capital Group. Inc.Idaho Power Company Sierra Pacific Power NF 7/8 LYPK M345
289 Morgan Stanley Capital Group. Inc.Sierra Pacific Power PacifiCorp East NF 7/8 M345 BORA
290 Morgan Stanley Capital Group. Inc.Sierra Pacific Power PacifiCorp East SFP 7/8 M345 BORA
291 Morgan Stanley Capital Group. Inc.Sierra Pacific Power NorthWestern/PacifiCorp East NF 7/8 M345 BPAT.NWMT
292 Morgan Stanley Capital Group. Inc.Sierra Pacific Power NorthWestern/PacifiCorp East SFP 7/8 M345 BPAT.NWMT
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")
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
Classification
(d)
Ferc Rate Schedule
of Tariff Number
(e)
Point of Receipt
(Substation or
Other
Designation)
(f)
Point of
Delivery
(Substation or
Other
Designation)
(g)
FERC FORM NO. 1 (ED. 12-90)
Page 328-330
293 Morgan Stanley Capital Group. Inc.Sierra Pacific Power PacifiCorp East NF 7/8 M345 BRDY
294 Morgan Stanley Capital Group. Inc.Sierra Pacific Power Bonneville Power Administration NF 7/8 M345 LAGRANDE
295 Morgan Stanley Capital Group. Inc.Sierra Pacific Power Bonneville Power Administration SFP 7/8 M345 LAGRANDE
296 Morgan Stanley Capital Group. Inc.PacifiCorp West PacifiCorp East NF 7/8 SMLK BORA
297 Morgan Stanley Capital Group. Inc.PacifiCorp West Sierra Pacific Power NF 7/8 SMLK M345
298 Morgan Stanley Capital Group. Inc.Idaho Power Company PacifiCorp East NF 7/8 WALLAWALLA BORA
299 Morgan Stanley Capital Group. Inc.Idaho Power Company PacifiCorp East NF 7/8 WALLAWALLA BRDY
300 Morgan Stanley Capital Group. Inc.Idaho Power Company Sierra Pacific Power NF 7/8 WALLAWALLA M345
301 Nevada Power Company d/b/a NV Energy PacifiCorp East Sierra Pacific Power NF 7/8 BORA M345
302 Nevada Power Company d/b/a NV Energy Bonneville Power Administration Sierra Pacific Power NF 7/8 LAGRANDE M345
303 Nevada Power Company d/b/a NV Energy Avista Sierra Pacific Power NF 7/8 LOLO M345
304 Nevada Power Company d/b/a NV Energy Sierra Pacific Power PacifiCorp East NF 7/8 M345 BORA
305 Nevada Power Company d/b/a NV Energy Sierra Pacific Power Bonneville Power Administration NF 7/8 M345 LAGRANDE
306 Nevada Power Company d/b/a NV Energy Sierra Pacific Power Avista NF 7/8 M345 LOLO
307 NorthWestern Energy PacifiCorp East Bonneville Power Administration NF 7/8 BRDY LAGRANDE
308 PacifiCorp PacifiCorp East Avista NF 7/8 BORA LOLO
309 PacifiCorp PacifiCorp East Avista SFP 7/8 BORA LOLO
310 PacifiCorp PacifiCorp East PacifiCorp East NF 7/8 BRDY BORA
311 PacifiCorp PacifiCorp East PacifiCorp East NF 7/8 BRDY BRDY
312 PacifiCorp PacifiCorp East Bonneville Power Administration NF 7/8 BRDY LAGRANDE
313 PacifiCorp PacifiCorp East Idaho Power Company NF 7/8 JEFF BGSY
314 PacifiCorp Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE BORA
315 PacifiCorp Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE BRDY
316 PacifiCorp Avista PacifiCorp East NF 7/8 LOLO BRDY
317 PacifiCorp PacifiCorp West PacifiCorp East NF 7/8 SMLK BORA
318 PacifiCorp PacifiCorp West PacifiCorp East NF 7/8 SMLK BRDY
319 PacifiCorp Idaho Power Company PacifiCorp East NF 7/8 WALLAWALLA BORA
320 Portland General Electric PacifiCorp East Bonneville Power Administration NF 7/8 BORA LAGRANDE
321 Portland General Electric PacifiCorp East PacifiCorp East NF 7/8 BRDY BORA
322 Portland General Electric PacifiCorp East Bonneville Power Administration NF 7/8 BRDY LAGRANDE
323 Portland General Electric PacifiCorp West Sierra Pacific Power NF 7/8 HURR M345
324 Portland General Electric PacifiCorp East Sierra Pacific Power NF 7/8 JEFF M345
325 Portland General Electric Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE BRDY
326 Portland General Electric Bonneville Power Administration Sierra Pacific Power NF 7/8 LAGRANDE M345
327 Portland General Electric Sierra Pacific Power Bonneville Power Administration NF 7/8 M345 LAGRANDE
328 Portland General Electric PacifiCorp West Sierra Pacific Power NF 7/8 SMLK M345
329 Powerex Corp.NorthWestern/PacifiCorp East Bonneville Power Administration NF 7/8 AVAT.NWMT LAGRANDE
330 Powerex Corp.Idaho Power Company PacifiCorp East SFP 7/8 BGSY JEFF
331 Powerex Corp.PacifiCorp East NorthWestern/PacifiCorp East NF 7/8 BORA BPAT.NWMT
332 Powerex Corp.PacifiCorp East PacifiCorp East NF 7/8 BORA BRDY
333 Powerex Corp.PacifiCorp East PacifiCorp West NF 7/8 BORA H500
334 Powerex Corp.PacifiCorp East PacifiCorp West NF 7/8 BORA HURR
335 Powerex Corp.PacifiCorp East PacifiCorp East NF 7/8 BORA JBSN
336 Powerex Corp.PacifiCorp East Bonneville Power Administration NF 7/8 BORA LAGRANDE
337 Powerex Corp.PacifiCorp East Bonneville Power Administration SFP 7/8 BORA LAGRANDE
338 Powerex Corp.PacifiCorp East Avista NF 7/8 BORA LOLO
339 Powerex Corp.PacifiCorp East Sierra Pacific Power NF 7/8 BORA M345
340 Powerex Corp.PacifiCorp East Sierra Pacific Power SFP 7/8 BORA M345
341 Powerex Corp.NorthWestern/PacifiCorp East PacifiCorp East NF 7/8 BPAT.NWMT BORA
342 Powerex Corp.NorthWestern/PacifiCorp East PacifiCorp East SFP 7/8 BPAT.NWMT BORA
343 Powerex Corp.NorthWestern/PacifiCorp East PacifiCorp East NF 7/8 BPAT.NWMT BRDY
344 Powerex Corp.NorthWestern/PacifiCorp East Sierra Pacific Power NF 7/8 BPAT.NWMT M345
345 Powerex Corp.NorthWestern/PacifiCorp East Sierra Pacific Power SFP 7/8 BPAT.NWMT M345
346 Powerex Corp.PacifiCorp East PacifiCorp East NF 7/8 BRDY BORA
347 Powerex Corp.PacifiCorp East NorthWestern/PacifiCorp East NF 7/8 BRDY BPAT.NWMT
348 Powerex Corp.PacifiCorp East PacifiCorp West NF 7/8 BRDY HURR
349 Powerex Corp.PacifiCorp East Bonneville Power Administration NF 7/8 BRDY LAGRANDE
350 Powerex Corp.PacifiCorp East Sierra Pacific Power NF 7/8 BRDY M345
351 Powerex Corp.PacifiCorp East Sierra Pacific Power SFP 7/8 BRDY M345
352 Powerex Corp.PacifiCorp East PacifiCorp East NF 7/8 GSHN BORA
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")
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
Classification
(d)
Ferc Rate Schedule
of Tariff Number
(e)
Point of Receipt
(Substation or
Other
Designation)
(f)
Point of
Delivery
(Substation or
Other
Designation)
(g)
FERC FORM NO. 1 (ED. 12-90)
Page 328-330
353 Powerex Corp.PacifiCorp East NorthWestern/PacifiCorp East NF 7/8 GSHN BPAT.NWMT
354 Powerex Corp.PacifiCorp East NorthWestern/PacifiCorp East SFP 7/8 GSHN BPAT.NWMT
355 Powerex Corp.PacifiCorp East PacifiCorp East NF 7/8 GSHN BRDY
356 Powerex Corp.PacifiCorp East Bonneville Power Administration NF 7/8 GSHN LAGRANDE
357 Powerex Corp.PacifiCorp East Bonneville Power Administration SFP 7/8 GSHN LAGRANDE
358 Powerex Corp.PacifiCorp East Avista NF 7/8 GSHN LOLO
359 Powerex Corp.PacifiCorp East Avista SFP 7/8 GSHN LOLO
360 Powerex Corp.PacifiCorp East Sierra Pacific Power NF 7/8 GSHN M345
361 Powerex Corp.PacifiCorp West PacifiCorp East NF 7/8 HURR BORA
362 Powerex Corp.PacifiCorp West NorthWestern/PacifiCorp East NF 7/8 HURR BPAT.NWMT
363 Powerex Corp.PacifiCorp West PacifiCorp East NF 7/8 HURR BRDY
364 Powerex Corp.PacifiCorp West Bonneville Power Administration NF 7/8 HURR LAGRANDE
365 Powerex Corp.PacifiCorp West Sierra Pacific Power NF 7/8 HURR M345
366 Powerex Corp.PacifiCorp East PacifiCorp East NF 7/8 JBSN BORA
367 Powerex Corp.PacifiCorp East NorthWestern/PacifiCorp East NF 7/8 JBSN BPAT.NWMT
368 Powerex Corp.PacifiCorp East PacifiCorp East NF 7/8 JBSN GSHN
369 Powerex Corp.PacifiCorp East Bonneville Power Administration NF 7/8 JBSN LAGRANDE
370 Powerex Corp.PacifiCorp East PacifiCorp East NF 7/8 JEFF BRDY
371 Powerex Corp.PacifiCorp East PacifiCorp East SFP 7/8 JEFF BRDY
372 Powerex Corp.PacifiCorp East Sierra Pacific Power NF 7/8 JEFF M345
373 Powerex Corp.PacifiCorp East Sierra Pacific Power SFP 7/8 JEFF M345
374 Powerex Corp.Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE BORA
375 Powerex Corp.Bonneville Power Administration PacifiCorp East SFP 7/8 LAGRANDE BORA
376 Powerex Corp.Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE BRDY
377 Powerex Corp.Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE JBSN
378 Powerex Corp.Bonneville Power Administration Sierra Pacific Power NF 7/8 LAGRANDE M345
379 Powerex Corp.Bonneville Power Administration Sierra Pacific Power SFP 7/8 LAGRANDE M345
380 Powerex Corp.Avista PacifiCorp East NF 7/8 LOLO BRDY
381 Powerex Corp.Avista PacifiCorp East SFP 7/8 LOLO BRDY
382 Powerex Corp.Avista Sierra Pacific Power NF 7/8 LOLO M345
383 Powerex Corp.Avista Sierra Pacific Power SFP 7/8 LOLO M345
384 Powerex Corp.Sierra Pacific Power PacifiCorp East NF 7/8 M345 BORA
385 Powerex Corp.Sierra Pacific Power NorthWestern/PacifiCorp East NF 7/8 M345 BPAT.NWMT
386 Powerex Corp.Sierra Pacific Power NorthWestern/PacifiCorp East SFP 7/8 M345 BPAT.NWMT
387 Powerex Corp.Sierra Pacific Power PacifiCorp East NF 7/8 M345 BRDY
388 Powerex Corp.Sierra Pacific Power PacifiCorp East SFP 7/8 M345 BRDY
389 Powerex Corp.Sierra Pacific Power PacifiCorp West NF 7/8 M345 H500
390 Powerex Corp.Sierra Pacific Power Bonneville Power Administration NF 7/8 M345 LAGRANDE
391 Powerex Corp.Sierra Pacific Power Bonneville Power Administration SFP 7/8 M345 LAGRANDE
392 Powerex Corp.Sierra Pacific Power Avista SFP 7/8 M345 LOLO
393 Powerex Corp.PacifiCorp West Bonneville Power Administration NF 7/8 POP LAGRANDE
394 Powerex Corp.PacifiCorp West PacifiCorp East NF 7/8 SMLK BORA
395 Powerex Corp.PacifiCorp West PacifiCorp East SFP 7/8 SMLK BORA
396 Powerex Corp.PacifiCorp West PacifiCorp East NF 7/8 SMLK BRDY
397 Powerex Corp.PacifiCorp West Sierra Pacific Power NF 7/8 SMLK M345
398 Powerex Corp.PacifiCorp West Sierra Pacific Power SFP 7/8 SMLK M345
399 Powerex Corp.Idaho Power Company PacifiCorp East NF 7/8 WALLAWALLA BORA
400 Powerex Corp.Idaho Power Company PacifiCorp East SFP 7/8 WALLAWALLA BORA
401 Powerex Corp.Idaho Power Company PacifiCorp East NF 7/8 WALLAWALLA BRDY
402 Powerex Corp.Idaho Power Company PacifiCorp East SFP 7/8 WALLAWALLA BRDY
403 Powerex Corp.Idaho Power Company Sierra Pacific Power NF 7/8 WALLAWALLA M345
404 Powerex Corp.Idaho Power Company Sierra Pacific Power SFP 7/8 WALLAWALLA M345
405 Prospector Windfarm, LLC NF 11
406 Puget Sound Energy Sierra Pacific Power Bonneville Power Administration NF 7/8 M345 LAGRANDE
407 Rainbow Energy Marketing Corporation PacifiCorp East NorthWestern/PacifiCorp East NF 7/8 BORA BPAT.NWMT
408 Rainbow Energy Marketing Corporation PacifiCorp East PacifiCorp West NF 7/8 BORA HURR
409 Rainbow Energy Marketing Corporation PacifiCorp East Bonneville Power Administration NF 7/8 BORA LAGRANDE
410 Rainbow Energy Marketing Corporation PacifiCorp East Avista NF 7/8 BORA LOLO
411 Rainbow Energy Marketing Corporation NorthWestern/PacifiCorp East PacifiCorp East NF 7/8 BPAT.NWMT BORA
412 Rainbow Energy Marketing Corporation NorthWestern/PacifiCorp East PacifiCorp East NF 7/8 BPAT.NWMT JBSN
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")
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
Classification
(d)
Ferc Rate Schedule
of Tariff Number
(e)
Point of Receipt
(Substation or
Other
Designation)
(f)
Point of
Delivery
(Substation or
Other
Designation)
(g)
FERC FORM NO. 1 (ED. 12-90)
Page 328-330
413 Rainbow Energy Marketing Corporation NorthWestern/PacifiCorp East Sierra Pacific Power NF 7/8 BPAT.NWMT M345
414 Rainbow Energy Marketing Corporation PacifiCorp East Bonneville Power Administration NF 7/8 BRDY LAGRANDE
415 Rainbow Energy Marketing Corporation PacifiCorp East Sierra Pacific Power NF 7/8 BRDY M345
416 Rainbow Energy Marketing Corporation PacifiCorp East Sierra Pacific Power NF 7/8 GSHN M345
417 Rainbow Energy Marketing Corporation PacifiCorp West PacifiCorp East NF 7/8 HURR BORA
418 Rainbow Energy Marketing Corporation PacifiCorp West Sierra Pacific Power NF 7/8 HURR M345
419 Rainbow Energy Marketing Corporation PacifiCorp East PacifiCorp East NF 7/8 JBSN BORA
420 Rainbow Energy Marketing Corporation PacifiCorp East Bonneville Power Administration NF 7/8 JBSN LAGRANDE
421 Rainbow Energy Marketing Corporation PacifiCorp East Sierra Pacific Power NF 7/8 JBSN M345
422 Rainbow Energy Marketing Corporation PacifiCorp East PacifiCorp West NF 7/8 JBSN POP
423 Rainbow Energy Marketing Corporation PacifiCorp East Sierra Pacific Power NF 7/8 JEFF M345
424 Rainbow Energy Marketing Corporation Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE BORA
425 Rainbow Energy Marketing Corporation Bonneville Power Administration Sierra Pacific Power NF 7/8 LAGRANDE M345
426 Rainbow Energy Marketing Corporation Avista PacifiCorp East NF 7/8 LOLO BORA
427 Rainbow Energy Marketing Corporation Sierra Pacific Power PacifiCorp East NF 7/8 M345 BORA
428 Rainbow Energy Marketing Corporation Sierra Pacific Power NorthWestern/PacifiCorp East NF 7/8 M345 BPAT.NWMT
429 Rainbow Energy Marketing Corporation Sierra Pacific Power Bonneville Power Administration NF 7/8 M345 LAGRANDE
430 Rainbow Energy Marketing Corporation Sierra Pacific Power Avista NF 7/8 M345 LOLO
431 Rainbow Energy Marketing Corporation Sierra Pacific Power PacifiCorp West NF 7/8 M345 POP
432 Rainbow Energy Marketing Corporation PacifiCorp West NorthWestern/PacifiCorp East NF 7/8 POP BPAT.NWMT
433 Rainbow Energy Marketing Corporation PacifiCorp West Bonneville Power Administration NF 7/8 POP LAGRANDE
434 Rainbow Energy Marketing Corporation PacifiCorp West Sierra Pacific Power NF 7/8 POP M345
435 Rainbow Energy Marketing Corporation PacifiCorp West PacifiCorp East NF 7/8 SMLK BORA
436 Rainbow Energy Marketing Corporation PacifiCorp West Sierra Pacific Power NF 7/8 SMLK M345
437 Rainbow Energy Marketing Corporation Idaho Power Company PacifiCorp East NF 7/8 WALLAWALLA BORA
438 Rainbow Energy Marketing Corporation Idaho Power Company Sierra Pacific Power NF 7/8 WALLAWALLA M345
439 Rockland Wind Farm, LLC NF 11
440 Shell Energy North America (US), L.P.NorthWestern/PacifiCorp East Sierra Pacific Power NF 7/8 AVAT.NWMT M345
441 Shell Energy North America (US), L.P.PacifiCorp East NorthWestern/PacifiCorp East NF 7/8 BORA BPAT.NWMT
442 Shell Energy North America (US), L.P.PacifiCorp East PacifiCorp East NF 7/8 BORA BRDY
443 Shell Energy North America (US), L.P.PacifiCorp East Bonneville Power Administration NF 7/8 BORA LAGRANDE
444 Shell Energy North America (US), L.P.PacifiCorp East Sierra Pacific Power NF 7/8 BORA M345
445 Shell Energy North America (US), L.P.NorthWestern/PacifiCorp East PacifiCorp East NF 7/8 BPAT.NWMT BORA
446 Shell Energy North America (US), L.P.NorthWestern/PacifiCorp East PacifiCorp East NF 7/8 BPAT.NWMT BRDY
447 Shell Energy North America (US), L.P.NorthWestern/PacifiCorp East Sierra Pacific Power NF 7/8 BPAT.NWMT M345
448 Shell Energy North America (US), L.P.PacifiCorp East PacifiCorp East NF 7/8 BRDY ANTE
449 Shell Energy North America (US), L.P.PacifiCorp East NorthWestern/PacifiCorp East NF 7/8 BRDY BPAT.NWMT
450 Shell Energy North America (US), L.P.PacifiCorp East Bonneville Power Administration NF 7/8 BRDY LAGRANDE
451 Shell Energy North America (US), L.P.PacifiCorp East Avista SFP 7/8 BRDY LOLO
452 Shell Energy North America (US), L.P.PacifiCorp East Sierra Pacific Power NF 7/8 BRDY M345
453 Shell Energy North America (US), L.P.PacifiCorp East Sierra Pacific Power SFP 7/8 BRDY M345
454 Shell Energy North America (US), L.P.PacifiCorp East Bonneville Power Administration NF 7/8 GSHN LAGRANDE
455 Shell Energy North America (US), L.P.PacifiCorp West PacifiCorp East NF 7/8 HURR BORA
456 Shell Energy North America (US), L.P.PacifiCorp West Bonneville Power Administration NF 7/8 HURR LAGRANDE
457 Shell Energy North America (US), L.P.PacifiCorp West Sierra Pacific Power NF 7/8 HURR M345
458 Shell Energy North America (US), L.P.Idaho Power Company Bonneville Power Administration NF 7/8 IPCOGEN LAGRANDE
459 Shell Energy North America (US), L.P.PacifiCorp East NorthWestern/PacifiCorp East NF 7/8 JBSN BPAT.NWMT
460 Shell Energy North America (US), L.P.PacifiCorp East Bonneville Power Administration NF 7/8 JBSN LAGRANDE
461 Shell Energy North America (US), L.P.PacifiCorp East Sierra Pacific Power NF 7/8 JBSN M345
462 Shell Energy North America (US), L.P.PacifiCorp East PacifiCorp West NF 7/8 JBSN M500
463 Shell Energy North America (US), L.P.PacifiCorp East Sierra Pacific Power NF 7/8 JEFF M345
464 Shell Energy North America (US), L.P.Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE BORA
465 Shell Energy North America (US), L.P.Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE BRDY
466 Shell Energy North America (US), L.P.Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE JBSN
467 Shell Energy North America (US), L.P.Bonneville Power Administration Sierra Pacific Power NF 7/8 LAGRANDE M345
468 Shell Energy North America (US), L.P.Avista PacifiCorp East NF 7/8 LOLO BRDY
469 Shell Energy North America (US), L.P.Avista Sierra Pacific Power NF 7/8 LOLO M345
470 Shell Energy North America (US), L.P.Idaho Power Company PacifiCorp East NF 7/8 LYPK BORA
471 Shell Energy North America (US), L.P.Idaho Power Company NorthWestern/PacifiCorp East NF 7/8 LYPK BPAT.NWMT
472 Shell Energy North America (US), L.P.Idaho Power Company PacifiCorp East NF 7/8 LYPK BRDY
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")
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
Classification
(d)
Ferc Rate Schedule
of Tariff Number
(e)
Point of Receipt
(Substation or
Other
Designation)
(f)
Point of
Delivery
(Substation or
Other
Designation)
(g)
FERC FORM NO. 1 (ED. 12-90)
Page 328-330
473 Shell Energy North America (US), L.P.Idaho Power Company PacifiCorp East SFP 7/8 LYPK BRDY
474 Shell Energy North America (US), L.P.Idaho Power Company Sierra Pacific Power NF 7/8 LYPK M345
475 Shell Energy North America (US), L.P.Idaho Power Company Sierra Pacific Power SFP 7/8 LYPK M345
476 Shell Energy North America (US), L.P.Sierra Pacific Power NorthWestern/PacifiCorp East NF 7/8 M345 BPAT.NWMT
477 Shell Energy North America (US), L.P.Sierra Pacific Power PacifiCorp East NF 7/8 M345 BRDY
478 Shell Energy North America (US), L.P.Sierra Pacific Power PacifiCorp East SFP 7/8 M345 BRDY
479 Shell Energy North America (US), L.P.Sierra Pacific Power Bonneville Power Administration NF 7/8 M345 LAGRANDE
480 Shell Energy North America (US), L.P.Sierra Pacific Power Bonneville Power Administration SFP 7/8 M345 LAGRANDE
481 Shell Energy North America (US), L.P.Sierra Pacific Power NorthWestern/PacifiCorp East NF 7/8 M345 MLCK
482 Shell Energy North America (US), L.P.PacifiCorp West PacifiCorp East NF 7/8 M500 BORA
483 Shell Energy North America (US), L.P.PacifiCorp West PacifiCorp East NF 7/8 M500 BRDY
484 Shell Energy North America (US), L.P.PacifiCorp West PacifiCorp East NF 7/8 SMLK BORA
485 Shell Energy North America (US), L.P.PacifiCorp West PacifiCorp East NF 7/8 SMLK BRDY
486 Shell Energy North America (US), L.P.PacifiCorp West Sierra Pacific Power NF 7/8 SMLK M345
487 Shell Energy North America (US), L.P.Idaho Power Company PacifiCorp East NF 7/8 WALLAWALLA BORA
488 Shell Energy North America (US), L.P.Idaho Power Company PacifiCorp East NF 7/8 WALLAWALLA BRDY
489 Shell Energy North America (US), L.P.Idaho Power Company PacifiCorp East NF 7/8 WALLAWALLA JBSN
490 Shell Energy North America (US), L.P.Idaho Power Company Bonneville Power Administration NF 7/8 WALLAWALLA LAGRANDE
491 Shell Energy North America (US), L.P.Idaho Power Company Sierra Pacific Power NF 7/8 WALLAWALLA M345
492 Tenaska Power Services PacifiCorp East NorthWestern/PacifiCorp East NF 7/8 BRDY BPAT.NWMT
493 Tenaska Power Services PacifiCorp East Bonneville Power Administration NF 7/8 BRDY LAGRANDE
494 Tenaska Power Services PacifiCorp East Sierra Pacific Power NF 7/8 BRDY M345
495 Tenaska Power Services PacifiCorp East Sierra Pacific Power SFP 7/8 BRDY M345
496 Tenaska Power Services Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE BRDY
497 Tenaska Power Services Bonneville Power Administration Sierra Pacific Power NF 7/8 LAGRANDE M345
498 Tenaska Power Services Avista PacifiCorp East NF 7/8 LOLO BRDY
499 Tenaska Power Services Avista Sierra Pacific Power NF 7/8 LOLO M345
500 Tenaska Power Services Sierra Pacific Power PacifiCorp East SFP 7/8 M345 BORA
501 Tenaska Power Services Sierra Pacific Power NorthWestern/PacifiCorp East NF 7/8 M345 BPAT.NWMT
502 Tenaska Power Services Sierra Pacific Power PacifiCorp East NF 7/8 M345 BRDY
503 Tenaska Power Services Idaho Power Company PacifiCorp East NF 7/8 MDSK BRDY
504 Tenaska Power Services Idaho Power Company PacifiCorp East SFP 7/8 MDSK BRDY
505 Tenaska Power Services Idaho Power Company PacifiCorp East NF 7/8 MDSK GSHN
506 Tenaska Power Services Idaho Power Company PacifiCorp East SFP 7/8 MDSK GSHN
507 Tenaska Power Services Idaho Power Company Sierra Pacific Power NF 7/8 MDSK M345
508 Tenaska Power Services Idaho Power Company Sierra Pacific Power SFP 7/8 MDSK M345
509 Tenaska Power Services PacifiCorp West Sierra Pacific Power SFP 7/8 SMLK M345
510 The Energy Authority, Inc.PacifiCorp East NorthWestern/PacifiCorp East NF 7/8 BORA BPAT.NWMT
511 The Energy Authority, Inc.PacifiCorp East PacifiCorp East NF 7/8 BORA BRDY
512 The Energy Authority, Inc.PacifiCorp East PacifiCorp West NF 7/8 BORA H500
513 The Energy Authority, Inc.PacifiCorp East PacifiCorp West NF 7/8 BORA HURR
514 The Energy Authority, Inc.PacifiCorp East Bonneville Power Administration NF 7/8 BORA LAGRANDE
515 The Energy Authority, Inc.PacifiCorp East Bonneville Power Administration SFP 7/8 BORA LAGRANDE
516 The Energy Authority, Inc.PacifiCorp East Avista NF 7/8 BORA LOLO
517 The Energy Authority, Inc.PacifiCorp East Sierra Pacific Power NF 7/8 BORA M345
518 The Energy Authority, Inc.PacifiCorp East PacifiCorp West NF 7/8 BORA M500
519 The Energy Authority, Inc.NorthWestern/PacifiCorp East PacifiCorp East NF 7/8 BPAT.NWMT BORA
520 The Energy Authority, Inc.NorthWestern/PacifiCorp East Bonneville Power Administration NF 7/8 BPAT.NWMT LAGRANDE
521 The Energy Authority, Inc.NorthWestern/PacifiCorp East Sierra Pacific Power NF 7/8 BPAT.NWMT M345
522 The Energy Authority, Inc.PacifiCorp East NorthWestern/PacifiCorp East NF 7/8 BRDY BPAT.NWMT
523 The Energy Authority, Inc.PacifiCorp East Bonneville Power Administration NF 7/8 BRDY LAGRANDE
524 The Energy Authority, Inc.PacifiCorp East Avista NF 7/8 BRDY LOLO
525 The Energy Authority, Inc.PacifiCorp East Sierra Pacific Power NF 7/8 BRDY M345
526 The Energy Authority, Inc.PacifiCorp East Bonneville Power Administration NF 7/8 GSHN LAGRANDE
527 The Energy Authority, Inc.PacifiCorp East NorthWestern/PacifiCorp East NF 7/8 JBSN BPAT.NWMT
528 The Energy Authority, Inc.PacifiCorp East Sierra Pacific Power NF 7/8 JBSN M345
529 The Energy Authority, Inc.PacifiCorp East PacifiCorp West NF 7/8 JBSN POP
530 The Energy Authority, Inc.PacifiCorp East PacifiCorp East NF 7/8 JEFF BORA
531 The Energy Authority, Inc.PacifiCorp East PacifiCorp East NF 7/8 JEFF GSHN
532 The Energy Authority, Inc.PacifiCorp East Sierra Pacific Power NF 7/8 JEFF M345
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")
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
Classification
(d)
Ferc Rate Schedule
of Tariff Number
(e)
Point of Receipt
(Substation or
Other
Designation)
(f)
Point of
Delivery
(Substation or
Other
Designation)
(g)
FERC FORM NO. 1 (ED. 12-90)
Page 328-330
533 The Energy Authority, Inc.PacifiCorp East Sierra Pacific Power NF 7/8 KPRT M345
534 The Energy Authority, Inc.Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE BORA
535 The Energy Authority, Inc.Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE BRDY
536 The Energy Authority, Inc.Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE JBSN
537 The Energy Authority, Inc.Bonneville Power Administration Sierra Pacific Power NF 7/8 LAGRANDE M345
538 The Energy Authority, Inc.Avista PacifiCorp East NF 7/8 LOLO BORA
539 The Energy Authority, Inc.Avista Sierra Pacific Power NF 7/8 LOLO M345
540 The Energy Authority, Inc.Sierra Pacific Power PacifiCorp East NF 7/8 M345 BORA
541 The Energy Authority, Inc.Sierra Pacific Power NorthWestern/PacifiCorp East NF 7/8 M345 BPAT.NWMT
542 The Energy Authority, Inc.Sierra Pacific Power Bonneville Power Administration NF 7/8 M345 LAGRANDE
543 The Energy Authority, Inc.Sierra Pacific Power Avista NF 7/8 M345 LOLO
544 The Energy Authority, Inc.PacifiCorp West NorthWestern/PacifiCorp East NF 7/8 POP BPAT.NWMT
545 The Energy Authority, Inc.PacifiCorp West Bonneville Power Administration NF 7/8 POP LAGRANDE
546 The Energy Authority, Inc.PacifiCorp West PacifiCorp East NF 7/8 SMLK BORA
547 The Energy Authority, Inc.PacifiCorp West PacifiCorp East NF 7/8 SMLK JBSN
548 The Energy Authority, Inc.PacifiCorp West Sierra Pacific Power NF 7/8 SMLK M345
549 The Energy Authority, Inc.PacifiCorp West Sierra Pacific Power SFP 7/8 SMLK M345
550 The Energy Authority, Inc.Idaho Power Company PacifiCorp East NF 7/8 WALLAWALLA BORA
551 The Energy Authority, Inc.Idaho Power Company PacifiCorp East NF 7/8 WALLAWALLA BRDY
552 The Energy Authority, Inc.Idaho Power Company PacifiCorp East NF 7/8 WALLAWALLA JBSN
553 The Energy Authority, Inc.Idaho Power Company Sierra Pacific Power NF 7/8 WALLAWALLA M345
554 Thunderegg Solar Center, LLC NF 11
555 TransAlta Energy Marketing (US) Inc.PacifiCorp East PacifiCorp East NF 7/8 BORA BRDY
556 TransAlta Energy Marketing (US) Inc.PacifiCorp East PacifiCorp West NF 7/8 BORA H500
557 TransAlta Energy Marketing (US) Inc.PacifiCorp East PacifiCorp West NF 7/8 BORA HURR
558 TransAlta Energy Marketing (US) Inc.PacifiCorp East Bonneville Power Administration NF 7/8 BORA LAGRANDE
559 TransAlta Energy Marketing (US) Inc.NorthWestern/PacifiCorp East Sierra Pacific Power NF 7/8 BPAT.NWMT M345
560 TransAlta Energy Marketing (US) Inc.PacifiCorp East NorthWestern/PacifiCorp East NF 7/8 BRDY BPAT.NWMT
561 TransAlta Energy Marketing (US) Inc.PacifiCorp East Bonneville Power Administration NF 7/8 BRDY LAGRANDE
562 TransAlta Energy Marketing (US) Inc.PacifiCorp East Bonneville Power Administration NF 7/8 GSHN LAGRANDE
563 TransAlta Energy Marketing (US) Inc.PacifiCorp West PacifiCorp East NF 7/8 HURR BORA
564 TransAlta Energy Marketing (US) Inc.PacifiCorp West PacifiCorp East NF 7/8 HURR JBSN
565 TransAlta Energy Marketing (US) Inc.PacifiCorp West Sierra Pacific Power NF 7/8 HURR M345
566 TransAlta Energy Marketing (US) Inc.PacifiCorp East PacifiCorp West NF 7/8 JBSN H500
567 TransAlta Energy Marketing (US) Inc.PacifiCorp East Bonneville Power Administration NF 7/8 JBSN LAGRANDE
568 TransAlta Energy Marketing (US) Inc.PacifiCorp East PacifiCorp West NF 7/8 JBSN POP
569 TransAlta Energy Marketing (US) Inc.PacifiCorp East PacifiCorp East NF 7/8 JEFF BORA
570 TransAlta Energy Marketing (US) Inc.PacifiCorp East PacifiCorp East NF 7/8 JEFF BRDY
571 TransAlta Energy Marketing (US) Inc.Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE BORA
572 TransAlta Energy Marketing (US) Inc.Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE BRDY
573 TransAlta Energy Marketing (US) Inc.Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE JBSN
574 TransAlta Energy Marketing (US) Inc.Bonneville Power Administration Sierra Pacific Power NF 7/8 LAGRANDE M345
575 TransAlta Energy Marketing (US) Inc.Avista PacifiCorp East NF 7/8 LOLO BORA
576 TransAlta Energy Marketing (US) Inc.Avista PacifiCorp East NF 7/8 LOLO BRDY
577 TransAlta Energy Marketing (US) Inc.Avista Sierra Pacific Power NF 7/8 LOLO M345
578 TransAlta Energy Marketing (US) Inc.Sierra Pacific Power PacifiCorp East NF 7/8 M345 BORA
579 TransAlta Energy Marketing (US) Inc.Sierra Pacific Power NorthWestern/PacifiCorp East NF 7/8 M345 BPAT.NWMT
580 TransAlta Energy Marketing (US) Inc.Sierra Pacific Power Bonneville Power Administration NF 7/8 M345 LAGRANDE
581 TransAlta Energy Marketing (US) Inc.Sierra Pacific Power Bonneville Power Administration SFP 7/8 M345 LAGRANDE
582 TransAlta Energy Marketing (US) Inc.Sierra Pacific Power Avista NF 7/8 M345 LOLO
583 TransAlta Energy Marketing (US) Inc.PacifiCorp West PacifiCorp West NF 7/8 POP H500
584 TransAlta Energy Marketing (US) Inc.PacifiCorp West Bonneville Power Administration NF 7/8 POP LAGRANDE
585 TransAlta Energy Marketing (US) Inc.PacifiCorp West PacifiCorp East NF 7/8 SMLK BORA
586 TransAlta Energy Marketing (US) Inc.PacifiCorp West PacifiCorp East NF 7/8 SMLK BRDY
587 TransAlta Energy Marketing (US) Inc.PacifiCorp West Bonneville Power Administration NF 7/8 SMLK LAGRANDE
588 TransAlta Energy Marketing (US) Inc.PacifiCorp West Sierra Pacific Power NF 7/8 SMLK M345
589 TransAlta Energy Marketing (US) Inc.Idaho Power Company PacifiCorp East NF 7/8 WALLAWALLA BORA
590 TransAlta Energy Marketing (US) Inc.Idaho Power Company Sierra Pacific Power NF 7/8 WALLAWALLA M345
591 Uniper Global Commodities North America Bonneville Power Administration PacifiCorp East NF 7/8 LAGRANDE BORA
592 Utah Associated Municipal Power Systems PacifiCorp East Sierra Pacific Power NF 7/8 BORA M345
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")
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
Classification
(d)
Ferc Rate Schedule
of Tariff Number
(e)
Point of Receipt
(Substation or
Other
Designation)
(f)
Point of
Delivery
(Substation or
Other
Designation)
(g)
FERC FORM NO. 1 (ED. 12-90)
Page 328-330
593 Vitol Inc.NorthWestern/PacifiCorp East PacifiCorp East NF 7/8 AVAT.NWMT BRDY
594 Vitol Inc.NorthWestern/PacifiCorp East Sierra Pacific Power NF 7/8 AVAT.NWMT M345
595 Vitol Inc.NorthWestern/PacifiCorp East Sierra Pacific Power SFP 7/8 AVAT.NWMT M345
596 Vitol Inc.PacifiCorp East Sierra Pacific Power SFP 7/8 BRDY M345
597 Vitol Inc.Avista PacifiCorp East NF 7/8 LOLO BRDY
598 Vitol Inc.Avista Sierra Pacific Power NF 7/8 LOLO M345
599 Vitol Inc.Sierra Pacific Power Bonneville Power Administration NF 7/8 M345 LAGRANDE
600 Vitol Inc.Idaho Power Company PacifiCorp East SFP 7/8 MDSK BORA
601 Vitol Inc.Idaho Power Company Bonneville Power Administration NF 7/8 MDSK LAGRANDE
602 Willow Spring Windfarm, LLC NF 11
35 TOTAL
FERC FORM NO. 1 (ED. 12-90)
Page 328-330
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")
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
Classification
(d)
Ferc Rate Schedule
of Tariff Number
(e)
Point of Receipt
(Substation or
Other
Designation)
(f)
Point of
Delivery
(Substation or
Other
Designation)
(g)
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")
TRANSFER OF ENERGY TRANSFER OF ENERGY REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM
TRANSMISSION
OF ELECTRICITY
FOR OTHERS
Line
No.
Billing Demand (MW)
(h)
Megawatt Hours Received
(i)
Megawatt Hours Delivered
(j)
Demand Charges ($)
(k)
Energy Charges ($)
(l)
Other Charges ($)
(m)
Total Revenues ($)
(k+l+m)
(n)
1 382,340 382,340 1,860,031 143,802 2,003,833
2 192,487 192,487 1,621,412 125,658 1,747,070
3 1,453,949 1,453,949 6,881,710 484,644 7,366,354
4 8,735 8,735 14,151 14,151
5 233,805 233,805 90,540 90,540
6 2,178 2,178 11,776 973 12,749
7 15,777 15,777 55,022 55,022
8 2,072 2,072 1,273 1,273
9 12,275 12,275 7,542 7,542
10 0 0 4,086 4,086
11 0 0 536 536
12 0 0 2,416 2,416
13 887,038 887,038 4,530,917 4,530,917
14 664,617 664,617 3,874,715 3,874,715
15 1,401,683 1,401,683 7,530,696 7,530,696
16 9,710 9,710 3,156,018 3,156,018
17 187,387 187,387 3,124,770 3,124,770
18 598,664 598,664 3,124,770 3,124,770
19 24,217 24,217 781,193 781,193
20 315,449 315,449 6,249,540 6,249,540
21 137,825 137,825 1,664,957 1,664,957
22 4,838 4,838 109,281 109,281
23 1,904 1,904 15,710 15,710
24 0 0 5,298 5,298
25 288 288 1,977 1,977
26 528 528 3,625 3,625
27 4,474 4,474 30,719 30,719
28 444 444 3,049 3,049
29 53 53 364 364
30 3,383 3,383 23,228 23,228
31 1,433 1,433 9,839 9,839
32 2,402 2,402 16,492 16,492
33 5 5 32 32
34 388 388 2,459 2,459
35 314 314 1,990 1,990
36 200 200 1,268 1,268
37 1,242 1,242 7,873 7,873
38 555 555 3,518 3,518
39 388 388 2,459 2,459
40 38 38 241 241
41 0 0 2,763 2,763
42 171 171 1,172 1,172
43 43 43 308 308
44 82 82 588 588
45 3,768 3,768 27,016 27,016
46 2 2 14 14
47 833 833 5,973 5,973
48 1 1 7 7
49 159 159 1,140 1,140
50 239 239 1,714 1,714
51 74 74 531 531
52 20,212 20,212 144,919 144,919
53 641 641 4,596 4,596
54 5,466 5,466 39,191 39,191
55 165 165 1,183 1,183
56 200 200 1,434 1,434
57 205 205 1,470 1,470
58 10 10 72 72
59 1,600 1,600 11,472 11,472
FERC FORM NO. 1 (ED. 12-90)
Page 328-330
60 4 4 29 29
61 851 851 6,102 6,102
62 1,542 1,542 11,056 11,056
63 618 618 4,431 4,431
64 377 377 2,703 2,703
65 10 10 72 72
66 0 0 32,389 32,389
67 0 0 86 86
68 0 0 2,763 2,763
69 231 231 844 844
70 231 231 844 844
71 25 25 203 203
72 17 17 138 138
73 375 375 3,046 3,046
74 55 55 447 447
75 497 497 4,961 4,961
76 1 1 10 10
77 1 1 10 10
78 2 2 20 20
79 25 25 222 222
80 23 23 204 204
81 250 250 2,223 2,223
82 715 715 6,357 6,357
83 1,048 1,048 9,317 9,317
84 260 260 2,312 2,312
85 75 75 667 667
86 114 114 1,014 1,014
87 1 1 9 9
88 10 10 89 89
89 150 150 1,334 1,334
90 1,006 1,006 8,944 8,944
91 559 559 4,970 4,970
92 1,364 1,364 12,127 12,127
93 36 36 320 320
94 117 117 1,040 1,040
95 80 80 711 711
96 36 36 320 320
97 607 607 5,396 5,396
98 3,997 3,997 35,535 35,535
99 2,487 2,487 22,110 22,110
100 30 30 267 267
101 2,658 2,658 23,631 23,631
102 670 670 5,957 5,957
103 320 320 2,845 2,845
104 7,171 7,171 63,753 63,753
105 520 520 4,623 4,623
106 551 551 4,899 4,899
107 130 130 1,156 1,156
108 153 153 1,360 1,360
109 228 228 2,027 2,027
110 8 8 71 71
111 25 25 222 222
112 14,649 14,649 130,236 130,236
113 1,237 1,237 10,997 10,997
114 173 173 1,538 1,538
115 12 12 107 107
116 1,043 1,043 9,273 9,273
117 4,983 4,983 44,301 44,301
118 236 236 2,098 2,098
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")
TRANSFER OF ENERGY TRANSFER OF ENERGY REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM
TRANSMISSION
OF ELECTRICITY
FOR OTHERS
Line
No.
Billing Demand (MW)
(h)
Megawatt Hours Received
(i)
Megawatt Hours Delivered
(j)
Demand Charges ($)
(k)
Energy Charges ($)
(l)
Other Charges ($)
(m)
Total Revenues ($)
(k+l+m)
(n)
FERC FORM NO. 1 (ED. 12-90)
Page 328-330
119 285 285 2,534 2,534
120 7,348 7,348 65,327 65,327
121 3,167 3,167 28,156 28,156
122 12,912 12,912 114,793 114,793
123 9 9 80 80
124 132,143 132,143 1,174,805 1,174,805
125 1,228 1,228 10,917 10,917
126 600 600 2,511 2,511
127 5 5 21 21
128 133 133 945 945
129 106 106 753 753
130 684 684 4,859 4,859
131 62 62 440 440
132 4,527 4,527 32,159 32,159
133 4,746 4,746 33,714 33,714
134 90 90 639 639
135 54 54 384 384
136 395 395 2,806 2,806
137 650 650 4,617 4,617
138 1,146 1,146 8,141 8,141
139 187 187 1,328 1,328
140 1,137 1,137 8,077 8,077
141 72 72 511 511
142 817 817 5,804 5,804
143 1,083 1,083 7,693 7,693
144 4,217 4,217 29,956 29,956
145 142 142 1,009 1,009
146 376 376 2,671 2,671
147 0 0 600 600
148 14 14 114 114
149 75 75 611 611
150 21 21 171 171
151 1,331 1,331 10,835 10,835
152 376 376 3,061 3,061
153 159 159 1,294 1,294
154 1,645 1,645 13,391 13,391
155 133 133 1,083 1,083
156 296 296 2,410 2,410
157 70 70 570 570
158 75 75 611 611
159 869 869 7,074 7,074
160 723 723 5,886 5,886
161 362 362 2,947 2,947
162 143 143 1,164 1,164
163 114 114 928 928
164 120 120 977 977
165 131 131 1,066 1,066
166 294 294 2,393 2,393
167 1,431 1,431 11,649 11,649
168 35 35 285 285
169 95 95 773 773
170 1,137 1,137 9,256 9,256
171 258 258 2,100 2,100
172 365 365 2,971 2,971
173 429 429 3,492 3,492
174 762 762 6,203 6,203
175 12 12 98 98
176 356 356 2,898 2,898
177 208 208 1,693 1,693
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")
TRANSFER OF ENERGY TRANSFER OF ENERGY REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM
TRANSMISSION
OF ELECTRICITY
FOR OTHERS
Line
No.
Billing Demand (MW)
(h)
Megawatt Hours Received
(i)
Megawatt Hours Delivered
(j)
Demand Charges ($)
(k)
Energy Charges ($)
(l)
Other Charges ($)
(m)
Total Revenues ($)
(k+l+m)
(n)
FERC FORM NO. 1 (ED. 12-90)
Page 328-330
178 1,727 1,727 14,059 14,059
179 200 200 1,628 1,628
180 297 297 2,418 2,418
181 397 397 3,232 3,232
182 85 85 692 692
183 25 25 204 204
184 213 213 1,734 1,734
185 149 149 1,213 1,213
186 136 136 1,107 1,107
187 0 0 3,257 3,257
188 0 0 200 200
189 0 0 3,257 3,257
190 0 0 3,257 3,257
191 0 0 3,257 3,257
192 0 0 3,257 3,257
193 0 0 3,257 3,257
194 0 0 5,337 5,337
195 0 0 2,763 2,763
196 0 0 171 171
197 2,350 2,350 38,098 38,098
198 76 76 1,232 1,232
199 400 400 6,485 6,485
200 217 217 3,518 3,518
201 75 75 1,216 1,216
202 152 152 2,464 2,464
203 991 991 16,066 16,066
204 6,281 6,281 101,827 101,827
205 557 557 9,030 9,030
206 568 568 9,208 9,208
207 407 407 6,598 6,598
208 5 5 81 81
209 670 670 10,862 10,862
210 12,136 12,136 196,748 196,748
211 229 229 3,713 3,713
212 3 3 49 49
213 210 210 3,404 3,404
214 1,509 1,509 24,464 24,464
215 3,066 3,066 49,706 49,706
216 80 80 1,297 1,297
217 1,755 1,755 28,452 28,452
218 1,742 1,742 28,241 28,241
219 5,303 5,303 85,972 85,972
220 9,967 9,967 161,584 161,584
221 252 252 4,085 4,085
222 14,912 14,912 241,752 241,752
223 88 88 1,427 1,427
224 188 188 3,048 3,048
225 299 299 4,847 4,847
226 528 528 4,029 4,029
227 660 660 5,036 5,036
228 2 2 15 15
229 181 181 1,381 1,381
230 1,208 1,208 9,217 9,217
231 15,718 15,718 119,931 119,931
232 1,290 1,290 9,843 9,843
233 3,475 3,475 26,515 26,515
234 11,579 11,579 88,350 88,350
235 2 2 15 15
236 750 750 10,270 10,270
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")
TRANSFER OF ENERGY TRANSFER OF ENERGY REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM
TRANSMISSION
OF ELECTRICITY
FOR OTHERS
Line
No.
Billing Demand (MW)
(h)
Megawatt Hours Received
(i)
Megawatt Hours Delivered
(j)
Demand Charges ($)
(k)
Energy Charges ($)
(l)
Other Charges ($)
(m)
Total Revenues ($)
(k+l+m)
(n)
FERC FORM NO. 1 (ED. 12-90)
Page 328-330
237 10 10 137 137
238 244 244 3,341 3,341
239 75 75 1,027 1,027
240 16,592 16,592 227,210 227,210
241 272 272 3,725 3,725
242 1,613 1,613 22,088 22,088
243 332 332 4,546 4,546
244 764 764 10,462 10,462
245 3,592 3,592 49,189 49,189
246 1 1 14 14
247 5,439 5,439 33,060 33,060
248 3,896 3,896 23,681 23,681
249 1,872 1,872 11,379 11,379
250 2,382 2,382 14,479 14,479
251 1,946 1,946 11,828 11,828
252 1,818 1,818 11,050 11,050
253 2,599 2,599 15,798 15,798
254 1,149 1,149 6,984 6,984
255 1,332 1,332 8,096 8,096
256 8,752 8,752 53,198 53,198
257 5,532 5,532 33,625 33,625
258 28,083 28,083 170,699 170,699
259 13,402 13,402 81,462 81,462
260 676 676 4,109 4,109
261 1,210 1,210 7,355 7,355
262 28,301 28,301 172,024 172,024
263 76,820 76,820 466,940 466,940
264 454 454 2,760 2,760
265 265 265 1,611 1,611
266 13,763 13,763 83,656 83,656
267 124 124 754 754
268 5,748 5,748 34,938 34,938
269 444 444 2,699 2,699
270 11,642 11,642 70,764 70,764
271 86,707 86,707 527,036 527,036
272 9 9 55 55
273 19 19 115 115
274 834 834 5,069 5,069
275 5,778 5,778 35,121 35,121
276 1,781 1,781 10,826 10,826
277 889 889 5,404 5,404
278 46,651 46,651 283,562 283,562
279 54,301 54,301 330,061 330,061
280 51,520 51,520 313,157 313,157
281 3,500 3,500 21,274 21,274
282 28 28 170 170
283 66,899 66,899 406,636 406,636
284 21,667 21,667 131,700 131,700
285 236 236 1,434 1,434
286 36,714 36,714 223,161 223,161
287 32 32 195 195
288 208 208 1,264 1,264
289 440 440 2,674 2,674
290 936 936 5,689 5,689
291 276 276 1,678 1,678
292 184 184 1,118 1,118
293 789 789 4,796 4,796
294 34,578 34,578 210,178 210,178
295 3,332 3,332 20,253 20,253
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")
TRANSFER OF ENERGY TRANSFER OF ENERGY REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM
TRANSMISSION
OF ELECTRICITY
FOR OTHERS
Line
No.
Billing Demand (MW)
(h)
Megawatt Hours Received
(i)
Megawatt Hours Delivered
(j)
Demand Charges ($)
(k)
Energy Charges ($)
(l)
Other Charges ($)
(m)
Total Revenues ($)
(k+l+m)
(n)
FERC FORM NO. 1 (ED. 12-90)
Page 328-330
296 21,846 21,846 132,788 132,788
297 52,284 52,284 317,801 317,801
298 49,213 49,213 299,134 299,134
299 217 217 1,319 1,319
300 5,823 5,823 35,394 35,394
301 125 125 673 673
302 238 238 1,281 1,281
303 813 813 4,374 4,374
304 1,150 1,150 6,187 6,187
305 151 151 812 812
306 1,050 1,050 5,649 5,649
307 240 240 1,541 1,541
308 10,461 10,461 65,358 65,358
309 154,020 154,020 962,278 962,278
310 717 717 4,480 4,480
311 2,508 2,508 15,669 15,669
312 24,818 24,818 155,057 155,057
313 255 255 1,593 1,593
314 5,372 5,372 33,563 33,563
315 2,948 2,948 18,418 18,418
316 132 132 825 825
317 911 911 5,692 5,692
318 1,231 1,231 7,691 7,691
319 77,511 77,511 484,269 484,269
320 6,400 6,400 54,917 54,917
321 51 51 438 438
322 474 474 4,067 4,067
323 1,816 1,816 15,583 15,583
324 25 25 215 215
325 50 50 429 429
326 4,548 4,548 39,026 39,026
327 18,822 18,822 161,508 161,508
328 615 615 5,277 5,277
329 517 517 1,261 1,261
330 128 128 312 312
331 1,264 1,264 3,082 3,082
332 81 81 198 198
333 40 40 98 98
334 581 581 1,417 1,417
335 195 195 476 476
336 14,633 14,633 35,684 35,684
337 135 135 329 329
338 604 604 1,473 1,473
339 1,474 1,474 3,595 3,595
340 216 216 527 527
341 49 49 119 119
342 79 79 193 193
343 227 227 554 554
344 67 67 163 163
345 70 70 171 171
346 59 59 144 144
347 467 467 1,139 1,139
348 288 288 702 702
349 7,591 7,591 18,512 18,512
350 1,423 1,423 3,470 3,470
351 3,283 3,283 8,006 8,006
352 185 185 451 451
353 17 17 41 41
354 23 23 56 56
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")
TRANSFER OF ENERGY TRANSFER OF ENERGY REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM
TRANSMISSION
OF ELECTRICITY
FOR OTHERS
Line
No.
Billing Demand (MW)
(h)
Megawatt Hours Received
(i)
Megawatt Hours Delivered
(j)
Demand Charges ($)
(k)
Energy Charges ($)
(l)
Other Charges ($)
(m)
Total Revenues ($)
(k+l+m)
(n)
FERC FORM NO. 1 (ED. 12-90)
Page 328-330
355 749 749 1,827 1,827
356 873 873 2,129 2,129
357 99 99 241 241
358 30 30 73 73
359 52 52 127 127
360 2 2 5 5
361 5,421 5,421 13,220 13,220
362 23 23 56 56
363 911 911 2,222 2,222
364 23 23 56 56
365 2,008 2,008 4,897 4,897
366 424 424 1,034 1,034
367 666 666 1,624 1,624
368 5 5 12 12
369 2,529 2,529 6,167 6,167
370 117 117 285 285
371 92 92 224 224
372 910 910 2,219 2,219
373 3,406 3,406 8,306 8,306
374 9,078 9,078 22,138 22,138
375 766 766 1,868 1,868
376 2,324 2,324 5,667 5,667
377 58 58 141 141
378 11,061 11,061 26,974 26,974
379 2,091 2,091 5,099 5,099
380 1,859 1,859 4,533 4,533
381 256 256 624 624
382 3,403 3,403 8,299 8,299
383 17,233 17,233 42,025 42,025
384 777 777 1,895 1,895
385 1,634 1,634 3,985 3,985
386 461 461 1,124 1,124
387 402 402 980 980
388 7,733 7,733 18,858 18,858
389 24 24 59 59
390 31,360 31,360 76,475 76,475
391 1,418 1,418 3,458 3,458
392 340 340 829 829
393 48 48 117 117
394 82,187 82,187 200,423 200,423
395 108,085 108,085 263,578 263,578
396 2,658 2,658 6,482 6,482
397 21,950 21,950 53,528 53,528
398 11,277 11,277 27,500 27,500
399 12,699 12,699 30,968 30,968
400 10,614 10,614 25,884 25,884
401 251 251 612 612
402 1,232 1,232 3,004 3,004
403 11,957 11,957 29,159 29,159
404 39,666 39,666 96,730 96,730
405 0 0 2,763 2,763
406 200 200 1,007 1,007
407 160 160 1,510 1,510
408 368 368 3,473 3,473
409 180 180 1,699 1,699
410 300 300 2,831 2,831
411 1,428 1,428 13,475 13,475
412 289 289 2,727 2,727
413 1,047 1,047 9,880 9,880
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")
TRANSFER OF ENERGY TRANSFER OF ENERGY REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM
TRANSMISSION
OF ELECTRICITY
FOR OTHERS
Line
No.
Billing Demand (MW)
(h)
Megawatt Hours Received
(i)
Megawatt Hours Delivered
(j)
Demand Charges ($)
(k)
Energy Charges ($)
(l)
Other Charges ($)
(m)
Total Revenues ($)
(k+l+m)
(n)
FERC FORM NO. 1 (ED. 12-90)
Page 328-330
414 80 80 755 755
415 670 670 6,322 6,322
416 169 169 1,595 1,595
417 1,134 1,134 10,701 10,701
418 1,784 1,784 16,834 16,834
419 206 206 1,944 1,944
420 418 418 3,944 3,944
421 13,665 13,665 128,945 128,945
422 1,681 1,681 15,862 15,862
423 60 60 566 566
424 702 702 6,624 6,624
425 996 996 9,398 9,398
426 107 107 1,010 1,010
427 1,762 1,762 16,627 16,627
428 714 714 6,737 6,737
429 4,790 4,790 45,199 45,199
430 1,553 1,553 14,654 14,654
431 200 200 1,887 1,887
432 669 669 6,313 6,313
433 675 675 6,369 6,369
434 192 192 1,812 1,812
435 2,330 2,330 21,986 21,986
436 2,439 2,439 23,015 23,015
437 5,770 5,770 54,447 54,447
438 21,506 21,506 202,934 202,934
439 0 0 6,017 6,017
440 200 200 71 71
441 170 170 60 60
442 136 136 48 48
443 248 248 88 88
444 70 70 25 25
445 64 64 23 23
446 591 591 209 209
447 5,942 5,942 2,101 2,101
448 51 51 18 18
449 2,223 2,223 786 786
450 4,822 4,822 1,705 1,705
451 520 520 184 184
452 21,652 21,652 7,655 7,655
453 34,659 34,659 12,254 12,254
454 47 47 17 17
455 24 24 8 8
456 310 310 110 110
457 377 377 133 133
458 181 181 64 64
459 126 126 45 45
460 1,395 1,395 493 493
461 109 109 39 39
462 14 14 5 5
463 233 233 82 82
464 661 661 234 234
465 3,007 3,007 1,063 1,063
466 654 654 231 231
467 22,841 22,841 8,076 8,076
468 171 171 60 60
469 778 778 275 275
470 49 49 17 17
471 816 816 289 289
472 32,688 32,688 11,557 11,557
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")
TRANSFER OF ENERGY TRANSFER OF ENERGY REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM
TRANSMISSION
OF ELECTRICITY
FOR OTHERS
Line
No.
Billing Demand (MW)
(h)
Megawatt Hours Received
(i)
Megawatt Hours Delivered
(j)
Demand Charges ($)
(k)
Energy Charges ($)
(l)
Other Charges ($)
(m)
Total Revenues ($)
(k+l+m)
(n)
FERC FORM NO. 1 (ED. 12-90)
Page 328-330
473 57,807 57,807 20,438 20,438
474 20,519 20,519 7,255 7,255
475 109,433 109,433 38,691 38,691
476 13,814 13,814 4,884 4,884
477 9,251 9,251 3,271 3,271
478 433 433 153 153
479 12,085 12,085 4,273 4,273
480 800 800 283 283
481 459 459 162 162
482 219 219 77 77
483 10 10 4 4
484 95 95 34 34
485 3,225 3,225 1,140 1,140
486 12,961 12,961 4,582 4,582
487 285 285 101 101
488 11,081 11,081 3,918 3,918
489 245 245 87 87
490 324 324 115 115
491 48,162 48,162 17,028 17,028
492 25 25 111 111
493 560 560 2,480 2,480
494 792 792 3,508 3,508
495 86,918 86,918 384,966 384,966
496 60 60 266 266
497 50 50 221 221
498 110 110 487 487
499 141 141 624 624
500 9,348 9,348 41,403 41,403
501 90 90 399 399
502 122 122 540 540
503 28 28 124 124
504 48 48 213 213
505 240 240 1,063 1,063
506 10,003 10,003 44,304 44,304
507 34 34 151 151
508 1,200 1,200 5,315 5,315
509 1,179 1,179 5,222 5,222
510 348 348 2,130 2,130
511 100 100 612 612
512 255 255 1,561 1,561
513 825 825 5,049 5,049
514 9,030 9,030 55,262 55,262
515 2,530 2,530 15,483 15,483
516 171 171 1,046 1,046
517 459 459 2,809 2,809
518 100 100 612 612
519 100 100 612 612
520 147 147 900 900
521 1,151 1,151 7,044 7,044
522 466 466 2,852 2,852
523 2,020 2,020 12,362 12,362
524 261 261 1,597 1,597
525 225 225 1,377 1,377
526 477 477 2,919 2,919
527 483 483 2,956 2,956
528 477 477 2,919 2,919
529 240 240 1,469 1,469
530 274 274 1,677 1,677
531 16 16 98 98
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")
TRANSFER OF ENERGY TRANSFER OF ENERGY REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM
TRANSMISSION
OF ELECTRICITY
FOR OTHERS
Line
No.
Billing Demand (MW)
(h)
Megawatt Hours Received
(i)
Megawatt Hours Delivered
(j)
Demand Charges ($)
(k)
Energy Charges ($)
(l)
Other Charges ($)
(m)
Total Revenues ($)
(k+l+m)
(n)
FERC FORM NO. 1 (ED. 12-90)
Page 328-330
532 150 150 918 918
533 254 254 1,554 1,554
534 2,121 2,121 12,980 12,980
535 216 216 1,322 1,322
536 27 27 165 165
537 22,371 22,371 136,907 136,907
538 954 954 5,838 5,838
539 1,830 1,830 11,199 11,199
540 18 18 110 110
541 155 155 949 949
542 37,056 37,056 226,777 226,777
543 30 30 184 184
544 15 15 92 92
545 976 976 5,973 5,973
546 7,107 7,107 43,494 43,494
547 27 27 165 165
548 12,600 12,600 77,110 77,110
549 400 400 2,448 2,448
550 3,706 3,706 22,680 22,680
551 225 225 1,377 1,377
552 33 33 202 202
553 6,251 6,251 38,255 38,255
554 0 0 2,599 2,599
555 5 5 31 31
556 25 25 153 153
557 830 830 5,086 5,086
558 1,564 1,564 9,583 9,583
559 127 127 778 778
560 148 148 907 907
561 910 910 5,576 5,576
562 20 20 123 123
563 408 408 2,500 2,500
564 73 73 447 447
565 464 464 2,843 2,843
566 48 48 294 294
567 10 10 61 61
568 541 541 3,315 3,315
569 29 29 178 178
570 19 19 116 116
571 2,175 2,175 13,327 13,327
572 1 1 6 6
573 315 315 1,930 1,930
574 11,085 11,085 67,922 67,922
575 45 45 276 276
576 250 250 1,532 1,532
577 725 725 4,442 4,442
578 200 200 1,225 1,225
579 880 880 5,392 5,392
580 16,197 16,197 99,245 99,245
581 324 324 1,985 1,985
582 92 92 564 564
583 150 150 919 919
584 225 225 1,379 1,379
585 2,082 2,082 12,757 12,757
586 100 100 613 613
587 8 8 49 49
588 1,130 1,130 6,924 6,924
589 30,469 30,469 186,695 186,695
590 1,432 1,432 8,774 8,774
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")
TRANSFER OF ENERGY TRANSFER OF ENERGY REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM
TRANSMISSION
OF ELECTRICITY
FOR OTHERS
Line
No.
Billing Demand (MW)
(h)
Megawatt Hours Received
(i)
Megawatt Hours Delivered
(j)
Demand Charges ($)
(k)
Energy Charges ($)
(l)
Other Charges ($)
(m)
Total Revenues ($)
(k+l+m)
(n)
FERC FORM NO. 1 (ED. 12-90)
Page 328-330
591 50 50 178 178
592 5,504 5,504 32,967 32,967
593 111 111 3,319 3,319
594 1,312 1,312 39,226 39,226
595 15,057 15,057 450,172 450,172
596 9,067 9,067 271,084 271,084
597 136 136 4,066 4,066
598 662 662 19,792 19,792
599 20 20 598 598
600 1,639 1,639 49,003 49,003
601 10 10 262 262
602 0 0 2,763 2,763
35 0 9,325,825 9,325,825 10,374,929 50,422,904 0 60,797,833
FERC FORM NO. 1 (ED. 12-90)
Page 328-330
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")
TRANSFER OF ENERGY TRANSFER OF ENERGY REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM TRANSMISSION
OF ELECTRICITY FOR OTHERS
REVENUE FROM
TRANSMISSION
OF ELECTRICITY
FOR OTHERS
Line
No.
Billing Demand (MW)
(h)
Megawatt Hours Received
(i)
Megawatt Hours Delivered
(j)
Demand Charges ($)
(k)
Energy Charges ($)
(l)
Other Charges ($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
FOOTNOTE DATA
(a) Concept: PaymentByCompanyOrPublicAuthority
(b) Concept: PaymentByCompanyOrPublicAuthority
(c) Concept: PaymentByCompanyOrPublicAuthority
(d) Concept: PaymentByCompanyOrPublicAuthority
(e) Concept: PaymentByCompanyOrPublicAuthority
(f) Concept: PaymentByCompanyOrPublicAuthority
(g) Concept: PaymentByCompanyOrPublicAuthority
(h) Concept: PaymentByCompanyOrPublicAuthority
(i) Concept: RateScheduleTariffNumber
(j) Concept: RateScheduleTariffNumber
(k) Concept: RateScheduleTariffNumber
(l) Concept: RateScheduleTariffNumber
(m) Concept: RateScheduleTariffNumber
(n) Concept: RateScheduleTariffNumber
FERC FORM NO. 1 (ED. 12-90)
Page 328-330
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
TRANSFER OF ENERGY TRANSFER OF ENERGY
Line
No.
Name of Company or Public Authority (Footnote Affiliations)
(a)
Statistical Classification
(b)
MegaWatt Hours Received
(c)
MegaWatt Hours Delivered
(d)
1 (a)
Avista Corp. - WWP Div.LFP 690,805 690,805
2 Avista Corp. - WWP Div.NF 9,919 9,919
3 Avista Corp. - WWP Div.SFP 47,988 47,988
4 (b)
Avista Corp. - WWP Div.OS
5 (c)
Bonneville Power Administration LFP 152,789 152,789
6 Bonneville Power Administration SFP 28,561 28,561
7 Bonneville Power Administration NF 9,826 9,826
8 (d)
Bonneville Power Administration OS
9 (e)
Bonneville Power Administration OS
10 (f)
Bonneville Power Administration OS 95,427 95,427
11 (g)
Bonneville Power Administration OS 13,030 13,030
12 (h)
Bonneville Power Administration OS 125,950 125,950
13 (i)
Bonneville Power Administration OS
14 NorthWestern Energy NF 10,192 10,192
15 NorthWestern Energy SFP 2,035 2,035
16 (j)
NorthWestern Energy OS
17 NV Energy NF 1,920 1,920
18 NV Energy SFP 3,934 3,934
19 (k)
NV Energy OS
20 (l)
PacifiCorp Inc.LFP 10,260 10,260
21 PacifiCorp Inc.NF 331,054 331,054
22 PacifiCorp Inc.SFP 592 592
23 (m)
PacifiCorp Inc.OS
24 (n)
PacifiCorp Inc.OS
25 (o)
PacifiCorp Inc.OS
26 (p)
PacifiCorp Inc.OS
27 (q)
Puget Sound Energy SFP
28 (r)
Seattle City Light SFP
29 Sierra Pacific Power Company NF 7,190 7,190
30 Sierra Pacific Power Company SFP 30,161 30,161
31 (s)
Sierra Pacific Power Company OS
32 (t)
Snohomish County PUD SFP
TOTAL 1,571,633 1,571,633
FERC FORM NO. 1 (REV. 02-04)
Page 332
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
EXPENSES FOR TRANSMISSION OF ELECTRICITY BY
OTHERS
EXPENSES FOR TRANSMISSION OF ELECTRICITY BY
OTHERS
EXPENSES FOR TRANSMISSION OF ELECTRICITY BY
OTHERS
EXPENSES FOR TRANSMISSION OF ELECTRICITY BY
OTHERS
Line
No.
Demand Charges ($)
(e)
Energy Charges ($)
(f)
Other Charges ($)
(g)
Total Cost of Transmission ($)
(h)
1 5,496,667 5,496,667
2 85,200 85,200
3 199,180 199,180
4 (261)(261)
5 1,090,506 1,090,506
6 179,348 179,348
7 56,284 56,284
8 233,802 233,802
9 22,642 22,642
10
11
12
13 5,000 5,000
14 75,186 75,186
15 10,501 10,501
16 2,414 2,414
17 12,321 12,321
18 30,700 30,700
19 1,126 1,126
20 807,006 807,006
21 2,163,459 2,163,459
22 5,375 5,375
23 186,038 186,038
24 (524)(524)
25 (52,710)(52,710)
26 (465)(465)
27 254,601 254,601
28 29,348 29,348
29 43,571 43,571
30 157,700 157,700
31 5,407 5,407
32 223,542 223,542
0 10,920,495 402,469 11,322,964
FERC FORM NO. 1 (REV. 02-04)
Page 332
FOOTNOTE DATA
(a) Concept: NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers
There are 2 Contracts with Expiration Dates of 04/30/2026 and 04/30/2027
(b) Concept: NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers
Credit of Imbalance Penalty Charges
(c) Concept: NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers
There are 3 contracts with Expiration Dates of 12/31/2025 and 12/31/2026
(d) Concept: NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers
Ancillary services
(e) Concept: NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers
Spinning/Supplemental Reserves
(f) Concept: NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers
Capacity reassignment, BPAT is provider for Snohomish
(g) Concept: NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers
Capacity reassignment, BPAT is provider for Seattle City Light
(h) Concept: NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers
Capacity reassignment, BPAT is provider for Puget Sound Energy
(i) Concept: NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers
Processing Fee for Transmission Service
(j) Concept: NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers
Ancillary services
(k) Concept: NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers
Ancillary services
(l) Concept: NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers
Contract Expiration Date 5/31/2024
(m) Concept: NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers
Ancillary services
(n) Concept: NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers
2021 Unreserved Use Refund
(o) Concept: NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers
2021 Rate True Up - LFP_Refund Rate True-up
(p) Concept: NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers
2020 Rate True Up - LFP_Refund Rate True-up
(q) Concept: NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers
Capacity reassignment, BPAT is provider
(r) Concept: NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers
Capacity reassignment, BPAT is provider
(s) Concept: NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers
Ancillary services
(t) Concept: NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers
Capacity reassignment, BPAT is provider
FERC FORM NO. 1 (REV. 02-04)
Page 332
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Line No.Description
(a)
Amount
(b)
1 Industry Association Dues 581,366
2 Nuclear Power Research Expenses
3 Other Experimental and General Research Expenses
4 Pub and Dist Info to Stkhldrs...expn servicing outstanding Securities (a)2,068,785
5 Oth Expn greater than or equal to 5,000 show purpose, recipient, amount. Group if less than $5,000
6 DIRECTOR FEES AND EXPENSES 0
7 ANDERSON, DARREL 35,063
8 BOLANO, ODETTE 96,030
9 CARLILE, THOMAS 91,575
10 DAHL, RICHARD J 193,545
11 ELG, ANNETTE G 104,445
12 JIBSON, RONALD W 92,565
13 JOHANSEN, JUDITH A 125,694
14 JOHNSON, DENNIS L 109,395
15 KINNEEVEAUK, JEFF 86,666
16 NAVARRO, RICHARD J 113,850
17 PETERS, MARK T 96,030
18 TRAVEL AND LODGING 99,267
19 CORP MEMBERSHIPS AND SUBSCRIPTIONS 0
20 ASSOCIATED TAXPAYERS OF IDAHO 24,000
21 BANNOCK DEVELOPMENT CORP 8,000
22 BOISE VALLEY ECONOMIC PARTNERS 17,500
23 BUSINESS PLUS INC 5,000
24 CEATI INTERNATIONAL INC 79,250
25 CHAMBER OF COMMERCE 34,725
26 CHARTWELL INC 54,989
27 E SOURCE 19,232
28 ELECTRIC POWER RESEARCH 20,000
29 NATIONAL HYDROPOWER ASSOC 47,322
30 NORTH AMERICAN ENERGY STANDARD 8,000
31 OREGON STATE UNIVERSITY 15,000
32 PACIFIC NW UTILITIES 54,178
33 PORT OF MORROW 5,475
34 SOUTHERN IDAHO ECONOMIC 5,000
35 SPGLO 30,000
36 WEI MEMBERSHIP 31,006
37 MISC MEMBERSHIPS OR SUBSCRIPTIONS UNDER 5000 25,971
46 TOTAL 4,378,924
FERC FORM NO. 1 (ED. 12-94)
Page 335
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
FOOTNOTE DATA
(a) Concept: PublicationAndDistributionExpensesForSecuritiesToStockholders
Pub & Distr info to Stckholders Purpose Amount
BANK OF NEW YORK Misc Expense 7,017.20
BROADRIDGE FINANCIAL SOLUTIONS Misc Expense 112,905.13
BUSINESS WIRE INC Misc Expense 10,890.00
DEUTSCH BANK TRUST CO Broker Fees 30,000.00
D F KING & COMPANY INC Misc Expense 30,886.59
EQ SHAREOWNER SERVICES MGMT Expenses 95,445.16
Fees & Training Related to Stockholder Services Misc Expense 20,332.90
JEROME 20/20 Misc Expense 5,000.00
MARKIT NORTH AMERICA INC Misc Expense 53,460.00
MISC OTHER EXPENSE Misc Expense 2,760.18
MODERN NETWORKS IR, LLC Misc Expense 11,820.60
MOODYS Financial Software 40,952.00
NASDAQ CORP SOLUTIONS Misc Expense 33,646.12
NEW YORK STOCK EXCHANGE Misc Expense 73,148.07
Payroll Related Misc Expense 221,786.83
Q4 INC Misc Expense 27,135.42
RIVEL RESEARCH GROUP INC MGMT Expenses 16,830.00
Stock Based Compensation Misc Expense 1,237,087.12
Travel Expense - Stock Related Misc Expense 37,681.59
2,068,784.91
FERC FORM NO. 1 (ED. 12-94)
Page 335
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
Depreciation and Amortization of Electric Plant (Account 403, 404, 405)
A. Summary of Depreciation and Amortization Charges A. Summary of Depreciation and
Amortization Charges
A. Summary of Depreciation and
Amortization Charges
A. Summary of Depreciation and
Amortization Charges
A. Summary of Depreciation and
Amortization Charges
A. Summary of Depreciation
and Amortization Charges
Line
No.
Functional Classification
(a)
Depreciation Expense (Account
403)
(b)
Depreciation Expense for Asset
Retirement Costs (Account 403.1)
(c)
Amortization of Limited Term
Electric Plant (Account 404)
(d)
Amortization of Other Electric Plant
(Acc 405)
(e)
Total
(f)
1 Intangible Plant 5,251,912 5,251,912
2 Steam Production Plant 32,883,838 32,883,838
3 Nuclear Production Plant
4 Hydraulic Production Plant-Conventional 23,889,746 23,889,746
5 Hydraulic Production Plant-Pumped Storage
6 Other Production Plant 17,796,103 17,796,103
7 Transmission Plant 25,225,761 25,225,761
8 Distribution Plant 45,595,429 45,595,429
9 Regional Transmission and Market Operation
10 General Plant 17,571,193 17,571,193
11 Common Plant-Electric
12 TOTAL (a)162,962,070 5,251,912 168,213,982
FERC FORM NO. 1 (REV. 12-03)
Page 336-337
B. Basis for Amortization Charges
C. Factors Used in Estimating Depreciation Charges
Line
No.
Account No.
(a)
Depreciable Plant Base (in
Thousands)
(b)
Estimated Avg. Service Life
(c)
Net Salvage
(Percent)
(d)
Applied Depr. Rates
(Percent)
(e)
Mortality Curve Type
(f)
Average Remaining Life
(g)
12 (b)
31020 0.649 75 years, 0 months 0%4.201%R4.0 17 years, 11 months
13 31100 121.196 100 years, 0 months (9)%2.831%S0.5 17 years, 11 months
14 31210 196.643 70 years, 0 months (5)%2.507%S1 18 years, 1 month
15 31220 452.892 53 years, 0 months (8)%3.583%R1.5 17 years
16 31230 2.504 35 years, 0 months 10%1.991%R3.0 13 years, 6 months
17 31400 141.07 45 years, 0 months (7)%3.734%S0.5 16 years, 6 months
18 31500 55.116 60 years, 0 months (3)%3.58%S1.5 16 years, 10 months
19 31600 13.81 35 years, 0 months 2%5.99%S0 14 years, 7 months
20 31610 0.587 13 years, 0 months 15%9.225%L2.0 5 years, 5 months
21 31640 0.24 13 years, 0 months 15%0.376%L2.0
22 31650 1.122 13 years, 0 months 15%3.812%L2.0 11 years, 10 months
23 31660 0.045 13.746%
24 31670 0.401 21 years, 0 months 15%2.185%S1 12 years, 2 months
25 31680 3.977 20 years, 0 months 25%5.535%O1 17 years, 10 months
26 31690 0.014 35 years, 0 months 15%2.651%S1 30 years, 7 months
27 31700 28.237
28 Sub-Total 1,018.503
29 (c)
33100 251.694 110 years, 0 months 2.11%R2.5 35 years, 7 months
30 33210 19.461 120 years, 0 months 1.07%R4.0 46 years, 10 months
31 33220 281.863 120 years, 0 months 1.75%R4.0 31 years, 6 months
32 33230 5.472 1.08%Square 52 years, 6 months
33 33300 363.714 100 years, 0 months 2.84%S1.5 27 years, 7 months
34 33400 72.053 60 years, 0 months 3.34%S0 23 years, 11 months
35 33500 30.56 90 years, 0 months 2.9%R1.5 28 years, 11 months
36 33510 0.162 15 years, 0 months 5.31%Square 8 years, 11 months
37 33520 0.042 20 years, 0 months 9.05%Square 12 years, 6 months
38 33530 0.463 5 years, 0 months 5.59%Square 2 years, 6 months
39 33600 14.79 90 years, 0 months 3.52%R4.0 23 years, 1 month
40 Sub-Total 1,040.274
41 34100 154.608 60 years, 0 months 2.59%R3.0 31 years, 8 months
42 34110 0.003 35 years, 0 months 0%2.96%R3.0 30 years, 8 months
43 34200 10.438 50 years, 0 months 2.66%S2.5 27 years, 8 months
44 34300 273.426 30 years, 0 months 3.85%R2.0 22 years, 7 months
45 34400 66.599 50 years, 0 months 2.39%R1.0 26 years, 0 months
46 34410 0.079 20 years, 0 months 0%5.84%S2.5 15 years, 6 months
47 34500 93.629 40 years, 0 months 2.91%L3 26 years, 0 months
48 34600 7.018 40 years, 0 months 3.18%S0.5 22 years, 6 months
49 34610 0.013 25 years, 0 months 0%4.42%S2.5 20 years, 6 months
50 Sub-Total 605.813
51 35020 36.326 85 years, 0 months 0%1.1%R3.0 67 years, 2 months
52 35022 0.254 30 years, 0 months 0%3.33%
53 35200 100.889 70 years, 0 months (40)%1.9%R3.0 54 years, 7 months
54 35300 474.045 52 years, 0 months (15)%2.18%S0 41 years, 1 month
55 35400 232.821 85 years, 0 months (20)%1.2%R5 72 years, 2 months
56 35500 225.91 61 years, 0 months (60)%2.54%S0.5 49 years, 11 months
57 35510 4.207 20 years, 0 months 0%4.28%S3 17 years, 0 months
58 35600 267.723 75 years, 0 months (30)%1.49%R1 64 years, 4 months
59 35900 0.39 70 years, 0 months 0%0.69%R2.5 37 years, 2 months
60 Sub-Total 1,342.565
61 36022 0.874 30 years, 0 months 0%3.33%
62 36100 59.518 70 years, 0 months (50)%2.14%R2.5 56 years, 7 months
63 36200 327.837 60 years, 0 months (15)%1.9%S0 48 years, 7 months
64 36400 309.641 64 years, 0 months (50)%1.83%R0.5 53 years, 5 months
65 36410 16.723 20 years, 0 months 0%4.63%S3 17 years, 1 month
66 36500 159.601 50 years, 0 months (25)%2.23%R0.5 38 years, 6 months
67 36600 54.626 58 years, 0 months (30)%2.37%R2 40 years, 10 months
68 36700 331.603 50 years, 0 months (20)%2.27%R1.5 38 years, 11 months
69 36800 730.455 51 years, 0 months (15)%1.92%O1.0 44 years, 8 months
70 36900 69.114 55 years, 0 months (40)%1.66%R1 43 years, 1 month
71 37000 18.301 27 years, 0 months (5)%3.45%O1.0 19 years, 7 months
72 37010 95.044 20 years, 0 months 0%5.25%L3 12 years, 10 months
73 37120 4.629 23 years, 0 months (10)%4.16%R1.0 15 years, 10 months
74 37320 6.029 37 years, 0 months (35)%3.32%R1.0 22 years, 8 months
75 37400 0
76 Sub-Total 2,183.995
77 39011 33.498 75 years, 0 months (10)%2.33%S0.5 31 years, 6 months
78 39012 123.337 65 years, 0 months (10)%1.99%S0.5 43 years, 8 months
79 39110 13.302 20 years, 0 months 0%5%Square 9 years, 10 months
80 39120 26.507 5 years, 0 months 0%20%Square 2 years, 8 months
81 39121 2.633 8 years, 0 months 0%12.5%Square 4 years, 11 months
82 39210 0.766 13 years, 0 months 15%6.81%L2.5 7 years, 7 months
83 39230 4.444 16 years, 0 months 40%1.63%S2.0 10 years, 5 months
84 39240 30.795 13 years, 0 months 15%6.27%L2.5 8 years, 2 months
85 39250 1.963 13 years, 0 months 15%7.96%L2.5 8 years, 8 months
86 39260 57.868 20 years, 0 months 15%4.66%S1.0 14 years, 8 months
87 39270 10.38 20 years, 0 months 15%4.62%S1.0 11 years, 11 months
88 39290 8.654 32 years, 0 months 15%2.86%S1.5 22 years, 5 months
89 39300 4.957 25 years, 0 months 0%4%Square 18 years, 10 months
90 39400 15.057 20 years, 0 months 0%5%Square 13 years, 2 months
91 39500 14.785 20 years, 0 months 0%5%Square 11 years, 1 month
92 39600 26.399 20 years, 0 months 25%3.21%O1.0 17 years, 0 months
93 39710 4.896 15 years, 0 months 0%6.67%Square 6 years, 2 months
94 39720 23.416 15 years, 0 months 0%6.67%Square 6 years, 5 months
95 39730 27.902 15 years, 0 months 0%6.67%Square 12 years, 5 months
96 39740 20.077 15 years, 0 months 0%6.67%Square 8 years, 11 months
97 39750 5.184 20 years, 0 months 0%5%Square
98 39800 10.777 15 years, 0 months 0%6.67%Square 7 years, 11 months
99 Sub-Total 467.597
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
FOOTNOTE DATA
(a) Concept: DepreciationExpenseExcludingAmortizationOfAcquisitionAdjustments
Account 404 - Basis used to compute charges:
Balance to be Balance to be Remaining
Amortized 2022 Amortized months of
1/1/2022 Amortization 12/31/2022 Amort 12/31/22
(1) Shoshone Bannock Agreement 12,000 12,000 0
(2) Mid Snake Relicensing 6,645,609 518,112 6,127,497 -
(3) Swan Falls Relicensing 3,924,764 189,908 3,734,856 236
(4) Software 18,784,301 3,865,213 26,481,925 -
(5) Shoshone Bannock ROW 1,732,703 287,899 1,444,804 60
(6) FERC Compliance Costs 8,958,816 264,008 21,940,621 -
(7) Radio Frequency - Spectrum 3,335,143 120,255 3,214,888 321
Total 43,393,336 5,257,395 62,944,591
(1) Shoshone-Bannock Tribe License & Use Agreement, fully amortized at December 31, 2022.
(2) Middle Snake Relicensing Costs (Amoritzed over a 30 year license period; licenses expire July 31, 2034 and February 28, 2035).
(3) Swan Falls Relicensing Costs (Amortized over a 30 year license period, license expires August 31, 2042).
(4) Computer Software packages (Amortized over a 60 - 120 month period, as applicable).
(5) Shoshone-Bannock Right of Way (Termination date December 31, 2027).
(6) FERC License Compliance Costs (amortized over the term of the applicable FERC Licenses)
(7) Radio Frequency Spectrum (Amorized using a 3.38% annual rate, effective January 2022)
(b) Concept: AccountNumberFactorsUsedInEstimatingDepreciationCharges
Line: 12 to 26 Column: c, d, f, g
Steam Production plant depreciation and amortization is maintained by plant location. Plant accounts 31020 through 31650 and 31670 through 31690 are presented with information from Jim Bridger's most recent depreciation study. Plant account 31660 is
associated with Valmy facility only. Plant assets at our Valmy location are no longer subject to depreciation studies, as Valmy plant is addressed through IPUC Order No. 33771 for the decommissioning of the plant location. There is no data for estimated service
life, net salvage percentage, mortality curve, or average remaining life for Valmy plant.
Line: 12 to 26 Column: e
An average plant balance was used in computing these rates by plant account.
(c) Concept: AccountNumberFactorsUsedInEstimatingDepreciationCharges
Line: 31 to 113 Column: c, d, e, f, g
Hydro Production Plant and Other Production Plant depreciation and amortization of certain electric plant is maintained by plant location. Effective January 1, 2022 by order IPC-E-21-18 the forecast life span method of analysis uses a combined interim and
terminal retirement rate to develop hydro and other production plant rates. Hydro and other production net salvage rates are specific to individual locations. Rates, service lives, and remaining lives presented are on a composite basis. Effective April 1, 1993 all
depreciable plant is being depreciated using the straight line method.
FERC FORM NO. 1 (REV. 12-03)
Page 336-337
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
REGULATORY COMMISSION EXPENSES
EXPENSES INCURRED
DURING YEAR
EXPENSES
INCURRED
DURING
YEAR
CURRENTLY CHARGED TO
CURRENTLY
CHARGED
TO
Line
No.
Description (Furnish name of regulatory commission or
body the docket or case number and a description of the
case)
(a)
Assessed by Regulatory
Commission
(b)
Expenses of Utility
(c)
Total Expenses for Current Year
(d)
Deferred in Account 182.3 at
Beginning of Year
(e)
Department
(f)
Account No.
(g)
1 Federal Energy Regulatory Commission:
2 Statutory fees assessed by FERC 4,754,608 4,754,608 Electric 928
3 General regulatory matters 109,055 109,055 Electric 928
4 Oregon Hydro Fees 271,717 271,717 Electric 928
5 Regulatory Commission Expenses - Idaho:
6 General regulatory matters 7,212 Electric 928
7 Regulatory Commission Expenses - Oregon:
8 Statutory fees assessed by Commission 41,909 Electric 928
9 General regulatory matters 1,345,352 1,345,352 Electric 928
46 TOTAL 5,026,325 1,454,407 6,480,732 49,121
FERC FORM NO. 1 (ED. 12-96)
Page 350-351
REGULATORY COMMISSION EXPENSES
EXPENSES INCURRED DURING YEAR EXPENSES INCURRED DURING YEAR AMORTIZED DURING YEAR AMORTIZED DURING YEAR AMORTIZED DURING YEAR
CURRENTLY CHARGED TO
Line
No.
Amount
(h)
Deferred to Account 182.3
(i)
Contra Account
(j)
Amount
(k)
Deferred in Account 182.3 End of Year
(l)
1
2 4,754,608
3 109,055
4 271,717
5
6 50,023 928203, 419000 36,197 21,038
7
8 82,291 928303, 419000 28,878 95,322
9 1,345,352
46 6,480,732 132,314 65,075 116,360
FERC FORM NO. 1 (ED. 12-96)
Page 350-351
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES
Line
No.
Classification
(a)
Description
(b)
Costs Incurred Internally Current Year
(c)
Costs Incurred Externally Current Year
(d)
1 Idaho Power did not incur any research and development expenditures in
2022.
FERC FORM NO. 1 (ED. 12-87)
Page 352-353
RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES
AMOUNTS CHARGED IN CURRENT YEAR AMOUNTS CHARGED IN CURRENT YEAR
Line No.Amounts Charged In Current Year: Account
(e)
Amounts Charged In Current Year: Amount
(f)
Unamortized Accumulation
(g)
1 0
FERC FORM NO. 1 (ED. 12-87)
Page 352-353
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
DISTRIBUTION OF SALARIES AND WAGES
Line
No.
Classification
(a)
Direct Payroll Distribution
(b)
Allocation of Payroll Charged for Clearing
Accounts
(c)
Total
(d)
1 Electric
2 Operation
3 Production 28,313,566
4 Transmission 8,659,848
5 Regional Market
6 Distribution 23,660,873
7 Customer Accounts 12,433,914
8 Customer Service and Informational 6,497,208
9 Sales
10 Administrative and General 149,151,243
11 TOTAL Operation (Enter Total of lines 3 thru 10)228,716,652
12 Maintenance
13 Production 6,232,049
14 Transmission 5,263,109
15 Regional Market
16 Distribution 10,381,157
17 Administrative and General 1,172,114
18 TOTAL Maintenance (Total of lines 13 thru 17)23,048,429
19 Total Operation and Maintenance
20 Production (Enter Total of lines 3 and 13)34,545,615
21 Transmission (Enter Total of lines 4 and 14)13,922,957
22 Regional Market (Enter Total of Lines 5 and 15)
23 Distribution (Enter Total of lines 6 and 16)34,042,030
24 Customer Accounts (Transcribe from line 7)12,433,914
25 Customer Service and Informational (Transcribe from line 8)6,497,208
26 Sales (Transcribe from line 9)
27 Administrative and General (Enter Total of lines 10 and 17)150,323,357
28 TOTAL Oper. and Maint. (Total of lines 20 thru 27)251,765,081 251,765,081
29 Gas
30 Operation
31 Production - Manufactured Gas
32 Production-Nat. Gas (Including Expl. And Dev.)
33 Other Gas Supply
34 Storage, LNG Terminaling and Processing
35 Transmission
36 Distribution
37 Customer Accounts
38 Customer Service and Informational
39 Sales
40 Administrative and General
41 TOTAL Operation (Enter Total of lines 31 thru 40)
42 Maintenance
43 Production - Manufactured Gas
44 Production-Natural Gas (Including Exploration and Development)
45 Other Gas Supply
46 Storage, LNG Terminaling and Processing
47 Transmission
48 Distribution
49 Administrative and General
50 TOTAL Maint. (Enter Total of lines 43 thru 49)
51 Total Operation and Maintenance
52 Production-Manufactured Gas (Enter Total of lines 31 and 43)
53 Production-Natural Gas (Including Expl. and Dev.) (Total lines 32,
54 Other Gas Supply (Enter Total of lines 33 and 45)
55 Storage, LNG Terminaling and Processing (Total of lines 31 thru
56 Transmission (Lines 35 and 47)
57 Distribution (Lines 36 and 48)
58 Customer Accounts (Line 37)
59 Customer Service and Informational (Line 38)
FERC FORM NO. 1 (ED. 12-88)
Page 354-355
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 0
65 TOTAL All Utility Dept. (Total of lines 28, 62, and 64)251,765,081 0 251,765,081
66 Utility Plant
67 Construction (By Utility Departments)
68 Electric Plant
69 Gas Plant
70 Other (provide details in footnote):
71 TOTAL Construction (Total of lines 68 thru 70)
72 Plant Removal (By Utility Departments)
73 Electric Plant
74 Gas Plant
75 Other (provide details in footnote):
76 TOTAL Plant Removal (Total of lines 73 thru 75)
77 Other Accounts (Specify, provide details in footnote):
78 Construction Work in Progress 96,219,573 96,219,573
79 Other Clearing Accounts 5,363,436 5,363,436
80 Store Expense 7,252,921 7,252,921
81 Other Accounts 4,422,803 4,422,803
82 Other Work in Progress (11,118,608)(11,118,608)
83 Preliminary Survey and Invest 14,798 14,798
84 Indirect Loading (a)57,393,518 57,393,518
85
86
87
88
89
90
91
92
93
94
95 TOTAL Other Accounts 102,154,923 57,393,518 159,548,441
96 TOTAL SALARIES AND WAGES 353,920,004 57,393,518 411,313,522
FERC FORM NO. 1 (ED. 12-88)
Page 354-355
DISTRIBUTION OF SALARIES AND WAGES
Line
No.
Classification
(a)
Direct Payroll Distribution
(b)
Allocation of Payroll Charged for Clearing
Accounts
(c)
Total
(d)
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
FOOTNOTE DATA
(a) Concept: SalariesAndWagesOtherAccounts
Amount reported is total amount of indirect loading. The loading is allocated to departments based on labor charges.
FERC FORM NO. 1 (ED. 12-88)
Page 354-355
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
PURCHASES AND SALES OF ANCILLARY SERVICES
Amount Purchased for the Year Amount Purchased for the Year Amount Purchased for the Year
Usage - Related Billing Determinant Usage - Related Billing Determinant Usage - Related Billing Determinant
Line
No.
Type of Ancillary Service
(a)
Number of Units
(b)
Unit of Measure
(c)
Dollar
(d)
1 Scheduling, System Control and Dispatch 300,605
2 Reactive Supply and Voltage 128,182
3 Regulation and Frequency Response
4 Energy Imbalance
5 Operating Reserve - Spinning 13,695
6 Operating Reserve - Supplement 8,947
7 Other
8 Total (Lines 1 thru 7)0 451,429
FERC FORM NO. 1 (New 2-04)
Page 398
PURCHASES AND SALES OF ANCILLARY SERVICES
Amount Sold for the Year Amount Sold for the Year Amount Sold for the Year
Usage - Related Billing Determinant Usage - Related Billing Determinant Usage - Related Billing Determinant
Line No.Number of Units
(e)
Unit of Measure
(f)
Dollars
(g)
1
2
3 3,483,028 KW 341,163
4
5 4,352,502 KW 426,328
6 4,352,502 KW 426,328
7
8 12,188,032 1,193,819
FERC FORM NO. 1 (New 2-04)
Page 398
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
MONTHLY TRANSMISSION SYSTEM PEAK LOAD
Line
No.
Month
(a)
Monthly Peak MW - Total
(b)
Day of Monthly Peak
(c)
Hour of Monthly Peak
(d)
Firm Network Service for Self
(e)
Firm Network Service for
Others
(f)
Long-Term
Firm Point-
to-point
Reservations
(g)
Other
Long-
Term
Firm
Service
(h)
Short-Term
Firm Point-
to-point
Reservation
(i)
Other
Service
(j)
NAME OF SYSTEM: IDAHO POWER COMPANY
- SYSTEM LOAD
1 January 3,781 28 8 2,121 273 1,131 0 256 0
2 February 3,829 25 8 2,225 278 1,131 0 195 0
3 March 3,599 10 8 2,131 261 1,131 0 76 0
4 Total for Quarter 1 6,477 812 3,393 0 527 0
5 April 3,369 28 11 1,334 235 1,202 0 598 0
6 May 4,007 26 19 2,015 325 1,202 0 465 0
7 June 5,006 27 21 3,184 388 1,202 0 232 0
8 Total for Quarter 2 6,533 948 3,606 0 1,295 0
9 July 5,081 15 18 3,145 384 1,202 0 350 0
10 August 4,730 19 18 2,774 354 1,202 0 400 0
11 September 4,536 2 18 2,598 355 1,202 0 381 0
12 Total for Quarter 3 8,517 1,093 3,606 0 1,131 0
13 October 3,364 5 18 1,680 226 1,202 0 256 0
14 November 3,695 22 9 1,931 246 1,202 0 316 0
15 December 4,032 19 10 1,976 268 1,202 0 586 0
16 Total for Quarter 4 5,587 740 3,606 0 1,158 0
17 Total 27,114 3,593 14,211 0 4,111 0
FERC FORM NO. 1 (NEW. 07-04)
Page 400
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
2023-04-13
Year/Period of Report
End of: 2022/ Q4
ELECTRIC ENERGY ACCOUNT
Line
No.
Item
(a)
MegaWatt Hours
(b)
Line
No.
Item
(a)
MegaWatt Hours
(b)
1 SOURCES OF ENERGY 21 DISPOSITION OF ENERGY
2 Generation (Excluding Station Use):22 Sales to Ultimate Consumers (Including Interdepartmental Sales)15,822,455
3 Steam 3,656,890 23 Requirements Sales for Resale (See instruction 4, page 311.)
4 Nuclear 24 Non-Requirements Sales for Resale (See instruction 4, page 311.)1,318,132
5 Hydro-Conventional 5,346,563 25 Energy Furnished Without Charge
6 Hydro-Pumped Storage 26 Energy Used by the Company (Electric Dept Only, Excluding Station Use)
7 Other 2,321,790 27 Total Energy Losses 1,238,736
8 Less Energy for Pumping 27.1 Total Energy Stored
9 Net Generation (Enter Total of lines 3 through 8)11,325,243 28 TOTAL (Enter Total of Lines 22 Through 27.1) MUST EQUAL LINE 20
UNDER SOURCES 18,379,323
10 Purchases (other than for Energy Storage)7,150,708
10.1 Purchases for Energy Storage 0
11 Power Exchanges:
12 Received 53,368
13 Delivered 151,411
14 Net Exchanges (Line 12 minus line 13)(98,043)
15 Transmission For Other (Wheeling)
16 Received 9,325,825
17 Delivered 9,324,410
18 Net Transmission for Other (Line 16 minus line 17)(a)1,415
19 Transmission By Others Losses
20 TOTAL (Enter Total of Lines 9, 10, 10.1, 14, 18 and 19)18,379,323
FERC FORM NO. 1 (ED. 12-90)
Page 401a
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
2023-04-13
Year/Period of Report
End of: 2022/ Q4
FOOTNOTE DATA
(a) Concept: NetTransmissionEnergyForOthersElectricPowerWheeling
Page 329 Column I differs from page 401 by 1,415 MWH, reported for Wheeling variation and BPA Energy imbalance schedules on page 401. The numbers that are shown on pages 328-330 are for account 456 wheeling only, the numbers on page 401 have to be
adjusted for account 447 transmission.
FERC FORM NO. 1 (ED. 12-90)
Page 401a
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
MONTHLY PEAKS AND OUTPUT
Line
No.
Month
(a)
Total Monthly Energy
(b)
Monthly Non-Requirement Sales for
Resale & Associated Losses
(c)
Monthly Peak - Megawatts
(d)
Monthly Peak - Day of Month
(e)
Monthly Peak - Hour
(f)
NAME OF SYSTEM: IDAHO POWER COMPANY - SYSTEM
LOAD
29 January 1,668,942 208,763 2,420 28 9
30 February 1,373,787 114,551 2,508 25 9
31 March 1,247,245 76,209 2,206 10 8
32 April 1,239,152 75,492 2,113 29 9
33 May 1,406,052 113,149 2,480 26 19
34 June 1,598,726 100,367 3,496 28 19
35 July 1,994,407 1,543 3,568 14 20
36 August 1,862,627 750 3,490 1 17
37 September 1,607,305 215,387 3,253 7 17
38 October 1,253,599 94,934 1,939 5 18
39 November 1,455,298 140,927 2,332 21 9
40 December 1,672,183 176,060 2,604 22 9
41 Total 18,379,323 1,318,132
FERC FORM NO. 1 (ED. 12-90)
Page 401b
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
Steam Electric Generating Plant Statistics
1. Report data for plant in Service only.
2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants.
3. Indicate by a footnote any plant leased or operated as a joint facility.
4. If net peak demand for 60 minutes is not available, give data which is available, specifying period.
5. If any employees attend more than one plant, report on line 11 the approximate average number of employees assignable to each plant.
6. If gas is used and purchased on a therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct.
7. Quantities of fuel burned (Line 38) and average cost per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20.
8. If more than one fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
9. Items under Cost of Plant are based on USofA accounts. Production expenses do not include Purchased Power, System Control and Load Dispatching, and Other Expenses Classified as Other Power Supply Expenses.
10. For IC and GT plants, report Operating Expenses, Account Nos. 547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants designed for peak load service.
Designate automatically operated plants.
11. For a plant equipped with combinations of fossil fuel steam, nuclear steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined cycle operation with a conventional
steam unit, include the gas-turbine with the steam plant.
12. If a nuclear power generating plant, briefly explain by footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units used for the various components of fuel cost; and (c)
any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the report period and other physical and operating characteristics of plant.
Line
No.
Item
(a)
Plant Name:
Bennett Mountain
Plant Name:
Boardman
Plant Name:
Danskin
Plant Name:
Jim Bridger
Plant Name:
Langley Gulch
Plant
Name:
Valmy
1 Kind of Plant (Internal Comb, Gas Turb, Nuclear)Gas Turbine STEAM Gas Turbine STEAM Gas Turbine STEAM
2 Type of Constr (Conventional, Outdoor, Boiler, etc)Conventional Conventional Conventional SEMI-OUTDOOR BOILER Conventional Outdoor
3 Year Originally Constructed 2005 (a)
1980 2001 (b)
1974 2012 (c)
1981
4 Year Last Unit was Installed 2005 1980 2008 1979 2012 1985
5 Total Installed Cap (Max Gen Name Plate Ratings-MW)172.8 (d)270.9 (e)775.29 318.45 (f)144.9
6 Net Peak Demand on Plant - MW (60 minutes)202 280 715 338 135
7 Plant Hours Connected to Load 1,903 3,383 8,753 5,837 3,714
8 Net Continuous Plant Capability (Megawatts)202 291 342
9 When Not Limited by Condenser Water (g)(h)(i)
10 When Limited by Condenser Water
11 Average Number of Employees 4 6 23
12 Net Generation, Exclusive of Plant Use - kWh 235,758,000 537,902,000 3,286,515,000 1,548,091,000 370,375,000
13 Cost of Plant: Land and Land Rights 106,610 402,745 509,671 2,287,261 1,106,140
14 Structures and Improvements 1,886,143 6,425,092 73,542,588 146,284,312 47,653,459
15 Equipment Costs 80,435,028 105,230,333 662,498,099 264,573,210 205,923,477
16 Asset Retirement Costs 3,767,793 24,720,682 (251,874)
17 Total cost (total 13 thru 20)82,321,171 3,874,403 112,058,170 761,271,040 413,144,783 254,431,202
18 Cost per KW of Installed Capacity (line 17/5) Including 476.3957 413.6514 981.9178 1,297.3615 1,755.9089
19 Production Expenses: Oper, Supv, & Engr 3,188 (130,832)5,635 231,676 618,282 531,405
20 Fuel 21,221,475 37,108,053 88,075,751 66,318,350 17,476,166
21 Coolants and Water (Nuclear Plants Only)
22 Steam Expenses 2,000 6,046,168 3,250,319
23 Steam From Other Sources
24 Steam Transferred (Cr)
25 Electric Expenses 333,363 970,850 3,598,276 1,128,466
26 Misc Steam (or Nuclear) Power Expenses 84,751 166,378 7,284,754 (311,363)1,301,526
27 Rents 229,461
28 Allowances
29 Maintenance Supervision and Engineering (251,338)12,403
30 Maintenance of Structures 28,793 54,489 75,748 2,540,010
31 Maintenance of Boiler (or reactor) Plant 850,175 4,229 6,756,285 29,103 2,017,796
32 Maintenance of Electric Plant 1,770,289 273,703 2,177,957 4,685,695 128,562
33 Maintenance of Misc Steam (or Nuclear) Plant 9,322,817 269,294
34 Total Production Expenses 24,292,034 (380,170)38,583,337 120,137,272 75,014,091 28,643,544
35 Expenses per Net kWh 0.103 0.0717 0.0366 0.0485 0.0773
35 Plant Name Bennett Mountain Boardman Boardman Danskin Jim Bridger Jim
Bridger
Langley
Gulch Valmy Valmy
36 Fuel Kind Gas Coal Oil Gas Coal Oil Gas Coal Oil
37 Fuel Unit MCF Tons Barrels MCF Tons Barrels MCF Tons Barrels
38 Quantity (Units) of Fuel Burned 2,650,671 0 0 5,770,618 1,885,281 5,918 10,361,586 195,768 4,904
39 Avg Heat Cont - Fuel Burned (btu/indicate if
nuclear)1,027 0 0 1,027 9,357 140,000 1,027 10,803 138,778
40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 8.006 0 0 6.431 45.482 4.241 6.4 46.832 0
41 Average Cost of Fuel per Unit Burned 8.006 0 0 6.431 46.337 91.517 6.4 84.082 199.677
42 Average Cost of Fuel Burned per Million BTU 11.98 0 0 9.66 2.461 15.563 9.71 3.892 34.259
43 Average Cost of Fuel Burned per kWh Net Gen 0.09 0 0 0.069 0.0268 0 0.043 0.0472 0
44 Average BTU per kWh Net Generation 11,547 0 0 11,018 10,809 0 6,874 11,497 0
FERC FORM NO. 1 (REV. 12-03)
Page 402-403
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
FOOTNOTE DATA
(a) Concept: YearPlantOriginallyConstructed
This footnote applies to lines 3 and 4. The Boardman plant consists of one unit constructed jointly by Portland General Electric Company, Idaho Power Company, and Pacific Northwest Generating Company, with Idaho Power owning 10%. The unit was placed
incommercial operation August 3, 1980 and ceased operations in October 2020.
(b) Concept: YearPlantOriginallyConstructed
This footnote applies to lines 3 and 4. The Jim Bridger Power Plant consists of four equal units constructed jointly by Idaho Power Company and Pacific Power and Light Company, with Idaho Power owning 1/3 and PacifiCorp owning 2/3. Unit #1 was placed
incommercial operation November 30, 1974, Unit #2 December 1, 1975, Unit #3 September 1, 1976, and Unit #4 November 29, 1979.
(c) Concept: YearPlantOriginallyConstructed
This footnote applies to lines 3 and 4. The Valmy plant consists of two units constructed jointly by Sierra Pacific Power Company and Idaho Power Company, with Sierra owning 1/2 and Idaho Power owning 1/2. Unit #1 was placed in commercial operation
December 11, 1981, and Unit #2 May 21, 1985. Idaho Power ended its participation in Unit #1 in December 2019.
(d) Concept: InstalledCapacityOfPlant
This footnote applies to line 5 and line 12 through 43. Information reflects Idaho Power Company's share as explained in the note for line 3 page 402 under Boardman.
(e) Concept: InstalledCapacityOfPlant
This footnote applies to line 5 and line 12 through 43. Information reflects Idaho Power Company's share as explained in the note for line 3 page 402 under Jim Bridger.
(f) Concept: InstalledCapacityOfPlant
This footnote applies to line 5 and line 12 through 43. Information reflects Idaho Power Company's share as explained in the note for line 3 page 402 under Valmy.
(g) Concept: NetContinuousPlantCapabilityNotLimitedByCondenserWater
This footnote applies to line 9, 10, and 11. Portland General Electric Company, as operator of the plant, will report this information.
(h) Concept: NetContinuousPlantCapabilityNotLimitedByCondenserWater
This footnote applies to line 9, 10, and 11. PacifiCorp, as operator of the plant, will report this information.
(i) Concept: NetContinuousPlantCapabilityNotLimitedByCondenserWater
This footnote applies to line 9, 10, and 11. Sierra Pacific Power, as operator of the plant, will report this information.
FERC FORM NO. 1 (REV. 12-03)
Page 402-403
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
Hydroelectric Generating Plant Statistics
1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings).
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in a footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available specifying period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each plant.
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.
Line
No.
Item
(a)
FERC
Licensed
Project No.
2736
Plant
Name:
American
Falls
FERC
Licensed
Project No.
1975
Plant
Name:
Bliss
FERC
Licensed
Project No.
1971
Plant Name:
Brownlee
FERC
Licensed
Project No.
2055
Plant
Name:
C J Strike
FERC
Licensed
Project
No.
2848
Plant
Name:
Cascade
FERC
Licensed
Project
No.
1971
Plant
Name:
Common
Facilities
FERC
Licensed
Project No.
1971
Plant Name:
Hells Canyon
FERC
Licensed
Project No.
2061
Plant
Name:
Lower
Salmon
FERC
Licensed
Project No.
2726
Plant
Name:
Malad
FERC
Licensed
Project No.
2899
Plant Name:
Milner
FERC
Licensed
Project No.
1971
Plant
Name:
Oxbow
FERC
Licensed
Project No.
2778
Plant Name:
Shoshone
Falls
FERC
Licensed
Project No.
503
Plant Name:
Swan Falls
FERC
Licensed
Project No.
18
Plant Name:
Twin Falls
FERC
Licensed
Project No.
2777
Plant
Name:
Upper
Salmon
1
Kind of Plant
(Run-of-River
or Storage)
Run-of-
River
Run-of-
River Storage Run-of-
River
Run-of-
River Storage Run-of-
River
Run-of-
River Run-of-River Storage Run-of-River Run-of-River Run-of-River Run-of-
River
2
Plant
Construction
type
(Conventional
or Outdoor)
Outdoor Outdoor Outdoor Outdoor Outdoor Outdoor Outdoor Outdoor Conventional Outdoor Conventional Conventional Conventional Outdoor
3
Year
Originally
Constructed
1978 1949 1958 1952 1983 1967 1949 1948 1992 1961 1907 1910 1935 1937
4 Year Last Unit
was Installed 1978 1950 1980 1952 1984 1967 1949 1948 1992 1961 1921 1994 1935 1947
5
Total installed
cap (Gen
name plate
Rating in
MW)
92.34 75.04 675 82.8 12.42 391.5 60 21.77 59.45 190 14.73 27.17 52.9 34.5
6
Net Peak
Demand on
Plant-
Megawatts
(60 minutes)
77 51 593 85 13 301 39 23 45 211 15 18 40 34
7
Plant Hours
Connect to
Load
4,608 8,760 8,565 8,757 8,718 8,754 8,760 8,541 1,389 8,758 8,201 8,759 6,027 8,746
8
Net Plant
Capability (in
megawatts)
9
(a) Under
Most
Favorable
Oper
Conditions
105 77 670 92 13 446 69 23 56 224 15 30 50 36
10
(b) Under the
Most Adverse
Oper
Conditions
1 220 84 1 137 60 21 1 202 11 14 50 32
11
Average
Number of
Employees
4 3 7 4 2 5 4 1 2 6 2 4 3 4
12
Net
Generation,
Exclusive of
Plant Use -
kWh
208,717,000 279,523,000 1,578,937,000 343,210,000 33,565,000 1,445,737,000 183,396,000 151,767,000 13,222,000 705,619,000 41,143,000 106,707,000 22,385,000 164,491,000
13 Cost of Plant
14 Land and
Land Rights 875,319 768,993 18,474,575 5,741,857 82,142 114,368 2,222,392 424,428 205,376 139,357 1,212,841 313,328 309,958 255,499 207,636
15
Structures
and
Improvements
12,811,615 1,945,961 42,280,889 10,139,543 7,333,768 69,427,868 6,676,033 3,607,092 15,874,282 10,687,132 19,272,706 7,093,484 28,159,720 12,004,023 3,802,371
16
Reservoirs,
Dams, and
Waterways
5,174,417 11,951,013 71,509,414 12,319,151 3,145,630 13,556,785 56,099,889 8,107,840 7,407,204 17,779,586 33,066,736 14,824,990 15,850,156 9,024,651 17,701,092
17 Equipment
Costs 33,294,649 20,500,123 138,934,014 15,074,075 13,501,398 3,710,265 38,980,842 40,440,135 18,417,818 29,852,886 22,311,465 18,388,506 32,755,121 25,100,700 9,401,951
18
Roads,
Railroads,
and Bridges
839,276 486,477 1,543,782 1,602,868 122,668 142,581 1,357,863 88,693 1,507,442 501,877 2,548,567 468,609 835,946 1,917,603 29,359
19
Asset
Retirement
Costs
20
Total cost
(total 13 thru
20)
52,995,276 35,652,567 272,742,674 44,877,494 24,185,606 86,951,867 105,337,019 52,668,188 43,412,122 58,960,838 78,412,315 41,088,917 77,910,901 48,302,476 31,142,409
21
Cost per KW
of Installed
Capacity (line
20 / 5)
573.9146 475.1142 404.0632 541.9987 1,947.3113 269.0601 877.8031 1,994.126 991.7719 412.6964 2,789.4716 2,867.5341 913.0903 902.6785
22 Production
Expenses
23
Operation
Supervision
and
Engineering
301,997 188,063 859,479 844,683 202,858 418,306 346,304 63,473 173,468 802,810 121,828 416,793 606,656 304,242
24 Water for
Power 409,077 266,809 925,329 914,913 253,952 535,754 418,121 118,801 234,464 836,058 165,025 513,700 478,083 411,883
25 Hydraulic
Expenses 290,125 205,600 625,982 888,563 171,915 13,566,943 362,684 310,025 64,811 153,995 566,288 115,403 371,432 310,234 324,230
26 Electric
Expenses 127,275 63,808 387,753 74,808 114,265 212,959 177,867 23,653 58,443 213,464 60,616 183,329 54,117 169,103
27
Misc
Hydraulic
Power
Generation
Expenses
336,857 197,731 777,651 554,289 238,894 541,744 245,409 68,130 219,492 813,924 128,255 354,840 263,425 265,924
28 Rents 18,876 11,645 42,666 42,217 11,718 24,721 19,293 3,767 10,819 38,578 7,615 23,704 22,060 19,006
29
Maintenance
Supervision
and
Engineering
5,628 7,068 19,783 8,277 3,923 21,705 5,797 3,016 3,693 7,491 4,127 7,575 3,249 5,569
30 Maintenance
of Structures 63,407 48,811 180,467 98,981 24,171 45,744 66,318 21,996 38,060 50,655 73,318 103,460 31,324 53,648
31
Maintenance
of Reservoirs,
Dams, and
Waterways
13,097 16,486 47,266 56,400 8,687 176,241 17,452 10,313 9,991 17,889 10,914 25,996 15,947 18,223
32
Maintenance
of Electric
Plant
150,020 196,133 426,075 227,066 67,110 300,859 188,775 75,586 101,552 120,142 125,506 226,053 101,062 198,000
33
Maintenance
of Misc
Hydraulic
Plant
174,381 242,047 687,974 207,138 166,088 192,207 949,324 140,375 106,904 113,432 319,420 84,208 184,031 83,074 126,842
34
Total
Production
Expenses
(total 23 thru
33)
1,890,740 1,444,201 4,980,425 3,917,335 1,263,581 13,759,150 3,590,041 1,935,736 560,450 1,117,409 3,786,719 896,815 2,410,913 1,969,231 1,896,670
35 Expenses per
net kWh 0.0091 0.0052 0.0032 0.0114 0.0376 0.0025 0.0106 0.0037 0.0845 0.0054 0.0218 0.0226 0.088 0.0115
FERC FORM NO. 1 (REV. 12-03)
Page 406-407
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
GENERATING PLANT STATISTICS (Small Plants)
Line
No.
Name of Plant
(a)
Year Orig. Const.
(b)
Installed Capacity Name Plate
Rating (MW)
(c)
Net Peak Demand MW (60 min)
(d)
Net Generation Excluding Plant Use
(e)
Cost of Plant
(f)
1 Hydro
2 Clear Lakes 1937 2.5 2.1 16,360 3,600,259
3 Thousand Springs 1912 6.8 6.8 51,784 14,163,124
4 Internal Combustion
5 Salmon Diesel 1967 5 2.8 39 884,134
FERC FORM NO. 1 (REV. 12-03)
Page 410-411
GENERATING PLANT STATISTICS (Small Plants)
Production Expenses Production Expenses
Line
No.
Plant Cost (Incl Asset Retire. Costs)
Per MW
(g)
Operation Exc'l. Fuel
(h)
Fuel Production Expenses
(i)
Maintenance Production Expenses
(j)
Kind of Fuel
(k)
Fuel Costs (in cents (per Million
Btu)
(l)
1
2 1,440,104 72,417 27,360
3 2,082,812 455,595 267,508
4
5 176,827 Diesel
FERC FORM NO. 1 (REV. 12-03)
Page 410-411
GENERATING PLANT STATISTICS (Small Plants)
Line No.Generation Type
(m)
1
2
3
4
5
FERC FORM NO. 1 (REV. 12-03)
Page 410-411
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
TRANSMISSION LINE STATISTICS
DESIGNATION DESIGNATION VOLTAGE (KV) - (Indicate where
other than 60 cycle, 3 phase)
VOLTAGE (KV) - (Indicate where
other than 60 cycle, 3 phase)
LENGTH (Pole
miles) - (In the
case of
underground
lines report circuit
miles)
LENGTH
(Pole miles) -
(In the case
of
underground
lines report
circuit miles)
Line
No.From To Operating Designated Type of Supporting
Structure
On Structure of
Line Designated
On
Structures of
Another Line
Number
of
Circuits
(a)(b)(c)(d)(e)(f)(g)(h)
1 (a)
Borah Midpoint 345 500 S Tower 62.35 0 1
2
(b)
Boardman Slatt 500 500 S Tower 1.79 0 1
3 (c)
Summer lake Hemingway 500 500 S Tower 0.08 0 1
4 (d)
Hemingway Midpoint 500 500 S Tower 0.15 0 1
5 (e)
Summer Lake Hemingway 500 500 S Tower 53.07 0 1
6 (f)
Hemingway Midpoint 500 500 S Tower 47.76 0 1
7 (g)
Jim Bridger Goshen 345 345 S Tower 66.15 0 1
8 State Line Midpoint 345 345 S Tower 76.05 0 2
9 Rogerson Midpoint 345 345 S Tower 1.08 0 1
10 (h)
Kinport Borah 345 345 S Tower 19.81 0 1
11 (i)
Jim Bridger Populus 345 345 S Tower 60.93 0 1
12 (j)
Populus Kinport 345 345 S Tower 7.42 0 1
13 (k)
Jim Bridger Populus 345 345 S Tower 61.1 0 1
14 (l)
Populus Borah 345 345 S Tower 9.05 0 1
15 (m)
Goshen Kinport 345 345 S Tower 7.49 0 1
16 (n)
Midpoint Borah #1 345 345 H Wood 51.07 0 1
17 (o)
Midpoint Borah #2 345 345 H Wood 49.98 0 2
18 (p)
Adelaide Tap Adelaide 345 345 H Wood 1.72 0 2
19 Quartz LaGrande 230 230 H Wood 45.97 0 1
20 Midpoint Hunt 230 230 S Tower 0.7 0 2
21 Brady Antelope 230 230 H Wood 56.38 0 1
22 Brady Treasureton 230 230 H Wood 0.08 0 1
23 Brady #1 & #2 Kinport 230 230 S Tower 17.94 0 2
24 Brownlee Ontario 230 230 S Tower 72.67 0 1
25 Mora Bowmont 138 230 S P Wood 9.99 0 1
26 Mora Bowmont 138 230 H Wood 8.71 0 1
27 Caldwell 710 Locust 230 230 SP Steel 18.5 0 1
28 Boise Bench Caldwell 230 230 S Tower 7.69 0 1
29 Boise Bench Caldwell 230 230 H Wood 33.49 0 1
30 Boise Bench Cloverdale 230 230 S Tower 16.07 0 2
31 (q)
Boardman Dalreed Sub 230 230 H Wood 1.67 0 1
32 Brownlee 714 Oxbow 230 230 SP Steel 10.96 0 2
33 Caldwell Ontario 230 230 H Wood 30.06 0 1
34 Caldwell Ontario 230 230 S Tower 3.14 0 1
35 Bennett Mtn PP Rattlesnake TS 230 230 SP Steel 4.39 0 1
36 Borah Hunt 230 230 H Steel 68.12 0 1
37 Danskin Hubbard 230 230 H Steel 36.25 0 1
38 Danskin Hubbard 230 230 SP Steel 1.84 0 1
39 Danskin Hubbard 230 230 SP Steel 1.3 0 2
40 Danskin Bennett Mtn 230 230 SP Steel 5.39 0 1
41 Hemingway Bowmont 230 230 SP Steel 12.94 0 1
42 Langley Gulch Galloway Rd 138 230 SP Steel 14.19 0 1
43 Galloway Rd Willis Tap 138 230 SP Steel 2.09 0 1
44 (r)
Walla Walla Hurricane 230 230 H Wood 31.67 0 1
45 Cloverdale Hubbard 230 230 SP Steel 6.86 0 2
46 Boise Bench Midpoint #1 230 230 S Tower 0.71 0 1
47 Boise Bench Midpoint #1 230 230 H Wood 108.67 0 1
48 Brownlee Quartz Jct 230 230 S Tower 1.51 0 1
49 Brownlee Quartz Jct 230 230 H Wood 41.3 0 1
FERC FORM NO. 1 (ED. 12-87)
Page 422-423
50 Brownlee Boise Bench #1 & #2 230 230 S Tower 99.78 0 2
51 Oxbow Brownlee 230 230 S Tower 10.32 0 2
52 Boise Bench Midpoint #2 230 230 S Tower 3.49 0 1
53 Boise Bench Midpoint #2 230 230 H Wood 102.13 0 1
54 Oxbow Pallette Jct 230 230 S Tower 19.98 0 2
55 Pallette Jct Imnaha 230 230 H Wood 24.43 0 2
56 Hells Canyon Palette Jct 230 230 S Tower 9.05 0 2
57 Brownlee Boise Bench 230 230 S Tower 102.1 0 2
58 Boise Bench Midpoint #3 230 230 H Wood 106.29 0 1
59 Palette Jct Enterprise 230 230 H Wood 29.6 0 1
60 Borah Brady #2 230 230 S Tower 0.42 0 1
61 Borah Brady #2 230 230 H Wood 3.52 0 1
62 Borah Brady #1 230 230 H Wood 3.84 0 1
63 (s)
Goshen State Line 161 161 H Wood 40.89 0 1
64 Don Goshen 161 161 S Tower 2.37 0 2
65 Don Goshen 161 161 H Wood 16.49 0 2
66 Don Goshen 138 161 H Wood 29.64 0 2
67 (t)
Antelope Goshen 161 161 H Wood 5.68 0 1
68 (u)
Goshen State Line 161 161 H Wood 10.9 0 1
69 (v)
Goshen State Line 161 161 H Wood 7.84 0 1
70 American Falls Power Plant Adelaide 138 138 H Wood 14.07 0 2
71 American Falls Power Plant Adelaide 138 138 S P Wood 0.12 0 2
72 Minidoka Loop Adelaide 138 138 S Tower 1.13 0 2
73 Nampa Caldwell 138 138 S P Wood 9.59 0 2
74 Skyway Tap 138 138 S P Steel 0.89 0 2
75 Upper Salmon Mountain Home Jct 138 138 H Wood 54.36 0 1
76 Upper Salmon Cliff 138 138 H Wood 30.81 0 1
77 Eastgate Russet 138 138 S P Wood 2.06 0 1
78 Brady Fremont 138 138 S Tower 1.01 0 2
79 Brady Fremont 138 138 H Wood 24.36 0 2
80 Brady Fremont 138 138 S P Wood 24.33 0 2
81 King Lower Malad 138 138 H Wood 84.71 0 2
82 Orchard Tap 138 138 S P Steel 3.81 0 1
83 Emmett Jct Payette 138 138 H Wood 66.41 0 2
84 Mountain Home AFB Tap 138 138 H Wood 6.2 0 1
85 Ontario Quartz 138 138 H Wood 73.2 0 1
86 King American Falls PP 138 138 S Tower 0.91 0 2
87 King American Falls PP 138 138 H Wood 142.06 0 1
88 King American Falls PP 138 138 S P Wood 3.71 0 1
89 Duffin Clawson 138 138 H Wood 6.19 0 1
90 American Falls Brady Tie 138 138 H Wood 0.33 0 1
91 Upper Salmon A-B King 138 138 H Wood 5.66 0 1
92 Upper Salmon B Wells 138 138 H Wood 125.47 0 1
93 King Wood River 138 138 H Wood 73.72 0 1
94 Toponis Pocket 138 138 S P Wood 9.8 0 1
95 Boise Bench Grove 138 138 S P Wood 10.5 0 2
96 Quartz John Day 138 138 H Wood 67.3 0 1
97 Sinker Creek Tap 138 138 H Wood 2.79 0 1
98 Mora Cloverdale 138 138 H Wood 2.51 0 1
99 Mora Cloverdale 138 138 S P Wood 22.26 0 1
100 Mora Cloverdale 138 138 S P Steel 0.96 0 2
101 Stoddard Jct Stoddard Sub 138 138 S P Steel 3.8 0 1
102 Fossil Gulch Tap 138 138 H Wood 1.81 0 1
103 Wood River Midpoint 138 138 H Wood 53.08 0 2
104 Wood River Midpoint 138 138 S P Wood 16.69 0 2
105 Oxbow McCall 138 138 H Wood 37.04 0 1
TRANSMISSION LINE STATISTICS
DESIGNATION DESIGNATION VOLTAGE (KV) - (Indicate where
other than 60 cycle, 3 phase)
VOLTAGE (KV) - (Indicate where
other than 60 cycle, 3 phase)
LENGTH (Pole
miles) - (In the
case of
underground
lines report circuit
miles)
LENGTH
(Pole miles) -
(In the case
of
underground
lines report
circuit miles)
Line
No.From To Operating Designated Type of Supporting
Structure
On Structure of
Line Designated
On
Structures of
Another Line
Number
of
Circuits
(a)(b)(c)(d)(e)(f)(g)(h)
FERC FORM NO. 1 (ED. 12-87)
Page 422-423
106 Oxbow McCall 138 138 S P Wood 2.32 0 1
107 Lowell Jct Nampa 138 138 S P Wood 7.49 0 2
108 Hunt Milner 138 138 S P Wood 19.41 0 1
109 Strike Bruneau Bridge 138 138 H Wood 13.49 0 1
110 American Falls Kramer Sub 138 138 S P Wood 18.46 0 2
111 Pingree Haven 138 138 S P Wood 11.72 0 1
112 Midpoint Twin Falls 138 138 S P Wood 25.23 0 2
113 Shoshone Tap 138 138 H Wood 7.09 0 2
114 Twin Falls Russett 138 138 S P Wood 1.71 0 1
115 Blackfoot Aiken 46 138 S P Wood 6.22 0 2
116 Peterson Tendoy 69 138 H Wood 57.04 0 1
117 Eastgate Tap Eastgate 138 138 S P Wood 6.39 0 1
118 Kimberly Tap Kimberly 138 138 S P Steel 1.84 0 2
119 Boise Bench Mora 138 138 H Wood 13.11 0 2
120 Bowmont-Caldwell Simplot Sub 138 138 S P Wood 0.51 0 1
121 Gary Lane Eagle 138 138 S P Wood 6.64 0 1
122 Locust Grove Blackcat Sub 138 138 S P Steel 9.26 2.98 1
123 Boise Bench Butler 138 138 S P Wood 0.14 4.02 1
124 Eagle Star 138 138 S P Wood 6.75 0 1
125 Star Lansing 138 138 S P Steel 5.5 0 1
126 Beacon Light Tap Beacon Light 138 138 S P Steel 4.32 0 1
127 Karcher Sub Zilog Tap 138 138 S P Steel 3.12 0 1
128 Zilog Can Ada 138 138 S P Steel 1.5 0 1
129 Blackcat Can Ada 138 138 H Wood 3.42 0 1
130 Cloverdale - 712 712 - Wye 138 138 S P Steel 0.42 4.02 1
131 Victory Jct Victory 138 138 S P Steel 1.88 0 1
132 Butler Wye 138 138 S P Steel 2.94 0 1
133 Horseflat Starkey 138 138 H Wood 33.97 0 1
134 Starkey Mccall 138 138 S P Steel 2.23 0 2
135 Starkey Mccall 138 138 H Wood 3.8 0 1
136 Starkey Mccall 138 138 S P Steel 1.5 0 1
137 Starkey Mccall 138 138 S P Wood 17.61 0 1
138 Chestnut Happy Valley 138 138 S P Steel 2.78 0 1
139 Garnet Ward 0 138 0 0 0
140 McCall Lake Fork 138 138 S P Wood 8.89 0 1
141 McCall Lake Fork 138 138 S Steel 2.9 0 1
142 Boulder Tap 138 138 S P Steel 1.98 0 1
143 Caldwell Willis 138 138 S P Steel 1.3 0 1
144 Caldwell Willis 138 138 S P Steel 3.63 0 1
145 Caldwell Willis 138 138 S P Wood 0.87 0 1
146 Willis Lansing 138 138 Verious 3.23 0 2
147 Valivue Tap 138 138 S P Steel 0.79 0 2
148 Bowmont Happy Valley 138 138 S P Steel 8.65 0 1
149 (w)
Antelope Scoville 138 138 H Wood 0.12 0 1
150 (x)
American Falls Wheelon 138 138 H Wood 1.05 0 1
151 Kinport Don #1 138 138 S Tower 1.27 0 2
152 Donn HOKU 138 138 S P Steel 2.69 0 1
153 HOKU Alamed 138 138 S P Steel 0.22 0 2
154 HOKU Alamed 138 138 S P Steel 0.23 0 2
155 HOKU Alamed 138 138 S P Steel 2.85 0 1
156 Eldridge tap 138 138 S P Steel 0.85 0 1
157 Mora Columbia 138 138 S P Steel 0 3.92 2
158 Rockland Jct Rockland Wind Farm 138 138 S P Steel 5.18 0 1
159 King Justice 138 138 S P Wood 0.07 0 1
160 NorthView Tap 138 138 S P Wood 6.17 0 1
161 Twin Falls PP Tap 138 138 H Wood 0.99 0 1
TRANSMISSION LINE STATISTICS
DESIGNATION DESIGNATION VOLTAGE (KV) - (Indicate where
other than 60 cycle, 3 phase)
VOLTAGE (KV) - (Indicate where
other than 60 cycle, 3 phase)
LENGTH (Pole
miles) - (In the
case of
underground
lines report circuit
miles)
LENGTH
(Pole miles) -
(In the case
of
underground
lines report
circuit miles)
Line
No.From To Operating Designated Type of Supporting
Structure
On Structure of
Line Designated
On
Structures of
Another Line
Number
of
Circuits
(a)(b)(c)(d)(e)(f)(g)(h)
FERC FORM NO. 1 (ED. 12-87)
Page 422-423
162 American Falls PP Amercian Falls Trans ST 138 138 S P Steel 0.37 0 1
163 Lower Salmon King Tie 138 138 H Wood 0.05 0 1
164 C J Strike Strike Jct 138 138 S Tower 4.3 0 2
165 Strike Jct Mountain Home Jct 138 138 H Wood 23.42 0 1
166 Strike Jct Bowmont 0 138 H Wood 0.05 0 1
167 Strike Jct Bowmont 138 138 S Tower 0.36 0 1
168 Strike Jct Bowmont 138 138 H Wood 67.89 0 1
169 Lucky Peak Lucky Peak Jct 138 138 H Wood 4.48 0 2
170 Bliss King 138 138 H Wood 10.51 0 1
171 Milner Deadend Milner PP 138 138 S P Wood 1.3 0 1
172 Swan Falls Tap 138 138 H Wood 0.95 0 1
173 Hines BPA (Harney)115 115 H Wood 3.35 0 1
174 69 Kv Lines 69 69 H Wood 205.81 0 1
175 69 Kv Lines 69 69 S P Wood 874 0 1
176 46 Kv Lines 46 46 S P Wood 374.13 0 1
177 NA 0 0 0
36 TOTAL 4,785.42 14.94 224
FERC FORM NO. 1 (ED. 12-87)
Page 422-423
TRANSMISSION LINE STATISTICS
DESIGNATION DESIGNATION VOLTAGE (KV) - (Indicate where
other than 60 cycle, 3 phase)
VOLTAGE (KV) - (Indicate where
other than 60 cycle, 3 phase)
LENGTH (Pole
miles) - (In the
case of
underground
lines report circuit
miles)
LENGTH
(Pole miles) -
(In the case
of
underground
lines report
circuit miles)
Line
No.From To Operating Designated Type of Supporting
Structure
On Structure of
Line Designated
On
Structures of
Another Line
Number
of
Circuits
(a)(b)(c)(d)(e)(f)(g)(h)
TRANSMISSION LINE STATISTICS
COST OF LINE (Include in
column (j) Land, Land rights,
and clearing right-of-way)
COST OF LINE (Include in
column (j) Land, Land rights,
and clearing right-of-way)
COST OF LINE (Include in
column (j) Land, Land rights,
and clearing right-of-way)
EXPENSES, EXCEPT
DEPRECIATION AND TAXES
EXPENSES, EXCEPT
DEPRECIATION AND
TAXES
EXPENSES,
EXCEPT
DEPRECIATION
AND TAXES
EXPENSES,
EXCEPT
DEPRECIATION
AND TAXES
Line
No.Size of Conductor and Material Land Construction Costs Total Costs Operation Expenses Maintenance Expenses Rents Total Expenses
(i)(j)(k)(l)(m)(n)(o)(p)
1 1272 ACSR 256,381 16,047,911 16,304,292 0 0 0 0
2 2X1780 ACSR 0 446,708 446,708 0 0 0 0
3 1272 ACSR 0 0 0 0 0 0 0
4 1272 ACSR 0 0 0 0 0 0 0
5 3x1272 ACSR 0 18,862,608 18,862,608 0 0 0 0
6 3x1272 ACSR 0 17,144,375 17,144,375 0 0 0 0
7 1272 ACSR 483,309 5,333,017 5,816,326 0 0 0 0
8 795 ACSR 572,296 13,138,420 13,710,716 0 0 0 0
9 795 ACSR 0 0 0 0 0 0 0
10 1272 ACSR 344,220 4,401,429 4,745,649 0 0 0 0
11 1272 ACSR 0 9,541,199 9,541,199 0 0 0 0
12 1272 ACSR 0 0 0 0 0 0 0
13 1272 ACSR 0 9,261,033 9,261,033 0 0 0 0
14 1272 ACSR 0 0 0 0 0 0 0
15 2x1272 ACSR 0 585,982 585,982 0 0 0 0
16 715.5 ACSR 283,143 20,443,196 20,726,339 0 0 0 0
17 715.5 ACSR 64,851 15,048,303 15,113,154 0 0 0 0
18 715.5 ACSR 51,448 227,554 279,002 0 0 0 0
19 795 ACSR 62,218 7,305,569 7,367,787 0 0 0 0
20 715.5 ACSR 9,145 999,238 1,008,383 0 0 0 0
21 1272 ACSR 163,320 4,696,608 4,859,928 0 0 0 0
22 795 ACSR 0 6,186 6,186 0 0 0 0
23 715.5 ACSR 18,829 1,212,762 1,231,591 0 0 0 0
24 2X954 ACSR 1,676,838 20,730,375 22,407,213 0 0 0 0
25 715.5 ACSR 413,793 2,397,704 2,811,497 0 0 0 0
26 715.5 ACSR 0 0 0 0 0 0 0
27 1590 ACSR 2,378,436 8,775,086 11,153,522 0 0 0 0
28 1272 ACSR 1,748,202 12,977,511 14,725,713 0 0 0 0
29 715.5 ACSR 0 0 0 0 0 0 0
30 1272 ACSR 3,062,812 7,280,035 10,342,847 0 0 0 0
31 795 AAC 0 89,089 89,089 0 0 0 0
32 954 ACSR 34,174 16,026,470 16,060,644 0 0 0 0
33 2X954 ACSR 236,152 9,384,090 9,620,242 0 0 0 0
34 1272 ACSR 0 0 0 0 0 0 0
35 1272 ACSR 81,701 1,666,354 1,748,055 0 0 0 0
36 1590 ACSR 624,917 22,468,412 23,093,329 0 0 0 0
37 1590 ACSR 19,020 15,210,560 15,229,580 0 0 0 0
38 1590 ACSR 0 0 0 0 0 0 0
39 1590 ACSR 0 0 0 0 0 0 0
40 1590 ACSR 0 3,528,033 3,528,033 0 0 0 0
41 1590 ACSR 1,854,996 9,277,980 11,132,976 0 0 0 0
42 1590 ACSR 948,166 9,067,609 10,015,775 0 0 0 0
43 1272 ACSR 0 0 0 0 0 0 0
44 1272 ACSR 0 6,912,812 6,912,812 0 0 0 0
45 1272 ACSR 287,582 8,925,685 9,213,267 0 0 0 0
46 715.5 ACSR 385,287 14,953,960 15,339,247 0 0 0 0
47 715.5 ACSR 0 0 0 0 0 0 0
48 795 ACSR 53,068 4,881,976 4,935,044 0 0 0 0
49 795 ACSR 0 0 0 0 0 0 0
50 VARIOUS 289,923 9,981,777 10,271,700 0 0 0 0
51 1272 ACSR 14,810 1,583,672 1,598,482 0 0 0 0
52 715.5 ACSR 227,814 18,995,600 19,223,414 0 0 0 0
53 VARIOUS 0 0 0 0 0 0 0
54 1272 ACSR 87,468 3,961,014 4,048,482 0 0 0 0
55 1272 ACSR 171,082 4,396,925 4,568,007 0 0 0 0
56 1272 ACSR 44,687 1,573,781 1,618,468 0 0 0 0
57 954 ACSR 184,805 6,484,895 6,669,700 0 0 0 0
58 715.5 ACSR 247,846 8,323,972 8,571,818 0 0 0 0
59 1272 ACSR 84,014 2,433,400 2,517,414 0 0 0 0
FERC FORM NO. 1 (ED. 12-87)
Page 422-423
60 1272 ACSR 3,068 864,609 867,677 0 0 0 0
61 715.5 ACSR 0 0 0 0 0 0 0
62 1272 ACSR 7,248 514,141 521,389 0 0 0 0
63 250 COPPER 375,576 3,295,299 3,670,875 0 0 0 0
64 715.5 ACSR 88,204 2,516,757 2,604,961 0 0 0 0
65 397.5 ACSR 0 0 0 0 0 0 0
66 397.5 ACSR 0 0 0 0 0 0 0
67 397.5 ACSR 0 798,373 798,373 0 0 0 0
68 250 COPPER 116,872 1,263,789 1,380,661 0 0 0 0
69 250 COPPER 76,969 646,194 723,163 0 0 0 0
70 250 COPPER 26,507 406,847 433,354 0 0 0 0
71 250 COPPER 0 0 0 0 0 0 0
72 715.5 ACSR 21,327 286,445 307,772 0 0 0 0
73 795 AAC 1,798,312 6,013,135 7,811,447 0 0 0 0
74 1272 ACSR 0 0 0 0 0 0 0
75 795 ACSR 78,078 5,041,254 5,119,332 0 0 0 0
76 795 ACSR 43,568 3,467,397 3,510,965 0 0 0 0
77 795 AAC 270,823 561,561 832,384 0 0 0 0
78 VARIOUS 564,932 5,258,747 5,823,679 0 0 0 0
79 VARIOUS 0 0 0 0 0 0 0
80 VARIOUS 0 0 0 0 0 0 0
81 VARIOUS 276,832 6,792,641 7,069,473 0 0 0 0
82 795 ACSR 0 0 0 0 0 0 0
83 VARIOUS 61,872 4,736,887 4,798,759 0 0 0 0
84 397.5 ACSR 5,086 90,415 95,501 0 0 0 0
85 VARIOUS 127,900 9,009,818 9,137,718 0 0 0 0
86 715.5 ACSR 216,919 14,524,197 14,741,116 0 0 0 0
87 715.5 ACSR 0 0 0 0 0 0 0
88 715.5 ACSR 0 0 0 0 0 0 0
89 4\0 4,191 562,786 566,977 0 0 0 0
90 954 ACSR 0 160,465 160,465 0 0 0 0
91 250 COPPER 2,741 916,775 919,516 0 0 0 0
92 VARIOUS 28,490 4,917,063 4,945,553 0
93 VARIOUS 186,198 25,907,146 26,093,344 0 0 0 0
94 397.5 ACSR 0 0 0 0 0 0 0
95 VARIOUS 225,602 1,637,292 1,862,894 0 0 0 0
96 397.5 ACSR 96,582 3,777,184 3,873,766 0 0 0 0
97 VARIOUS 11,083 309,769 320,852 0 0 0 0
98 715.5 ACSR 3,123,381 10,252,929 13,376,310 0 0 0 0
99 VARIOUS 0 0 0 0 0 0 0
100 795AAC 0 0 0 0 0 0 0
101 1272 ACSR 0 0 0 0 0 0 0
102 250 COPPER 450 190,553 191,003 0 0 0 0
103 397.5 ACSR 349,712 8,398,720 8,748,432 0 0 0 0
104 397.5 ACSR 0 0 0 0 0 0 0
105 397.5 ACSR 141,534 2,852,639 2,994,173 0 0 0 0
106 397.5 ACSR 0 0 0 0 0 0 0
107 715.5 ACSR 211,131 1,465,044 1,676,175 0 0 0 0
108 715.5 ACSR 3,324 1,569,973 1,573,297 0 0 0 0
109 397.5 ACSR 14,927 761,064 775,991 0 0 0 0
110 715.5 ACSR 13,734 1,303,623 1,317,357 0 0 0 0
111 397.5 ACSR 18,223 1,343,412 1,361,635 0 0 0 0
112 VARIOUS 107,132 7,773,257 7,880,389 0 0 0 0
113 397.5 ACSR 0 0 0 0 0 0 0
114 715.5 ACSR 16,790 213,033 229,823 0 0 0 0
115 715.5 ACSR 13,616 580,168 593,784 0 0 0 0
116 397.5 ACSR 395,696 3,617,011 4,012,707 0 0 0 0
117 715.5 ACSR 343,955 2,195,624 2,539,579 0 0 0 0
118 795 ACSR 0 0 0 0 0 0 0
TRANSMISSION LINE STATISTICS
COST OF LINE (Include in
column (j) Land, Land rights,
and clearing right-of-way)
COST OF LINE (Include in
column (j) Land, Land rights,
and clearing right-of-way)
COST OF LINE (Include in
column (j) Land, Land rights,
and clearing right-of-way)
EXPENSES, EXCEPT
DEPRECIATION AND TAXES
EXPENSES, EXCEPT
DEPRECIATION AND
TAXES
EXPENSES,
EXCEPT
DEPRECIATION
AND TAXES
EXPENSES,
EXCEPT
DEPRECIATION
AND TAXES
Line
No.Size of Conductor and Material Land Construction Costs Total Costs Operation Expenses Maintenance Expenses Rents Total Expenses
(i)(j)(k)(l)(m)(n)(o)(p)
FERC FORM NO. 1 (ED. 12-87)
Page 422-423
119 715.5 ACSR 14,697 756,210 770,907 0 0 0 0
120 795 AAC 0 50,319 50,319 0 0 0 0
121 795 AAC 308,141 2,261,204 2,569,345 0 0 0 0
122 1272 ACSR 935,810 3,852,101 4,787,911 0 0 0 0
123 1272 ACSR 34,687 838,605 873,292 0 0 0 0
124 715.5 ACSR 630,977 8,660,880 9,291,857 0 0 0 0
125 795 AAC 0 0 0 0 0 0 0
126 795 AAC 0 0 0 0 0 0 0
127 795 AAC 541,877 3,506,249 4,048,126 0 0 0 0
128 795 AAC 0 0 0 0 0 0 0
129 397.5 ACSR 0 0 0 0 0 0 0
130 1272 ACSR 140,412 2,602,119 2,742,531 0 0 0 0
131 1272 ACSR 0 0 0 0 0 0 0
132 795 ACSR 134,471 1,405,436 1,539,907 0 0 0 0
133 715.5 ACSR 2,473,833 19,071,763 21,545,596 0 0 0 0
134 715.5 ACSR 0 0 0 0 0 0 0
135 715.5 ACSR 0 0 0 0 0 0 0
136 715.5 ACSR 0 0 0 0 0 0 0
137 715.5 ACSR 0 0 0 0 0 0 0
138 1272 ACSR 78,579 2,221,530 2,300,109 0 0 0 0
139 40,580 0 40,580 0 0 0 0
140 715.5 ACSR 331,539 4,916,115 5,247,654 0 0 0 0
141 715.5 ACSR 0 0 0 0 0 0 0
142 715.5 ACSR 0 0 0 0 0 0 0
143 1272 ACSR 846,523 5,865,417 6,711,940 0 0 0 0
144 795 ACSR 0 0 0 0 0 0 0
145 795 ACSR 0 0 0 0 0 0 0
146 795 ACSR 0 0 0 0 0 0 0
147 795 ACSR 0 351,497 351,497 0 0 0 0
148 1272 ACSR 691,728 6,045,286 6,737,014 0 0 0 0
149 397.5 ACSR 0 94,004 94,004 0 0 0 0
150 250 COPPER 0 105,684 105,684 0 0 0 0
151 715.5 ACSR 1,174 267,313 268,487 0 0 0 0
152 1272 ACSR 327,334 2,143,350 2,470,684 0 0 0 0
153 1272 ACSR 0 0 0 0 0 0 0
154 795 ACSR 0 0 0 0 0 0 0
155 795 ACSR 0 0 0 0 0 0 0
156 795 ACSR 0 0 0 0 0 0 0
157 795 ACSR 0 531,352 531,352 0 0 0 0
158 795 ACSR 0 (16,973)(16,973)0 0 0 0
159 1590 ACSR 0 60,659 60,659 0 0 0 0
160 715.5 ACSR 105,933 4,125,054 4,230,987 0 0 0 0
161 250 COPPER 58 112,537 112,595 0 0 0 0
162 715.5 ACSR 0 176,784 176,784 0 0 0 0
163 397.5 ACSR 0 76,469 76,469 0 0 0 0
164 715.5 ACSR 1,074 706,413 707,487 0 0 0 0
165 397.5 ACSR 6,332 2,613,111 2,619,443 0 0 0 0
166 715.5 ACSR 86,651 4,895,949 4,982,600 0 0 0 0
167 715.5 ACSR 0 0 0 0 0 0 0
168 715.5 ACSR 0 0 0 0 0 0 0
169 715.5 ACSR 7 295,569 295,576 0 0 0 0
170 715.5 ACSR 5,620 1,744,668 1,750,288 0 0 0 0
171 715.5 ACSR 14,968 186,543 201,511 0 0 0 0
172 397.5 ACSR 17,207 262,545 279,752 0 0 0 0
173 397.5 ACSR 1,978 117,770 119,748 0 0 0 0
174 VARIOUS 1,471,284 98,517,829 99,989,113 0 0 0 0
175 VARIOUS 0 0 0 0 0 0 0
176 VARIOUS 782,797 27,844,413 28,627,210 0 0 0 0
177 0 0 0 8,252,130 2,486,170 4,855,402 15,593,702
TRANSMISSION LINE STATISTICS
COST OF LINE (Include in
column (j) Land, Land rights,
and clearing right-of-way)
COST OF LINE (Include in
column (j) Land, Land rights,
and clearing right-of-way)
COST OF LINE (Include in
column (j) Land, Land rights,
and clearing right-of-way)
EXPENSES, EXCEPT
DEPRECIATION AND TAXES
EXPENSES, EXCEPT
DEPRECIATION AND
TAXES
EXPENSES,
EXCEPT
DEPRECIATION
AND TAXES
EXPENSES,
EXCEPT
DEPRECIATION
AND TAXES
Line
No.Size of Conductor and Material Land Construction Costs Total Costs Operation Expenses Maintenance Expenses Rents Total Expenses
(i)(j)(k)(l)(m)(n)(o)(p)
FERC FORM NO. 1 (ED. 12-87)
Page 422-423
36 36,961,609 731,050,685 768,012,294 8,252,130 2,486,170 4,855,402 15,593,702
FERC FORM NO. 1 (ED. 12-87)
Page 422-423
TRANSMISSION LINE STATISTICS
COST OF LINE (Include in
column (j) Land, Land rights,
and clearing right-of-way)
COST OF LINE (Include in
column (j) Land, Land rights,
and clearing right-of-way)
COST OF LINE (Include in
column (j) Land, Land rights,
and clearing right-of-way)
EXPENSES, EXCEPT
DEPRECIATION AND TAXES
EXPENSES, EXCEPT
DEPRECIATION AND
TAXES
EXPENSES,
EXCEPT
DEPRECIATION
AND TAXES
EXPENSES,
EXCEPT
DEPRECIATION
AND TAXES
Line
No.Size of Conductor and Material Land Construction Costs Total Costs Operation Expenses Maintenance Expenses Rents Total Expenses
(i)(j)(k)(l)(m)(n)(o)(p)
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
FOOTNOTE DATA
(a) Concept: TransmissionLineStartPoint
Borah Midpoint - This line is jointly owned with PacifiCorp and Idaho Power owns 73.2% of this 85.4 mile line.
(b) Concept: TransmissionLineStartPoint
Boardman Slatt - This line is jointly owned with Portland General Electric and Idaho Power owns 10% of this 17.8 mile line.
(c) Concept: TransmissionLineStartPoint
Summer Lake Hemingway - This line is jointly owned with PacifiCorp and Idaho Power owns 22.0% of this 241.3 mile line.
(d) Concept: TransmissionLineStartPoint
Hemingway Midpoint - This line is jointly owned with PacifiCorp and Idaho Power owns 37.0% of this 129.3 mile line.
(e) Concept: TransmissionLineStartPoint
Summer Lake Hemingway - This line is jointly owned with PacifiCorp and Idaho Power owns 22.0% of this 241.3 mile line.
(f) Concept: TransmissionLineStartPoint
Hemingway Midpoint - This line is jointly owned with PacifiCorp and Idaho Power owns 37.0% of this 129.3 mile line.
(g) Concept: TransmissionLineStartPoint
Jim Bridger Goshen - This line is jointly owned with PacifiCorp and Idaho Power owns 29.2% of this 226.6 mile line.
(h) Concept: TransmissionLineStartPoint
Kinport Borah (Row 8) - This line is jointly owned with PacifiCorp and Idaho Power owns 73.2% of this 27.1 mile line.
(i) Concept: TransmissionLineStartPoint
Jim Bridger Populus - This line is jointly owned with PacifiCorp and Idaho Power owns 29.2% of this approximately 193 mile line.
(j) Concept: TransmissionLineStartPoint
Populus Kinport This line is jointly owned with PacifiCorp and Idaho Power owns 29.2% of this 41.2 mile line.
(k) Concept: TransmissionLineStartPoint
Jim Bridger Populus - This line is jointly owned with PacifiCorp and Idaho Power owns 29.2% of this approximately 193 mile line.
(l) Concept: TransmissionLineStartPoint
Populus Borah - This line is jointly owned with PacifiCorp and Idaho Power owns 29.2% of this 47.3 mile line.
(m) Concept: TransmissionLineStartPoint
Goshen - Kinport - This line is jointly owned with PacifiCorp and Idaho Power owns 18.3% of this 40.9 mile line.
(n) Concept: TransmissionLineStartPoint
Midpoint Borah #1 - This line is jointly owned with PacifiCorp and Idaho Power owns 64.4% of this 79.5 mile line.
(o) Concept: TransmissionLineStartPoint
Midpoint Borah #2 - This line is jointly owned with PacifiCorp and Idaho Power owns 64.4% of this 77.9 mile line.
(p) Concept: TransmissionLineStartPoint
Adelaide Tap Adelaide - This line is jointly owned with PacifiCorp and Idaho Power owns 64.4% of this 0.9 mile line.
(q) Concept: TransmissionLineStartPoint
Boardman Dalreed Sub - This line is jointly owned with Portland General Electric and Idaho Power owns 10% of this 16.7 mile line.
(r) Concept: TransmissionLineStartPoint
Walla Walla - Hurricane - This line is jointly owned with PacifiCorp and Idaho Power owns 40.8% of this 77.6 mile line.
(s) Concept: TransmissionLineStartPoint
Goshen Stateline - This line is jointly owned with PacifiCorp. Idaho Power owns 37.8% of the Goshen Jefferson 28.9 mile segment, 37.8% of the Jefferson Big Grassy 20.8 mile segment and 100% of the Big Grassy Stateline 40.9 mile segment.
(t) Concept: TransmissionLineStartPoint
Antelope Goshen - This line is jointly owned with PacifiCorp and Idaho Power owns 21.9% of this 25.8 mile line.
(u) Concept: TransmissionLineStartPoint
Goshen Stateline - This line is jointly owned with PacifiCorp. Idaho Power owns 37.8% of the Goshen Jefferson 28.9 mile segment, 37.8% of the Jefferson Big Grassy 20.8 mile segment and 100% of the Big Grassy Stateline 40.9 mile segment.
(v) Concept: TransmissionLineStartPoint
Goshen Stateline - This line is jointly owned with PacifiCorp. Idaho Power owns 37.8% of the Goshen Jefferson 28.9 mile segment, 37.8% of the Jefferson Big Grassy 20.8 mile segment and 100% of the Big Grassy Stateline 40.9 mile segment.
(w) Concept: TransmissionLineStartPoint
Antelope - Scoville - This line is jointly owned with PacifiCorp and Idaho Power owns 11.5% of this 1 mile line.
(x) Concept: TransmissionLineStartPoint
American Falls Wheelon - This line is jointly owned with PacifiCorp and Idaho Power owns 7.2% of this 29.1 mile line.
FERC FORM NO. 1 (ED. 12-87)
Page 422-423
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
TRANSMISSION LINES ADDED DURING YEAR
LINE DESIGNATION LINE DESIGNATION SUPPORTING
STRUCTURE SUPPORTING STRUCTURE CIRCUITS PER
STRUCTURE
Line
No.From To Line Length in Miles Type Average Number per Miles Present
(a)(b)(c)(d)(e)(f)
1 (a)
Boise Bench Blacks Creek 1.47 H Wood 18 1
2 (b)
Orchard Orchard Tap 3.81 S P Steel 16 1
3 (c)
Mora Columbia 3.92 S P Steel 11 2
4 (d)
Rogerson Midpoint 1.08 S P Steel 7 1
44 TOTAL 10.28 52 5
FERC FORM NO. 1 (REV. 12-03)
Page 424-425
TRANSMISSION LINES ADDED DURING YEAR
CIRCUITS PER STRUCTURE CONDUCTORS CONDUCTORS CONDUCTORS LINE COST
Line
No.Ultimate Size Specification Configuration and Spacing Voltage KV (Operating)Land and Land Rights
(g)(h)(i)(j)(k)(l)
1 1 397.5 ACSR IBIS MULTIPLE 69
2 1 795 ACSR TERN MULTIPLE 138 200,143
3 2 795 ACSR TERN MULTIPLE 138
4 1 795 ACSR TERN MULTIPLE 345 317
44 5 200,460
FERC FORM NO. 1 (REV. 12-03)
Page 424-425
TRANSMISSION LINES ADDED DURING YEAR
LINE COST LINE COST LINE COST LINE COST
Line
No.Poles, Towers and Fixtures Conductors and Devices Asset Retire. Costs Total Construction
(m)(n)(o)(p)(q)
1 4,453 6,324 (e)10,777
2 1,453,736 979,255 2,633,134
3 5,688 525,664 531,352
4 818,319 958,935 (f)1,777,571
44 2,282,196 2,470,178 0 4,952,834
FERC FORM NO. 1 (REV. 12-03)
Page 424-425
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
FOOTNOTE DATA
(a) Concept: TransmissionLineStartPoint
Estimated amounts are reported.
(b) Concept: TransmissionLineStartPoint
Estimated amounts are reported.
(c) Concept: TransmissionLineStartPoint
Estimated amounts are reported.
(d) Concept: TransmissionLineStartPoint
Estimated amounts are reported.
(e) Concept: CostOfTransmissionLinesAdded
Construction totals include customer contributions.
(f) Concept: CostOfTransmissionLinesAdded
Construction totals include customer contributions.
FERC FORM NO. 1 (REV. 12-03)
Page 424-425
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
SUBSTATIONS
Character of Substation Character of Substation VOLTAGE (In MVa)VOLTAGE (In
MVa)VOLTAGE (In MVa)
Line
No.
Name and Location of Substation
(a)
Transmission or Distribution
(b)
Attended or Unattended
(b-1)
Primary Voltage (In MVa)
(c)
Secondary
Voltage (In MVa)
(d)
Tertiary Voltage (In
MVa)
(e)
Capacity
of
Substation
(In
Service)
(In MVa)
(f)
1 (a)
Adelaide Transmission Unattended (u)345 (v)138 (w)13.8 (x)500
2 Aiken Distribution Unattended 46 13 27
3 Alameda Distribution Unattended 138 13 30
4 Alameda Distribution Unattended 138 13.09 30
5 American Falls PP Transmission Attended 138 13.8 120
6 American Falls Transmission Unattended 138 46 12.47 47
7
(b)
Antelope Transmission Unattended 230 161 13.8 224
8 (c)
Antelope Transmission Unattended 161 138 12.47 103
9 (d)
Antelope Transmission Unattended 161 138 13.8 92
10 Artesian Distribution Unattended 46 13 14
11 Bannock Creek Distribution Unattended 46 13 14
12 Beacon Light Distribution Unattended 138 13.09 45
13 Bennett Mountain Power Plant Transmission Attended 230 18 225
14 Bennett Mountain Power Plant Distribution Attended 18 4.16 5
15 Bethel Court Distribution Unattended 138 13 28
16 (e)
Big Grassy Transmission Unattended 161
17 Black Cat Distribution Unattended 138 13.09 90
18 Black Mesa Distribution Unattended 138 13 11
19 Blackfoot Distribution Unattended 46 13 56
20 Blackfoot Transmission Unattended 161 46 12.47 93
21 Blackfoot Distribution Unattended 161 138 12.98 135
22 Bliss Transmission Attended 138 13.8 86
23 Blue Gulch Distribution Unattended 138 35 48
24 Boise Bench Transmission Unattended 230 138 13.2 448
25 Boise Bench Distribution Unattended 138 35 30
26 Boise Bench Transmission Unattended 138 69 12.98 125
27 Boise Bench Transmission Unattended 230 138 13.8 448
28 Boise Bench Distribution Unattended 138 36.2 45
29 Boise Distribution Unattended 138 13 117
30 (f)
Borah Transmission Unattended 345 230 13.8 750
31 Border Distribution Unattended 138 12.47 11
32 Border Distribution Unattended 35 12.47 5
33 Boulder Distribution Unattended 138 35 30
34 Bowmont Distribution Unattended 138 35 30
35 Bowmont Transmission Unattended 138 69 12.98 46
36 Bowmont Transmission Unattended 138 69 12.47 47
37 Bowmont Transmission Unattended 230 138 13.8 600
38 Brady Transmission Unattended 230 138 13.8 312
39 Brady Transmission Unattended 138 46 12.47
40 Brady Distribution Unattended 46 13
41 Brady Distribution Unattended 46 7.2
42 Brownlee Transmission Attended 230 13.8 856
43 Bruneau Bridge Distribution Unattended 138 35 30
44 Bruneau Bridge Distribution Unattended 138 36.2 45
45 Buckhorn Distribution Unattended 69 35 37
46 Buhl Distribution Unattended 46 13.2
47 Burley Rural Distribution Unattended 69 13 20
48 Burley Rural Distribution Unattended 69 13.09 30
49 Butler Distribution Unattended 138 13.09 90
50 Caldwell Distribution Unattended 138 13 28
51 Caldwell Transmission Unattended 230 138 225
52 Caldwell Distribution Unattended 138 13.09 45
53 Caldwell Transmission Unattended 138 69 12.47 140
54 Caldwell Transmission Unattended 230 138 12.47 200
FERC FORM NO. 1 (ED. 12-96)
Page 426-427
55 Camas Distribution Unattended 35 12.47 5
56 Camas Distribution Unattended 35 14.4 10
57 Can-Ada Distribution Unattended 138 13.09 45
58 Canyon Creek Distribution Unattended 138 36.2 45
59 Canyon Creek Transmission Unattended 138 69 12.98 20
60 Cartwright Distribution Unattended 138 13 11
61 Cascade Power Plant Transmission Attended 69 4.6 16
62 Cascade Distribution Unattended 69 13.09 7
63 Cascade Distribution Unattended 69 13.09 14
64 Cascade Distribution Unattended 25 12.5 5
65 Chestnut Distribution Unattended 138 13 45
66 Chestnut Distribution Unattended 138 13.09 45
67 Cinder Distribution Unattended 46 13 11
68 Clear Lake Transmission Attended 46 2.4 5
69 Cliff Transmission Unattended 138 46 12.5 21
70 Cliff Transmission Unattended 138 46 12.95 10
71 Cloverdale Distribution Unattended 138 13 90
72 Cloverdale Distribution Unattended 138 13.09 45
73 Cloverdale Transmission Unattended 230 138 13.8 300
74 Columbia Distribution Unattended 138 13.09 45
75 Council Distribution Unattended 69 13 14
76 Crane Creek Distribution Unattended 69 13 11
77 Crater Distribution Unattended 46 13 11
78 Dale Distribution Unattended 46 4.6
79 Dale Distribution Unattended 46 13
80 Dale Distribution Unattended 69 13
81 Dale Distribution Unattended 138 36.2 90
82 Dale Transmission Unattended 138 46 12.47 47
83 Danskin Transmission Attended 230 18 233
84 Danskin Transmission Attended 230 138 13.8 300
85 Danskin Distribution Attended 18 4.16 6
86 Danskin Transmission Attended 138 12 160
87 Danskin Distribution Attended 35 13.8 5
88 Deen Distribution Unattended 46 13 11
89 Dietrich Distribution Unattended 46 13.09 14
90 Don Distribution Unattended 138 7.6
91 Don Distribution Unattended 138 13.2 180
92 Don Distribution Unattended 138 13 44
93 DRAM Distribution Unattended 138 13.09 168
94 DRAM Transmission Unattended 230 138 13.8 212
95 DRAM Distribution Unattended 138 12.47 28
96 DRAM Distribution Unattended 138 13 28
97 Duffin Distribution Unattended 138 35 60
98 Eagle Distribution Unattended 138 13.09 67
99 Eastgate Distribution Unattended 138 13.09 75
100 Eckert Distribution Unattended 138 36.2 30
101 Eden Distribution Unattended 138 36.2 45
102 Eden Transmission Unattended 138 46 12.98 20
103 Eldredge Distribution Unattended 138 13.09 45
104 Elkhorn Distribution Unattended 138 12.47 11
105 Elkhorn Distribution Unattended 138 13 11
106 Elmore Distribution Unattended 138 35 28
107 Elmore Transmission Unattended 138 69 12.5 25
108 Elmore Transmission Unattended 138 69 12.98 20
109 Emmett Distribution Unattended 138 13.09 45
110 Emmett Transmission Unattended 138 69 12.47 47
111 Emmett-Boise Cascade #1 Distribution Unattended 69 13.09 14
112 Falls Distribution Unattended 46 13 28
SUBSTATIONS
Character of Substation Character of Substation VOLTAGE (In MVa)VOLTAGE (In
MVa)VOLTAGE (In MVa)
Line
No.
Name and Location of Substation
(a)
Transmission or Distribution
(b)
Attended or Unattended
(b-1)
Primary Voltage (In MVa)
(c)
Secondary
Voltage (In MVa)
(d)
Tertiary Voltage (In
MVa)
(e)
Capacity
of
Substation
(In
Service)
(In MVa)
(f)
FERC FORM NO. 1 (ED. 12-96)
Page 426-427
113 Filer Distribution Unattended 46 13 14
114 Flat Top Distribution Unattended 46 13 11
115 Flat Top Distribution Unattended 46 13.09 14
116 Flying H Distribution Unattended 69 2.4 20
117 Fort Hall Distribution Unattended 46 13 14
118 Fossil Gulch Distribution Unattended 138 35 28
119 Fremont Transmission Unattended 138 46 12.5 67
120 Fruitland Distribution Unattended 69 13 20
121 Gary Distribution Unattended 138 13.09 37
122 Gary Distribution Unattended 138 13 28
123 Gem Distribution Unattended 69 13
124 Gem Distribution Unattended 69 13.09 28
125 Glenns Ferry Distribution Unattended 138 13 11
126 Gooding Rural Distribution Unattended 46 13 20
127 Golden Valley Distribution Unattended 69 13 14
128 (g)
Goshen Transmission Unattended 345 161 13.8 1608
129 Gowen Substation Distribution Unattended 138 35 45
130 Gowen Substation Distribution Unattended 138 36.2 45
131 Grindstone Distribution Unattended 35 2.4 14
132 Grove Distribution Unattended 138 13.09 90
133 Grove Distribution Unattended 138 13 45
134 Hagerman Distribution Unattended 46 13 14
135 Hagerman Distribution Unattended 69 13 6
136 Hailey Distribution Unattended 138 13 37
137 Happy Valley Distribution Unattended 138 13.09 30
138 Haven Distribution Unattended 138 35 20
139 Haven Transmission Unattended 138 46 47
140 (h)
Hemingway Transmission Unattended 500 230 34.5 1000
141 Hewlett Packard Distribution Unattended 138 13 37
142 Hidden Springs Distribution Unattended 138 13 11
143 Highland Distribution Unattended 138 13 30
144 Hill Distribution Unattended 138 13 73
145 Hillsdale Distribution Unattended 138 13.09 45
146 Homedale Distribution Unattended 69 13 34
147 Horse Flat Transmission Unattended 230 138 13.8 100
148 Horseshoe Bend Distribution Unattended 35 13.09 7
149 Horseshoe Bend Distribution Unattended 69 36.2 22
150 Horseshoe Bend Distribution Unattended 69 25 7
151 Huston Distribution Unattended 69 13 14
152 Hulen Distribution Unattended 46 13 14
153 Hunt Transmission Unattended 230 138 13.8 336
154 Hydra Distribution Unattended 138 36.2 90
155 Island Distribution Unattended 69 13 20
156 (i)
Jefferson Transmission Unattended 161
157 Jerome Distribution Unattended 138 13 37
158 Jerome Distribution Unattended 138 13.09 37
159 Julion Clawson Distribution Unattended 138 35 56
160 Joplin Distribution Unattended 138 13 28
161 Joplin Distribution Unattended 138 36.2 45
162 Justice Transmission Unattended 230 138 13.8 300
163 Karcher Distribution Unattended 138 13 20
164 Kenyon Distribution Unattended 69 13.09 28
165 Ketchum Distribution Unattended 138 13 75
166 Kimberly Distribution Unattended 138 13.09 45
167 Kinport Transmission Unattended 161 46 13.2
168 Kinport Transmission Unattended 230 138 12.47 300
169 Kinport Transmission Unattended 230 138 13.8 300
SUBSTATIONS
Character of Substation Character of Substation VOLTAGE (In MVa)VOLTAGE (In
MVa)VOLTAGE (In MVa)
Line
No.
Name and Location of Substation
(a)
Transmission or Distribution
(b)
Attended or Unattended
(b-1)
Primary Voltage (In MVa)
(c)
Secondary
Voltage (In MVa)
(d)
Tertiary Voltage (In
MVa)
(e)
Capacity
of
Substation
(In
Service)
(In MVa)
(f)
FERC FORM NO. 1 (ED. 12-96)
Page 426-427
170 (j)
Kinport Transmission Unattended 345 230 13.8 1000
171 Kramer Distribution Unattended 138 35 20
172 Kramer Distribution Unattended 138 36.2 30
173 Kuna Distribution Unattended 138 13.09 45
174 Lake Distribution Unattended 69 13 14
175 Lake Fork Distribution Unattended 138 36.2 30
176 Lake Fork Transmission Unattended 138 69 12.5 20
177 Lamb Distribution Unattended 138 13 30
178 Langley Gulch Transmission Attended 230 138 13.8 636
179 Langley Gulch Transmission Attended 230 410
180 Langley Gulch Transmission Attended 230 150
181 Lansing Distribution Unattended 138 13.09 45
182 Lincoln Distribution Unattended 138 13.09 14
183 Linden Distribution Unattended 138 13 58
184 Locust Distribution Unattended 138 36.2 134
185 Locust Transmission Unattended 230 138 13.8 600
186 Lower Malad Transmission Attended 138 7.2 16
187 Lower Salmon Transmission Attended 138 13.8 70
188 Map Rock Distribution Unattended 69 13.09 14
189 McCall Distribution Unattended 138 13.09 22
190 McCall Distribution Unattended 138 36.2 30
191 Melba Distribution Unattended 69 13 11
192 Meridian Distribution Unattended 138 13 60
193 Micron Distribution Unattended 138 13.09 40
194 Micron Distribution Unattended 138 13 40
195 Midpoint Transmission Unattended 230 138 13.8 300
196 Midpoint Transmission Unattended 345 230 13.8 1400
197 (k)
Midpoint Transmission Unattended 500 345 1500
198 Midrose Distribution Unattended 138 13.09 45
199 Milner Transmission Unattended 138 69 12.47 125
200 Milner Distribution Unattended 69 46 6.9 8
201 Milner Distribution Unattended 138 35 50
202 Milner PP Transmission Attended 138 13.8 60
203 Moonstone Distribution Unattended 138 35 20
204 Mora Distribution Unattended 138 36.2 90
205 Moreland Distribution Unattended 46 36.2 28
206 Mountain Home Distribution Unattended 69 13 28
207 Mountain Home Air Force Base Distribution Unattended 69 13
208 Mountain Home Air Force Base Distribution Unattended 138 13 34
209 Nampa Transmission Unattended 230 138 13.8 300
210 Nampa Distribution Unattended 138 13 87
211 New Meadows Distribution Unattended 138 36.2 22
212 New Plymouth Distribution Unattended 69 13.09 14
213 Northview Distribution Unattended 138 13.09 45
214 Notch Butte Distribution Unattended 138 13.09 14
215 Orchard Distribution Unattended 138 36.2 45
216 Parma Distribution Unattended 69 13 14
217 Parma Distribution Unattended 69 35 22
218 Parma Distribution Unattended 69 36.2 14
219 Paul Distribution Unattended 138 35 30
220 Paul Distribution Unattended 138 36.2 45
221 Payette Distribution Unattended 138 13.09 45
222 Pingree Transmission Unattended 138 46 12.5 67
223 Pingree Distribution Unattended 138 35 34
224 Pleasant Valley Distribution Unattended 138 35 30
225 Pleasant Valley Distribution Unattended 138 36.2 45
226 Pocatello Distribution Unattended 46 13 60
SUBSTATIONS
Character of Substation Character of Substation VOLTAGE (In MVa)VOLTAGE (In
MVa)VOLTAGE (In MVa)
Line
No.
Name and Location of Substation
(a)
Transmission or Distribution
(b)
Attended or Unattended
(b-1)
Primary Voltage (In MVa)
(c)
Secondary
Voltage (In MVa)
(d)
Tertiary Voltage (In
MVa)
(e)
Capacity
of
Substation
(In
Service)
(In MVa)
(f)
FERC FORM NO. 1 (ED. 12-96)
Page 426-427
227 Pocket Distribution Unattended 138 36.2 45
228 Poleline Distribution Unattended 138 13.09 30
229 (l)
Populus Transmission Unattended 345
230 Portneuf Distribution Unattended 138 35 30
231 Portneuf Distribution Unattended 46 35
232 Rockford Distribution Unattended 46 13 25
233 Russett Distribution Unattended 138 13 30
234 Sailor Creek Distribution Unattended 138 2.4 21
235 Sailor Creek Distribution Unattended 138 35 28
236 Salmon Distribution Unattended 69 13.09 22
237 Salmon Distribution Unattended 69 36.2 22
238 Shoshone Distribution Unattended 46 13.09 14
239 Shoshone Transmission Unattended 138 46 12.47 47
240 Shoshone Falls Transmission Attended 46 4.16 4
241 Shoshone Falls Transmission Attended 46 6.6 14
242 Silver Distribution Unattended 138 35 20
243 Simplot Distribution Unattended 138 13 53
244 Sinker Creek Distribution Unattended 138 35 20
245 Siphon Distribution Unattended 138 36.2 75
246 Skyway Distribution Unattended 138 13.09 45
247 South Park Distribution Unattended 46 13 14
248 Spring Valley Distribution Unattended 138 12.47 11
249 Star Distribution Unattended 138 13.09 30
250 Starkey Transmission Unattended 138 69 12.47 30
251 State Distribution Unattended 69 13 58
252 Sterling Distribution Unattended 46 13 11
253 Stoddard Distribution Unattended 138 13 28
254 Strike Power Plant Transmission Attended 138 13.8 104
255 Sugar Distribution Unattended 138 35 28
256 Swan Falls Transmission Attended 138 6.9 34
257 Taber Distribution Unattended 46 13 6
258 Tamarack Distribution Unattended 138 2.4 11
259 Ten Mile Distribution Unattended 138 13.09 90
260 Terry Distribution Unattended 138 13.09 20
261 Terry Distribution Unattended 138 13 50
262 Thousand Springs Transmission Attended 46 7.2 8
263 (m)
Three Mile Knoll Transmission Unattended 345
264 Toponis Distribution Unattended 138 33 30
265 Twin Falls Distribution Unattended 138 13.09 82
266 Twin Falls Transmission Unattended 138 46 12.98 50
267 Twin Falls PP Transmission Attended 138 7.2 13
268 Twin Falls PP Transmission Attended 138 13.2 72
269 Tyhee Distribution Unattended 46 13 14
270 Upper Malad Transmission Attended 45 7.2 8
271 Upper Salmon Transmission Attended 138 7.2 42
272 Ustick Distribution Unattended 138 13 77
273 Vallivue Distribution Unattended 138 13.09 30
274 Victory Distribution Unattended 138 13 45
275 Victory Distribution Unattended 138 13.09 30
276 Ware Distribution Unattended 69 13 20
277 Weiser Distribution Unattended 69 13 28
278 Weiser Transmission Unattended 138 69 12.47 42
279 Wilder Distribution Unattended 69 13 14
280 Willis Distribution Unattended 138 13.09 30
281 Willow Creek Distribution Unattended 138 13 11
282 Wye Distribution Unattended 138 13 60
283 Wye Distribution Unattended 138 13.09 37
284 Zilog Distribution Unattended 138 13.09 45
SUBSTATIONS
Character of Substation Character of Substation VOLTAGE (In MVa)VOLTAGE (In
MVa)VOLTAGE (In MVa)
Line
No.
Name and Location of Substation
(a)
Transmission or Distribution
(b)
Attended or Unattended
(b-1)
Primary Voltage (In MVa)
(c)
Secondary
Voltage (In MVa)
(d)
Tertiary Voltage (In
MVa)
(e)
Capacity
of
Substation
(In
Service)
(In MVa)
(f)
FERC FORM NO. 1 (ED. 12-96)
Page 426-427
285 The above are all State of Idaho
286 Montana:
287 (n)
Mill Creek Transmission Unattended 230
288 Peterson Transmission Unattended 230 69 13.2 56
289 Nevada:
290 (o)
Valmy Transmission Attended 345 18 315
291 Wells Transmission Unattended 138 69 13 25
292 Oregon:
293 Adrian Distribution Unattended 69 13 11
294
(p)
Burns Transmission Unattended 500
295 Cairo Distribution Unattended 69 13 20
296 Hells Canyon Transmission Attended 230 13.8 560
297 Hells Canyon Distribution Attended 69 0.5 1
298 Hines Transmission Unattended 138 115 12.47 80
299 Holly Distribution Unattended 69 13.09 14
300 (q)
Hurricane Transmission Unattended 230
301 Jacobson Gulch Distribution Unattended 69 2.4 11
302 Malheur Butte Distribution Unattended 69 34.5 11
303 Nyssa Distribution Unattended 69 13 28
304 Ontario Distribution Unattended 138 13 67
305 Ontario Transmission Unattended 138 69 12.47 47
306 Ontario Transmission Unattended 230 138 13.8 400
307 Ontario Transmission Unattended 138 69 12.98 93
308 Ontario Transmission Unattended 138 69 13.09
309 Ontario Transmission Unattended 138 69 12.5
310 Ore-Ida Distribution Unattended 69 13 28
311 Oxbow Transmission Attended 138 69 13 13
312 Oxbow Transmission Attended 230 13.8 274
313 Oxbow Transmission Attended 230 138 13.8 100
314 Quartz Transmission Unattended 138 69 12.5 25
315 Quartz Transmission Unattended 230 138 12.98 167
316 Quartz Transmission Unattended 138 69 12.98 20
317 (r)
Summer Lake Transmission Unattended 500
318 Vale Distribution Unattended 69 13 14
319 Washington:
320 (s)
Walla Walla Transmission Unattended 230
321 Wyoming:
322 (t)
Jim Bridger Transmission Attended 345 22 34.5 2244
323 Transformers-under 10,000
324 KVA 58 unattended.Distribution Unattended 196
325 Distribution Substations 22,788 4,014.3 19.880000000000003 7,295
326 Distribution Substations Attended 140 22.62 0 17
327 Distribution Substations Unattended 22,648 3,991.68 19.880000000000003 7,278
328 Transmission Substations 19,893 7,483.26 881.8800000000002 22,572
329 Transmission Substations Attended 4,944 905.26 88.9 6,998
330 Transmission Substations Unattended 14,949 6,578 792.9800000000004 15,574
331 Total 29,867
FERC FORM NO. 1 (ED. 12-96)
Page 426-427
SUBSTATIONS
Character of Substation Character of Substation VOLTAGE (In MVa)VOLTAGE (In
MVa)VOLTAGE (In MVa)
Line
No.
Name and Location of Substation
(a)
Transmission or Distribution
(b)
Attended or Unattended
(b-1)
Primary Voltage (In MVa)
(c)
Secondary
Voltage (In MVa)
(d)
Tertiary Voltage (In
MVa)
(e)
Capacity
of
Substation
(In
Service)
(In MVa)
(f)
SUBSTATIONS
Conversion Apparatus and Special Equipment Conversion Apparatus and Special
Equipment
Conversion Apparatus and Special
Equipment
Line
No.
Number of Transformers In Service
(g)
Number of Spare Transformers
(h)
Type of Equipment
(i)
Number of Units
(j)
Total Capacity (In MVa)
(k)
1 2
2 2
3 1
4 1
5 1
6 1
7 1
8 1
9 1
10 1
11 1
12 1
13 1
14 1
15 1
16
17 2
18 1
19 2
20 3 1
21 1
22 3
23 2
24 2
25 1
26 3
27 2
28 1
29 3
30 3 1
31 1
32 3
33 1
34 1
35 1
36 1
37 2
38 3
39 1
40 5
41 2
42 5 1
43 1
44 1
45 1
46 1
47 1
48 1
49 2
50 1
51 1
52 1
53 3
54 1
55 3 1
56 3 1
57 1
58 1
59 1
60 1
61 1
FERC FORM NO. 1 (ED. 12-96)
Page 426-427
62 1
63 1
64 1
65 1
66 1
67 1
68 1
69 2 1
70 1
71 2
72 1
73 1
74 1
75 1
76 1
77 1
78 1
79 7
80 1
81 2
82 1
83 1
84 1
85 1
86 2
87 1
88 1
89 1
90 1
91 6 1
92 1
93 6
94 2
95 1
96 1
97 2
98 2
99 2
100 1
101 1
102 1
103 1
104 1
105 1
106 1
107 1
108 1
109 1
110 1
111 1
112 2
113 1
114 1
115 1
116 2
117 1 1
118 1
119 3 1
120 1
121 1
122 1
SUBSTATIONS
Conversion Apparatus and Special Equipment Conversion Apparatus and Special
Equipment
Conversion Apparatus and Special
Equipment
Line
No.
Number of Transformers In Service
(g)
Number of Spare Transformers
(h)
Type of Equipment
(i)
Number of Units
(j)
Total Capacity (In MVa)
(k)
FERC FORM NO. 1 (ED. 12-96)
Page 426-427
123 1
124 2
125 1
126 2
127 1 1
128 5
129 1
130 1
131 2
132 2
133 1
134 1
135 1
136 1
137 1
138 1
139 1
140 3 1
141 1
142 1
143 1
144 2
145 1
146 2
147 1
148 1
149 1
150 1
151 1
152 1
153 3
154 2
155 1
156
157 1
158 1
159 2
160 1
161 1
162 1
163 1
164 2
165 2
166 1
167 7
168 1
169 1
170 3 1
171 1
172 1
173 1
174 1
175 1
176 1
177 1
178 2
179 2
180 1
181 1
182 1
183 2
SUBSTATIONS
Conversion Apparatus and Special Equipment Conversion Apparatus and Special
Equipment
Conversion Apparatus and Special
Equipment
Line
No.
Number of Transformers In Service
(g)
Number of Spare Transformers
(h)
Type of Equipment
(i)
Number of Units
(j)
Total Capacity (In MVa)
(k)
FERC FORM NO. 1 (ED. 12-96)
Page 426-427
184 3
185 2
186 1
187 4
188 1
189 1
190 1
191 1
192 2
193 2
194 2
195 1 1
196 2 1
197 3
198 1
199 3 1
200 3 1
201 2
202 1
203 1
204 2
205 2
206 1
207 1
208 1
209 1
210 3
211 1
212 1
213 1
214 1
215 1
216 1
217 1
218 1
219 1 1
220 1
221 1
222 3
223 2
224 1
225 1
226 2
227 1
228 1
229
230 1
231 1
232 2
233 1
234 2
235 1
236 1
237 1
238 1
239 1
240 1
241 1
242 1
243 2
244 1
SUBSTATIONS
Conversion Apparatus and Special Equipment Conversion Apparatus and Special
Equipment
Conversion Apparatus and Special
Equipment
Line
No.
Number of Transformers In Service
(g)
Number of Spare Transformers
(h)
Type of Equipment
(i)
Number of Units
(j)
Total Capacity (In MVa)
(k)
FERC FORM NO. 1 (ED. 12-96)
Page 426-427
245 2
246 1
247 1
248 1
249 1
250 1
251 2
252 2
253 1
254 3
255 2
256 1
257 1
258 1
259 2
260 1
261 2
262 1
263
264 1
265 2
266 2
267 1
268 1
269 1
270 1
271 4
272 2
273 1
274 1
275 1
276 1 1
277 2
278 1
279 1
280 1
281 1
282 2
283 1
284 1
285
286
287
288 1 1
289
290 1
291 3 1
292
293 1
294
295 1
296 3
297 1
298 1 1
299 1
300
301 1
302 3 1
303 2
304 2 1
305 1
SUBSTATIONS
Conversion Apparatus and Special Equipment Conversion Apparatus and Special
Equipment
Conversion Apparatus and Special
Equipment
Line
No.
Number of Transformers In Service
(g)
Number of Spare Transformers
(h)
Type of Equipment
(i)
Number of Units
(j)
Total Capacity (In MVa)
(k)
FERC FORM NO. 1 (ED. 12-96)
Page 426-427
306 2
307 2
308 1
309 1
310 1
311 3 1
312 2
313 1
314 1
315 3 1
316 1
317
318 1
319
320
321
322 4
323
324
325 277 31 0 0
326 4 0 0 0
327 273 31 0 0
328 155 26 0 0
329 54 3 0 0
330 101 23 0 0
331
FERC FORM NO. 1 (ED. 12-96)
Page 426-427
SUBSTATIONS
Conversion Apparatus and Special Equipment Conversion Apparatus and Special
Equipment
Conversion Apparatus and Special
Equipment
Line
No.
Number of Transformers In Service
(g)
Number of Spare Transformers
(h)
Type of Equipment
(i)
Number of Units
(j)
Total Capacity (In MVa)
(k)
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
FOOTNOTE DATA
(a) Concept: SubstationNameAndLocation
PacifiCorp has an ownership interest in certain high-voltage transmission related and interconnection equipment located at Idaho Power's Adelaide station. Ownership interest varies by terminal. 100% of the capacity is reported.
(b) Concept: SubstationNameAndLocation
Idaho Power has an ownership interest in certain high-voltage transmission related and interconnection equipment located at PacifiCorp's Antelope station. Ownership interest varies by terminal. 100% of the capacity is reported.
(c) Concept: SubstationNameAndLocation
Jointly owned with PacifiCorp, Idaho Power has 66.7% share of ownership. 100% of the capacity is reported.
(d) Concept: SubstationNameAndLocation
Jointly owned with PacifiCorp, Idaho Power has 66.7% share of ownership. 100% of the capacity is reported.
(e) Concept: SubstationNameAndLocation
Idaho Power has an ownership interest in certain high-voltage transmission related and interconnection equipment located at PacifiCorp's Big Grassy station. Ownership interest varies by terminal.
(f) Concept: SubstationNameAndLocation
PacifiCorp has an ownership interest in certain high-voltage transmission related and interconnection equipment located at Idaho Power's Borah station. Ownership interest varies by terminal. 100% of the capacity is reported.
(g) Concept: SubstationNameAndLocation
Idaho Power has an ownership interest in certain high-voltage transmission related and interconnection equipment located at PacifiCorp's Goshen station. Ownership interest varies by terminal. 100% of the capacity is reported.
(h) Concept: SubstationNameAndLocation
PacifiCorp has an ownership interest in certain high-voltage transmission related and interconnection equipment located at Idaho Power's Hemingway station. Ownership interest varies by terminal. 100% of the capacity is reported.
(i) Concept: SubstationNameAndLocation
Idaho Power has an ownership interest in certain high-voltage transmission related and interconnection equipment located at PacifiCorp's Jefferson station. Ownership interest varies by terminal.
(j) Concept: SubstationNameAndLocation
PacifiCorp has an ownership interest in certain high-voltage transmission related and interconnection equipment located at Idaho Power's Kinport station. Ownership interest varies by terminal. 100% of the capacity is reported.
(k) Concept: SubstationNameAndLocation
PacifiCorp has an ownership interest in certain high-voltage transmission related and interconnection equipment located at Idaho Power's Midpoint station. Ownership interest varies by terminal. 100% of the capacity is reported.
(l) Concept: SubstationNameAndLocation
Idaho Power has an ownership interest in certain high-voltage transmission related and interconnection equipment located at PacifiCorp's Populus station. Ownership interest varies by terminal.
(m) Concept: SubstationNameAndLocation
Idaho Power has an ownership interest in certain high-voltage transmission related and interconnection equipment located at PacifiCorp's Three Mile Knoll station. Ownership interest varies by terminal.
(n) Concept: SubstationNameAndLocation
Idaho Power has 32% ownership in certain transmission related equipment located at Northwestern Energy's Mill Creek Station.
(o) Concept: SubstationNameAndLocation
Jointly owned with Sierra Pacific Power Company, d/b/a NV Energy. Idaho Power has a 50% share of ownership. 100% of the capacity reported.
(p) Concept: SubstationNameAndLocation
Idaho Power has a 22% ownership interest in certain high-voltage transmission related and interconnection equipment located at PacifiCorp's Burns station.
(q) Concept: SubstationNameAndLocation
Idaho Power has an ownership interest in certain high-voltage transmission related and interconnection equipment located at PacifiCorp's Hurricane station. Ownership interest varies by terminal.
(r) Concept: SubstationNameAndLocation
Idaho Power has an ownership interest in certain high-voltage transmission related and interconnection equipment located at PacifiCorp's Summer Lake station. Ownership interest varies by terminal.
(s) Concept: SubstationNameAndLocation
Idaho Power has an ownership interest in certain high-voltage transmission related and interconnection equipment located at PacifiCorp's Walla Walla station. Ownership interest varies by terminal.
(t) Concept: SubstationNameAndLocation
Jointly owned with PacifiCorp. Idaho Power has a 33.3% share of ownership. 100% of the capacity is reported.
(u) Concept: PrimaryVoltageLevel
For all of column c: Primary voltages reported in KV unless otherwise noted.
(v) Concept: SecondaryVoltageLevel
For all of column d: Secondary voltages reported in KV unless otherwise noted.
(w) Concept: TertiaryVoltageLevel
For all of column e: Tertiary voltages reported in KV unless otherwise noted.
(x) Concept: SubstationInServiceCapacity
For all of column f: Top rating capacity reported unless otherwise noted.
FERC FORM NO. 1 (ED. 12-96)
Page 426-427
Name of Respondent:
Idaho Power Company
This report is:
(1) ☑ An Original
(2) ☐ A Resubmission
Date of Report:
04/13/2023
Year/Period of Report
End of: 2022/ Q4
TRANSACTIONS WITH ASSOCIATED (AFFILIATED) COMPANIES
Line
No.
Description of the Good or Service
(a)
Name of Associated/Affiliated Company
(b)
Account(s) Charged or
Credited
(c)
Amount Charged or Credited
(d)
1 Non-power Goods or Services Provided by Affiliated
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20 Non-power Goods or Services Provided for Affiliated
21 Managerial Expenses 417420 IDACORP, INC.417420 535,732
22 Managerial Expenses 922000 IDACORP, INC.922000 31,181
42
FERC FORM NO. 1 ((NEW))
Page 429
December 31, 2022
ANNUAL REPORT
IDAHO SUPPLEMENT TO FERC FORM 1
MULTI-STATE ELECTRIC COMPANIES
INDEX
Page
Number Title
1 Statement of Income for the Year
2 Taxes Allocated to Idaho
3 Notes and Accounts Receivable
3 Accumulated Provision for Uncollectible Accounts
4 Receivables from Associated Companies
5 Gain or Loss on Disposition of Property
6 Professional or Consultative Services
7-10 Electric Plant in Service
11 Electric Operating Revenues
12-15 Electric Operation and Maintenance Expenses
15 Number of Electric Department Employees
IDAHO SUPPLEMENT
December 31, 2022
STATEMENT OF INCOME FOR THE YEAR
1. Report amounts for accounts 412 and 413, Revenue and Expenses from Utility Plant Leased to Others, in another utility
column (i,k,m,o) in a similar manner to a utility department. Spread the amount(s) over lines 01 thru 24 as appropriate.
Include these amounts in columns (c) and (d) totals.
2. Report amounts in account 414, Other Utility Operating Income, in the same manner as accounts 412 and 413 above.
3. Report data for lines 7, 9, and 10 for Natural Gas companies using accounts 404.1, 404.2, 404.3, 407.1, and 407.2.
4. Use page 122 for important notes regarding the state ment of income or any account thereof.
5. Give concise explanations concerning unsettled rate proceedings where a contingency exists such that refunds of a
material amount may need to be made to the utility's customers or which may result in 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.
(Ref.)
Line Account Page TOTAL
No.No.Current Year Previous Year
(a)(b)(c)(d)
1 UTILITY OPERATING INCOME
2 Operating Revenues (400).................................................................................................................................................................xxx111,565,702,981$ 1,388,475,677$
3 Operating Expenses
4 Operation Expenses (401)...............................................................................................................................................................xxx15972,301,086 807,748,455
5 Maintenance Expenses (402).................................................................................................................................................................xxx1577,797,062 64,276,452
6 Depreciation Expense (403)..............................................................................................................................................................xxx156,731,590 158,708,540
7 Amort. & Depl. of Utility Plant (404-405)...............................................................................................................................................xxx4,651,348 8,153,605
8 Amort. of Utility Plant Acq. Adj. (406)...............................................................................................................................................xxx
9 Amort. of Property Losses, Unrecovered Plant and
10 Accretion Expense (411).........................................................................26,077 54,557
11 Regulatory Study Costs (407).........................................................................................................................................................xxx
12 Amort. of Conversion Expenses (407)...................................................................................................................................................xxx
13 Regulatory Debits/Credits (407.3 & 407.4)...................................................................................................................................................................................xxx1,450,259 1,219,115
14 Taxes Other Than Income Taxes (408.1)..................................................................................................................................................xxx226,463,412 28,778,496
15 Income Taxes - Federal (409.1).........................................................................................................................................................xxx231,277,584 34,389,338
16 - Other (409.1)...........................................................................................................................................................xxx211,523,183 13,053,377
17 Provision for Deferred Income Taxes (410.1 & 411.1) Net…………………………………………..2 (9,982,999)(20,863,440)
18 Investment Tax Credit Adj. - Net (411.4).................................................................................................................................................xxx25,576,962 11,353,062
19 (Less) Gains from Disp. of Utility Plant (411.6).........................................................................................................................................xxx
20 Losses from Disp. of Utility Plant (411.7)..............................................................................................................................................xxx
21 (Less) Gains from Disposition of Allowances (411.8).....................................................................................................................................................xxx
22 Losses from Disposition of Allowances (411.9).....................................................................................................................................................xxx
23
24 TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 22)....................................................................................................................xxx1,277,815,564 1,106,871,556
25
26
27 Net Utility Operating Income (Enter Total of line 2 less 24)………………….287,887,417$ 281,604,122$
IDAHO SUPPLEMENT Page 1
December 31, 2022
TAXES ALLOCATED TO IDAHO
Taxes Charged
Kind of Tax During Year
Taxes Other Than Income Taxes:
Labor Related:
FICA..................................................................................................................................................xxx17,425,018$
FUTA..................................................................................................................................................xxx90,220$
State Unemployment....................................................................................................................................xxx233,885
Payroll Deduction & Loading....................(17,749,123)
Total Labor Related......................................................................................................................................xxx0
Property Taxes...........................................................................................................................................xxx22,723,241
Kilowatt-hour Tax........................................................................................................................................xxx939,618
Licenses.................................................................................................................................................xxx4,070
Regulatory Commission Fees...............................................................................................................................xxx2,616,251
Irrigation PIC...........................................................................................................................................xxx180,233
Canada Sales Tax...........................................................................................................................................xxx0
Total Taxes Other Than Income Taxes........................................................................................................................xxx26,463,412
Federal Income Taxes.......................................................................................................................................xxx31,277,584
State Income Taxes.........................................................................................................................................xxx11,523,183
Deferred Income Taxes......................................................................................................................................xxx(9,982,999)
Investment Tax Credit Adjustment - Net.....................................................................................................................xxx5,576,962
Total Taxes Allocated to Idaho.............................................................................................................................xxx64,858,141$
IDAHO SUPPLEMENT Page 2
December 31, 2022
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)
Balance Balance
Line Accounts Beginning of End of
Year Year
No. (a)(b)(c)
1 Notes Receivable (Account 141)....................................................................................................................................................xxx-$ -$
2 Customer Accounts Receivable (Account 142)........................................................................................................................................xxx83,325,175 119,228,349
3 Other Accounts Receivable (Account 143)...........................................................................................................................................xxx12,806,869 46,115,478
4 (Disclose any capital stock subscription received)
5 Total......................................................................................................................................96,132,043$ 165,343,827$
6
7 Less: Accumulated Provision for Uncollectible
8 Accounts-Cr. (Account 144)..............................................................................5,015,917 5,545,578
9
10 Total, Less Accumulated Provision for
11 Uncollectible Accounts.....................................................................................................................................................xxx91,116,126$ 159,798,248$
12
13
14
15
16
17
18
19
20
ACCUMULATED PROVISION FOR UNCOLLECTIBLE ACCOUNTS - CR. (Account 144)
1. Report below the information called for concerning this accumulated provision.
2. Explain any important adjustments of subaccounts.
3. Entries with respect to officers and employees shall not include items for utility services.
Mdse,
Line Item Utility Jobbing &Officers Other Total
Customers Contract and
No.(a)Work Employees
(b)(c)(d)(e)(f)
21 Balance Beg of Year:5,015,917$ 5,015,917$
22 -$
23 Uncollectible Retail Electric Sales 534,663 $ $ 534,663$
24
25 Uncollectible Damage Claims (5,002)(5,002)$
26
27 Uncollectibe Other Revenues --$
28
29
30
31
32 Balance end of year........................................................................................................................xxx5,545,578$ -$ -$ -$ 5,545,578$
33
IDAHO SUPPLEMENT Page 3
December 31, 2022
RECEIVABLES FROM ASSOCIATED COMPANIES (Accounts 145, 146)
1. Report particulars of notes and accounts receivable from associated companies at end of year.
2. Provide separate headings and totals for accounts 145, Notes Receivable from Associated Companies, and 146,
Accounts Receivable from Associated Companies, in addition to a total for the combined accounts.
3. For notes 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. If any note was received in satisfaction of an open account, state the period covered by such open account.
5. Include 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.
Balance
Line Particulars Beginning Totals for Year Balance Interest
of Year Debits Credits End of Year For Year
No.(a)(b)(c)(d)(e)(f)
1 Account 145:
2
3 IERCO……………………….6,169,545$ 45,476,797$ 37,143,585$ 14,502,758$
4
5
6
7
8
9
10 Total Account 145………………..10,088,722 45,476,797 37,143,585 14,502,758
11
12 Account 146:
13
14
15
16 IDACORP, Inc……………….-$ 4,651,759$ 4,651,759$ -$
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31 Total Account 146.....................................................................................................................xxx-$ 4,651,759$ 4,651,759$ -$
32
IDAHO SUPPLEMENT Page 4
December 31, 2022
STATE OF IDAHO - TOTAL SYSTEM DATA
GAIN OR LOSS ON DISPOSITION OF PROPERTY (Account 421.1 and 421.2)
1. Give a brief description of property creating the gain or loss. Include name of party acquiring the property (when
acquired by another utility or associated company) and the date transaction was completed. Identify property
by type; Leased, Held for Future Use, or Nonutility.
2. Individual gains or losses relating to property with an original cost of less than $50,000 may be grouped, with the
number of such transactions disclosed in column (a).
3. Give the date of Commission approval of journal entries in column (b), when approval is required. Where approval
is required but has not been received, give explanation following the item in column (a). (See account 102, Utility
Plant Purchased or Sold.)
Original Cost Date Journal
Line Description of Property of Related Entry Approved Acct 421.1 Acct 421.2
(When Required)
No.(a)(b)(c)(d)(e)
1 Gain on disposition of property
2 property: -$ -$ $
3
4 Hells Canyon Power Plant - Wallowa, Oregon 3,080.00$ (62,312.36)$
5 partial land disposal to US Forest Service
6
7
8
9
10
11
12
13
14
15
16 Total gain....................................................................................................................................................xxx3,080.00$ (62,312.36)$ -$
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31 Total loss......................................................................................................................................................xxx0$ 0$ 0$
IDAHO SUPPLEMENT Page 5
December 31, 2022
STATE OF IDAHO - TOTAL SYSTEM DATA
PROFESSIONAL OR CONSULTATIVE SERVICES - ITEMS $10,000 AND OVER
Line PAYEE SERVICE TYPE Amount
No.(a)(b)(c)
1 ACCENTURE LLP IT Services 18,750.00
2 ADAMS COUNTY SHERIFF'S OFFICE Management Services 15,000.00
3 ADM ASSOCIATES INC Energy Management Consulting 116,303.25
4 AGREE TECHNOLOGIES AND SOLUTIO IT Services 30,678.50
5 APPLIED ENERGY GROUP Energy Management Consulting 188,802.50
6 AUTOSORT Management Services 44,358.58
7 BAKER BOTTS LLP Legal Services 1,147,939.90
8 BARKER, ROSHOLT & SIMPSON LLP Legal Services 214,516.01
9 BROWN AND CALDWELL Legal Services 81,748.25
10 CASCADE ENERGY INC Energy Management Consulting 597,437.90
11 CLEAN HARBORS ENVIRONMENTAL SE Environmental Services 10,187.58
12 COMPUNET, INC Legal Services 63,243.75
13 DNV ENERGY SERVICES USA INC Management Services 1,316,527.45
14 DONNELLEY FINANCIAL SOLUTIONS Risk and Compliance Software 17,425.00
15 EQ SHAREOWNER SERVICES Management Services 95,445.16
16 EVERGREEN CONSULTING GROUP, LL Management Services 381,758.54
17 EXPONENT, INC Management Services 13,013.50
18 EXPRESS SERVICES INC Staffing Services 81,451.41
19 FRESHWATER TRUST, THE Environmental Services 382,762.66
20 GIVENS PURSLEY LLP Legal Services 51,567.79
21 HAWLEY TROXELL ENNIS & HAWLEY Legal Services 23,982.40
22 HDR ENGINEERING, INC Engineering Consultants 37,493.95
23 HOLLAND & HART LLP Legal Services 27,776.50
24 ICEBERG NETWORKS CORPORATION IT Services 40,348.75
25 IDAHO EFFICIENCY SOLUTIONS Energy Management Consulting 11,888.28
26 J J KELLER & ASSOCIATES I Legal Services 10,000.00
27 JACKSON LEWIS PC Legal Services 19,504.00
28 KIRTON MCCONKIE Legal Services 183,498.73
29 KW ENGINEERING INC Engineering Consultants 90,659.43
30 LUMEN TECHNOLOGIES GROUP IT Services 30,240.00
31 MARSH USA INC Insurance 31,097.33
32 MCDOWELL RACKNER & GIBSON PC Legal Services 2,259,786.83
33 MEDIANT COMMUNICATIONS INC Management Services 37,131.39
34 MORROW & FISCHER PLLC Legal Services 23,457.15
35 NATIONAL ECONOMIC RESEARCH ASSOCIATES Management Services 28,818.75
36 NEEA EVALUATION Energy Management Consulting 20,403.75
37 NEI ELECTRIC POWER ENGINEERING Engineering Consultants 44,640.00
38 NIELSEN GROUP INC, THE IT Services 30,197.85
39 NORTHWEST TOWER ENGINEERING PL Engineering Consultants 10,000.00
40 OPTIV SECURITY INC Security Consultants 99,202.50
41 PARSONS BEHLE & LATIMER Legal Services 80,234.00
42 PERKINS COIE LLP Legal Services 670,830.25
43 PRODUCTIVE ENERGY SOLUTIONS LLC Energy Management Consulting 10,158.97
44 PROFESSIONAL INSPECTION SERVICES Inspection Services 20,547.54
Page 6
IDAHO SUPPLEMENT
December 31, 2022
STATE OF IDAHO - TOTAL SYSTEM DATA
PROFESSIONAL OR CONSULTATIVE SERVICES - ITEMS $10,000 AND OVER
Line PAYEE SERVICE TYPE Amount
No.(a)(b)(c)
45 QUINTEL-MC INC Management Services 138,663.88
46 RAPID RESPONSE SYSTEMS Training Services 13,911.00
47 RM ENERGY CONSULTING Energy Management Consulting 147,885.93
48 ROCK CREEK ENERGY GROUP LLP Legal Services 74,288.20
49 SOVOS COMPLIANCE LLC IT Services 16,207.50
50 STANLEY ASSOCIATES, INC IT Services 14,950.00
51 STOEL RIVES LLP Legal Services 78,515.71
52 STRATEGIC ENERGY GROUP Energy Management Consulting 96,192.50
53 TETRA TECH INC Consulting Services 139,695.50
54 TINKER LLC Energy Management Consulting 13,447.60
55 TUCKER, JAMES C Consulting Services 36,767.50
56 UNIVERSITY OF IDAHO Management Services 244,674.21
57 VAN NESS FELDMAN LLP Legal Services 179,547.43
58 WINNER MANAGEMENT INC Property Management 13,508.00
59 WITHERSPOON KELLEY Legal Services 12,725.00
60 YTURRI& ROSE& BURNHAM& BENTZ Management Services 192,121.43
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
81
82
83
TOTAL 10,123,917$
Page 6A
IDAHO SUPPLEMENT
December 31, 2022
PROFESSIONAL OR CONSULTATIVE SERVICES
ITEMS $5,000 OR MORE BUT LESS THAN $10,000
Line PREDOMINANT
No.PAYEE NATURE OF SERVICE AMOUNT
1 ACCRUENT LLC IT Services 8,858
2 AVTEC INC IT Services 9,143
3 CCRCORP Legal Services 6,565
4 CLARK WARDLE LLP Legal Services 6,982
5 CORPORATE OFFICE INSTALLATIONS Property Management Services 7,660
6 CUSTER AGENCY, INC Security Services 7,206
7 DAVIS WRIGHT TREMAINE LLP Legal Services 8,890
8 GREENBACK HOME SOLUTIONS LLC Property Management Services 5,600
9 IDAHO EMPLOYMENT LAWYERS, PLLC Legal Services 8,020
10 ITRON, INC.IT Services 6,050
11 JENSEN HUGHES Security Services 7,866
12 MARNE AND ASSOCIATES Training Services 6,124
13 MUSCROVE ENGINEERING PA Engineering Services 6,314
14 PROFESSIONAL TRAINING SYSTEMS Training Services 5,992
15 SPATIAL BUSINESS SYSTEMS INC Infrastructure Consulting 8,800.00
16 TUIT PROJECTS, LLC IT Services 6,786.00
17 WOOD SCIENCE CONSULTING Management Services 7,238.78
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43 TOTAL 124,094$
IDAHO SUPPLEMENT Page 6B
December 31, 2022
ELECTRIC PLANT IN SERVICE (Accounts 101, 102, 103 and 106)
1. Report below the original cost of electric plant in service according to the prescribed accounts.
2. In addition to Account 101, Electric Plant in Service (Classified), this page and the next include Account 102, Electric Plant
Purchased or Sold; Account 103, Experimental Electric Plant Unclassified; and Account 106, Completed Construction
Not Classified - Electric.
3. Include in column (c) or (d), as appropriate, corrections of additions and retirements for the current or preceding year.
4. Enclose in parentheses credit adjustments of plant accounts to indicate the negative effect of such accounts.
5. Classify Account 106 according to prescribed accounts, on an estimated basis if necessary, and include the entries in
column (c) . Also to be included in column (c) are entries for reversals of tentative distributions of prior year reported in
column (b). Likewise, if the respondent has a significant amount of plant retirements the end of the year, include in
column (d) a tentative distribution of such retirements, on an estimated basis, with appropriate contra entry to the account
for accumulated depreciation provision. Include also in column (d) reversals of tentative distributions of prior year of un-
classified retirements. Attach supplemental statement showing 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 of the above instructions and the texts of Accounts 101 and 106 will avoid serious omissions of the reported amount
of respondent's plant actually in service at end of year.
Line Account Beginning of year Additions
No.(a)(b)(c)
1 1. INTANGIBLE PLANT
2 (301) Organization......................................................................................................................................................xxx5,472$
3 (302) Franchises and Consents...........................................................................................................................................xxx36,559,366
4 (303) Miscellaneous Intangible Plant...................................................................................................................................xxx42,707,437
5 TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4)...............................................................................................................xxx73,195,198
6 2. PRODUCTION PLANT
7 A. Steam Production Plant
8 (310) Land and Land Rights..............................................................................................................................................xxx
9 (311) Structures and Improvements.......................................................................................................................................xxx
10 (312) Boiler Plant Equipment...........................................................................................................................................xxx
11 (313) Engines and Engine Driven Generators..............................................................................................................................xxx
12 (314) Turbogenerator Units......................................................................................................................................................xxx
13 (315) Accessory Electric Equipment...........................................................................................................................................xxx
14 (316) Misc. Power Plant Equipment......................................................................................................................................xxx
15 (317) Asset Retirement Costs for Steam Production……………… …………………..25,482,471
16 TOTAL Steam Production Plant (Enter Total of lines 8 thru 15).....................................................................................................................xxx970,930,307
17 B. Nuclear Production Plant
18 (320) Land and Land Rights.............................................................................................................................................xxx
19 (321) Structures and Improvements.......................................................................................................................................xxx
20 (322) Reactor Plant Equipment...........................................................................................................................................xxx
21 (323) Turbogenerator Units...............................................................................................................................................xxx
22 (324) Accessory Electric Equipment.......................................................................................................................................xxx
23 (325) Misc. Power Plant Equipment......................................................................................................................................xxx
24 (326) Asset Retirement Costs for Nuclear Production………………..…………………
25 TOTAL Nuclear Production Plant (Enter Total of lines 17 thru 24)...............................................................................................................xxx
26 C. Hydraulic Production Plant
27 (330) Land and Land Rights...............................................................................................................................................xxx
28
29 (332) Reservoirs, Dams, and Waterways....................................................................................................................................xxx
30 (333) Water Wheels, Turbines, and Generators...............................................................................................................................xxx
31 (334) Accessory Electric Equipment.....................................................................................................................................xxx
32 (335) Misc. Power Plant Equipment......................................................................................................................................xxx
33 (336) Roads, Railroads, and Bridges....................................................................................................................................xxx
34 (337) Asset Retirement Costs for Hydraulic Production………………..…………………
35 TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34).....................................................................................................xxx990,128,902
36 D. Other Production Plant
37 (340) Land and Land Rights.............................................................................................................................................xxx
38 (341) Structures and Improvements......................................................................................................................................xxx
39 (342) Fuel Holders, Products and Accessories............................................................................................................................xxx
40 (343) Prime Movers.....................................................................................................................................................xxx
41 (344) Generators........................................................................................................................................................xxx
42 (345) Accessory Electric Equipment.......................................................................................................................................xxx
43 (346) Misc Power Plant Equipment.......................................................................................................................................xxx
Page 7IDAHO SUPPLEMENT
December 31, 2022
Show in column (f) reclassifications or transfers within utility plant accounts. Include also in column
(f) the additions or reductions of primary account classifications arising from distribution of amounts
initially recorded in Account 102. In showing the clearance of Account 102, include in column (e) the
amounts with respect to accumulated provision for depreciation, acquisition adjustments, etc., and show
in column (f) only the offset to the debits or credits distributed in column (f) to primary account classifications.
For Account 399, state the nature and use of plant included in this account and if substantial in amount
submit a supplementary statement showing subaccount classification of such plant conforming to the
requirements of these pages.
For each amount comprising the reported balance and changes in Account 102, state the property purchased
or sold, name of vendor or purchaser, and date of transaction. If proposed journal entries have been filed
with the Commission as required by the Uniform System of Accounts, give also date of such filing.
Retirements Adjustments Transfers End of Year Line
(d)(e) (f) (g)No.
1
5,459$ (301)2
49,203,660 (302)3
48,832,992 (303)4
98,042,111 5
6
7
(310)8
(311)9
(312)10
(313)11
(314)12
(315)13
(316)14
27,102,602 (317)15
978,629,853 16
17
(320)18
(321)19
(322)20
(323)21
(324)22
(325)23
(326)24
25
26
(330)27
(331)28
(332)29
(333)30
(334)31
(335)32
(336)33
(337)34
1,029,335,681 35
36
(340)37
(341)38
(342)39
(343)40
(344)41
(345)42
(345)43
ELECTRIC PLANT IN SERVICE (Accounts 101, 102, 103 and 106) (Continued)
Page 8IDAHO SUPPLEMENT
December 31, 2022
ELECTRIC PLANT IN SERVICE (Accounts 101, 102, 103 and 106) (Continued)
Line Balance at
Account Beginning of year Additions
No.(a) (b)(c)
44 (346) Misc. Power Plant Equipment.....................................................................................................................................xxx
45 TOTAL Other Production Plant (Enter Total of lines 37 thru 44)..........................................................................................................xxx532,713,240$
46 TOTAL Production Plant (Enter Total of lines 16, 25, 35, and 45)..............................................................................................................xxx2,493,772,449
47 3. TRANSMISSION PLANT
48 (350) Land and Land Rights..............................................................................................................................................xxx38,038,072
49 (352) Structures and Improvements........................................................................................................................................xxx83,986,744
50 (353) Station Equipment..................................................................................................................................................xxx451,357,571
51 (354) Towers and Fixtures................................................................................................................................................xxx222,111,189
52 (355) Poles and Fixtures..................................................................................................................................................xxx215,197,387
53 (356) Overhead Conductors and Devices......................................................................................................................................xxx245,813,303
54 (357) Underground Conduit...................................................................................................................................................xxx
55 (358) Underground Conductors and Devices.................................................................................................................................xxx
56 (359) Roads and Trails..................................................................................................................................................xxx374,713
57 (359.1) Asset Retirement Costs for Transmission Plant………………..…………………
58 TOTAL Transmission Plant (Enter Total of lines 48 thru 57).............................................................................................................xxx1,256,878,979
59 4. DISTRIBUTION PLANT
60 (360) Land and Land Rights................................................................................................................................................xxx7,640,364
61 (361) Structures and Improvements........................................................................................................................................xxx49,536,165
62 (362) Station Equipment...................................................................................................................................................xxx288,442,652
63 (363) Storage Battery Equipment...........................................................................................................................................xxx
64 (364) Poles, Towers, and Fixtures.......................................................................................................................................xxx282,980,841
65 (365) Overhead Conductors and Devices.........................................................................................................................................xxx143,391,424
66 (366) Underground Conduit.................................................................................................................................................xxx52,525,989
67 (367) Underground Conductors and Devices....................................................................................................................................xxx308,886,276
68 (368) Line Transformers....................................................................................................................................................xxx658,856,816
69 (369) Services.............................................................................................................................................................xxx63,794,607
70 (370) Meters..............................................................................................................................................................xxx106,387,667
71 (371) Installations on Customer Premises................................................................................................................................xxx4,953,808
72 (372) Leased Property on Customer Premises................................................................................................................................xxx
73 (373) Street Lighting and Signal Systems.................................................................................................................................xxx5,320,596
74 (374) Asset Retirement Costs for Distribution Plant………………..…………………
75 TOTAL Distribution Plant (Enter Total of lines 60 thru 74)...................................................................................................................xxx1,972,717,206
76 5. GENERAL PLANT
77 (389) Land and Land Rights..................................................................................................................................................xxx19,851,492
78 (390) Structures and Improvements...........................................................................................................................................xxx135,415,417
79 (391) Office Furniture and Equipment........................................................................................................................................xxx41,259,844
80 (392) Transportation Equipment..............................................................................................................................................xxx104,860,168
81 (393) Stores Equipment......................................................................................................................................................xxx4,105,787
82 (394) Tools, Shop, and Garage Equipment....................................................................................................................................xxx11,855,992
83 (395) Laboratory Equipment................................................................................................................................................xxx14,180,032
84 (396) Power Operated Equipment...........................................................................................................................................xxx22,957,093
85 (397) Communication Equipment...............................................................................................................................................xxx78,043,602
86 (398) Miscellaneous Equipment.............................................................................................................................................xxx9,795,834
87 SUBTOTAL (Enter Total of lines 77 thru 86)..........................................................................................................................xxx442,325,261
88 (399) Other Tangible Property...........................................................................................................................................xxx
89 (399.1) Asset Retirement Costs for General Plant………………..…………………
90 TOTAL General Plant (Enter Total of lines 87, 88 and 89)....................................................................................................................xxx442,325,261
91 TOTAL (Accounts 101 and 106)....................................................................................................................................xxx6,244,966,169
92 (102) Electric Plant Purchased ..........................................................................................................................................xxx
93
94 TOTAL Electric Plant in Service.......................................................................................................................................xxx6,244,966,169$
Page 9 IDAHO SUPPLEMENT
December 31, 2022
ELECTRIC PLANT IN SERVICE (Accounts 101, 102, 103 and 106) (Continued)
Balance at Line
Retirements Adjustments Transfers End of Year
(d)(e) (f) (g)No.
(346)44
584,074,711$ 45
2,592,040,245 46
47
38,852,757 (350)48
96,836,817 (352)49
454,974,918 (353)50
223,470,309 (354)51
220,842,813 (355)52
256,946,825 (356)53
(357)54
(358)55
374,593 (359)56
(359.1)57
1,292,299,032 58
59
8,625,808 (360)60
56,873,252 (361)61
314,307,682 (362)62
(363)63
300,945,745 (364)64
150,615,154 (365)65
53,781,011 (366)66
326,833,697 (367)67
690,152,131 (368)68
66,234,679 (369)69
109,928,854 (370)70
4,324,418 (371)71
(372)72
5,772,410 (373)73
(374)74
2,088,394,842 75
76
19,922,844 (389)77
150,137,308 (390)78
40,629,055 (391)79
109,966,099 (392)80
4,745,770 (393)81
14,414,358 (394)82
14,153,793 (395)83
25,271,872 (396)84
77,995,393 (397)85
10,316,463 (398)86
467,552,955 87
(399)88
(399.1)89
467,552,955 90
6,538,329,186 91
(102)92
93
6,538,329,186$ 94
Page 10 IDAHO SUPPLEMENT
December 31, 2022
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 (f) and (g), on the basis of meters, in addition to the number of flat rate
accounts; except that where separate meter readings are added for billing purposes, one customer should be counted
for each group of meters added. The average number of customers means the average of twelve figures at the close
of each month.
3. If previous year (columns (c), (e) and (g), are not derived from previously reported figures, explain any
inconsistencies in a footnote.
OPERATING REVENUES
Amount for Amount for
No.Current Year Previous Year
(a)(b)(c)
1 Sales of Electricity
2 (440) Residential Sales............................................................................................................................................xxx626,554,696$ 567,032,561$
3 (442) Commercial and Industrial Sales
4 Small (or Commercial)(See Instr. 4) (1)............................................................................................................................xxx496,354,347 461,736,010
5 Large (or Industrial)(See Instr. 4) (2)..............................................................................................................................xxx199,572,880 179,498,602
6 (444) Public Street and Highway Lighting................................................................................................................................xxx3,883,881 3,797,771
7 (445) Other Sales to Public Authorities.................................................................................................................................xxx
8 (446) Sales to Railroads and Railways..................................................................................................................................xxx
9 (448) Interdepartmental Sales........................................................................................................................................xxx
10 TOTAL Sales to Ultimate Consumers................................................................................................................................xxx1,326,365,804 *1,212,064,944
11 (447) Sales for Resale - Opportunity.…Non-Firm Only........................................................................................................................xxx139,411,329 86,431,325
12 TOTAL Sales of Electricity....................................................................................................................................xxx1,465,777,132 1,298,496,269
13 (449) Provision for Rate Refunds............................................................................................................................xxx(13,816,992)(13,699,093)
14 TOTAL Revenue Net of Provision for Refunds........................................................................................................................xxx1,451,960,140 1,284,797,176
15 Other Operating Revenues
16 (450) Forfeited Discounts........................................................................................................................................xxx
17 (451) Miscellaneous Service Revenues..................................................................................................................................xxx4,890,357 4,613,049
18 (453) Sales of Water and Water Power................................................................................................................................xxx
19 (454) Rent from Electric Property.....................................................................................................................................xxx18,009,242 17,583,812
20 (455) Interdepartmental Rents........................................................................................................................................xxx
21 (456) Other Electric Revenues.........................................................................................................................................xxx90,843,241 81,481,640
22
23
24
25 TOTAL Other Operating Revenues...................................................................................................................................xxx113,742,840 103,678,502
26 TOTAL Electric Operating Revenues..............................................................................................................................xxx1,565,702,981$ 1,388,475,677$
(1) Commercial and Industrial sales - Small - under 1,000 KW and includes all irrigation customers.
(2) Commercial and Industrial sales - Large - 1,000 KW and over.
Page 11
IDAHO SUPPLEMENT
December 31, 2022
ELECTRIC OPERATING REVENUES (Account 400) (Continued)
4. Commercial and Industrial Sales, Account 442, may be classified according to the basis of classification
(Small or Commercial, and Large or Industrial) regularly used by the respondent if such basis of classification
is not generally greater than 1000 Kw of demand. (See Account 442 of the Uniform System of Accounts. Explain
5. See page 108, Important 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. Include unmetered sales. Provide details of such sales in a footnote.
KILOWATT HOURS SOLD AVERAGE NUMBER OF CUSTOMERS PER MONTH
Amount for Amount for Amount for Number for Line
Current Year Previous Year Current Year Previous Year No.
(d)(e)(f)(g)
1
5,854,670,342 5,457,378,298 498,920 485,475 2
3
6,008,192,190 6,034,805,124 88,334 87,130 4
3,238,724,828 3,200,734,385 119 120 5
25,475,399 27,303,850 4,394 4,083 6
7
8
9
15,127,062,759 **14,720,221,657 591,767 576,808 10
1,260,388,904 1,279,924,492 N/A N/A 11
16,387,451,662 16,000,146,149 591,767 576,808 12
13
* Includes <$9,862,806> in unbilled revenues.
** Includes 41,693,626 KWH relating to unbilled revenues.
Lines 11 through 21 are on an "allocated" basis.
Page 11a
IDAHO SUPPLEMENT
December 31, 2022
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnotes.
Line Amount for Amount for
No.Account Current Year Previous Year
(a)(b)(c)
1 1. POWER PRODUCTION EXPENSES
2 A. Steam Power Generation
3 Operation
4 (500) Operation Supervision and Engineering..................................................................................................................................606,857$ 865,075$
5 (501) Fuel.............................................................................................................................................................................................................................100,928,029$ 91,112,173
6 (502) Steam Expenses..........................................................................................................................................................................................8,891,150 8,823,203
7 (503) Steam from Other Sources................................................................................................................................................................................
8 (Less) (504) Steam Transferred-Cr............................................................................................................................................................
9 (505) Electric Expenses..........................................................................................................................................................................................1,079,032 1,225,479
10 (506) Miscellaneous Steam Power Expenses..................................................................................................................................................8,241,450 8,147,229
11 (507) Rents........................................................................................................................................................................................................................220,246 208,271
12 (509) Allowances............................................................................................................................................................................................................................................
13 TOTAL Operation (Enter Total of lines 4 thru 12)....................................................................................................................119,966,764 110,381,430
14 Maintenance
15 (510) Maintenance Supervision and Engineering.......................................................................................................................................................(229,340)(1,684)
16 (511) Maintenance of Structures...........................................................................................................................................................................2,438,001 1,228,023
17 (512) Maintenance of Boiler Plant...........................................................................................................................................................8,389,717 8,516,751
18 (513) Maintenance of Electric Plant...........................................................................................................................................................2,205,478 2,573,376
19 (514) Miscellaneous Steam Plant...........................................................................................................................................................9,206,886 7,735,655
20 TOTAL Maintenance (Enter Total of Lines 15 thru 19).............................................................................................................................22,010,742 20,052,121
21 TOTAL Power Production Expenses-Steam Power (Enter Total of lines 13 and 20).......................................................141,977,506 130,433,551
22 B. Nuclear Power Generation
23 Operation
24 (517) Operation Supervision and Engineering.................................................................................................................................................
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 24 thru 32)..................................................................................................................................
34 Maintenance
35 (528) Maintenance Supervision and Engineering............................................................................................................................................
36 (529) Maintenance of Structures...............................................................................................................................................................................
37 (530) Maintenance of Reactor Plant Equipment...........................................................................................................................................................
38 (531) Maintenance of Electric Plant...............................................................................................................................................................................
39 (532) Maintenance of Miscellaneous Nuclear Plant.................................................................................................................................................
40
41 TOTAL Power Production Expenses-Nuclear Power (Enter Total of lines 33 and 40)
42 C. Hydraulic Power Generation
43 Operation
44 (535) Operation Supervision and Engineering.......................................................................................................................................5,525,626 5,209,565
45 (536) Water for Power..............................................................................................................................................................................................................6,361,336 5,450,799
46 (537) Hydraulic Expenses....................................................................................................................................................................................................17,693,352 15,444,546
47 (538) Electric Expenses........................................................................................................................................................................................................1,879,390 1,708,881
48 (539) Miscellaneous Hydraulic Power Generation Expenses..................................................................................................................................4,925,124 4,719,626
49 (540) Rents..............................................................................................................................................................................................................291,217 294,344
50 TOTAL Operation (Enter Total of lines 44 thru 49)....................................................................................................36,676,045 32,827,761
Page 12 IDAHO SUPPLEMENT
December 31, 2022
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnotes.
Line Amount for Amount for
No.Account Current Year Previous Year
(a)(b)(c)
51 C. Hydraulic Power Generation (Continued)
52 Maintenance
53 (541) Maintenance Supervision and Engineering..............................................................................................................................106,525$ 129,022$
54 (542) Maintenance of Structures...........................................................................................................................................................................894,850 953,612
55 (543) Maintenance of Reservoirs, Dams, and Waterways...............................................................................................................435,855 572,405
56 (544) Maintenance of Electric Plant.......................................................................................................................................................2,503,987 2,521,344
57 (545) Maintenance of Miscellaneous Hydraulic Plant...............................................................................................................3,761,811 2,944,067
58 TOTAL Maintenance (Enter Total of lines 53 thru 57)..............................................................................................................7,703,028 7,120,450
59 TOTAL Power Production Expenses-Hydraulic Power (Enter Total of lines 50 and 58) 44,379,073 39,948,211
60 D. Other Power Generation
61 Operation
62 (546) Operation Supervision and Engineering..................................................................................................................................601,921 567,362
63 (547) Fuel........................................................................................................................................................................................................................119,197,497 81,460,446
64 (548) Generation Expenses.........................................................................................................................................................................................4,687,727 4,575,255
65 (549) Miscellaneous Other Power Generation Expenses..................................................................................................................................8,758 1,416,339
66 (550) Rents.........................................................................................................................................................................................................0 0
67 TOTAL Operation (Enter Total of lines 62 thru 66).........................................................................................................................124,495,903 88,019,403
68 Maintenance
69 (551) Maintenance Supervision and Engineering..................................................................................................................................0 0
70 (552) Maintenance of Structures.......................................................................................................................................................152,643 157,424
71 (553) Maintenance of Generating and Electric Plant...............................................................................................................887,372 69,702
72 (554) Maintenance of Miscellaneous Other Power Generation Plant...............................................................................................6,460,322 2,097,662
73 TOTAL Maintenance (Enter Total of lines 69 thru 72).................................................................................7,500,338 2,324,788
74 TOTAL Power Production Expenses-Other Power (Enter Total of lines 67 and 73).........................................131,996,240 90,344,191
75 E. Other Power Supply Expenses
76 (555) Purchased Power..........................................................................................................................................................................................509,681,789 369,574,908
77 (556) System Control and Load Dispatching.................................................................................................................................................0 340
78 (557) Other Expenses...................................................................................................................................................................................................(93,495,372)(44,614,590)
79 TOTAL Other Power Supply Expenses (Enter Total of lines 76 thru 78)............................................................416,186,417 324,960,659
80 TOTAL Power Production Expenses (Enter Total of lines 21, 41, 59, 74, and 79)..............................................734,539,237 585,686,613
81 2. TRANSMISSION EXPENSES
82 Operation
83 (560) Operation Supervision and Engineering........................................................................................................................................3,065,451 2,783,962
84 (561) Load Dispatching.........................................................................................................................................................................................5,159,690 5,087,881
85 (562) Station Expenses..............................................................................................................................................................................................2,676,494 2,909,865
86 (563) Overhead Line Expenses..........................................................................................................................................................................................1,076,544 1,012,935
87 (564) Underground Line Expenses................................................................................................................................................................................0 -
88 (565) Transmission of Electricity by Others.......................................................................................................................................................10,826,941 6,712,280
89 (566) Miscellaneous Transmission Expenses.................................................................................................................................................................7 -
90 (567) Rents..................................................................................................................................................................................................................................4,660,084 4,385,743
91 TOTAL Operation (Enter Total of lines 83 thru 90).........................................................................................................................27,465,212 22,892,667
92 Maintenance
93 (568) Maintenance Supervision and Engineering.......................................................................................................................................198,495 176,934
94 (569) Maintenance of Structures.................................................................................................................................................................1,831,010 1,467,327
95 (570) Maintenance of Station Equipment.............................................................................................................................................2,506,340 1,703,470
96 (571) Maintenance of Overhead Lines..................................................................................................................................................2,182,732 1,081,969
97 (572) Maintenance of Underground Lines...........................................................................................................................................................
98 (573) Maintenance of Miscellaneous Transmission Plant.............................................................................................................................4,908 2,443
99 (575) Transmission Market Administration - EIM.............................................................................................................................659,249 703,432
99 TOTAL Maintenance (Enter Total of lines 93 thru 98)...............................................................................................................7,382,733 5,135,576
100 TOTAL Transmission Expenses (Enter Total of lines 91 and 99).....................................................................................34,847,945 28,028,242
101 3. DISTRIBUTION EXPENSES
102 Operation
103 (580) Operation Supervision and Engineering.......................................................................................................................................5,631,403 3,912,375
Page 13
IDAHO SUPPLEMENT
December 31, 2022
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnotes.
Line Amount for Amount for
No.Account Current Year Previous Year
(a)(b)(c)
104 3. DISTRIBUTION EXPENSES (Continued)
105 (581) Load Dispatching...............................................................................................................................................................................................4,978,423$ 4,720,436$
106 (582) Station Expenses....................................................................................................................................................................................................1,785,614 1,511,068
107 (583) Overhead Line Expenses...............................................................................................................................................................................5,037,439 4,506,880
108 (584) Underground Line Expenses...............................................................................................................................................................................4,648,975 4,503,905
109 (585) Street Lighting and Signal System Expenses...................................................................................................................................42,854 537
110 (586) Meter Expenses...............................................................................................................................................................................................5,547,173 4,846,360
111 (587) Customer Installations Expenses.................................................................................................................................................................1,023,145 948,551
112 (588) Miscellaneous Distribution Expenses...........................................................................................................................................................................4,466,054 3,937,734
113 (589) Rents............................................................................................................................................................................................................................706,258 421,100
114 TOTAL Operation (Enter Total of lines 103 thru 113)....................................................................................................33,867,336 29,308,946
115 Maintenance
116 (590) Maintenance Supervision and Engineering.......................................................................................................................................................11,402 10,469
117 (591) Maintenance of Structures...............................................................................................................................................................................0 0
118 (592) Maintenance of Station Equipment...........................................................................................................................................................................3,950,689 3,902,335
119 (593) Maintenance of Overhead Lines..........................................................................................................................................................................................20,379,133 16,428,368
120 (594) Maintenance of Underground Lines...........................................................................................................................................................................740,652 588,903
121 (595) Maintenance of Line Transformers...........................................................................................................................................................88,896 55,701
122 (596) Maintenance of Street Lighting and Signal Systems...................................................................................................................196,215 252,270
123 (597) Maintenance of Meters.....................................................................................................................................................................................836,018 813,794
124 (598) Maintenance of Miscellaneous Distribution Plant...................................................................................................................115,612 91,906
125 TOTAL Maintenance (Enter Total of lines 116 thru 124)........................................................................................................................................26,318,616 22,143,747
126 TOTAL Distribution Expenses (Enter Total of lines 114 and 125)...............................................................................................................60,185,952 51,452,693
127 4. CUSTOMER ACCOUNTS EXPENSES
128 Operation
129 (901) Supervision.............................................................................................................................................................................................................808,235 800,134
130 (902) Meter Reading Expenses.....................................................................................................................................................................................1,576,198 1,535,472
131 (903) Customer Records and Collection Expenses.......................................................................................................................................................14,548,025 13,542,425
132 (904) Uncollectible Accounts..........................................................................................................................................................................................2,860,862 2,193,997
133 (905) Miscellaneous Customer Accounts Expenses...........................................................................................................................................................................(2,887)401
134 TOTAL Customer Accounts Expenses (Enter Total of lines 129 thru 133).............................................19,790,434 18,072,429
135 5. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
136 Operation
137 (907) Supervision....................................................................................................................................................................................................966,922 745,616
138 (908) Customer Assistance Expenses................................................................................................................................................................................38,764,930 34,276,036
139 (909) Informational and Instructional Expenses.............................................................................................................................................285,579 284,745
140 (910) Miscellaneous Customer Service and Informational Expenses...................................................................................................................715,010 799,680
141 TOTAL Cust. Service and Informational Expenses (Enter Total of lines 137 thru 140)...................................40,732,441 36,106,077
142 6. SALES EXPENSES
143 Operation
144 (911) Supervision..................................................................................................................................................................................................................
145 (912) Demonstrating and Selling Expenses..........................................................................................................................................................................................- -
146 (913) Advertising Expenses...................................................................................................................................................................................................
147 (916) Miscellaneous Sales Expenses................................................................................................................................................................................
148 TOTAL Sales Expenses (Enter Total of lines 144 thru 147).........................................................................................................- -
149 7. ADMINISTRATIVE AND GENERAL EXPENSES
150 Operation
151 (920) Administrative and General Salaries................................................................................................................................................................91,614,326 83,409,198
152 (921) Office Supplies and Expenses...........................................................................................................................................................................14,477,554 13,372,062
153 (Less) (922) Administrative Expenses Transferred-Credit.............…….....….....................……(33,600,237)(31,283,163)
Page 14
IDAHO SUPPLEMENT
December 31, 2022
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnotes.
Line Amount for Amount for
No.Account Current Year Previous Year
(a)(b)(c)
154 7. ADMINISTRATIVE AND GENERAL EXPENSES (Continued)
155 (923) Outside Services Employed........................................................................................................................................8,352,471$ 7,474,551$
156 (924) Property Insurance................................................................................................................................................................................3,765,831 3,426,724
157 (925) Injuries and Damages...........................................................................................................................................................................6,259,262 6,191,531
158 (926) Employee Pensions and Benefits..................................................................................................................................................51,976,040 53,460,438
159 (927) Franchise Requirements................................................................................................................................................................................0 0
160 (928) Regulatory Commission Expenses.....................................................................................................................................................................4,957,986 4,857,719
161 (929) Duplicate Charges-Cr.........................................................................................................................................................................................
162 (930.1) General Advertising Expenses...............................................................................................................................................................................470,045 364,434
163 (930.2) Miscellaneous General Expenses...............................................................................................................................................................................4,188,008 3,905,591
164 (931) Rents.......................................................................................................................................................................................................................0 0
165 TOTAL Operation (Enter Total of lines 151 thru 164)........................................................................................................................152,461,286 145,179,084
166 Maintenance
167 (935) Maintenance of General Plant......................................................................................................................................................................7,540,853 7,499,770
168 TOTAL Admin and General Expenses (Enter Total of lines 165-167)……………………………………... 160,002,140 152,678,854
169 TOTAL Elec Op and Maint Exp (Total of 80, 100, 126, 134, 141, 148, 168)………………….. 1,050,098,148$ 872,024,907$
IDAHO ONLY
NUMBER OF ELECTRIC DEPARTMENT EMPLOYEES
1. 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 after October 31.
2. If the respondent's payroll for the 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 department from joint functions of combination utilities
may be determined by estimate, on the basis of employee equivalents. Show the estimated number of equiv-
alent employees attributed to the electric department from joint functions.
1 Payroll Period Ended (Date)..................................................................................................................................................December 31, 2022 December 31, 2021
2 Total Regular Full-Time Employees...................................................................................................................................2,062 1,983
3 Total Part-Time and Temporary Employees....................................................................................................................4 5
4 Total Employees................................................................................................................................................................................2,066 1,988
Page 15IDAHO SUPPLEMENT