2023Annual FERC Q4 Financial Report Electric.pdf

THIS FILING IS
Item 1: An Initial(Original)Submission OR ❑ Resubmission No.
E,y� �-_4�I
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)
Year/Period of Report
Avista Corporation
End of:2023/Q4
FERC FORM NO.1 (REV.02-04)

INSTRUCTIONS FOR FILING FERC FORM NOS. 1 and 3-Q
GENERAL INFORMATION
I• 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.
II. 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:
1. one million megawatt hours of total annual sales,
2. 100 megawatt hours of annual sales for resale,
3. 500 megawatt hours of annual power exchanges delivered,or
4. 500 megawatt hours of annual wheeling for others(deliveries plus losses).
III. What and Where to Submit
a. Submit FERC Form Nos.1 and 3-Q electronically through the eCollection portal at httosJ/eCollection.ferc.aov,and according to the
specifications in the Form 1 and 3-Q taxonomies.
b. The Corporate Officer Certification must be submitted electronically as part of the FERC Forms 1 and 3-Q filings.
c. 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
d. 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:
a. 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
b. 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
e. 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
pages above do not conform to the Commission's requirements.Describe the discrepancies that exist.

f. 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 httos://www.ferc.gov/ferc-online/ferc-onlineffrequently-asked-0uesGons-faas-
efilingferc-online.
g. 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.
IV. When to Submit
FERC Forms 1 and 3-Q must be filed by the following schedule:
a. FERC Form 1 for each year ending December 31 must be filed by April 18th of the following year(18 CFR§141.1),and
b. FERC Form 3-Q for each calendar quarter must be filed within 60 days after the reporting quarter(18 C.F.R.§141.400).
V. 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
I. 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.
II. Enter in whole numbers(dollars or MWH)only,except where otherwise noted.(Enter cents for averages and figures per unitwhere 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.
III. 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.
IV. 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.
V. 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).
VI. 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.
VII. For any resubmissions,please explain the reason for the resubmission in a footnote to the data field.
Vill. Do not make references to reports of previous periods/years or to other reports in lieu of required entries,except as specifically
authorized.
IX. 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.
X. 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
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
I. 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.
II. 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:
3. '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;
4. 'Person'means an individual or a corporation;
5. '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;
7. '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;......
11. "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
a. '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.
a. 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 otherthings,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 otherfacilities,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
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 02 Year/Period of Report
Avista Corporation
End of.2023/04
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)
1411 East Mission Avenue,Spokane,WA 99207
05 Name of Contact Person 06 Title of Contact Person
Ryan L.Krasselt VP,Controller,Prin.Acctg Officer
07 Address of Contact Person(Street,City,State,Zip Code)
1411 East Mission Avenue,Spokane,WA 99207
09 This Report is An Original/A
Resubmission
08 Telephone of Contact Person,Including Area
Code 10 Date of Report(Mo,Da,Yr)
(1)0 An Original
[phone] 04/12/2024
(2) ElA Resubmission
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 03 Signature 04 Date Signed(Mo,Da,Yr)
Ryan L.Krasselt Ryan L.Krasselt 04/12/2024
02 Title
VP,Controller,Prin.Acctg Officer
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

This report is:
Name of Respondent: (1)0 An Original Date of Report: Year/Period of Report
Avista Corporation (2) El A Resubmission 04/12/2024 End of:2023/Q4
LIST OF SCHEDULES(Electric Utility)
Line Title of Schedule Reference Page No. Remarks
No. (a) (b) (c)
LIdentification 1
List of Schedules 2
f 1 General Information 101_
12 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 Eamings for the Year 118
12 Statement of Cash Flows 120
12 Notes to Financial Statements L
13 Statement of Accum Other Comp Income,Comp 122a
Income,and Hedging Activities
14 Summary of Utility Plant&Accumulated Provisions 200
for Dep,Amort&Dep
15 Nuclear Fuel Materials 202
16 Electric Plant in Service 204
17 Electric Plant Leased to Others 213
18 Electric Plant Held for Future Use 214
19 Construction Work in Progress-Electric 216
20 Accumulated Provision for Depreciation of Electric 219
Utility Plant —
21 Investment of Subsidiary Companies 224
22 Materials and Supplies 227
23 Allowances 228 NA
24 Extraordinary Property Losses 230a
25 Unrecovered Plant and Regulatory Study Costs 230b
26 Transmission Service and Generation 231
Interconnection Study Costs
27 Other Regulatory Assets 232
FERC FORM No.1 (ED.12-96)
Page 2

LIST OF SCHEDULES(Electric Utility)
Line Tide of Schedule Reference Page No. Remarks
(a) (b) (c)
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 261
Inc for Fed Inc Tax
35 Taxes Accrued,Prepaid and Charged During the 262
Year
36 Accumulated Deferred Investment Tax Credits 266
37 Other Deferred Credits 269
38 Accumulated Deferred Income Taxes-Accelerated 272
Amortization Property —
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 302
457.1)
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
50 Transmission of Electricity by Others 332
51 Miscellaneous General Expenses-Electric 355
52 Depreciation and Amortization of Electric Plant 336
(Account 403,404,405)
53 Regulatory Commission Expenses 350
54 Research,Development and Demonstration 352
Activities —
55 Distribution of Salaries and Wages 354
56 Common Utility Plant and Expenses 356
57 Amounts included in ISO/RTO Settlement 397
Statements --
FERC FORM No.1 (ED.12-96)

Page 2
LIST OF SCHEDULES(Electric Utility)
Line Title of Schedule Reference Page No. Remarks
No. (a) (b) (c)
58 Purchase and Sale of Ancillary Services 398
59 Monthly Transmission System Peak Load 400
60 Monthly ISO/RTO Transmission System Peak Load 400a
61 Electric Energy Account 401 a
62 Monthly Peaks and Output 401 b
63 Steam Electric Generating Plant Statistics 402
64 Hydroelectric Generating Plant Statistics 406
65 Pumped Storage Generating Plant Statistics 408
66 Generating Plant Statistics Pages 410
66.1 Energy Storage Operations(Large Plants) 414
66.2 Energy Storage Operations(Small Plants) 419
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

This report is:
Name of Respondent: (1)21 An Original Date of Report: Year/Period of Report
Avista Corporation 04/12/2024 End of 2023/Q4
(2) ❑A Resubmission
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.
Avista Corporation
Ryan L.Krasselt
VP,Controller,Prin Acctg Officer
1411 E.Mission Avenue,Spokane,WA 99207
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.
State of Washington,Incorporated March 15,1889
State of Incorporation:WA
Date of Incorporation:1889-03-15
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.
(a)Name of Receiver or Trustee Holding Properly of the Respondent:None
(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 fumished by respondent during the year in each State in which the respondent operated.
Electric service in the states of Washington,Idaho,and Montana Natural gas service in the states of Washington,Idaho,and 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)0 No
FERC FORM No.1 (ED.12-87)
Page 101

This report is:
Name of Respondent: (1)®An Original Date of Report: Year/Period of Report
Avista Corporation 04/12/2024 End of:2023/Q4
(2) El A Resubmission
CORPORATIONS CONTROLLED BY RESPONDENT
Percent
Line Name of Company Controlled Kind of Business Voting Stock Footnote Ref.
No. (a) (b) Owned (d)
(c)
1 Avista Capital,Inc. Parent to the Co's Subsidiary 100% 1
2 Avista Development,Inc. Investment in Real Estate 100% 2
3 Avista Edge,Inc. Investment in Internet Tech. 100% 3
4 Pentzer Corporation Parent of Pentzer Venture Holdings 100% 4
5 PentzerVenture Holdings II,Inc. Holding Company-Inactive 100% 5
6 LLC University Development Company, Facilitates Properly Acquisitions 100% 6
7 Avista Capital II Affiliated business trust issued 100% 7
preferred trust Securities
8 Avista Northwest Resources,LLC Owns an interest in a venture fund 100% 8
investment
9 Courtyard Office Center,LLC Inactive 100% 9
10 Salix,Inc. Liquified Natural Gas Operations 100% 10
11 Alaska Energy and Resources Parent Co of Alaska Opertions 100% 11
Company(AERC)
12 Alaska Electric Light and Power Utility Operations in Juneau 100% 12
Company
13 AJT Mining Properties,Inc. Inactive mining Co holding certain 100% 13
properties
14 Snettisham Electric Company Right to Purchase Snettisham 100% 14
FERC FORM No.1 (ED.12-96)
Page 103

report is:e This rpo
Name of Respondent: Th Th po Original Date of Report: Year/Period of Report
Avista Corporation 04/12/2024 End of:2023/04
(2) ❑A Resubmission
OFFICERS
Line Title Name of Officer Salary for Year Date Started in Date Ended in
Period Period
No. (a) (b) (c) (d) (e)
1 Chief Executive Officer D.P.Vermillion 868,569 2023-01-01 2023-12-31
2 President and Chief Operating H.L.Rosentrater 424,279 2023-10-01 2023-12-31
Officer
3 Executive Vice President M.T.Thies 264,568 2023-05-11 2023-10-01
Senior Vice President,Chief
4 Financial Officer,Treasurer and K.J.Christie 382,338 2023-05-11 2023-12-31
Regulatory Affairs Officer
Senior Vice President,Chief
5 Strategy and Clean Energy J.R.Thackston 384,928 2023-01-01 2023-12-31
Officer
Senior Vice President,General
6 Council,Corporate Secretary G.C.Hester 400,719 2023-01-01 2023-12-31
and Chief Ethics/Compliance
Officer
7 Senior Vice President,Safety B.A.Cox 351,862 2023-01-01 2023-12-31
and Chief People Officer
Vice President Community
8 Affairs and Chief Customer L.D.Hill 308,281 2023-01-01 2023-12-31
Officer
Vice President,Chief Information
9 Officer,and Chief Security J.M.Kensok 204,423 2023-01-01 2023-08-01
Officer
10 Vice President,Controller,and R.L.Krasselt 271,959 2023-01-01 2023-12-31
Principal Accounting Officer
Vice President and Chief
11 Counsel for Regulatory and D.J.Meyer 326,254 2023-01-01 2023-12-31
Governmental Affairs
12 Vice President,Energy S.J.Kinney 284,654 2023-01-01 2023-12-31
Resources
13 Vice President,Energy Delivery J.D.DiLuciano 249,749 2023-01-01 2023-12-31
Vice President,Chief Information
14 Officer,and Chief Security W.O.Manuel 193,847 2023-06-01 2023-12-31
Officer
FERC FORM No.1 (ED.12-96)
Page 104

This report is:
Name of Respondent: (1) An Original Date of Report: Year/Period of Report
Avista Corporation 04/12/2024 End of:2023/Q4
(2) ❑A Resubmission
DIRECTORS
Line Name(and Title)of Director Principal Business Address Member of the Executive Chairman of the Executive
No. (a) (b) Committee Committee
(c) (d)
1 Scott L.Moms(Chairman of the 1411 E.Mission Ave,Spokane, true true
Board) WA 99202
2 Dennis P.Vermillion(CEO) 1411 E.Mission Ave,Spokane, true false
WA 99202
3 Kristianne Blake P.O.Box 3727,Spokane,WA true false
99220
4 Donald C.Burke 16 Ivy Court,Langhorne,PA false false
19047
5 Scott H.Maw 115 NW 78th St.,Seattle,WA false false
98117
6 Rebecca A.Klein 611 S.Congress Ave.,Suite false false
125,Austin,TX 78704
7 Jeffry L.Philipps P.O.Box 9000,Spokane,WA false false
99209
8 Heidi B.Stanley P.O.Box 2884,Spokane,WA true false
99220
9 Janet D.Widmann 26 Sanford Ln.,Lafayette,CA false false
94549
10 Julie A.Bentz 38748 Lulay Rd,Scio,OR false false
97374
11 Sena M.Kwawu 2507 101 st Lane NE,Bellevue, false false
WA 98004
12 Kevin B.Jacobsen 1221 Broadway,Oakland,CA false false
94607
FERC FORM No.1 (ED.12-95)
Page 105

This report is:
Name of Respondent: (1)0 An Original Date of Report: Year/Period of Report
Avista Corporation 04/12/2024 End of:2023/Q4
(2) ❑A Resubmission
IMPORTANT CHANGES DURING THE QUARTERIYEAR
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 contractor 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.
1. None
2.None
3.None
4.None
5.None
6.Reference is made to Notes 10,11,and 12 of the Notes to Financial Statements.
7.None

8.Average annual wage increases were 5.4%for non-exempt employees effective February 27,2023.Average annual wage increases were 5.8%for
exempt employees effective February 27,2023.Officers received average increases of 6.4%effective February 13,2023.Certain bargaining unit employees
received average increases of 3.5%effective March 26,2023 and April 1,2023.
9.Reference is made to Note 15 of the Notes to Financial Statements.
10.None
12.Seepage 123 of this report.
13.Effective May 1lth,2023,Kristianne Blake retired from the Company's Board of Directors.On May I Ith,2023,Kevin Jacobson was elected to the
Board of Directors.
On May 1,2023,Mark Thies,Executive Vice President,Chief Financial Officer,and Treasurer,announced to the Company's board of directors that he
would retire,effective October 1,2023.Following the announcement,the Company's board of directors appointed Kevin Christie as Chief Financial Officer,
Treasurer,and Senior Vice President of Regulatory Affairs,effective May 11,2023.Mr.Thies continued to serve as Executive Vice President until his
retirement date.
Effective May 11,2023,Latisha Hill added corporate communications,customer service and energy efficiency to her previous responsibilities.Her new title
is Vice President of Community Affairs and Chief Customer Officer.
Effective June 1,2023,Wayne Manuel joined the Company as Vice President,Chief Information Officer and Chief Security Officer.This role was
previously held by Jim Kensok,who retired from the Company effective August 1,2023.
Effective October 1,2023,Senior Vice President and COO Heather Rosentrater became President and COO of the Company.Also effective October 1,
2023,Vice President,Safety and Chief People Officer Bryan Cox became Senior Vice President,Safety and Chief People Officer.
14.Proprietary capital is not less than 30 percent
FERC FORM No.1 (ED.12-96)
Page 108-109

This report is:
Name of Respondent: (1)®An Original Date of Report: Year/Period of Report
Avista Corporation 04/12/2024 End of:2023/Q4
(2) ❑A Resubmission
COMPARATIVE BALANCE SHEET(ASSETS AND OTHER DEBITS)
Line Title of Account Ref.Page No. Current Year End of Prior Year End Balance 12/31
No. (a) (b) Quarter/Year Balance (d)
(c)
1 UTILITY PLANTF -i
2 Utility Plant(101-106,114) 200 7,852,959,203 7,477,186,308
3 Construction Work in Progress(107) 200 170,812,964 155,475,677
4 TOTAL Utility Plant(Enter Total of lines 2 and 3) 8,023,772,167 7,632,661,985
5 (Less)Accum.Prov.for Depr.Amort.Depl.(108, 200 2,796,332,034 2,624,302,472
110,111,115)
6 Net Utility Plant(Enter Total of line 4 less 5) 5,227,440,133 5,008,359,513
7 Nuclear Fuel in Process of Ref.,Conv.,Enrich., 202
and Fab.(120.1)
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 202
Assemblies(120.5)
13 Net Nuclear Fuel(Enter Total of lines 7-11 less 0 0
12)
14 Net Utility Plant(Enter Total of lines 6 and 13) 5,227,440,133 5,008,359,513
15 Utility Plant Adjustments(116)
16 Gas Stored Underground-Noncurrent(117) 6,992,076 6,992,076
17 OTHER PROPERTY AND INVESTMENTS
18 Nonutility Property(121) 22,796,933 11,036,947
19 (Less)Accum.Prov.for Depr.and Amort.(122) 110,345 103,609
20 Investments in Associated Companies(123) 11,547,000 11,547,000
21 Investment in Subsidiary Companies(123.1) 224 265,210,641 260,760,970
23 Noncurrent Portion of Allowances 228
24 Other Investments(124) 14,094 73,448
25 Sinking Funds(125) 0 0
26 Depreciation Fund(126) 0 0
27 Amortization Fund-Federal(127) 0 0
28 Other Special Funds(128) 15,335,490 11,797,054
-729 Special Funds(Non Major Only)(129) 0 0
FERC FORM No.1 (REV.12-03)
Page 110-111

COMPARATIVE BALANCE SHEET(ASSETS AND OTHER DEBITS)
Line Title of Account Ref.Page No. Current Year End of Prior Year End Balance 12/31
No. (a) (b) Quarter/Year'r Balance (d)
30 Long-Term Portion of Derivative Assets(175) 0 2,944,915
31 Long-Term Portion of Derivative Assets-Hedges 0 0
(176)
32 TOTAL Other Property and Investments(Lines 314,793,813 298,056,725
18-21 and 23-31)
33 CURRENT AND ACCRUED ASSETS
MEIN Em"616--
34 Cash and Working Funds(Non-major Only) 0 0
(130)
35 Cash(131) 11,843,507 4,465,295
36 Special Deposits(132-134) 0 66,141,689
37 Working Fund(135) 758,362 776,205
38 Temporary Cash Investments(136) 15,991,036 496,573
39 Notes Receivable(141) 0 0
40 Customer Accounts Receivable(142) 199,763,204 219,394,599
41 Other Accounts Receivable(143) 38,651,095 67,155,969
42 ess)
Accum.Prov.for Uncollectible Acct.-Credit 4,905,146 6,345,841
43 N45) Receivable from Associated Companies 20,584,744 9,364,617
44 Accounts Receivable from Assoc.Companies 978,859 787,177
45 Fuel Stock(151) 227 4,683,150 4,252,607
46 Fuel Stock Expenses Undistributed(152) 227 0 0
47 Residuals(Elec)and Extracted Products(153) 227 0 0
48 Plant Materials and Operating Supplies(154) 227 79,492,528 73,453,924
49 Merchandise(155) 227 0 0
50 Other Materials and Supplies(156) 227 0 0
51 Nuclear Materials Held for Sale(157) 202/227 0 0
52 Allowances(158.1 and 158.2) 228 30,071,678 0
53 (Less)Noncurrent Portion of Allowances 228
54 Stores Expense Undistributed(163) 227 0 I 0
55 Gas Stored Underground-Current(164.1) 16,271,620 26,788,027
56 Liquefied Natural Gas Stored and Held for 0 0
Processing(164.2-164.3)
57 Prepayments(165) 50,221,552 28,311,482
58 Advances for Gas(166-167) 0 0
FERC FORM No.1 (REV.12-03)
Page 110-111

COMPARATIVE BALANCE SHEET(ASSETS AND OTHER DEBITS)
Line Title of Account Ref.Page No. Current Year End of Prior Year End Balance 12131
No. (a) (b) Quarter/Y(eca)r Balance — (d)
59 Interest and Dividends Receivable(171) 2,627,341 621,880
60 Rents Receivable(172) 7,380,742 4,556,651
61 Accrued Utility Revenues(173) 0 0
62 Miscellaneous Current and Accrued Assets(174) 0 230,226
63 Derivative Instrument Assets(175) 11,821,033 21,142,955
(Less)Long-Term Portion of Derivative
64 Instrument Assets(175) 0 2,944,915
65 Derivative Instrument Assets-Hedges(176) 0 0
66 (Less)Long-Term Portion of Derivative 0 0
Instrument Assets-Hedges(176)
67 Total Current and Accrued Assets(Lines 34 486,235,305 518,649,120
through 66)
68 DEFERRED DEBITS
69 Unamortized Debt Expenses(181) 21,586,301 20,719,467
70 Extraordinary Property Losses(182.1) 230a 0 0
71 Unrecovered Plant and Regulatory Study Costs 230b 0 0
(182.2)
72 Other Regulatory Assets(182.3) 232 898,192,107 912,434,228
73 Prelim.Survey and Investigation Charges 0 0
(Electric)(183)
74 Preliminary Natural Gas Survey and 0 0
Investigation Charges 183.1)
75 Other Preliminary Survey and Investigation 0 0
Charges(183.2)
76 Clearing Accounts(184) 858,506 872,806
77 Temporary Facilities(185) 0 0
78 Miscellaneous Deferred Debits(186) 233 87,517,904 68,920,168
79 Def.Losses from Disposition of Utility Plt.(187) 0 0
80 Research,Devel.and Demonstration Expend. 352 0 0
(188)
81 Unamortized Loss on Reaquired Debt(189) 5,701,051 6,177,054
82 Accumulated Deferred Income Taxes(190) 234 214,152,188 269,470,612
83 Unrecovered Purchased Gas Costs(191) 51,370,535 52,091,145
F84 Total Deferred Debits(lines 69 through 83) 1,279,378,592 1,330,685,480
85 TOTAL ASSETS(lines 14-16,32,67,and 84) 7,314,839,919 7,162,742,914
FERC FORM No.1 (REV.12-03)
Page 110-111

This report is:
Name of Respondent: (1)0 An Original Date of Report: Year/Period of Report
Avista Corporation (2) ❑A Resubmission 04/12/2024 End of:2023/Q4
COMPARATIVE BALANCE SHEET(LIABILITIES AND OTHER CREDITS)
Line Title of Account Ref.Page No. Current Year End of Prior Year End Balance 12131
No. (a) (b) Quarter/Year Balance (d)
(c)
1 PROPRIETARY CAPITAL _F
2 Common Stock Issued(201) 250 1,596,986,047 1,481,787,168
3 Preferred Stock Issued(204) 250 0 0
4 Capital Stock Subscribed(202,205) 0 0
5 Stock Liability for Conversion(203,206) 0 0
6 Premium on Capital Stock(207) 0 0
7 Other Paid-In Capital(208-211) 253 (2,732,405) (10,696,711)
8 Installments Received on Capital Stock(212) 252 0 0
9 (Less)Discount on Capital Stock(213) 254 0 0
10 (Less)Capital Stock Expense(214) 254b (50,073,294) (54,094,483)
11 Retained Earnings(215,215.1,216) 118 798,215,179 772,567,765
12 Unappropriated Undistributed Subsidiary 118 43,138,900 38,974,396
Earnings(216.1)
13 (Less)Reacquired Capital Stock(217) 250 0 0
14 Noncorporate Proprietorship(Non-major only) 0 0
(218)
15 Acc�u)mulated Other Comprehensive Income 122(a)(b) (357,109) (2,058,225)
(21
16 Total Proprietary Capital(lines 2 through 15) 2,485,323,906 2,334,668,876
17 LONG-TERM DEBT
18 Bonds(221) 256 2,543,700,000 2,307,200,000
19 (Less)Reacquired Bonds(222) 256 83,700,000 83,700,000
20 Advances from Associated Companies(223) 256 51,547,000 51,547,000
21 Other Long-Term Debt(224) 256 0 0
22 Unamortized Premium on Long-Term Debt(225) 106,600 115,483
23 (Less)Unamortized Discount on Long-Term 795,576 841,286
Debt-Debit(226)
24 Total Long-Term Debt(lines 18 through 23) 2,510,858,024 2,274,321,197
25 OTHER NONCURRENT LIABILITIES
26 Obl g)ations Under Capital Leases-Noncurrent 63,558,661 64,284,097
(22
Accumulated Provision for Property Insurance
27 (228.1) 0 0
FERC FORM No.1 (REV.12-03)
Page 112-113

COMPARATIVE BALANCE SHEET(LIABILITIES AND OTHER CREDITS)
Line Title of Account Ref.Page No. Current Year End of Prior Year End Balance 12/31
No. (a) (b) Quarter/Year Balance (d)
(c)
28 Accumulated Provision for Injuries and Damages 995,000 1,320,000
(228.2)
Accumulated Provision for Pensions and
29 Benefits(228.3) 89,829,937 93,900,990
30 Accumulated Miscellaneous Operating 0 0
Provisions(228.4)
31 Accumulated Provision for Rate Refunds(229) 618,329 774,805
32 Long-Term Portion of Derivative Instrument 17,902,180 7,891,963
Liabilities
33 Long-Term Portion of Derivative Instrument 0 0
Liabilities-Hedges
34 Asset Retirement Obligations(230) 18,058,399 15,783,066
35 Total Other Noncurrent Liabilities(lines 26 190,962,506 183,954,921
through 34)
36 CURRENT AND ACCRUED LIABILITIES
37 Notes Payable(231) 349,000,000 463,000,000
38 Accounts Payable(232) 136,101,468 195,759,919
39 Notes Payable to Associated Companies(233) 0 0
40 Accounts Payable to Associated Companies 0 114
(234)
41 Customer Deposits(235) 11,208,693 6,929,872
42 Taxes Accrued(236) 262 31,879,207 38,520,487
43 Interest Accrued(237) 22,318,892 19,663,017
44 Dividends Declared(238) 0 0
45 Matured Long-Term Debt(239) 0 0
46 Matured Interest(240) 0 0
47 Tax Collections Payable(241) 40,534 202,211
48 Miscellaneous Current and Accrued Liabilities 99,744,896 84,650,630
(242)
49 Obligations Under Capital Leases-Current(243) 4,490,212 4,348,776
50 Derivative Instrument Liabilities(244) 35,118,959 34,802,627
51 (Less)Long-Term Portion of Derivative 17,902,180 7,891,963
Instrument Liabilities
52 Derivative Instrument Liabilities-Hedges(245) 0 0
53 (Less)Long-Term Portion of Derivative 0 0
Instrument Liabilities-Hedges
54 Total Current and Accrued Liabilities(lines 37 672,000,681 839,985,690
through 53)
FERC FORM No.1 (REV.12-03)
Page 112-113

COMPARATIVE BALANCE SHEET(LIABILITIES AND OTHER CREDITS)
Line Title of Account Ref.Page No. Current Year End of Pryor Year End Balance 12131
No. (a) (b) Quarter/Year Balance (d)
(c)
55 DEFERRED CREDITS
56 Customer Advances for Construction(252) 4,436,513 4,211,506
57 Accumulated Deferred Investment Tax Credits 266 28,233,162 28,784,445
58 Deferred Gains from Disposition of Utility Plant 0 0
(256)
59 Other Deferred Credits(253) 269 32,918,243 48,402,602
60 Other Regulatory Liabilities(254) 278 479,233,915 525,409,545
61 Unamor ized Gain on Reacquired Debt(257) 942,384 1,059,748
62 Accum.Deferred Income Taxes-Accel.Amort. 272 0 0
(281)
63 Accum.Deferred Income Taxes-Other Property 653,219,870 636,821,685
(282)
64 Accum.Deferred Income Taxes-Other(283) 1 256,710,715 285,122,699
65 Total Deferred Credits(lines 56 through 64) 1,455,694,802 1,529,812,230
66 TOTAL LIABILITIES AND STOCKHOLDER 7,314,839,919 7,162,742,914
EQUITY(lines 16,24,35,54 and 65)
FERC FORM No.1 (REV.12-03)
Page 112-113

This report is:
Name of Respondent: (1)21 An Original Date of Report: Year/Period of Report
Avista Corporation 04/12/2024 End of:2023/Q4
(2) El A Resubmission
STATEMENT OF INCOME
Current 3 Prior 3
Total Current Months Months Electric Utility
Total Prior Year Electric Utility
(Ref.) Year to Date Ended- Ended- Previous Year
Line Title of Account to Date Balance Current Year to
No. (a) Page No. Balance for for Quarter/Year Quarterly Quarterly Date(in dollars) to Date(in
(b) Quarter/Year ( )d Only-No 4th Only-No 4th dollars)
(c) Quarter Quarter (9) (h)
(e) M
UTILITY
1 OPERATING
INCOME
2 Op0e0)ting Revenues 300 1,813,140,867 1,753,175,600 1,193,674,365 1,167,462,735
3 Operating Expenses
4 (401)Operation Expenses 320 1,129,074,478 1,115,606,858 674,026,748 702,986,085
5 Maintenance 320 86,720,955 90,443,526 71,447,477 73,669,737
Expenses(402)
6 Depreciation 336 194,611,959 185,002,792 149,272,689 142,463,452
Expense(403)
Depreciation
7 Expense for Asset 336 0 0 0 0
Retirement Costs
(403.1)
8 Amort.&Depl.of 336 62,239,993 56,467,917 46,738,641 42,661,543
Utility Plant(404-405)
9 Amort.of Utility Plant 336 0 0 0 0
Acq.Adj.(406)
Amort.Property
10 Losses,Unrecov 0 0
Plant and Regulatory
Study Costs(407)
11 Amort.of Conversion 0 0 0 0
Expenses(407.2)
12 Regulatory Debits 64,155,411 18,495,696 21,751,021 12,678,285
(407.3)
13 (Less)Regulatory 102,019,225 49,733,468 43,048,247 44,548,411
Credits(407.4)
14 Taxes Other Than 262 118,141,439 121,401,780 79,882,775 86,410,192
Income Taxes(408.1)
15 Income Taxes- 262 2,419,168 (1,018,866) (7,715,052) (3,578,734)
Federal(409.1)
16 Income Taxes-Other 262 895,264 789,848 20,224 (43,263)
(409.1)
17 Provision for Deferred 234. 36,404,931 40,312,733 29,355,257 29,270,294
Income Taxes(410.1) 272
FERC FORM No.1 (REV.02-04)
Page 114-117

STATEMENT OF INCOME
Current 3 Prior 3
Total Current Total Prior Year Months Months Electric Utility Electric Utility
(Ref.) Year to Date Ended- Ended- Previous Year
Line Title of Account Page No. Balance for to Date Balance Quarterly Quarterly Current Year to to Date(in
No. (a) for QuarterNear Date(in dollars)
(b) QuarterNear (d) Only-No 4th Only-No 4th (g) dollars)
(c) Quarter Quarter (h)
(e) l8
(Less)Provision for 234,
18 Deferred Income 272 74,741,597 64,172,849 47,088,945 46,062,769
Taxes-Cr.(411.1)
Investment Tax Credit
19 Adj.-Net(411.4) 266 (551,283) (528,730) (546,563) (528,748)
(Less)Gains from
20 Disp.of Utility Plant 0 0
(411.6)
21 Losses from Disp.of 0 0
Utility Plant(411.7)
(Less)Gains from
22 Disposition of 0 0
Allowances(411.8)
Losses from
23 Disposition of 0 0
Allowances(411.9)
Accretion Expense
24 (411.10) 0 0
TOTAL Utility
25 Operating Expenses 1,517,351,493 1,513,067,237 974,096,025 995,377,663
(Enter Total of lines 4
thru 24)
Net Util Oper Inc
27 (Enter Tot line 2 less 295,789,374 240,108,363 219,578,340 172,085,072
25)
28 Other Income and
Deductions
29 Other Income
30 Nonutilty Operating —
Income
Revenues From
31 Merchandising, 0
Jobbing and Contract
Work(415)
(Less)Costs and Exp.
32 of Merchandising, 0 0
Job.&Contract Work
(416)
Revenues From
33 Nonutility Operations 0 75,755
(417)
(Less)Expenses of
34 Nonutility Operations 7,891,784 11,488,060
(417.1)
FERC FORM No.1 (REV.02-04)
Page 114-117

STATEMENT OF INCOME
Current 3 Prior 3
Total Current Total Prior Year Months Months Electric Utility Electric Utility
(Ref.) Year to Date Ended- Ended- Previous Year
Line Title of Account Page No. Balance for to Date Balance(d) Quarterly Quarterly Current Year to to Date(in
No. (a) (b) Quarter/Year for Quarter/Year Only-No 4th Only-No 4th Date(in dollars) dollars)
(c) Quarter Quarter (g) (h)
(e) M
35 Nonoperating Rental (1,034) (6,089)
Income(418)
Equity in Earnings of
36 Subsidiary 119 4,449,671 39,795,257
Companies(418.1)
Interest and Dividend
37 15,537,184 2,112,087
Income(419)
Allowance for Other
38 Funds Used During (39,011) 804,751
Construction(419.1)
Miscellaneous
39 Nonoperating Income 16,773 0
(421)
40 Gain on Disposition 0 1,747,858
of Property(421.1)
TOTAL Other Income
41 (Enter Total of lines 12,071,799 33,041,559
31 thru 40)
Other Income l
42 Deductions
43 Loss on Disposition 40,896 0 I
of Property(421.2)
44 Miscellaneous 5,616 5,616
Amortization(425)
45 Donations(426.1) 2,755,476 2,832,367
46 Life Insurance(426.2) 2,661,064 3,588,360
47 Penalties(426.3) 25,450 24,039
i
Exp.for Certain Civic,
48 Political&Related 1,775,518 1,731,972
Activities(426.4)
49 Other Deductions 1,410,301 4,469,119
(426.5)
TOTAL Other Income
50 Deductions(Total of 8,674,321 12,651,473
lines 43 thru 49)
Taxes Applic.to Other
51 Income and
Deductions
52 Taxes Other Than 262 462,271 670,496
Income Taxes(408.2)
53 Income Taxes- 262 (2,079,651) (478,795)
Federal(409.2)
FERC FORM No.1 (REV.02-04)
Page 114-117

STATEMENT OF INCOME
Current 3 Prior 3
Total Current Total Prior Year Months Months Electric Utility Electric Utility
(Ref.) Year to Date Ended- Ended- Previous Year
Line Title of Account Page No. Balance for to Date Balance Quarterly Quarterly Current Year to to Date(in
No. (a) for Quarter/Year Date(in dollars)
(b) Quarter/Year (d) Only-No 4th Only-No 4th (g) dollars)
(c) Quarter Quarter (h)
(e) M
54] Income Taxes-Other
54 (409.2) 262 (75,004) (668,970)
55 Provision for Deferred 234. 3,954,988 1,568,707
Inc.Taxes(410.2) 272
(Less)Provision for 234,
56 Deferred Income 272 2,286,595 4,155,913
Taxes-Cr.(411.2)
Investment Tax Credit
57 Adj.-Net(411.5) 0 0
58 (Less)Investment Tax
Credits(420)
TOTAL Taxes on
59 Other Income and (23,991) (3,064,475)
Deductions(Total of
lines 52-58)
Net Other Income and
60 Deductions(Total of 3,421,469 23,454,561
lines 41,50,59)
61 Interest Charges
62 Interest on Long-Term 110,131,468 99,558,755
Debt(427)
63 Amort.of Debt Disc. 1,544,188 470,608
and Expense(428)
Amortization of Loss
on Reaquired Debt
64 (428.1) 1,317,067 1,433,640
(Less)Amort.of
65 Premium on Debt- 8,883 8,883
Credit(429)
(Less)Amortization of
66 Gain on Reaquired
Debt-Credit(429.1)
Interest on Debt to _
67 Assoc.Companies 2,503,671 1,062,531
(430)
68 Other Interest 21,435,607 9,696,574
Expense(431)
(Less)Allowance for
69 Borrowed Funds 8,892,489 3,826,333
Used During
Construction-Cr.(432)
Net Interest Charges
70 (Total of lines 62 thru 128,030,629 108,386,892
69)
FERC FORM No.1 (REV.02-04)
Page 114-117

STATEMENT OF INCOME
Current 3 Prior 3
Total Current Months Months Electric Utility
Total Prior Year Electric Utility
(Ref.) Year to Date Ended- Ended- Previous Year
No. (a) for Quarter/Year Line Title of Account Page No. Balance for to Qu Balance Ended
Quarterly Quarterly Current Year to Date(in dollars) to Date(in
(b) Quarter/Year (d) Only-No 4th Only-No 4th (g) dollars)
(c) Quarter Quarter (h)
(e) (�
Income Before
71 Extraordinary Items 171,180,214 155,176,032
(Total of lines 27,60
and 70)
72 Extraordinary Items
73 Extraordinary Income 0 0
(434)
74 (Less)Extraordinary
Deductions(435)
Net Extraordinary
75 Items(Total of line 73 0 0
less line 74)
Income Taxes-
76 Federal and Other 262 0 0
(409.3)
Extraordinary Items
77 After Taxes(line 75 0 0
less line 76)
78 Net Income(Total of 171,180,214 155,176,032
line 71 and 77)
FERC FORM No.1 (REV.02-04)
Page 114-117

STATEMENT OF INCOME
Line Gas Utiity Current Year to Date Gas Utility Previous Year to Other Utility Current Year to Other Utility Previous Year to
No. (in dollars) Date(in dollars) Date(in dollars) Date(in dollars)
(i1 Q1 (k) (I)
1
2 619,466,502 585,712,865
3 I
4 455,047,730 412,620,773
5 15,273,478 16,773,789
6 45,339,270 42,539,340 f
7 0 0
8 15,501,352 13,806,374
9 0 0
10
11 0 0
12 42,404,390 5,817,411
13 58,970,978 5,185,057
14 38,258,664 34,991,588
15 10,134,220 2,559,868
16 875,040 833,111
17 7,049,674 11,042,439
18 27,652,652 18,110,080
19 (4,720) 18
20
21
22
23
24
25 543,255,468 517,689,574 0 0
27 76,211,034 68,023,291 0 0
28 —
29
30
31
32
33
34
FERC FORM No.1 (REV.02-04)
Page 114-117

STATEMENT OF INCOME
Line Gas Utiity Current Year to Date Gas Utility Previous Year to Other Utility Current Year to Other Utility Previous Year to
No. (in dollars) Date(in dollars) Date(in dollars) Date(in dollars)
(k) (I)
35 - -
36
37
t
38 i
39 I-
40
41
42 -- - - -^- - -
43
44
45
46 - _
r, p4v
47
48 .
49 _
1
50
51
52
53
54
55
56
57
58
59 j
60
61
62
63
64
65
66 '
67
FERC FORM No.1 (REV.02-04)
Page 114-117

STATEMENT OF INCOME
Line Gas Utiity Current Year to Date Gas Utility Previous Year to Other Utility Current Year to Other Utility Previous Year to
No. (in dollars) Date(in dollars) Date(in dollars) Date(in dollars)
0) G) (k) (1)
68
69
70
71
72
73
74
75
76
77
78
FERC FORM No.1(REV.02-04)
Page 114-117

This report is: Year/Period of Report
Name of Respondent: (1)0 An Original Date of Report:
Avista Corporation (2) El A Resubmission 04/12/2024 End of:2023/Q4
STATEMENT OF RETAINED EARNINGS
Item Contra Primary Current QuarterlYear Year to Previous Quarter/Year Year
Line No. (a) Account Affected Date Balance to Date Balance
(b) (c) (d)
UNAPPROPRIATED RETAINED EARNINGS
(Account 216) fthw�
1 Balance-Beginning of Period 717,509,955 729,502,158
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)
16 Balance Transferred from Income(Account 433 166,730,543 115,380,775
less Account 418.1)
FERC FORM No.1 (REV.02-04)
Page 118-119

STATEMENT OF RETAINED EARNINGS
Item Contra Primary Current QuarterNear Year to Previous Quarterfyear Year
Line No. (a) Account Affected Date Balance to Date Balance
(b) (c) (d)
17 Appropriations of Retained Earnings(Acct.436)
17.1 Excess Earnings (1,835,879) (3,539,494)
17.2
17.3
17.4
22 TOTAL Appropriations of Retained Earnings (1,835,879) (3,539,494)
(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 Dividends Declared-Common Stock 141,368,296 129 264 336
30.2
30.3
30.4
30.5
36 TOTAL Dividends Declared-Common Stock (141,368,296) (129,264,336)
(Acct.438)
37 Transfers from Acct 216.1,Unapprop.Und i strib. 285,167 5,430,852
Subsidiary Earnings
38 Balance-End of Period(Total 741,321,490 717,509,955
1,9,15,16,22,29,36,37)
39 APPROPRIATED RETAINED EARNINGS
(Account215)
39.1 Appropriated Retained Earnings 56,893,689 55,057,810
39.2
39.3
39.4
39.5
39.6
FERC FORM No.1 (REV.02-04)
Page 118-119

STATEMENT OF RETAINED EARNINGS
Contra Primary Current Quarter/Year Year to Previous Quarter/Year Year
Line No. I a) Account Affected Date Balance to Date Balance
(b) (c) (d)
45 TOTAL Appropriated Retained Earnings 56,893,689 55,057,810
(Account215)
APPROP.RETAINED EARNINGS-AMORT.
Reserve,Federal(Account 215.1)
46 TOTAL Approp.Retained Eamings-Amort.
Reserve,Federal(Acct.215.1)
47 TOTAL Approp.Retained Earnings(Acct.215, 56,893,689 55,057,810
215.1)(Total 45,46)
48 TOTAL Retained Earnings(Acct.215,215.1, 798,215,179 772,567,765
216)(Total 38,47)(216.1)
UNAPPROPRIATED UNDISTRIBUTED
SUBSIDIARY EARNINGS(Account Report
only on an Annual Basis,no Quarterly)
49 Balance-Beginning of Year(Debit or Credit) ! 38,974,396 4,609,991
50 Equity in Earnings for Year(Credit)(Account 1 4,449,671 39,795,257
418.1)
51 (Less)Dividends Received(Debit) 5,000,000
52 TOTAL other Changes in unappropriated (285,167) (430,852)
undistributed subsidiary earnings for the year
52.1 Corporate Costs Allocated to Subsidiaries (285,167) (430,852)
r53 Balance-End of Year(Total lines 49 thru 52) 43,138,900 38,974,396
FERC FORM No.1 (REV.02-04)
Page 118-119

This report is:
Name of Respondent: (1)0 An Original Date of Report: Year/Period of Report
Avista Corporation (2) ❑A Resubmission 04/12/2024 End of:2023/Q4
STATEMENT OF CASH FLOWS
Description(See Instructions No.1 for explanation of Current Year to Date Quarter/Year Previous Year to Date
Line No. codes) Quarter/Year
(a) O (c)
1 Net Cash Flow from Operating Activities
2 Net Income(Line 78(c)on page 117) 171,180,214 155,176,032
3 Noncash Charges(Credits)to Income:
4 Depreciation and Depletion 256,851,952 241,470,709
5 Amortization of(Specify)(footnote details)
5.1 Amortization of Deferred Power and Natural Gas Costs 7,171,847 (77,882,317)
5.2 Amortization of Debt Expense 2,852,372 1,895,365
5.3 Amortization of Investment in Exchange Power
8 Deferred Income Taxes(Net) (36,037,425) (26,131,896)
9 Investment Tax Credit Adjustment(Net) (551,283) (528,731)
10 Net(Increase)Decrease in Receivables 39,845,414 (57,081,996)
11 Net(Increase)Decrease in Inventory 4,047,260 (22,224,699)
12 Net(Increase)Decrease in Allowances Inventory (30,071,678)
13 Net Increase(Decrease)in Payables and Accrued -(50,860,477) -83,122,813
Expenses
14 Net(Increase)Decrease in Other Regulatory Assets (53,098,758) 583,561
15 Net Increase(Decrease)in Other Regulatory Liabilities 34,302,152 10,248,033
16 (Less)Allowance for Other Funds Used During 6,340,790 6,543,085
Construction
17 (Less)Undistributed Earnings from Subsidiary 4,449,671 39,795,257
Companies
18 Other(provide details in footnote):
18.1 Cash Received for Settlement of Interest Rate Swaps 7,868,930
18.2 Other(provide details in footnote): -101,860,887 10(141,411,327)
18.3 Allowance for Doubtful Accounts 3,917,172 3,545,696
18.4 Changes in Other Non-Current Assets and Liabilities (13,741,356) 6,069,824
18.5 Cash Paid for Settlement of Interest Rate Swaps (409,000) (17,035,230)
22 Net Cash Provided by(Used in)Operating Activities 434,337,762 113,477,495
(Total of Lines 2 thru 21)
24 Cash Flows from Investment Activities:
25 Construction and Acquisition of Plant(including land): '
26 Gross Additions to Utility Plant(less nuclear fuel) ll(490,335,100) lw(449,340,115)
FERC FORM No.1 (ED.12-96)
Page 120-121

STATEMENT OF CASH FLOWS
Description(See Instructions No.1 for explanation of Current Year to Date Quarter/Year Previous Year to Date
Line No. codes) Quarteu'Year
(a) O (�)
27 Gross Additions to Nuclear Fuel
28 Gross Additions to Common Utility Plant
29 Gross Additions to Nonutility Plant
30 (Less)Allowance for Other Funds Used During
Construction
31 Other(provide details in footnote):
34 Cash Outflows for Plant(Total of lines 26 thru 33) (490,335,100) (449,340,115)
36 Acquisition of Other Noncurrent Assets(d)
37 Proceeds from Disposal of Noncurrent Assets(d) 1,913,172
39 Investments in and Advances to Assoc.and Subsidiary (11,411,922) (10,836,472)
Companies
40 Contributions and Advances from Assoc.and Subsidiary
Companies
41 Disposition of Investments in(and Advances to)
42 Disposition of Investments in(and Advances to)
Associated and Subsidiary Companies
44 Purchase of Investment Securities(a)
45 Proceeds from Sales of Investment Securities(a)
46 Loans Made or Purchased
47 Collections on Loans
49 Net(Increase)Decrease in Receivables
50 Net(Increase)Decrease in Inventory
51 Net(Increase)Decrease in Allowances Held for
Speculation
52 Net Increase(Decrease)in Payables and Accrued
Expenses
53 Other(provide details in footnote):
53.1 Other 1,199,766 1,820,492
53.2 Dividends Received from Subsidiaries 0 5,000,000
57 Net Cash Provided by(Used in)Investing Activities(Total (500,547,256) (451,442,923)
of lines 34 thru 55)
59 Cash Flows from Financing Activities:
60 Proceeds from Issuance of:
61 Long-Term Debt(b) 250,000,000 399,856,000
62 Preferred Stock
63 Common Stock 112,308,131 137,778,394
FERC FORM No.1 (ED.12-96)
Page 120-121

STATEMENT OF CASH FLOWS
Description(See Instructions No.1 for explanation of Current Yea t Date Quarter/Year Previous Year to Date
ro
Line No. codes) (b) Quarter/Year
(a) (c)
64 Other(provide details in footnote):
66 Net Increase in Short-Term Debt(c) 179,000,000
67 Other(provide details in footnote):
70 Cash Provided by Outside Sources(Total 61 thru 69) 362,308,131 716,634,394
72 Payments for Retirement of.,
73 Long-term Debt(b) (13,500,000) (250,000,000)
74 Preferred Stock
75 Common Stock
76 Other(provide details in footnote):
76.1 Debt Issuance Costs (3,323,740) (5,681,390)
76.2 Minimum Tax Witholdings m(1,497,107) -(1,462,256)
78 Net Decrease in Short-Term Debt(c) (114,000,000)
80 Dividends on Preferred Stock
81 Dividends on Common Stock (140,922,959) (129,060,998)
83 Net Cash Provided by(Used in)Financing Activities 89,064,325 330,429,750
(Total of lines 70 thru 81)
85 Net Increase(Decrease)in Cash and Cash Equivalents
86 Net Increase(Decrease)in Cash and Cash Equivalents 22,854,831 (7,535,678)
(Total of line 22,57 and 83)
88 Cash and Cash Equivalents at Beginning of Period 5,738,074 13,273,752
90 Cash and Cash Equivalents at End of Period 28,592,905 5,738,074
FERC FORM No.1 (ED.12-96)
Page 120-121

This report is:
Name of Respondent: (1)0 An Original Date of Report: Year/Period of Report
Avista Corporation 04/12/2024 End of:2023/Q4
(2) ❑ A Resubmission
FOOTNOTE DATA
U Concept:NetlncreaseDecreaselnPayablesAndAccruedExpensesOperatingActivities
Cash paid(received)during the period for:
Income taxes:$(1,439,727)
Interest:$125,249,194
Lb)Concept:OtherAdjustmentsToCashFlowsFromOperatingActivities
Power and natural gas deferrals(6,119,299);Change in special deposits 129,225,987;Change in other current assets(26,445,069);Non-cash stock
compensation 8,441,581;Loss on sale of property and equipment 40,896;Other(3,283,209).
Lc)Concept:GrossAdditionsToUtilityPlantLessNuclearFuellnvestingActivities
Additions to PPE in Accounts Payable:$33,691,044
Concept:OtherRetirementsOfBalances Impacting Cash Flows From Fin ancingActivities
Payment of minimum tax withholdings for share-based payment awards
Ue Concept:NetlncreaseDecreaselnPayablesAndAccruedExpensesOperatingActivities
Cash paid during the period for:
Income taxes:$445,203
Interest:$101,077,254
Mf Concept:OtherAdjustmentsToCashFlowsFromOperatingActivities
Power and natural gas deferrals(1,797,792);Change in special deposits(141,014,015);Change in other current assets(6,946,745);Non-cash stock
compensation 8,716,734;Gain on sale of property and equipment(1,747,858);Other 1,378,349.
kW Concept:GrossAdditionsToUtilityPlantLessNuclearFuellnvestingActivities
Additions to PPE in Accounts Payable:$27,708,348
Concept:OtherRetirementsOfBaIanceslmpactingCash Flows From FinancingActivities
Payment of minimum tax withholdings for share-based payment awards
FERC FORM No.1 (ED.12-96)
Page 120-121

This report is:
Name of Respondent: (1)®An Original Date of Report: Year/Period of Report
Avista Corporation (2) El A Resubmission 04/12/2024 End of:2023/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. Fumish particulars(details)as to any significant contingent assets or liabilities existing at end of year,including a brief explanation of
any action initiated by the 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. ForAccount 116,Utility Plant Adjustments,explain the origin of such amount,debits and credits during the year,and plan of
disposition contemplated,giving references to Commission 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.
NOTES TO FINANCIAL STATEMENTS
NOTE 1.SUMMARYOF SIGNIFICANT ACCOUNTING POLICIES
Nature of Business
Avista Corp.(the Company)is primarily an electric and natural gas utility with certain otherbusiness ventures.Avista Corp.provides electric distribution and transmission,and
natural gas distribution services in parts of eastern Washington and northern Idaho.Avista Corp.also provides natural gas distribution service in parts of northeastem and soutbwestem
Oregon.Avista Corp.has electric generating facilities in Washington,Idaho,Oregon and Montana.Avista Corp.also supplies electricity to a small number of customers in Montana.
Alaska Electric and Resource Company(AERC)is a wholly-owned subsidiary ofAvista Corp.The primary subsidiary ofAERC is Alaska Electric Light and Power(AEL&P),which
comprises Avista Corp:s regulated utility operations in Alaska.
Avista Capital,a wholly owned non-regulated subsidiary ofAvista Corp.,is the parent company ofthe subsidiary companies except AERC(and its subsidiaries}
Basis of Reporting
The financial statements include the assets,liabilities,revenues and expenses ofthe Company and have been prepared in accordance with the accounting requirements ofthe Federal
Energy Regulation Commission(FERC)as set forth in its applicable Uniform Systems ofAccounts and published accounting releases,which is a comprehensive basis of accounting
other than accounting principles generally accepted in the United States ofAmerica(U.S.GAAP).As required by the FERC,the Company accounts for its investment in majority
owned subsidiaries as required by U.S.GAAP.The accompanying financial statements include the Company's proportionate share ofutility plant and related operations associated
with its interests in jointly owned plants.hi addition,under the requirements ofthe 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 ofremoval of assets,(3)assets held for Sale,(4)regulatory assets and liabilities,(5)deferred income taxes associated with accounts other than
utility property,plant and equipment,(6)comprehensive income,(7)unamortized debt issuance costs,(8)operating revenues and resource costs associated with settled energy
contracts that are"booked out",(9)non-service portion ofpension and other postretirement benefit costs,and(10)leases.
Use of Estimates
The preparation ofthe financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported for assets and liabilities
and the disclosure of contingent assets and liabilities at the date ofthe financial statements and the reported amounts ofrevenues and expenses during the reporting period.Significant
estimates include:
• determining the market value of energy commodity derivative assets and liabilities,
• pension and other postretirement benefit plan obligations,
• contingent liabilities,
• goodwill impairment testing,
• recoverability ofregulatory assets,and
• unbilled revenues.
Changes in these estimates and assumptions are considered reasonably possible and may have a material effect on the financial statements and thus actual results could differ from the
amounts reported and disclosed herein.
System ofAccounts
The accounting records ofthe Company's utility operations are maintained in accordance with the uniform system of accounts prescribed by the FERC and adopted by the state
regulatory commissions in Washington,Idaho,Montana and Oregon.
Regulation
The Company is subject to state regulation in Washington,Idaho,Montana,Oregon and Alaska.The Company is subject to federal regulation primarily by the FERC,as well as
various other federal agencies with regulatory oversight ofparticular aspects ofits operations.

Depreciation
For utility operations,depreciation expense is estimated by a method ofdepreciation accounting utilizing composite rates for utility plant.Such rates are designed to provide for
retirements ofproperties at the expiration oftbeir service lives.For utility operations,the ratio ofdepreciation provisions to average depreciable property was as follows for the years
ended December 31:
2023 2022
Avista Corp. 3.52% 3.50%
The avenge service lives for the following broad categories ofutility plant in service are(in years):
Electric thermal/otherproduction 26
Hydroelectric production 79
Electric transmission 50
Electric distribution 40
Natural gas distribution property 44
Other shorter-lived general plant 8
AllowancejorFunds Used During Construction(AFUDQ
AFUDC represents the cost of both the debt and equity funds used to finance utility plant additions during the construction period.As prescribed by regulatory authorities,AFUDC is
capitalized as a part ofthe cast ofutility plant.The debt component ofAFUDC is credited against total interest expense in the Statements of Income in the line item"capitalized
interest."The equity component ofAFUDC is included in the Statements of Income in the line item"other income-net."The Company is permitted,under established regulatory rate
practices,to recover the capitalized AFUDC,and a reasonable return thereon,through its inclusion in rate base and the provision for depreciation after the related utility plant is
placed in service.Cash inflow related to AFUDC does not occur until the related utility plant is placed in service and included in rate base.
The WUTC and IPUC have authorized Avista Corp.to calculate AFUDC using its allowed rate ofretum.To the extent amounts calculated using this rate exceed the AFUDC amounts
calculated using the FERC formula,Avista Corp.capitalizes the excess as a regulatory asset.The regulatory asset associated with plant in service is amortized overtbe average useful
life ofAvista Corp.'s utility plant which is approximately 30 years.The regulatory asset associated with construction work in progress is not amortized until the plant is placed in
service.
The effective AFUDC rate was the following for the years ended December 31:
2023 2022
Avista Corp. 7.03% 7.12%
Income Taxes
Deferred income tax assets represent future income tax deductions the Company expects to utilize in future tax returns to reduce taxable income.Deferred income tax liabilities
represent future taxable income the Company expects to recognize in future tax returns.Deferred tax assets and liabilities arise when there are temporary differences resulting from
differing treatment of items for tax and accounting purposes.A deferred income tax asset or liability is determined based on the enacted tax rates that will be in effect when the
temporary differences between the financial statement carrying amounts and tax basis of existing assets and liabilities are expected to be reported in the Company's income tax returns.
The effect on deferred income taxes from a change in tax rates is recognized in income in the period that includes the enactment date unless a regulatory order specifies deferral ofthe
effect ofthe change in tax rates over a longer period of time.The Company establishes a valuation allowance when it is more likely than not that all,or a portion,of a deferred tax
asset will not be realized.Deferred income tax assets and liabilities and regulatory assets and liabilities are established for income tax benefits flawed through to customers.
The Company has elected to account for transferable tax credits as a component ofthe income tax provision.The Company recognizes the benefit ofproduction tax credits as a
reduction of income tax expense in the period the credit is generated,which corresponds to the period the energy production occurs.The Company applies the deferral method of
accounting for investment tax credits(ITCs).Under this method,ITCs are amortized as a reduction to income tax expense over the estimated useful lives of the underlying property
that gave rise to the credit.
The Company's largest deferred income tax item is the difference between the book and tax basis ofutility plant.This item results from the temporary difference on depreciation
expense.In early tax years,this item is recorded as a deferred income tax liability that will eventually reverse and become subject to income tax in later tax years.
The Company did not incurpenalties on income tax positions in 2023 or 2022.The Company would recognize interest accrued related to income tax positions as interest expense or
interest income and penalties incurred as other operating expense.
Stock-Based Compensation
The Company issues three types ofstock-based compensation awards-restricted shares,market-based awards and performance-based awards.Compensation cost relating to share-
based payment transactions is recognized in the Company's financial statements based on the fair value ofthe equity instruments issued and recorded over the requisite service period.
The Company recorded stock-based compensation expense(included in other operating expenses)and income tax benefits in the Statements of Income ofthe following amounts for
the years ended December 31(dollars in thousands):
2023 2022
Stock-based compensation expense $7,144 $7,567
Income tax benefits 1,500 1,589
Excess tax benefits(expenses)on settled share-based employee
payments 84 (19 )
Restricted share awards vest in equal thirds each year over 3 years and are payable in Avista.Corp.common stock at the end of each year if the service condition is met.Restricted
stock is valued at the close ofmarket ofthe Company's common stock on the grant date.
Total Shareholder Return(TSR)awards are market-based awards and Cumulative Earnings Per Share(CEPS)awards are performance awards.Both types of awards vest after a period of
3 years and are payable in cash or Avista Corp.common stock at the end ofthe three-year period.The method of settlement is at the discretion ofthe Company and historically the
Company has settled these awards through issuance of Avista Corp.common stock and intends to continue this practice.Both types of awards entitle the recipients to dividend
equivalent rights,are subject to forfeiture under certain circumstances,and are subject to meeting specific market or performance conditions.Based on the level of attainment ofthe
market orperformance conditions,the amount of cash paid or common stock issued will range from 0 to 200 percent ofthe initial awards granted.Dividend equivalent rights are
accumulated and paid out only on shares that have vested and have met the market and performance conditions.
The Company accounts for both the TSR awards and CEPS awards as equity awards and compensation cost for these awards is recognized over the requisite service period,provided
the requisite service period is rendered.For TSR awards,if the market condition is not met at the end ofthe three-year service period,there will be no change in the cumulative amount
of compensation cost recognized,since the awards are still considered vested even though the market metric was not met.For CEPS awards,at the end ofthe three-year service period,
ifthe internal performance metric of cumulative earnings per share is not met,all compensation cost for these awards is reversed as these awards are not considered vested.
The fair value ofeach TSR award is estimated on the date ofgrant using a statistical model incorporating the probability ofineeting the market targets based on historical returns
relative to a peer group.CEPS awards are valued at the close ofmarket ofthe Company's common stock on the grant date.
The following table summarizes the number ofgrants,vested and unvested shares,earned shares(based on market metrics),and other pertinent information related to the Company's
stock compensation awards for the years ended December 31:
2023 2022
Restricted Shares
Shares granted during the year 76,806 115,746
Shares vested during the year 75,007 44,829
Unvested shares at end ofyear 152,140 157,860
Unrecognized compensation expense at end ofyear
(in thousands) $3,477 $3,923
TSR Awards
TSR shares granted during the year 34,912 69,814
TSR shares vested during the year 61,456 43,730
TSR shares earned based on market metrics 44,863 48,890

Unvested TSR shares at end ofyear 96,915 130,567
Unrecognized compensation expense at end ofyear
(in thousands) $2,235 $3,533
CEPS Awards
CEPS shares granted during the year 104,685 69,814
CEPS shares vested during the year 61,456 43,730
CEPS shares earned based on performance metrics 33,801
Unvested CEPS shares at end ofyear 161,235 130,567
Unrecognized compensation expense at end ofyear
(in thousands) $2,439 $2,471
Outstanding restricted,TSR and CEPS share awards include a dividend component paid in cash.Aliability forthe dividends payable related to these awards is accrued as dividends
are announced throughout the life ofthe award.As ofDecember 31,2023 and 2022,the Company had recognized a liability of$2.2 million and$1.7 million,respectively,related to
the dividend equivalents payable on the outstanding and unvested share grants.
Cash and Cash Equivalents
For the purposes ofthe Statements of Cash Flows,the Company considers all temporary investments with a maturity of three months or less when purchased to be cash equivalents.
Allowance forpoubtful Accounts
The Company maintains an allowance for doubtful accounts to provide for estimated and potential losses on accounts receivable.The Company determines the allowance for utility
and othercustonwaeeounts receivable based on historical write-offs as compared to accounts receivable and operating revenues.Additionally,the Company establishes specific
allowances for certain individual accounts
Utility Plant in Service
The cost ofadditions to utility plant in service,including AFUDC and replacements ofunits ofproperty and improvements,is capitalized.The cost ofdepreciable units ofproperty
retired plus the cost ofremoval less salvage is charged to accumulated depreciation.
Asset Retirement Obligations(ARO)
The Company records the fair value of a liability for an ARO in the period in which it is incurred.When the liability is initially recorded,the associated costs ofthe ARO are
capitalized as part ofthe carrying amount ofthe related long-lived asset.The liability is accreted to its present value each period and the related capitalized costs are depreciated over
the useful life ofthe related asset.in addition,ifthere arc changes in the estimated timing or estimated costs ofthe AROs,adjustments ate recorded during the period new information
becomes available as an increase or decrease to the liability,with the offset recorded to the related long-lived asset.Upon retirement ofthe asset,the Company either settles the ARO
for its recorded amount or recognizes a regulatory asset or liability for the difference,which will be sureharged/refunded to customers through the mtemaking process.The Company
records regulatory assets and liabilities forthe difference between asset retirement costs currently recovered in rates and AROs recorded since asset retirement costs are recovered
through rates charged to customers(see Note 11 for further discussion ofthe Company's AROs).
Derivative Assets and Liabilities
Derivatives are recorded as either assets or liabilities on the Balance Sheets measured at estimated fair value.
The Washington Utilities and Transportation Commission(WUTC)and the Idaho Public Utilities Commission(IPUC)issued accounting orders authorizing Avista Corp.to offset
energy commodity derivative assets or liabilities with a regulatory asset or liability.This accounting treatment is intended to defer the recognition ofmark-to-market gains and losses
on energy commodity transactions until the period ofdelivery.Realized benefits and costs result in adjustments to retail rates through Purchase Gas Adjustments(PGAs),the Energy
Recovery Mechanism(ERM)in Washington,the Power Cost Adjustment(PCA)mechanism in Idaho,and periodic general rate cases.The resulting regulatory assets associated with
energy commodity derivative instruments are probable ofrecovery through future rates.
Substantially all forward contracts to purchase or sell power and natural gas are recorded as derivative assets or liabilities at estimated fair value with an offsetting regulatory asset or
liability.Contracts not considered derivatives are accounted for on the accrual basis until they are settled or realized unless there is a decline in the fair value ofthe contract
determined to be other-than-temporary.
For interest rate swap derivatives,Avista Corp.records all mark-to-market gains and losses in each accounting period as assets and liabilities,as well as offsetting regulatory assets and
liabilities,such that there is no income statement impact.The interest rate swap derivatives are risk management tools similar to energy commodity derivatives.Upon settlement of
interest rate swap derivatives,the regulatory asset or liability is amortized as a component of interest expense over the term ofthe associated debt.The Company records an offset of
interest rate swap derivative assets and liabilities with regulatory assets and liabilities,based on the prior practice ofthe commissions to provide recovery through the ratemaking
process.
The Company has multiple master netting agreements with a variety ofentitics allowing for cross-commodity netting ofderivative agreements with the same counterparty(i.e.power
derivatives can be netted with natural gas derivatives).In addition,some master netting agreements allow for the netting ofcommodity derivatives and interest rate swap derivatives
for the same counterparty.The Company does not have agreements which allow for cross-affiliate netting among multiple affiliated legal entities.The Company nets all derivative
instruments when allowed by the agreement forpresentation in the Balance Sheets.
Fair Value Measurements
Fair value represents the price that would be received when selling an asset orpaid to transfer a liability(an exit price)in an orderly transaction between market participants at the
measurement date.Energy commodity derivative assets and liabilities,deferred compensation assets,as well as derivatives related to interest rate swaps and foreign currency exchange
contracts,are reported at estimated fairvalue on the Balance Sheets.See Note 13 forthe Company's fairvalue disclosures.
Regulatory Deferred Charges and Credits
The Company prepares its financial statements in accordance with regulatory accounting practices because:
• rates for regulated services are established by or subject to approval by independent third-party regulators,
• the regulated rates are designed to recover the cost ofproviding the regulated services,and
• in view of demand for the regulated services and the level of competition,it is reasonable to assume that rates can be charged to and collected from customers
at levels that will recover costs.
Regulatory accounting pmctiou require certain costs and/or obligations(such as incurred power and natural gas costs not currently reflected in rates,but expected to be recovered or
refunded in the future),to be reflected as deferred charges or credits on the Balance Sheets.These costs and/or obligations are not reflected in the Statements of Income until the period
during which matching revenues are recognized.The Company also has decoupling revenue deferrals.See Note 2 for discussion on decoupling revenue deferrals.
Ifat some point in the future the Company determines it no longer meets the criteria for continued application ofregulatory accounting practices for all or a portion ofits regulated
operations,the Company could be:
• required to write off its regulatory assets,and
• precluded from the future deferral of costs or decoupled revenues not recovered through rates at the time such amounts are incurred,even if the Company
expected to recover these amounts from customers in the future.
Unamortized Debt Expense
Unamortized debt expense includes debt issuance costs that are amortized over the life ofthe related debt.
Unamortized Debt Repurchase Costs
For the Company's Washington regulatory jurisdiction and for any debt repurchases beginning in 2007 in all jurisdictions,premiums and discounts paid to repurchase debt are
amortized over the remaining life ofthe original debt repurchased or,ifnew debt is issued in connection with the repurchase,these amounts are amortized over the life ofthe new debt.
In the Companys other regulatory jurisdictions,premiums or discounts paid to repurchase debt prior to 2007 are being amortized over the average remaining maturity ofoutstanding
debt when no new debt was issued in connection with the debt repurchase.The premium and discount costs am recovered or returned to customers through retail rates as a component

o£interest expense.
Appropriated Retained Earnings
In accordance with the hydroelectric licensing requirements of section 10(d)oftbe Federal Power Act(FPA),the Company maintains an appropriated retained earnings account for
earnings in excess ofthe specified rate of return on the Company's investment in the licenses for its various hydroelectric projects.Per section 10(d)of the FPA,the Company must
maintain these excess earnings in an appropriated retained earnings account until the termination ofthe licensing agreements or apply them to reduce the net investment in the
licenses ofthe hydroelectric projects at the discretion ofthe FERC.The Company calculates the earnings in excess ofthe specified rate ofretum on an annual basis,usually during the
second quarter
The appropriated retained earnings amounts included in retained earnings were as follows as of December 31(dollars in thousands):
2023 2022
Appropriated retained earnings $56,894 $55,058
Contingencies
The Company has unresolved regulatory,legal and tax issues which have inherently uncertain outcomes.The Company accrues a loss contingency ifit is probable that a liability has
been incurred and the amount ofthe loss or impairment can be reasonably estimated.The Company also discloses loss contingencies that do not meet these conditions for accrual,if
there is a reasonable possibility that a material loss may be incurred.As ofDecember 31,2023,the Company has not recorded significant amounts related to unresolved contingencies.
See Note 15 for further discussion ofthe Company's commitments and contingencies.
Equity in Earnings(Losses)of Subsidiaries
The Company records all the earnings(losses)from its subsidiaries under the equity method.The Company had the following equity in earnings(losses)of its subsidiaries for the
years ended December 31(dollars in thousands):
2023 2022
Avista Capital $ (4,288) $ 32,423
AERC 8,738 7,372
Total equity in earnings of subsidiary companies $ 4,450 $ 39,795
Subsequent Events
Management has evaluated the impact of events occurring after December 31,2023 up to February 20,2024,the date that Avista Corp.'s U.S.GAAP financial statements were issued
and has updated such evaluation for disclosure purposes through the date ofthis filing.These financial statements include all necessary adjustments and disclosures resulting from
these evaluations.
NOTE 2.REVENUE
The core principle ofthe revenue recognition model is that an entity should identify the various performance obligations in a contract,allocate the transaction price among the
performance obligations and recognize revenue when(or as)the entity satisfies each performance obligation.
Utility Revenues
Revenue from Contracts with Customers
General
The majority ofAvista Corp's revenue is from rate-regulated sales of electricity and natural gas to retail customers,which has two performance obligations,(1)having service
available for a specified period(typically a month at a time)and(2)the delivery of energy to customers.The total energy price generally has a fixed component(basic charge)related
to having service available and a usage-based component,related to the delivery and consumption of energy.The commodity is sold and/or delivered to and consumed by the
customer simultaneously,and the provisions ofthe relevant utility commission authorization determine the charges the Company may bill the customer.Since all revenue recognition
criteria are met upon the delivery of energy to customers,revenue is recognized immediately.
hi addition,the sale of electricity and natural gas is governed by the various state utility commissions,which set rates,charges,terms and conditions of service,and prices.
Collectively,these rates,charges,terms and conditions are included in a"tariff,"which governs all aspects ofthe provision ofregulated services.Tariffs are only permitted to be
changed through a rate-setting process involving an independent,third-party regulator empowered by statute to establish rates that bind customers.Thus,all regulated sales by the
Company are conducted subject to the regulator-approved tariff.
Tariffsales involve the current provision ofcommodity service(electricity and/ornatural gas)to customers for a price that generally has a basic charge and a usage-based component.
Tariffrates also include certain pass-through costs to customers such as natural gas costs,retail revenue credits and other miscellaneous regulatory items that do not impact net income,
but can cause total revenue to fluctuate significantly up or down compared to previous periods.The commodity is sold and/or delivered to and consumed by the customer
simultaneously,and the provisions of the relevant tariffdetemrine the charges the Company may bill the customer,payment due date,and other pertinent rights and obligations of
both parties.Generally,tariffsales do not involve a written contract.Since all revenue recognition criteria are met upon the delivery of energy to customers,revenue is recognized at
that time.
Unbilled Revenuefrom Contracts with Customers
The determination ofthe volume of energy sales to individual customers is based on the reading of their meters,which occurs on a systematic basis throughout the month(once per
month for each individual customer).At the end of each calendarmonth,the amount of energy delivered to customers since the date ofthe last meterreading is estimated and the
corresponding unbilled revenue is estimated and recorded.The Company's estimate of unbilled revenue is based on:
the number of customers,
tariff rates,
meterreading dates,
actual native load for electricity,
actual throughputfornatural gas,and
electric line losses and natural gas system losses.
Any difference between actual and estimated revenue is automatically corrected in the following month when the meterreading and customerbilling occurs.
Accounts receivable includes unbilled energy revenues ofthe following amounts as ofDecember3l(dollars in thousands):
2023 2022
Unbilled accounts receivable $ 75,650 $ 78,873
Non-Derivative Wholesale Contracts
The Company has certain wholesale contracts that are not accounted for as derivatives and are considered revenue from contracts with customers.Revenue is recognized as energy is
delivered to the customer or the service is available for specified period of time,consistent with the discussion ofrate regulated sales above.
Alternative Revenue Programs(Decoupling)
ASC 606 retained existing GAAP associated with alternative revenue programs,which specified alternative revenue programs are contracts between an entity and a regulator of
utilities,not a contract between an entity and a customer.GAAPrequires the presentation of revenue arising from alternative revenue programs separately from revenues arising from
contracts with customers on the Statements ofIncome.The Company's decoupling mechanisms(also known as a FCAin Idaho)qualify as alternative revenue programs.Decoupling

revenue deferrals are recognized in the Statements of income during the period they occur(i.e.during the period ofrevenue shortfall or excess due to fluctuations in customer usage),
subject to certain limitations,and a regulatory asset or liability is established which will be surcharged or rebated to customers in future periods.GAAP requires that for an alternative
revenue program,like decoupling,the revenue must be expected to be collected from customers within 24 months ofthe deferral to qualify for recognition in the Statements of
Income.Amounts included in the Company's decoupling program that are not expected to be collected from customers within 24 months are not recorded in the financial statements
until the period in which revenue recognition criteria are met.The amounts expected to be collected from customers within 24 months represents an estimate made by the Company on
an ongoing basis due to it being based on the volumes of electric and natural gas sold to customers on a go-forward basis.
The Company records alternative program revenues under the gross method,which is to amortize the decoupling regulatory asset/liability to the alternative revenue program line item
on the Statements of Income as it is collected from orrefunded to customers.The cash passing between the Company and the customers is presented in revenue from contracts with
customers since it is a portion ofthe overall tariffpaid by customers.This method results in a gross-up to both revenue from contracts with customers and revenue from alternative
revenue programs,but has a net zero impact on total revenue.Depending on whetherthe previous deferral balance being amortized was a regulatory asset orregulatory liability,and
depending on the size and direction ofthe current year deferral ofsurcharges and/or rebates to customers,it could result in negative alternative revenue program revenue during the
year.
Derivative Revenue
Most wholesale electric and natural gas transactions(including both physical and financial transactions),and the sale offuel are considered derivatives,which are disclosed separately
from revenue from contracts with customers.Revenue is recognized for these items upon the settlement/expiration ofthe derivative contract.Derivative revenue includes transactions
entered into and settled within the same month.
Other Utility Revenue
Other utility revenue includes rent,sales of materials,late fees and other charges that do not represent contracts with customers.This revenue is excluded from revenue from contracts
with customers,as this revenue does not represent items where a customer is a party that has contracted with the Company to obtain goods or services that are an output ofthe
Company's ordinary activities in exchange for consideration.As such,these revenues are presented separately from revenue from contracts witb customers.
Other Considerations for Utility Revenues
Gross Versus Net Presentation
Utility-related taxes collected from customers(primarily state excise taxes and city utility taxes)are imposed on Avista Corp.as opposed to being imposed on customers;therefore,
Avista Corp.is the taxpayer and records these transactions on a gross basis in revenue from contracts with customers and operating expense(taxes other than income taxes).
Utility-related taxes included in revenue from contracts with customers were as follows for the years ended December 31(dollars in thousands):
2023 2022
Utility-related taxes $75,404 $69,931
Significant Judgments and Unsatisfied Performance Obligations
The only significant judgments involving revenue recognition are estimates surrounding unbilled revenue and receivables from contracts with customers and estimates surrounding
the amount of decoupling revenues that will be collected from customers within 24 months(discussed above).
The Company has certain capacity arrangements,where the Company has a contractual obligation to provide either electric or natural gas capacity to its customers for a fixed fee.
Most of these arrangements are paid for in arrears by the customers and do not result in deferred revenue and only result in receivables from the customers.The Company has one
capacity agreement where the customer makes payments throughout the year.As of December 3l,2023,the Company estimates it had unsatisfied capacity performance obligations of
$7.4 million,which will be recognized as revenue in future periods as the capacity is provided to the customers.These performance obligations are not reflected in the financial
statements,as the Company has not received payment for these services.
NOTE 3.LEASES
The core principle of lease accounting is that an entity should recognize the ROU assets and liabilities from leases on the balance sheet and depreciate or amortize the asset and
liability over the term ofthe lease,as well as provide disclosure to enable users ofthe financial statements to assess the amount,timing,and uncertainty of cash flows from leases.For
regulatory reporting,the FERC provided prescribed accounts for the ROU assets and liabilities,with the ROU assets being included in utility plant(FERC account 101)and the lease
liabilities being included in capital lease obligations(FERC account 227).These accounts are different than the accounts allowed for in GAAP reporting,which results in a
FERC/GAAP difference.
Significant Judgments and Assumptions
The Company determines if an arrangement is a lease,as well as its classification,at its inception.
ROU assets represent the Company's right to use an underlying asset for the lease term,and lease liabilities represent the Company's obligation to make lease payments.Operating
lease ROU assets and lease liabilities are recognized at the commencement date ofthe agreement based on the present value of lease payments over the lease term.As most ofthe
Company's leases do not provide an implicit rate,the Company uses its incremental borrowing rate based on the information available at the commencement date to determine the
present value of lease payments.The implicit rate is used when it is readily determinable.The operating lease ROU assets also includes lease payments made and exclude lease
incentives,ifany,that accrue to the benefit ofthe lessee.
Lease terms may include options to extend orterminate the lease when it is reasonably certain the Company will exercise that option.Lease expense is recognized on a straight-line
basis over the lease term.The difference between lease expense and cash paid for leased assets is recognized as a regulatory asset or regulatory liability.
Description ofLeases
Operating Leases
The Company's most significant operating lease is with the State ofMontana associated with submerged land around the Company's hydroelectric facilities in the Clark Fork River
basin,which expires in 2046.The terms of this lease are subject to adjustment-depending on the outcome of ongoing litigation between the State ofMontana and NorthWestem.In
addition,the State ofMontana and Avista Corp.were engaged in litigation regarding lease terms,including how much money,if any,the State ofMontana should return to Avista
Corp.;however,that litigation was dismissed as premature pending the outcome ofthe ongoing litigation between the State ofMontana and NorthWestem.Any reduction in future
lease payments orthe return to Avista Corp.of amounts previously paid will be included in the future mtemaking process.
In addition to the lease with the State ofMontana,the Company has other operating leases for land associated with its utility operations,as well as communication sites which support
network and radio communications within its service territory.The Company's leases have remaining terms of 1 to 70 years.Most ofthe Company's leases include options to extend
the lease term forperiods of5 to 50 years.Options are exercised at the Company's discretion.
Certain ofthe Company's lease agreements include rental payments which are periodically adjusted overthe term ofthe agreement based on the consumerprice index.The Company's
lease agreements do not include material residual value guarantees ormaterial restrictive covenants.
In March 2023,the Company entered into an agreement with Rathdrum Power,LLC amending and restating a PPAfor the output ofthe Lancaster Plant.The restated PPA meets the
accounting definition ofa lease,and all payments are variable in nature,based on capacity,usage,orperformance ofthe plant.Therefore,there is no lease obligation or corresponding
ROU asset recorded by the Company related to this agreement.The variable lease costs related to this agreement are included in resource costs on the Statements of Income.
Avista Corp.does not record leases with a term of 12 months or less in the Balance Sheets.Total short-terns lease costs for the year ended December 31,2023 are immaterial.
The components oflease expense were as follows for the year ended December 31(dollars in thousands):
2023 2022 2021
Operating lease cost:
Fixed lease cost(Other operating expenses) f 5,096 $ 4,986 $ 4,970
Variable lease cost(Other operating expenses and Resource costs) 24,628 1,567 1,180
Total operating lease cost S 29,724 $ 6,553 $ 6,150
Supplemental cash flow information related to leases was as follows for the year ended December 31(dollars in thousands):
2023 2022 2021

Cash paid for amounts included in the measurement of lease liabilities:
Operating cash outflows:
Operating lease payments $4,960 $4,828 $4,805
Supplemental balance sheet information related to leases was as follows for December 31(dollars in thousands):
December 31, December 31,
2023 2022
Operating Leases
Operating lease ROU assets(Utility Plant) $67,585 $68,238
Obligations under capital lease-current $4,490 $4,349
Obligations under capital lease-noncurrent 63,559 64,284
Total operating lease liabilities $68,049 $68,633
Weighted Average Remaining Lease Term
Operating leases 2228 years 2328 years
Weighted Average Discount Rate
Operating leases 4.29 % 4.28 %
Maturities of lease liabilities(including principal and interest)were as follows as ofDecember 31,2023(dollars in thousands):
Operating Lcascs
2024 $4,988
2025 4,984
2026 4,981
2027 5,007
2028 4,992
Thereafter 83,532
Total lease payments $108,484
Less:imputed interest (40,435 )
Total $68,049
Maturities oflease liabilities(including principal and interest)were as follows as ofDecember 31,2022(dollars in thousands):
Oper ting Lcaus
2023 $4,850
2024 4,877
2025 4,884
2026 4,869
2027 4,880
Thereafter 86,991
Total lease payments $111,351
Less:imputed interest (42,718 )
Total $68,633
NOTE 4.DERIVATIVES AND RISK MANAGEMENT
Energy Commodity Derivatives
Avista Corp.is exposed to market risks relating to changes in electricity and natural gas commodity prices and certain other fuel prices.Market risk is,in general,the risk of
fluctuation in the market price ofthe commodity being traded and is influenced primarily by supply and demand.Market risk includes the fluctuation in the market price of associated
derivative commodity instruments.Avista Corp.utilizes derivative instruments,such as forwards,futures,swap derivatives and options to manage the various risks relating to these
commodity price exposures.Avista Corp.has an energy resources risk policy and control procedures to manage these risks.
As part of Avista Corp.'s resource procurement and management operations in the electric business,Avista Corp.engages in an ongoing process of resource optimization,which
involves the economic selection from available energy resources to serve Avista Corp.'s load obligations and the use ofthese resources to capture available economic value through
wholesale market transactions.These include sales and purchases of electric capacity and energy,fuel for electric generation,and derivative contracts related to capacity,energy and
fuel.Such transactions are part ofthe process ofmatching resources with load obligations and hedging a portion ofthe related financial risks.These transactions range from terms of
intra-hour up to multiple years.
As part of its resource procurement and management of its natural gas business,Avista Corp.makes continuing projections of its natural gas loads and assesses available natural gas
resources including natural gas storage availability.Natural gas resource planning typically includes peak requirements,low and average monthly requirements and delivery
constraints from natural gas supply locations to Avista Corp.'s distribution system.However,daily variations in natural gas demand can be significantly different than monthly
demand projections.Based on these projections,Avista Corp.plans and executes a series oftransactions to hedge a portion of its projected natural gas requirements through forward
market transactions and derivative instruments.These transactions may extend as much as three natural gas operating years(November through October)into the future.Avista Corp.
also leaves a significant portion of its natural gas supply requirements unhedged forpurchase in short-term and spot markets.
Avista Corp.plans for sufficient natural gas delivery capacity to serve its retail customers for a theoretical peak day event.Avista Corp.generally has more pipeline and storage
capacity than what is needed during periods other than a peak day.Avista Corp.optimizes its natural gas resources by using market opportunities to generate economic value that
mitigates the fixed costs.Avista Corp.also optimizes its natural gas storage capacity by purchasing and storing natural gas when prices are traditionally lower,typically in the summer;
and withdrawing during higherpriced months,typically during the winter.However,if market conditions and prices indicate that Avista Corp.should buy or sell natural gas at other
times during the year,Avista Corp.engages in optimization transactions to capture value in the marketplace.Natural gas optimization activities include,but are not limited to,
wholesale market sales of surplus natural gas supplies,purchases and sales ofnatural gas to optimize use ofpipeline and storage capacity,and participation in the transportation
capacity release market.
The following table presents the underlying energy commodity derivative volumes as of December31,2023 expected to be delivered in each respective year(in thousands ofMWhs
and mmBTUs):
Purchases Sales
Electric Derivatives Gas Derivatives Electric Derivatives Gas Derivatives
Physical(1) Financial(1) Physical(1) Financial(1) Physical(1) Financial(1) Physical(1) Financial(1)
Year MWh MWh mmBTUs mmBTUs MWh NM -BTUs mmBTUs
2024 9 22,747 74,596 472 510 1,723 12,038
2025 12,505 19,590 11 96 1,115 1,125
2026 5570 3,940
As ofDecember 31,2023,there are no expected deliveries of energy commodity derivatives after 2026.
The following table presents the underlying energy commodity derivative volumes as ofDecember 31,2022 that were expected to be delivered in each respective year(in thousands
ofMWhs and mmBTUs):

Purcbases Sales
Electric Derivatives Gas Derivatives Electric Derivatives Gas Derivatives
Physical(1) Financial(1) Physical(1) Financial(1) Physical(1) Financial(1) Physical(1) Financial(1)
Year MWh MWh ..BTUs ..BTUs MWh MWh m.BTUs m.BTUs
2023 5 19,140 79,253 136 1,011 4,145 29,473
2024 533 30,658 1,370 9,668
2025 450 4,895 1,115 1,125
As of December 31,2022,there were no expected deliveries of energy commodity derivatives after 2025.
(I)Physical transactions represent commodity transactions in which Avista Corp.will take or make delivery ofeitherelectricity or natural gas;financial transactions represent
derivative instruments with delivery of cash in the amount ofthe benefit or cost but with no physical delivery ofthe commodity,such as futures,swap derivatives,options,or
forward contracts.
The electric and natural gas derivative contracts above will be included in either power supply costs ornatural gas supply costs during the period they are scheduled to be delivered
and will be included in the various deferral and recovery mechanisms(@RM,PCA,and PGAs),or in the general rate case process,and are expected to be recovered through retail rates
from customers.
Foreign Currency Exchange Derivatives
Asignificant portion of Avista Corp.'s natural gas supply(including fuel for power generation)is obtained from Canadian sources.Most of those transactions are executed in U.S.
dollars,which avoids foreign currency risk.Aportion of Avista Corp.'s short-term natural gas transactions and long-term Canadian transportation contracts are committed based on
Canadian currency prices.The short term natural gas transactions arc settled within 60 days with U.S.dollars.Avista Corp.hedges a portion ofthe foreign currency risk by purchasing
Canadian currency exchange derivatives when such commodity transactions are initiated.The foreign currency exchange derivatives and the unbedged foreign currency risk have not
had a material effect on Avista Corp.'s financial condition,results of operations or cash flows and these differences in cost related to currency fluctuations are included with natural gas
supply costs for ratemaking.
The following table summarizes the foreign currency exchange derivatives outstanding as ofDecember 31(dollars in thousands):
2023 2022
Number of contracts 5 19
Notional amount(in United States dollars) $81 $8,563
Notional amount(in Canadian dollars) 109 11,659
Interest Rate Swap Derivatives
Avista Corp.is affoeted by fluctuating interest rates related to a portion of its existing debt,and future borrowing requirements.Avista Corp.may hedge a portion of its interest rate risk
with financial derivative instruments,including interest rate swap derivatives.These interest rate swap derivatives are considered economic hedges against fluctuations in future cash
flows associated with anticipated debt issuances.
The following table summarizes the unsettled interest rate swap derivatives outstanding as ofthe balance sheet date indicated below(dollars in thousands):
Mandatory Cash
Balance Sheet Date Number of Contracts Notional Amount Settlement Date
December31,2023 2 $ 20,000 2024
1 10,000 2025
December 31,2022 4 S 40,000 2023
1 10,000 2024
The fair value ofoutstanding interest rate swap derivatives can vary significantly from period to period depending on the total notional amount ofswap derivatives outstanding and
fluctuations in market interest rates compared to the interest rates fixed by the swaps.Avista Corp.is required to make cash payments to settle the interest rate swap derivatives when
the fixed rates are higher than prevailing market rates at the date ofsculement.Conversely,Avista Corp.receives cash to settle its interest rate swap derivatives when prevailing market
rates at the time of settlement exceed the fixed swap rates.
Summary of Outstanding Derivative Instruments
The amounts recorded on the Balance Sheets as of December3l,2023 and December 3l,2022 reflect the offsetting ofderivative assets and liabilities where a legal right ofoffset
exists.
The following table presents the fair values and locations of derivative instruments recorded on the Balance Sheets as ofDecember 31,2023(dollars in thousands):
Fair Nblue
Net Asset
(Liability)
Gross Gross Collateral on Balance
Derivative and Balance Sheet Location Asset Liability Netting Sheet
Foreign currency exchange derivatives
Derivative instrument assets current S 2 $ $ $ 2
Interest rate swap derivatives
Derivative instrument assets current 3,667 3,667
Long-term portion ofderivative liabilities (182) (182)
Energy commodity derivatives
Derivative instrument assets current 8,531 (379) 8,152
Derivative instrument liabilities current 19,510 (79,082) 42,355 (17,217
Long-term portion ofderivative liabilities 2,913 (20,633) (17,720)
Total derivative instruments recorded on the
balance sheet $ 34,623 $ (100,276) $ 42,355 $ (23,298)
The following table presents the fairvalues and locations ofderivative instruments recorded on the Balance Sheets as ofDecember3l,2022(dollars in thousands):
Fair Value
Net Asset
(Liability)
Gross Gross Collateral on Balance
Derivative and Balance Sheet Location Asset Liability Netting Sheet
Foreign currency exchange derivatives
Derivative instrument assets current $43 S $ $43
Derivative instrument liabilities current (3 ) (3 )
Interest rate swap derivatives
Derivative instrument assets current 8,536 8,536
Long-term portion ofderivative assets 2,648 2,648
Derivative instrument liabilities current (52 1 (52 )
Energy commodity derivatives
Derivative instrument assets current 32,257 (22,638 ) 9,619
Long-term portion ofderivative assets 312 (16 1 296
Derivative instrument liabilities current 107,902 (229,607 94,850 (26,855
Long-term portion ofderivative liabilities 6,049 (24,530 ) 10,589 (7,892 )
Total derivative instruments recorded on the
balance sheet $$157,7477 $$(276,8® $105,439 $(13,660 )
Exposure to Demandsfor Collateral

Avista Corp's derivative contmets o$en require collateral(in the form of cash or le—tters of credit)or other credit enhancements,or reductions or terminations inations of a portion of the
contract through cash settlement.In the event of changes in market prices or a downgrade in Avista Corp:s credit ratings or other established credit criteria,additional collateral may
be required.In periods ofprice volatility,the level of exposure can change significantly.As a result,sudden and significant demands may be made against Avista Corp:s credit
facilities and cash.Avista Corp.actively monitors the exposure to possible collateral calls and takes steps to mitigate capital requirements.
The following table presents collateral outstanding related to its derivative instruments as of December 31(dollars in thousands):
2023 2022
Energy commodity derivatives
Cash collateral posted $ 43,095 $ 171,581
Letters of credit outstanding 20,000 49,425
Balance sheet offsetting(cash collateral against net derivative positions) 42,355 105,439
There were no letters of credit outstanding related to interest rate swap derivatives as of December 31,2023 and December 31,2022.
Certain of Avista Corps derivative instruments contain provisions requiring Avista Corp.to maintain an"investment grade"credit rating from the major credit rating agencies.If
Avista Corp.'s credit ratings were to fall below"investment grade,"it would be in violation ofthese provisions,and the counterparties to the derivative instruments could request
immediate payment ordemand immediate and ongoing collateralization on derivative instruments in net liability positions.
The following table presents the aggregate fair value of all derivative instruments with credit-risk-related contingent features in a liability position and the amount of additional
collateral Avista Corp.could be required to post as of December 31(dollars in thousands):
2023
Interest rate swap derivatives
Liabilities with credit-risk-related contingent features S 182
Additionall collateral to post 182
Energy commodity derivatives
Liabilities with credit-risk-related contingent features $ 18,016
Additional collateral to post 15,125
NOTE 5.JOINTLYOWNED ELECTRIC FACILITIES
The Company has a 15 percent ownership interest in Units 3 and 4 of Colstrip,and provides financing for its ownership interest in the project.Pursuant to the ownership and operating
agreements among the co-owners,the Company's share ofrelated fuel costs as well as operating expenses forplant in service are included in the corresponding accounts in the
Statements of Income.The Company's share ofutility plant in service for Colstrip and accumulated depreciation(inclusive ofthe ARO assets and accumulated amortization)were as
follows as of December31(dollars in thousands):
2023 2022
Utility plant in service $ 394,398 $ 390,852
Accumulated depreciation (334,339) (315,223)
See Note 6 for further discussion of AROs.
While the obligations and liabilities with respect to Colstrip are to be shared among the co-owners on a pro-rata basis,many of the environmental liabilities are joint and several under
the law,so that if any co-owner failed to pay its share of such liability,the other co-owners(or any one of them)could be required to pay the defaulting co-owner's share(or the entire
liability).
In January 2023,the Company entered into an agreement with NorthWestem to transfer its ownership in Colstrip Units 3 and 4.The Company will retain responsibility for remediation
obligations in existence at the time the transaction closes.See further discussion ofthe transaction within Note 15.
NOTE 6.ASSET RETIREMENT OBLIGATIONS
The Company has recorded liabilities for future AROs to:
• restore coal ash containment ponds and coal holding areas at Colstrip,
• cap a landfill at the Kettle Falls Plant,and
• remove plant and restore the land at the Coyote Springs 2 site at the termination ofthe land lease.
Due to an inability to estimate a range of settlement dates,the Company cannot estimate a liability for the:
• removal and disposal ofcertain transmission and distribution assets,and
• abandonment and decommissioning ofcertain hydroelectric generation and natural gas storage facilities.
In 2015,the EPA issued a final rule regarding CCRs.Colstrip produces this byproduct.The CCR rule has been the subject of ongoing litigation.In August 2018,the D.C.Circuit
struck down provisions ofthe rule.The rule includes technical requirements for CCR landfills and surface impoundments.The Colstrip owners developed a multi-year compliance
plan to address the CCR requirements and existing state obligations.
The actual asset retirement costs related to the CCR rule requirements may vary substantially from the estimates used to record the ARO due to the uncertainty and evolving nature of
the compliance strategies that will be used and the availability ofdata used to estimate costs,such as the quantity ofcoal ash present at certain sites and the volume offill that will be
needed to cap and cover certain impoundments.The Company updates its estimates as new information becomes available.The Company expects to seek recovery of costs related to
complying with the CCR role through the ratemaking process.
In addition to the above,under a 2018 Administrative Order on Consent and ongoing negotiations with the Montana Department of Ecological Quality,the owners of Colstrip are
required to provide financial assurance,primarily in the form of surety bonds,to secure each owner's pro-rata share of various anticipated closure and remediation ofthe ash ponds and
coal holding areas.The amount of financial assurance required of each owner may,like the ARO,vary substantially due to the uncertainty and evolving nature of anticipated closure
and remediation activities,and as those activities are completed over time.
The following table documents the changes in the Company's asset retirement obligation during the years ended December 31(dollars in thousands):
2023 2022
Asset retirement obligation at beginning ofyear $ 15,783 $ 17,142
Liabilities incurred 1,927
Liabilities settled (232) (1,964)
Accretion expense 580 605
Asset retirement obligation at end ofyear $ 18,058 $ 15,783
NOTE 7.PENSION PLANS AND OTHER POSTRETHREMENT BENEFIT PLANS
The Company has a defined benefit pension plan covering the majority of regular full-time non-union employees at Avista Corp.hired prior to January I,2014 and regular full-time
union employees that were hired prior to January 1,2024.Employees eligible for the plan continue to accrue benefits.Individual benefits under this plan are based upon the
employee's years of service,date of hire and average compensation as specified in the plan.Non-union employees hired on or after January 1,2014 and union employees hired on or
after January 1,2024 participate in a defined contribution 401(k)plan in lieu of a defined benefit pension plan.The Company's funding policy is to contribute at least the minimum
amounts required to be funded under the Employee Retirement Income Security Act,but not more than the maximum amounts currently deductible for income tax purposes.The
Company contributed$10.0 million in cash to the pension plan in 2023,and$42.0 million in 2022.The Company expects to contribute$10.0 million in cash to the pension plan in
2024.
In 2022,the defined benefit pension plan lump sum payments exceeded the annual service and interest costs for the plan.This resulted in a partial settlement ofthe plan,and the
Company recorded a settlement loss of$11.8 million for the previously unrecognized losses in the year ended December 31,2022.This loss was deferred as a regulatory asset and is
being amortized over 12 years in accordance with regulatory accounting orders.
The Company has a SERPproviding additional pension benefits to certain executive officers and certain key employees ofthe Company.The SERPprovides benefits to individuals
whose benefits under the defined benefit pension plan are reduced due to the application of Section 415 of the Internal Revenue Code of 1986 and the deferral of salary under deferred
compensation plans.The liability and expense forthis plan are included as pension benefits in the tables included in this Note.
The Company expects benefit payments underthe pension plan and the SERPwill total(dollars in thousands):

Total 2029-
2024 2025 2026 2027 2028 2033
Expected benefit payments $ 41,562 $ 42,123 S 42,941 $ 43,517 $ 44,700 $ 232,345
The expected long-term rate ofretum on plan assets is based on past performance and economic forecasts for the types of investments held by the plan.In selecting a discount rate,the
Company considers yield rates for highly rated corporate bond portfolios with maturities similar to that ofthe expected term ofpension benefits.
The Company provides certain health care and life insurance benefits for eligible retired employees hired prior to January 1,2014.The Company accrues the estimated cost of
postretirement benefit obligations during the years employees provide services.The liability and expense ofthis plan are included as other postretirement benefits.Non-union
employees hired on or after January 1,2014,will have access to the retiree medical plan upon retirement;however,Avista Corp.will no longerprovide a contribution toward their
medical premium.
The Company has a Health Reimbursement Arrangement(HRA)to provide employees with tax-advantaged funds to pay for allowable medical expenses upon retirement.The amount
earned by the employee is fixed on the retirement date based on the employee's years of service and the ending salary.The liability and expense of the HRA are included as other
postretirement benefits.
The Company provides death benefits to beneficiaries ofexecutive officers who die during their term ofoffice or after retirement.Under the plan,an executive officer's designated
beneficiary will receive a payment equal to twice the executive officer's annual base salary at the time of death(or ifdeath occurs after retirement,a payment equal to twice the
executive officees total annual pension benefit).The liability and expense for this plan are included as other postretirement benefits.
The Company expects benefit payments under other postretirement benefit plans will total(dollars in thousands):
Total 2029-
2024 2025 2026 2027 2028 2033
Expected benefit payments $ 7,084 $ 7,266 $ 7,436 S 7,608 $ 7,822 $ 40,805
The Company expects to contribute$7.1 million to other postretirement benefit plans in 2024.The Company uses a December 31 measurement date for its pension and other
postretirement benefit plans.
The following table sets forth the pension and otberpostretirement benefit plan disclosures as of December 31,2023 and 2022 and the components ofnet periodic benefit costs for the
years ended December 31,2023 and 2022(dollars in thousands):
Other Post-
Pension Benefits retirement Benefits
2023 2022 2023 2022
Change in benefit obligation:
Benefit obligation as ofbeginning ofyear $557,709 S 799,042 $115,635 $ 167,598
Service cost 14,350 23,877 2,394 4,369
Interest cost 33,245 26,536 6,766 5,503
Actuarial(gain)/loss 21,373 (204,775) 4,799 (54,120)
Plan change 3,302
Settlement (60,206)
Benefits paid (41,432)
Benefit obligation as ofend ofyear $585,245 (57,709 (2,384 (5,635)
$ 557,709 $122,384 $ 115,635
Change in plan assets:
Fairvalue ofplan assets as ofbeginning ofyear $540,703 $ 750,963 S 49,472 S 59,544
Actual return on plan assets 78,838
(163,866)
8,654 (10,072)
Employer contributions 10,000 42,000
Settlement
(60,206)
Benefits paid (39,558) (28,188)
Fair value ofplan assets as ofend ofyear $589,983 $ 540,703 $ 58,126 $ 49,472
Funded status $ 4,738 $ (17,006)$(64,258)$ (66,163)
Amounts recognized in the Balance Sheets:
Non-current assets S 32,997 S 13,382 $ $
Current liabilities 212
(2, ) (1,934) (652) (706)
Noncurrent liabilities (26,047) (28,454) (63,606) (65,457
Net amount recognized $ 4,738 $ 17,006 $ 64,258 $ )( ) ( ) (66,163)
Accumulated pension benefit obligation $514,295 $ 495,654
Accumulated postretirement benefit obligation:
Forretirees $ 68,087 $ 61,984
For fully eligible employees $ 16,054 $ 19,731
For other participants S 38,243 $ 33,920
Included in accumulated other comprehensive loss(income)(net of tax):
Unrecognized prior service cost(credit) $ 3,717 $ 4,105 $ (1,081)$ (1,911)
Unrecognized net actuarial loss 69,002 83,794 13,103 13,643
Total 72,719 87,899 12,022 11,732
Less regulatory asset (71,983) (85,198) (12,401) (12,375)
Accumulated other comprehensive loss for unfimded benefit
obligation forpensions and other postretirement benefit plans $ 736 $ 2,701 $ (379)$ (643)
Other Post-
Pension Benefits retirement Benefits
2023 2022 2023 2022
Weighted-average assumptions as of December 31: -
Discount rate forbenefitobligation 5.86% 6.10% 5.83% 6.10%
Discount rate forannual expense 6.10% 3.39% 6.10% 3.40%
Expected long-term return on plan assets 8.30% 5.80% 7.20% 4.70%
Rate ofcompensation increase 4.87% 4.69%
Medical cost trend pre-age 65-initial 6.50% 6.25%
Medical cost trend pre-age 65-ultimate 5.00% 5.00%
Ultimate medical cost trend year pre-age 65 2030 2028
Medical cost trend post-age 65-initial 6.50% 6.25%
Medical cost trend post-age 65-ultimate 5.00% 5.00%
Ultimate medical cost trend year post-age 65 2030 2028
Pcnsion Benefits Other Post-retirement Benefits
2023 2022 2023 2022
Components otnet periodic benefit cost:
Service cost(1) $14,350 $23,877 $2,394 $4,369
Interest cost 33,245 26,536 6,766 5,503
Expected return on plan assets (43,656) (43,872) (3,562) (2,799)
Amortization ofprior service cost(credit) 491 257 (1,050) (1,050)
Net loss recognition 4,915 4,180 319 3,344
Settlement loss(2) 11,828
Net periodic benefit cost $ 9,345 $22,806 $4,867 $9,367
(1)Total service costs in the table above are recorded to the same accounts as labor expense.Labor and benefits expense is recorded to various projects based on whether the work is a

capital projector an operating expense.Approximately 40 percent of all labor and benefits is capitalized to utility property and 60 percent is expensed to utility other
operating expenses.
(2)The settlement loss was deferred as a regulatory asset and is being amortized over 12 years in accordance with regulatory accounting orders.
Plan Assets
The Finance Committee oftbe Board of Directors approves investment policies,objectives and strategies that seek an appropriate return for the pension plan and other postretirement
benefit plans and reviews and approves changes to the investment and funding policies.
The Company has contracted with investment consultants who are responsible for monitoring the individual investment managers.The investment managers'performance and related
individual fund performance is periodically reviewed by an internal benefits committee and by the Finance Committee to monitor compliance with investment policy objectives and
strategies.
Pension plan assets are invested in mutual funds,and trusts and partnerships that hold marketable debt and equity securities and real estate.In seeking to obtain a return that aligns
with the funded status ofthe pension plan,the investment consultant recommends allocation percentages by asset classes.These recommendations are reviewed by the internal
benefits committee,which then recommends their adoption by the Finance Committee.The Finance Committee has established target investment allocation percentages by asset
classes and investment ranges for each asset class.The target investment allocation percentages are typically the midpoint ofthe established range.The target investment allocation
percentages by asset classes are indicated in the table below:
2023 2022
Equity securities 55% 55%
Debt securities 40% 40%
Real estate 5% 5%
The fairvalue ofpension plan assets invested in debt and equity securities was based primarily on fairvalue(market prices).The fair value of investment securities traded on a
national securities exchange is determined based on the reported last sales price;securities traded in the over-the-counter market are valued at the last reported bid price.Investment
securities for which market prices are not readily available or for which market prices do not represent the value at the time ofpricing,the investment manager estimates fairvalue
based upon otherinputs(including valuations ofsecurities comparable in coupon,rating,maturity and industry).
Pension plan and otber postretirement plan assets with fair values are measured using net asset value(NAV)are excluded from the fairvalue hierarchy and included as reconciling
items in the tables below.
The plan's investments in common/collective trusts have redemption limitations that permit quarterly redemptions following notice requirements of45 to 60 days.Most ofthe plan's
investments in closely held investments and partnership interests have redemption limitations ranging from bi-monthly to semi-annually following redemption notice requirements of
60 to 90 days.
The following table discloses by level within the fairvalue hierarchy(see Note 13 for a description ofthe fairvalue hierarchy)ofthe pension plan's assets measured and reported as of
December 31,2023 at fairvalue(dollars in thousands):
Level l Leve1 2 Levd 3 Total
Cash equivalents S $ 6,984 $ $ 6,984
Fixed income securities:
U.S.government issues 19,293 19,293
Corporate issues 175,460 175,460
International issues 27,052 27,052
Municipal issues 13,772 13,772
Mutual funds:
U.S.equity securities 169,993 169,993
International equity securities 74,749 74,749
Plan assets measured atNAV(not subject to hierarchy
disclosure)
Common/collective trusts:real estate 25,284
Partnership/closely held investments:
International equity securities 70,652
Real estate 6,744
Total $ 244,742 $ 242,561 $ $ 589,983
The following table discloses by level within the fairvalue hierarchy(see Note 13 for a description ofthe fair value hierarchy)ofthe pension plan's assets measured and reported as of
December3l,2022 at fairvalue(dollars in thousands):
Level! Leve1 2 Leve13 Total
Cash equivalents $ $ 5,110 $ $ 5,110
Fixed income securities:
U.S.government issues 16,732 16,732
Corporate issues 161,180 161,180
International issues 23,108 23,108
Municipal issues 13,427 13,427
Mutual funds:
U.S.equity securities 154,442 154,442
International equity securities 58,933 58,933
Plan assets measured atNAV(not subject to hierarchy
disclosure)
Common/collective trusts:real estate 30,406
Partnership/closely held investments:
International equity securities 69,792
Real estate 7,573
Total $ 213,375 $ 219,557 $ $ 540,703
The fairvalue of other postretirement plan assets invested in debt and equity securities was based primarily on market prices.The fairvalue of investment securities traded on a
national securities exchange is determined based on the last reported sales price;securities traded in the over-the-counter market are valued at the last reported bid price.For
investment securities for which market prices are not readily available,the investment manager determines fairvalue based upon other inputs(including valuations of securities
comparable in coupon,rating,maturity and industry).The target asset allocation was 60 percent equity securities and 40 percent debt securities in both 2023 and 2022.
The fairvalue of other postretirement plan assets was determined to be$58.1 million and$49.5 million as of December 31,2023 and 2022,respectively.The assets consist of a
balanced index mutual fund,which is a single mutual fund that includes a percentage of U.S.equity and fixed income securities and International equity and fixed income securities.
This mutual fund is classified as Level 1 in the fairvalue hierarchy(see Note 13 for a description ofthe fairvalue hierarchy).
401(7c)Plans and Executive Deferral Plan
Avista Corp.has a salary deferral 401(k)plan that is a defined contribution plan and covers substantially all employees.Employees can make contributions to their respective
accounts in the plans on a pre-tax basis up to the maximum amount permitted by law.The Company matches a portion oftbe salary deferred by each participant according to the
schedule in the respective plan.
Employer matching contributions were as follows for the years ended December 31(dollars in thousands):
2023 2022
Employer 401(k)matching contributions $ 15,022 $ 13,258
The Company has an Executive Deferral Plan.This plan allows executive officers and other key employees the opportunity to defer until the earlier oftheir retirement,termination,
disability or death,up to 75 percent oftheir base salary and/or up to 100 percent oftheir incentive payments.Deferred compensation funds are held by the Company in a Rabbi Trust.
There were deferred compensation assets corresponding deferred compensation liabilities on the Balance Sheets oftbe following amounts as ofDecember3I(dollars in thousands):

Deferred compensation assets and liabilities $ 2023 7,794 $ 20227,541
NOTE 8.ACCOUNTING FOR INCOME TAXES
The realization ofdeferred income tax assets is dependent upon the ability to generate taxable income in future periods.The Company evaluated available evidence supporting the
realization ofits deferred income tax assets and determined it is more likely than not that deferred income tax assets will be realized.
As ofDecember 31,2023,the Company had$17.3 million of state tax credit carryforwards.Ofthe total amount,the Company believes that it is more likely than not that it will only
be able to utilize$6.8 million ofthe state tax credits.As such,the Company has recorded a valuation allowance of$10.5 million against the state tax credit carryforwards and reflected
the net amount of$6.8 million as an asset as of December 31,2023.State tax credits expire from 2024 to 2037.
Status oflnternal Revenue Service(IRS)and Slate Examinations
The Company and its eligible subsidiaries file consolidated federal income tax returns.All tax years after 2018 are open for an IRS tax examination.The IRS is reviewing tax year
2019.
The Company files state income tax returns in certain jurisdictions,including Idaho,Oregon,Montana and Alaska.Subsidiaries are charged or credited with the tax effects of tbeir
operations on a stand-alone basis.
All tax years after 2019 are open for examination in Idaho,Oregon,Montana and Alaska.
The Company believes open tax years for federal or state income taxes will not result in adjustments that would be significant to the financial statements.
NOTE 9.ENERGYPURCHASE CONTRACTS
Avista Corp.has contracts for the purchase of fuel for thermal generation,natural gas for resale and various agreements for the purchase or exchange ofelectric energy with other
entities.The remaining term ofthe contracts range from one month to twenty-five years.
Total expenses for power purchased,natural gas purchased,fuel for generation and other fuel costs,which are included in utility resource costs in the Statements of Income,were as
Follows for the years ended December 31(dollars in thousands):
2023 2022
Utility power resources $ 607,155 S 660,967
The following table details Avista Corp.'s future contractual commitments for power resources(including transmission contracts)and natural gas resources(including transportation
contracts)(dollars in thousands):
2024 2025 2026 2027 2028 Thereafter Total
Power resources $ 336,766 $ 293,389 $ 266,251 $ 235,751 $ 234,756 $ 2,245,762 $ 3,612,675
Natural gas resources 122,241 81,141 46,033 41,708 41,168 280,562 612,853
Total $ 459,007 $ 374,530 $ 312,284 $ 277,459 $ 275,924 S 2,526,324 $ 4,225,528
These energy purchase contracts were entered into as part ofAvista Corp.'s obligation to serve its retail electric and natural gas customers'energy requirements,including contracts
entered into for resource optimization.These costs are recovered either through base retail rates or adjustments to retail rates as part ofthe power and natural gas cost deferral and
recovery mechanisms.
The future contractual commitments for power resources include fixed contractual amounts related to the Company's contracts with Public Utility Districts(PUDs)to purchase portions
ofthe output of certain generating facilities.Although Avista Corp.has no investment in the PUD generating facilities,the contracts obligate Avista Corp.to pay certain minimum
amounts whether or not the facilities are operating.The cost ofpower obtained under the contracts,including payments made when a facility is not operating,is included in utility
resource costs in the Statements oflncome.The contractual amounts included above consist ofAvista Corp.'s share ofexisting debt service cost and its proportionate share ofthe
variable operating expenses ofthese projects.The minimum amounts payable under these contracts are based in part on the proportionate share ofthe debt service requirements of the
PUD's revenue bonds for which the Company is indirectly responsible.The Company's total future debt service obligation associated with the revenue bonds outstanding at December
31,2023(principal and interest)was$275.1 million.
In addition,Avista Corp.has operating agreements,settlements and other contractual obligations related to its generating facilities and transmission and distribution services.The
expenses associated with these agreements are reflected as other operating expenses in the Statements of Income.The following table details future contractual commitments under
these agreements(dollars in thousands):
2024 2025 2026 2027 2028 Thereafter Total
Contractual obligations $ 39,156 $ 40,226 S 18,630 $ 19,085 $ 9,390 S 177,553 $ 304,040
NOTE 10.NOTES PAYABLE
Lines of Credit
Avista Corp.has a committed line ofcredit in the total amount of$500.0 million.with expiration date of June 2028.The Company has the option to extend for two additional one
yearperiods(subject to customary conditions).In June 2023,the then-existing agreement was amended to increase the capacity ofthe committed line of credit from$400.0 million to
$500.0 million,extend the expiration date,and replace the London Interbank Offered Rate(LIBOR)provisions with Secured Overnight Financing Rate(SOFA)provisions.The
committed line of credit is secured by non-transferable first mortgage bonds ofthe Company issued to the agent bank that would only become due and payable in the event,and then
only to the extent,that the Company defaults on its obligations under the committed line ofcredit.
Balances outstanding and interest rates ofborrowings(excluding letters ofcredit)under the Company's revolving committed line ofcredit were as follows as ofDecember 31(dollars
in thousands):
2023 2022
Balance outstanding at end ofperiod $ 349,000 $ 313,000
Letters of credit outstanding at end ofperiod 4,700 35,563
Average interest rate at end ofperiod 6.46% 5.31%
In December 2022,Avista Corp.entered into an additional revolving credit agreement in the amount of$100.0 million.As ofDecember 31,2022,the Company did not have any
outstanding borrowings under this agreement.The agreement was terminated in June 2023.
As ofDecember 31,2023 and 2022,the borrowings outstanding under Avista Corp.'s committed lines ofcredit were classified as short-term borrowings on the Balance Sheets.
2022 Term Loan
In December 2022,the Company entered into a term loan agreement in the amount of$150.0 million with a maturity date of March 30,2023.The Company borrowed the entire
$150.0 million available under the agreement in 2022 and repaid the entire outstanding balance in March 2023.The borrowings outstanding under this agreement were classified as
short-term borrowings on the Balance Sheets.
2022 Letter of Credit Facility
In December 2022,the Company entered into a continuing letter ofcredit agreement in the aggregate amount of$50.0 million.Eitherparty may terminate the agreement at any time.
The Company had$20.0 million and$18.5 million in letters ofcredit outstanding under this agreement as ofDecember 31,2023 and December 31,2022,respectively.Letters of
credit are not reflected on the Balance Sheets.If a letter ofcredit were drawn upon by the holder,we would have an immediate obligation to reimburse the bank that issued that letter.
Covenants and Default Provisions
The short-term borrowing agreements contain customary covenants and default provisions,including a change in control(as defined in the agreements).The events of default under
each ofthe credit facilities also include a cross default from other indebtedness(as defined)and in some cases other obligations.Most ofthe short-term borrowing agreement also
include a covenant which does not permit the ratio of"total debt"to"total capitalization"ofAvista Corp.to be greater than 65 percent at any time.As ofDecember 31,2023,the

Company complied with this covenant.
NOTE 11.BONDS
The following details long-term debt outstanding as of December 31(dollars in thousands):
Maturity Interest
Year Description Ra[0 2023 2022
Avista Corp.Secured Long-Term Debt
2023 Secured Medium-Term Notes 7.18%-7.54% 13,500
2028 Secured Medium-Term Notes 6.37% 25,000 25,000
2032 Secured Pollution Control Bonds(1) (1) 66,700 66,700
2034 Secured Pollution Control Bonds(1) (1) 17,000 17,000
2035 First Mortgage Bonds 6.25% 150,000 150,000
2037 First Mortgage Bonds 5.70% 150,000 150,000
2040 First Mortgage Bonds 5.55% 35,000 35,000
2041 First Mortgage Bonds 4.45% 85,000 85,000
2044 First Mortgage Bonds 4.11% 60,000 60,000
2045 First Mortgage Bonds 4.37% 100,000 100,000
2047 First Mortgage Bonds 4.23% 80,000 80,000
2047 First Mortgage Bonds 3.91% 90,000 90,000
2048 First Mortgage Bonds 4.35% 375,000 375,000
2049 First Mortgage Bonds 3.43% 180,000 180,000
2050 First Mortgage Bonds 3.07% 165,000 165,000
2051 First Mortgage Bonds 3.54% 175,000 175,000
2051 First Mortgage Bonds 2.90% 140,000 140,000
2052 First Mortgage Bonds 4.00% 400,000 400,000
2053 First Mortgage Bonds(2) 5.66% 250,000
Total Avista Corp.secured long-term debt 2,543,700 2,307,200
Secured Pollution Control Bonds held by Avista
Corporation(1) (93.700) (83,700)
Total long-term debt $ 2460.000 S 2,223,500
(1)In December 2010,$66.7 million and$17.0 million ofthe City of Forsyth,Montana Pollution Control Revenue Refunding Bonds(Avista Corporation Colstrip Project)due in
2032 and 2034,respectively,which had been held by Avista Corp.since 2008 and 2009,respectively,were refunded by new variable rate bond issues.The newbonds were
not offered to the public and were purchased by Avista Corp.due to market conditions.The Company can remarket these bonds to unaffiliated investors at a later date,
subject to market conditions.So long as Avista Corp.is the holder of these bonds,the bonds are not reflected as an asset or a liability on the Balance Sheets.In April 2024,
the Company remarketed these bonds.See Note 18 for further discussion.
(2)ln March 2023,the Company issued and sold$250.0 million of 5.66 percent first mortgage bonds due in 2053 with institutional investors in the private placement market.A
portion oftbe net proceeds from the sale of these bonds was used for the construction or improvement ofutility facilities,and a portion was used to refinance existing
indebtedness,including the repayment ofAvista Corp.'s$150.0 million term loan.In connection with the pricing ofthe first mortgage bonds in March 2023,the Company
cash settled four interest rate swap derivatives(notional aggregate amount of$40.0 million)and received a net amount of$7.5 million.See Note 4 fora discussion of interest
rate swap derivatives.
The following table details future long-term debt maturities including advances from associated affiliates(see Note 12)(dollars in thousands):
2024 2025 2026 2027 2028 Thereafter Total
Debt maturities $ 15,000 $ $ $ $ 25,000 $ 2,561,547 $ 2,601,547
Substantially all ofAvista Corp's owned properties are subject to the lien oftheir respective mortgage indentures.Under the Mortgages and Deeds of Trust(Mortgages)securing their
first mortgage bonds(including secured medium-term notes),Avista Corp.may issue additional first mortgage bonds under their specific mortgage in an aggregate principal amount
equal to the sum of:
• 66-2/3 percent ofthe cost or fair value to the Company(whichever is lower)ofproperty additions ofthat entity which have not previously been made the basis ofany
application under that entity's Mortgage,or
• an equal principal amount ofretired first mortgage bonds of that entity which have not previously been made the basis of any application under that entity's Mortgage,or
• depositofcash.
Avista Corp.may not individually issue any additional first mortgage bonds(with certain exceptions in the case ofbonds issued on the basis ofretired bonds)unless the particular
entity issuing the bonds has"net earnings"(as defined in that entity's Mortgage)for any period of 12 consecutive calendar months out ofthe preceding 18 calendar months that were
at least twice the annual interest requirements on all mortgage securities at the time outstanding,including the first mortgage bonds to be issued,and on all indebtedness ofpriorrank.
As ofDecember 31,2023,property additions and retired bonds would have allowed,and the net earnings test would not have prohibited,the issuance of$1.2 billion in an aggregate
principal amount ofadditional first mortgage bonds at an assumed interest rate of 8 percent,
NOTE 12.ADVANCES FROM ASSOCIATED COMPANIES
In 1997,the Company issued Floating Rate Junior Subordinated Deferrable Interest Debentures,Series B,with a principal amount of$51.5 million to Avista Capital II,an affiliated
business trust formed by the Company.Avista Capital II issued$50.0 million ofPreferred Trust Securities witb a floating distribution rate of LIBOR plus 0.875 percent,calculated and
reset quarterly.Effective on July 3,2023,the reference to LIBOR in the formulation far the distribution rate on these securities was replaced,by operation of law,with three-month
CME Term SOFR,as calculated and published by CME Group Benchmark Administration,Ltd.(a successor administrator),plus a tenor spread adjustment of 0.26 percent.
Accordingly,the distribution rate on the Preferred Trust Securities is now three-month CME Term SOFR plus 1.137 percent.
The distribution rates paid were as follows during the years ended December 31:
2023 2022 2021
Low distribution rate 5.64% 1.05% 0.99%
High distribution rate 6.55% 5.64% 1.10%
Distribution rate at the end of the year 6.51% 5.64% 1.05%
Concurrent with the issuance ofthe Preferred Trust Securities,Avista Capital II issued$1.5 million of Common Trust Securities to the Company.These Preferred Trust Securities may
be redeemed at the option ofAvista Capital II at any time and mature on June 1,2037.In December 2000,the Company purchased$10.0 million of these Preferred Trust Securities.
The Company owns 100 percent ofAvista Capital II and has solely and unconditionally guaranteed the payment ofdistributions on,and redemption price and liquidation amount for,
the Preferred Trust Securities to the extent Avista Capital II has funds available for such payments from the respective debt securities.Upon maturity or prior redemption of such debt
securities,the Preferred Trust Securities will be mandatorily redeemed.
NOTE 13.FAIR VALUE
The carrying values of cash and cash equivalents,special deposits,accounts and notes receivable,accounts payable and notes payable are reasonable estimates oftheir fair values.
Bonds and advances from associated companies are reported at carrying value on the Balance Sheets.
The fair value hierarchy prioritizes the inputs used to measure fair value.The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or
liabilities(Level 1 measurements)and the lowest priority to fairvalues derived from unobservable inputs(Level 3 measurements).
The three levels ofthe fair value hierarchy are defined as follows:
Level 1-Quoted prices are available in active markets for identical assets or liabilities.Active markets are those in which transactions for the asset or liability occur with
sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2-Pricing inputs are other than quoted prices in active markets included in Level 1,but which are either directly or indirectly observable as ofthe reporting date.Level 2

includes financial instruments valued using models or other valuation methodologies.These models are primarily industry-standard models that consider various assumptions,
including quoted forward prices for commodities,time value,volatility factors,and current market and contractual prices for the underlying instruments,as well as other relevant
economic measures.Substantially all of these assumptions are observable to the markemplace throughout the full term ofthe]ris LLl-Il eat,can be derived ftrn observable data crate
supported by observable levels at which transactions are executed in the marketplace.
Level -Pricing inputs include significant inputs generally unobservable from objective sources.These inputs may be used with internally developed methodologies that result
in management's best estimate offairvalue.
Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fairvalue measurement.The Company's assessment ofthe
significance of a particular input 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 levels.The determination ofthe fair values incorporates various factors that not only include the credit standing ofthe counterparties involved and the impact of
credit enhancements(such as cash deposits and letters ofcredit),but also the impact ofAvista Corp.'s nonperformance risk on its liabilities.
The following table sets forth the carrying value and estimated fairvalue ofthe Company's financial instruments not reported at estimated fairvalue on the Balance Sheets as of
December3l(dollars in thousands):
2023 2022
Carrying Estimated Carrying Estimated
Value Fair Value Value Fair value
Bonds(Level 2) $ 1,100,000 $ 968,893 $ 1,113,500 $ 966,881
Bonds(Level 3) 1,360,000 1,088,500 1,110,000 805,802
Advances from associated companies(Level 3) 51,547 46,098 51,547 42,836
These estimates of fair value of long-term debt and long-term debt to affiliated trusts were primarily based on available market information,which generally consists of estimated
market prices from third party brokers for debt with similar risk and terms.The price ranges obtained from the third party brokers consisted ofparvalues of 62.73 to 107.245,where a
par value of 100.00 represents the carrying value recorded on the Balance Sheets.Level long-term debt represents publicly issued bonds with quoted market prices;however;due to
their limited trading activity,they are classified as Level because brokers must generate quotes and make estimates using comparable debt with similar risk and terms iftbere is no
trading activity near a period end.Level 3 long-term debt consists ofprivate placement bonds and debt to affiliated trusts,which typically have no secondary trading activity.Fair
values in Level are estimated based on market prices from third party brokers using secondary market quotes for debt with similar risk and terms to generate quotes for Avista Corp.
bonds.
The following table discloses by level within the fair value hierarchy the Company's assets and liabilities measured and reported on the Balance Sheets as of December 31,2023 at fair
value on a recurring basis(dollars in thousands):
Counterparty
and Cash
Collateral
Leven Level2 Leve13 Netting(1) Total
December 31,2023
Assets:
Energy commodity derivatives(2) $ $ 30,954 $ $ (22,802) $ 8,152
Foreign currency exchange derivatives 2 2
Interest rate swap derivatives 3,667 3,667
Deferred compensation assets:
Mutual Funds:
Fixed income securities 1,117 1,117
Equity securities 6,524 6,524
Total $ 7,641 $ 34,623 $ $ (22,802) $ 19,462
Liabilities:
Energy commodity derivatives(2) $ $ 91,844 $ 8,250 $ (65,157) $ 34,937
Interest rate swap derivatives 182 182
Total $ $ 92,026 $ 8,250 $ (65,157) $ 35,119
The following table discloses by level within the fairvalue hierarchy the Company's assets and liabilities measured and reported on the Balance Sheets as ofDecember31,2022 at fair
value on a recurring basis(dollars in thousands):
Counterparty
and Cash
Collateral
Leven Level2 Level3 Netting(1) Total
December 31,2022
Assets:
Energy commodity derivatives(2) $ $ 146,232 $ 288 $ (136,605) $ 9,915
Foreign currency exchange derivatives 43 43
Interest rate swap derivatives 11,184 11,184
Deferred compensation assets:
Mutual Funds:
Fixed income securities 1,267 1,267
Equity securities 6,132 6,132
Total $ 7,399 $ 157,459 $ 288 $ (136,605) $ 28,541
Liabilities:
Energy commodity derivatives(2) $ $ 258,769 $ 18,022 $ (242,044) $ 34,747
Foreign currency exchange derivatives 3 3
Interest rate swap derivatives 52 52
Total $ $ 258,824 S 18,022 $ (242,044) $ 34,802
(1)The Company is permitted to net derivative assets and derivative liabilities with the same counterparty when a legally enforceable master netting agreement exists.In addition,the
Company nets derivative assets and derivative liabilities against payables and receivables for cash collateral held or placed with these same counterparties.
(2)The Level 3 energy commodity derivative balances are associated with natural gas exchange agreements.
The difference between the amount of derivative assets and liabilities disclosed in respective levels in the table above and the amount of derivative assets and liabilities disclosed on
the Balance Sheets is due to netting arrangements with certain counterparties.See Note 4 foradditional discussion ofderivative netting.
To establish fair value for energy commodity derivatives,the Company uses quoted market prices and forward price curves to estimate the fairvalue of energy commodity derivative
instruments included in Level 2.In particular,electric derivative valuations are performed using market quotes,adjusted for periods in between quotable periods.Natural gas
derivative valuations are estimated using New York Mercantile Exchange pricing for similar instruments,adjusted for basin differences,using market quotes.Where observable inputs
are available for substantially the full term ofthe contract,the derivative asset or liability is included in Level 2.
To establish fair values for interest rate swap derivatives,the Company uses forward market curves for interest rates for the term ofthe swaps and discounts the cash flows back to
present value using an appropriate discount rate.The discount rate is calculated by third party brokers according to the terms ofthe swap derivatives and evaluated by the Company
for reasonableness,with consideration given to the potential non-performance risk by the Company.Future cash flows ofthe interest rate swap derivatives are equal to the fixed
interest rate in the swap compared to the floating market interest rate multiplied by the notional amount for each period.
To establish fair value for foreign currency derivatives,the Company uses forward market curves for Canadian dollars against the U.S.dollar and multiplies the difference between the
locked-in price and the market price by the notional amount ofthe derivative.Forward foreign currency market curves are provided by third party brokers.The Company's credit
spread is factored into the locked-in price ofthe foreign exchange contracts.
Deferred compensation assets and liabilities represent funds held by the Company in a Rabbi Trust for an executive deferral plan.These funds consist of actively traded equity and
bond funds with quoted prices in active markets.

Level Fair Value
Natural Gas ExchangeAgneemenl
For the natural gas commodity exchange agreement,the Company uses the same Level 2 brokered quotes described above;however the Company also estimates the purchase and
sales volumes(within contractual limits)as well as the timing of those transactions.Changing the timing ofvolume estimates changes the timing ofpurchases and sales,impacting
which brokered quote is used.Because the brokered quotes can vary significantly from period to period,the unobservable estimates of the timing and volume of transactions can have
a significant impact on the calculated fair value.The Company estimates volumes and timing of transactions based on a most likely scenario using historical data.Historically,the
timing and volume of transactions have not been highly correlated with market prices and market volatility.
The following table presents the quantitative information which was used to estimate the fair values ofthe Level 3 assets and liabilities above as of December 31,2023(dollars in
thousands):
Fair value(Net)at
December 31,2023 valuation Tecbnique Unobservable Input Range
Natural gas exchange $ (8,250) Internally derived Forward purchase prices $1.64-$3.07/mmBTU
weighted average $2.40 Weighted Average
cost ofgas
Forward sales prices $2.13-$8.99/mmBTU
$5.45 Weighted Average
Purchase volumes 300,000-310,000 mmBTUs
Sales volumes 75,000-310,000 mmBTUs
The valuation methods,significant inputs and resulting fair values described above were developed by the Company's management and are reviewed on at least a quarterly basis to
ensure they provide a reasonable estimate offair value each reporting period.
The following table presents activity for assets and liabilities measured at fair value using significant unobservable inputs(Level 3)for the years ended December 31(dollars in
thousands):
Natural Gas Exchange
Agrecment(l)
Year ended December 31,2023:
Balance as ofJanuary 1,2023 $ (17,734)
Total gains or(losses)(realized/unrealized):
Included in regulatory assets 9,238
Settlements 246
Ending balance as of December 31,2023 $ (8,250)
Year ended December 31,2022:
Balance as ofJanuary 1,2022 $ (7,771)
Total gains or(losses)(realized/unrealized):
Included in regulatory assets (4,740)
Settlements (5,223)
Ending balance as ofDecember 31,2022 $ (17,734)
(I)There were no purchases,issuances or transfers from other categories ofderivatives instruments during the periods presented in the table above.
NOTE 14.COMMON STOCK
The payment of dividends on common stock could be limited by:
• certain covenants applicable to preferred stock(when outstanding)contained in the Company's Restated Articles of Incorporation,as amended(currently there are no
preferred shares outstanding),
• certain covenants applicable to the Company's outstanding long-term debt and committed line ofcredit agreements,
• the hydroelectric licensing requirements ofsection 10(d)ofthe FPA(see Note 1),and
• certain requirements under the OPUC approval ofthe AERC acquisition in 2014.The OPUC's AERC acquisition order requires Avista Corp.to maintain a capital
structure ofno less than 35 percent common equity(inclusive ofshort-term debt).This limitation may be revised upon request by the Company with approval from the
OPUC.
The requirements ofthe OPUC approval of the AERC acquisition are the most restrictive.Under the OPUC restriction,the amount available for dividends at December 31,2023 was
$295.6 million.
The Company has 10 million authorized shares ofpreferred stock.The Company did not have preferred stock outstanding as of December 31,2023 and 2022.
Common Stock Issuances
The Company issued common stock for total net proceeds of$112.3 million in 2023.Most ofthese issuances came through the Company's sales agency agreements under which the
sales agents may offer and sell new shares of common stock from time to time.In 2023,3.0 million shares were issued under these agreements resulting in total net proceeds of$I I1.8
million.
NOTE 15.COMMITMENTS AND CONTINGENCIES
In the course ofits business,the Company becomes involved in various claims,controversies,disputes and other contingent matters,including the items described in this Note.Some
of these claims,controversies,disputes and other contingent matters involve litigation or other contested proceedings.For all such matters,the Company will vigorously protect and
defend its interests and pursue its rights.However,no assurance can be given as to the ultimate outcome of any matterbecause litigation and other contested proceedings are subject to
numerous uncertainties.For matters affecting Avista Corp:s operations,the Company intends to seek,to the extent appropriate,recovery of incurred costs through the ratemaking
process.
Collective Bargaining Agreements
The Company's collective bargaining agreement with the IBEW represents 36 percent of all Avista Corp's employees.The Company's largest represented group,representing
approximately 90 percent of Avista Corp.'s bargaining unit employees in Washington and Idaho,are covered under a four year agreement which expires in March 2025.
The current agreement includes a clause to negotiate wages in effect for the last year ofthe agreement.The Company is in the process ofnegotiating these wages.There is a risk that if
an agreement on wages is not reached,the employees subject to the agreement could strike.Given the number of employees that are covered by the collective bargaining agreement,a
strike could result in disruptions to the Company's operations.However the Company believes the possibility ofthis occurring is remote.
Boyds Fire(State of Washington Department of Natural Resources is Avista)
In August 2019,the Company was served with a complaint,captioned"State of Washington Department ofNatuml Resources v.Avista Corporation;'seeking recovery of up to$4.4
million for fire suppression and investigation costs and related expenses incurred in connection with a wildfire that occurred in Ferry County,Washington,in August 2018.
Specifically,the complaint alleges the fire,which became known as the"Boyds Fire,"was caused by a dead ponderosa pine tree falling into an overhead distribution line,and that
Avista Corp.,along with its independent vegetation management contractors Asplundh Tree Company and CN Utility Consulting,were negligent in failing to identify and remove the
tree before it came into contact with the line.Avista Corp.disputes that it was negligent in failing to identify and remove the tree in question.Additional lawsuits were subsequently
filed by private landowners seeking property damages,and holders ofinsumnce subrogation claims seeking recovery of insurance proceeds paid.
The lawsuits were filed in the Superior Court of Ferry County,Washington.The Company continues to vigorously defend itself in the litigation.However,at this time the Company is
unable to predict the likelihood of an adverse outcome or estimate a range ofpotential loss in the event of such an outcome.
Road 11 Fire
In April 2022,Avista Corp.received a notice ofclaim from property owners seeking damages of$5 million in connection with a fire that occurred in Douglas County,Washington,in
July 2020.In June 2022,those claimants filed suit in the Superior Court ofDouglas County,Washington,seeking unspecified damages.The fire,which was designated as the"Road
I 1 Fire,"occurred in the vicinity of an Avista Corp.115kv line,resulting in damage to three overhead transmission structures.The fire occurred during a high wind event and grew to
10,000 acres before being contained.The Company disputes that it is liable for the fire and will vigorously defend itself in the pending legal proceeding;however,at this time the
Company is unable to predict the likelihood of an adverse outcome or estimate a range ofpotential loss in the event of such an outcome.

Labor Day 2020 Windstorm
General
In September 2020,a severe windstorm occurred in eastern Washington and northern Idaho.The extreme weather event resulted in customer outages and multiple wildfires in the
region.
The Company has become aware of instances where,during the storm,otherwise healthy trees and limbs,located in areas outside its maintenance right-of-way,broke under the
extraordinary wind conditions and caused damage to its energy delivery system at or near what is believed to be the potential area of origin ofa wildfire.However,the Company's
investigations found no evidence ofnegligence with respect to any of those fires.Consistent with that conclusion,the statute of limitations with respect to the claims arising out ofthe
Labor Day 2020 Windstorm has now passed and,except with respect to the Babb Road Fire discussed below,no legal action has been commenced.
Babb Road Fire
In May 2021 the Company learned the Washington Department ofNatural Resources(DNR)had completed its investigation and issued a report on the Babb Road Fire.The Babb
Road fire covered approximately 15,000 acres and destroyed approximately 220 structures.There are no reports ofpersonal injury or death resulting from the fire.
The DNR report concluded,among other things,that
• the fire was ignited when a branch ofa multi-dominant Ponderosa Pine tree was broken offby the wind and fell on an Avista Corp.distribution line;
• the tree was located approximately 30 feet from the center ofAvista Corp:s distribution line and approximately 20 feet beyond Avista Corp.'s right-of-way;
• the tree showed some evidence of insect damage,damage at the top ofthe tree from porcupines,a small area of scaring where a lateral branch/leader(LBL)had broken
offin the past,and some past signs of Gall Rust disease.
The DNR report concluded as follows:"It is my opinion that because ofthe unusual configuration ofthe tree,and its proximity to the powerline,a closer inspection was warranted.A
nearer inspection ofthe tree should have revealed the cut LBL ends and its previous failure,and necessitated determination ofthe failure potential ofthe adjacent LBL,implicated in
starting the Babb Road Fire."
The DNRreport acknowledged that,otherthan the multi-dominant nature ofthe tree,the conditions mentioned above would not have been easily visible without close-up inspection
of,or cutting into,the tree.The report also acknowledged that,while the presence ofmultiple tops would have been visible from the nearby roadway,the tree did not fail at a v-fork
due to the presence ofmultiple tops.The Company contends that applicable inspection standards did not require a closer inspection ofthe otherwise healthy tree,norwas the
Company negligent with respect to its maintenance,inspection or vegetation management practices.
Eleven lawsuits have been filed in connection with the Babb Road fire.Asplundh Tree Company and CNUC Utility Consulting,which both perform vegetation management services
as independent contractors to the Company,are also named as defendants in each ofthe lawsuits.The lawsuits include six subrogation actions filed by insurance companies seeking to
recover approximately$23 million purportedly paid to insureds to date;four actions on behalfofindividual plaintiffs seeking unspecified damages;and a class action lawsuit seeking
unspecified damages.All proceedings,except for one action filed on September 1,2023 on behalfof three individual plaintiffs,have been consolidated in the Superior Court of
Spokane County Washington under the lead action Blakeley v.Avista Corporation et al.,and variously assert causes ofaction for negligence,private nuisance,and trespass(the
Blakeley Proceeding).
In November 2023,all parties to the Blakeley Proceeding agreed to a stipulated order,which was presented to and entered by the Superior Court of Spokane County,Washington.The
order consolidates the Blakeley Proceeding fortrial(in addition to discovery and pre-trial proceedings)and bifurcates the trial into liability and damages phases,such that the initial
trial in the case will focus solely on whether the defendants are legally responsible for the Babb Road Fire.Atrial date on the liability phase has been set forMay 5,2025.
In addition,the order memorializes the plaintiffs'agreement to voluntarily dismiss all claims asserting inverse condemnation as a theory of liability without prejudice to their ability
to seek permission from the Court to refile those claims at a later date if there is good cause to do so.The individual action that was not consolidated into the Blakeley Proceeding
does not include claims forinverse condemnation.The parties to the Blakeley Proceeding agreed to a preliminary mediation no laterthan 60 days priorto the liability trial,and,if
there is a trial following that mediation and ifthe jury returns a verdict in the plaintiffs'favor in the liability trial,a second mediation within 90 days following the verdict focusing on
damages.Finally,the plaintiffs agreed to complete a damages questionnaire identifying all claimed damages being sought in connection with the litigation.
The Company will vigorously defend itself in the legal proceedings;however,at this time the Company is unable to predict the likelihood of an adverse outcome or estimate a range
ofpotential loss in the event ofsuch an outcome.
Orofino Fire
In August 2023,a fire subsequently referred to as the"Hospital Fire",started in windy conditions near Omfino,Idaho,burning 53 acres and seven primary residences,as well as several
outbuildings.The Idaho Department of Lands investigated and has issued a report in which it concluded the fire was caused by an electrical fault igniting three separate spots which
then spread uphill.The Company has a distribution line in the area near the ignition point.While the Company has not yet completed its own investigation,the Company has to date
found no evidence suggesting negligence on its part.Except for one claim for damage to personal property,the Company has not,at this time,received any claims in connection with
the fire.The Company will vigorously defend itselfin the event any such claims are asserted;however,at this time,it is unable to estimate the likelihood ofan adverse outcome nor
the amount or range ofa potential loss in the event of an adverse outcome.
Colstrip
Colstrip Owners Arbitration and Litigation
Colstrip Units 3 and 4 are owned by the Company,PacifiCorp,Portland General Electric(PGE),and Puget Sound Energy(PSE)(collectively,the"Western Co-Owners"),as well as
NorthWestem and Talen Montana,LLC(Talen),as tenants in common under an Ownership and Operating Agreement,dated May 6,1981,as amended(O&O Agreement),in the
percentages set forth below:
Co-Owner Unit 3 unit
Avista 15% L5%
PacifiCorp 10% 10%
PGE 20% 20%
PSE 25% 25%
NorthWestem 30%
Talen 30%
Colstrip Units 1 and 2,owned by PSE and Talen,were shut down in 2020 and are in the process ofbeing decommissioned.The co-owners ofUnits 3 and 4 also own undivided
interests in facilities common to both Units 3 and 4,as well as in certain facilities common to all four Colstrip units.
The Washington Clean Energy Transformation Act(CETA),among other things,imposes deadlines by which each electric utility must eliminate from its electricity rates in
Washington the costs and benefits associated with coal-fired resources,such as Colstrip.The practical impact of CETAis electricity from such resources,including Colstrip,may no
longerbe delivered to Washington retail customers after 2025.
The co-owners of Colstrip Units 3 and 4 have differing needs for the generating capacity ofthese units.Accordingly,certain business disagreements have arisen among the coowners,
including,disagreements as to the requirements for shutting down these units.NorthWestem has initiated arbitration pursuant to the O&O Agreement to resolve these business
disagreements,and two actions have been initiated to compel arbitration ofthose disputes:one by Talen in the Montana Thirteenth Judicial District Court for Yellowstone County,
and one by the Western Co-Owners,which is pending in Montana Federal District Court.In light ofthe ownership transfer agreements discussed below,the Colstrip owners agreed to
stay both the litigation and the arbitration through March 2024.On April 1,2024,the agreement to stay lapsed and at least one owner,Puget Sound Energy,has indicated they wish to
resume the arbitration proceeding.
Agreement Between Talen and Puget Sound Energy
In September 2022,PSE and Talen entered into an agreement through which PSE has agreed to transfer its 25 percent ownership in Colstrip Units 3 and 4 to Talen at the end of 2025.
The terms and conditions ofthe agreement are similar in most respects to the NorthWestem transaction discussed below.
Agreement Between Avista and Northwestern
In January 2023,the Company entered into an agreement with NorthWestem underwhich,subject to the terms and conditions specified in the agreement,the Company will transfer its
15 percent ownership in Colstrip Units 3 and 4 to NorthWestem.There is no monetary exchange included in the transaction.The transaction is scheduled to close on December 3l,
2025 or such other date as the parties mutually agree upon.
Under the agreement,the Company will remain obligated through the close ofthe transaction to pay its share of(i)operating expenses,(ii)capital expenditures,but not in excess of
the portion allocable pro rata to the portion ofuseful life(through 2030)expired through the close ofthe transaction,and(iii)except for certain costs relating to post-closing
activities,site remediation expenses.In addition,the Company would enter into an agreement under which it would retain its voting rights with respect to decisions relating to
remediation.
The Company will retain its Colstrip transmission system assets,which are excluded from the transaction.
Underthe Colstrip O&O Agreement,each ofthe other owners of Colstrip has a 90day period in which to evaluate the transaction and determine whether to exercise their respective
rights of first refusal as to a portion ofthe generation being turned over to NorthWestem.That period has now expired,and no owners have exercised a right to first refusal.

The transaction is subject to the satisfaction of customary closing conditions including the receipt of any required regulatory approvals,as well as NorthWestem's ability to enter into
a new coal supply agreement by December 31,2024.
The Company does not expect this transaction to have a direct material impact on its financial results.
Burnell el al.v.Talen et al.
Multiple property owners initiated a legal proceeding(titled Burnett et al,v.Talen et al.)in the Montana District Court for Rosebud County against Talen,PSE,PacifiCorp,PGE,
Avista Corp.,NorthWestem,and Westmoreland Rosebud Mining.The plaintiffs allege a failure to contain coal dust in connection with the operation of Colstrip,and seek unspecified
damages.The Company will vigorously defend itself in the litigation,but at this time is unable to predict the outcome,nor an amount or range of potential impact in the event of an
outcome adverse to the Company's interests.
Westmoreland Mine Permits
Two lawsuits have been commenced by the Montana Environmental Information Center and others,challenging certain permits relating to the operation ofthe Westmoreland
Rosebud Mine,which provides coal to Colstrip.In the first,the Montana District Court for Rosebud County issued an order vacating a permit for one area ofthe mine,which decision
was subsequently upheld by the Montana Supreme Court.hi the second,the Montana Federal District Court vacated a decision by the federal Office of Surface Mining Reclamation
and Enforcement,a branch ofthe United States Department of Interior,approving expansion of the mine into a new area,pending further analysis ofpotential environmental impact.
An initial appeal ofthat decision to the Ninth Circuit was dismissed for lack of jurisdiction,pending further proceedings before the Department ofthe Interior.Avista Corp.is not a
party to either ofthese proceedings,but continues to monitor the progress of both issues and assess the impact,if any,ofthe proceedings on Westmoreland's ability to meet its
contractual coal supply obligations.
National Park Service(NPS)-Natural and Cultural Damage Claim
In March 2017,the Company accessed property managed by the National Park Service(NPS)to prevent the imminent failure of a power pole surrounded by flood water in the
Spokane River.The Company voluntarily reported its actions to the NPS several days later.Thereafter,in March 2018,the NPS notified the Company that it might seek recovery for
unspecified costs and damages allegedly caused during the incident pursuant to the System Unit Resource Protection Act(SURPA),54 U.S.C.100721 et seq.In January 2021,the
United States Department ofJustice(DOJ)requested the Company and the DOJ renew discussions relating to the matter.In July 2021,the DOI communicated that it may seek damages
of approximately$2 million in connection with the incident for alleged damage to"natural and cultural resources".In addition,the DOJ indicated that it may seek treble damages
under the SURPA and state law,bringing its total potential claim to approximately$6 million.
The Company disputes the position taken by the DOJ with respect to the incident,as well as the nature and extent ofthe DOJ's alleged damages,and will vigorously defend itself in
any litigation that may arise with respect to the matter.The Company and the DOJ have engaged in discussions to understand their respective positions and determine whether a
resolution ofthe dispute may be possible.However,the Company cannot predict the outcome ofthe matter.
Rathdrum,Idaho Natural Gas Incident
In October 2021,there was an incident in Ratbdmm,Idaho involving the Company's natural gas infrastructure.The incident occurred after a third party damaged those facilities
during excavation work.The incident resulted in a fire which destroyed one residence and resulted in minor injuries to the occupants.In January 2023,the Company was served with a
lawsuit filed in the District Court of Kootenai County,Idaho by one property owner,seeking unspecified damages.In February 2024,the Company became aware of a second lawsuit
filed by the owners ofthe adjacent property,seeking damages for personal injury and emotional distress from having witnessed the incident.The Company intends to vigorously
defend itself in both actions.
Other Contingencies
In the normal course ofbusiness,the Company has various other legal claims and contingent matters outstanding.The Company believes any ultimate liability arising from these
actions will not have a material impact on its financial condition,results of operations or cash flows.It is possible a change could occur in the Company's estimates ofthe probability
or amount ofa liability being incurred.Such a change,should it occur,could be significant.
The Company routinely assesses,based on studies,expert analysis and legal reviews,its contingencies,obligations and commitments for remediation of contaminated sites,including
assessments ofranges and probabilities of recoveries from other responsible parties who either have or have not agreed to a settlement as well as recoveries from insurance carriers.The
Company's policy is to accrue and charge to current expense identified exposures related to environmental remediation sites based on estimates of investigation,cleanup and
monitoring costs to be incurred.
The Company has potential liabilities under the Endangered Species Act and similar state statutes for species offish,plants and wildlife that have either already been added to the
endangered species list,listed as"threatened"or petitioned for listing.Thus far measures adopted and implemented have had minimal impact on the Company.However,the Company
will continue to seek recovery,through the mtemaking process,of all operating and capitalized costs related to these issues.
Under the federal licenses for its hydroelectric projects,the Company is obligated to protect its property rights,including water rights.In addition,the Company holds additional non-
hydro water rights.The States ofMontana and Idaho are each conducting general adjudications ofwater rights in areas that include the Company's facilities in these states.Claims
within the Clark Fork River basin and the Spokane Riverbasin could adversely affect the energy production of the Company's hydroelectric facilities.The Company is and will
continue to be a participant in the adjudication processes.The complexity of such adjudications makes each unlikely to be concluded in the foreseeable future.As such,it is not
possible for the Company to estimate the impact of any outcome at this time.The Company will continue to seek recovery,through the ratemaking process,of all costs related to this
issue.
NOTE 16.REGULATORYMATTERS
Power Cost Deferrals and Recovery Mechanisms
Deferred power supply costs are recorded as a deferred charge or liability on the Balance Sheets for future prudence review and recovery or rebate through retail rates.The power
supply costs deferred include certain differences between actual net power supply costs incurred by Avista Corp.and the costs included in base retail rates.This difference in net power
supply costs primarily results from changes in:
short-term wholesale market prices and sales and purchase volumes,
the level,availability and optimization ofhydroelectric generation,
the level and availability ofthermal generation(including changes in fuel prices),
retail loads,and
sales of surplus transmission capacity.
In Washington,the ERM allows Avista Corp.to periodically increase or decrease electric rates with WUTC approval to reflect changes in power supply costs.The ERM is an
accounting method used to track certain differences between actual power supply costs,net ofwholesale sales and sales of fuel,and the amount included in base retail rates for
Washington customers.Under the ERM,the Company defers these differences(over the$4.0 million deadband and sharing bands)for future surcharge or rebate to customers.
The following is a summary ofthe ERM:
Deferred for
Future
Surcharge or Expense or
Rebate Benefit
Annual Pa"t Sunoly Cod Mainbility to Customers to the Company
within+/-$0 to$4 million(deadband) 0% 100%
higher by$4 million to$10 million 50% 50%
lower by$4 million to$10 million 75% 25%
higher or lower by over$10 million 90% 10%
Total net deferred power costs under the ERM were assets of$37.6 million as of December 31,2023 and$30.5 million as of December 31,2022.The deferred power cost assets
represent amounts due from customers,and deferred power cost liabilities represent amounts due to customers.
Pursuant to WUTC requirements,should the cumulative deferral balance exceed$30 million in the rebate or surcharge direction,the Company must make a filing with the WUTC to
adjust customer rates to either return the balance to customers or recover the balance from customers.Avista Corp.makes an annual filing on,orbefore,April 1 of each year to provide
the opportunity for the WUTC staff and other interested parties to review the prudence of,and audit,the ERM deferred power cost transactions for the prior calendar year.In June
2023,the Company received approval from the WUTC for a rate surcharge to customers over a two-yearperiod,effective July 1,2023.
In the 2024 Washington general rate case,the Company proposed changing the ERM so the entire mechanism would result in a 95 percent customer,5 percent company sharing basis.
This request is pending WUTC approval.
Avista Corp.has a PCAmechanism in Idaho allowing for the modification of electric rates on October 1 of each year with IPUC approval.Under the PCAmechanism,Avista Corp.

defers 90 percent ofthe difference between certain actual net power supply expenses and the amount included in base retail rates for its Idaho customers.The October 1 rate
adjustments recover or rebate power costs deferred during the preceding July-June twelve-month period.Total net power supply costs deferred under the PCAmechanism were assets of
$7.6 million as ofDecember 31,2023 and$16.3 million as ofDecember 31,2022.Deferred power cost assets represent amounts due from customers and liabilities represent amounts
due to customers.
Natural Gas Cost Deferrals and Recovery Mechanisms
Avista Corp.files a PGAin all three states it serves to adjust natural gas rates for.1)estimated commodity and pipeline transportation costs to serve natural gas customers for the
coming year,and 2)the difference between actual and estimated commodity and transportation costs for the prior year.In Oregon,the Company absorbs(cost orbenefit)10 percent of
the difference between actual and projected natural gas costs included in base retail rates for supply that is not hedged.Total net deferred natural gas costs were an asset of$51.4
million as of December 31,2023 and$52.1 million as of December 31,2022.Asset balances represent amounts due from customers and liabilities represent amounts due to customers.
Decoupling and Earnings Sharing Mechanisms
Decoupling(also known as an FCAin Idaho)is a mechanism designed to sever the link between a utility's revenues and consumers'energy usage.In each ofAvista Corp:s
jurisdictions,Avista Corp.'s electric and natural gas revenues are adjusted so as to be based on the number of customers in certain customer rate classes and assumed"normal"kilowatt
hour and therm sales,ratherthan being based on actual kilowatt hour and therm sales.The difference between revenues based on the number ofcustomers and"normal"sales and
revenues based on actual usage is deferred and either surcharged or rebated to customers beginning in the following year.Only residential and certain commercial customer classes are
included in decoupling mechanisms.
Washington Decoupling and Earnings Sharing
In Washington,the WUTC approved the Company's decoupling mechanisms for electric and natural gas through March 31,2025.In the Company's 2024 Washington general rate
cases,it requested the mechanisms be extended through December 2026.That request is pending before the WUTC.
Electric and natural gas decoupling surcharge rate adjustments to customers are limited to a 3 percent increase on an annual basis,with remaining surcharge balance carried forward for
recovery in a future period.There is no limit on the level ofrebate rate adjustments.New customers added after a test period are not decoupled until included in a future test period.
The decoupling mechanisms each include an after-the-fact earnings test.At the end of each calendaryear,separate electric and natural gas earnings calculations are made for the
calendar year just ended.These earnings tests reflect actual decoupled revenues,normalized power supply costs and other normalizing adjustments.Through the 2022 general rate
cases,the Company modified its earnings test so that if the Company earns more than 0.5 percent higher than the rate of return authorized by the WUTC in the multi-year rate plan,the
Company would defer these excess revenues and later return them to customers.
Idaho FCA and Earnings Sharing Mechanisms
In Idaho,the IPUC approved the implementation ofFCAs for electric and natural gas through March 31,2025.
Oregon Decoupling Mechanism
In Oregon,the Company has a decoupling mechanism for natural gas.An earnings review is conducted on an annual basis.In the annual earnings review,if the Company cams more
than 100 basis points above its allowed return on earnings,one-third ofthe earnings above the 100 basis points would be deferred and later returned to customers.The earnings review
is separate from the decoupling mechanism and was in place prior to decoupling.
Cumulative Decoupling and Earnings Sharing Mechanism Balances
As ofDecember 31,2023 and December 31,2022,the Company had the following cumulative balances outstanding related to decoupling and earnings sharing mechanisms in its
various jurisdictions(dollars in thousands):
December 31, December 31,
2023 2022
washington
Decoupling rebate $ (3,232) $ (13,210)
Idaho
Decoupling rebate $ (7,961) $ (7,889)
Provision for earnings sharing rebate (572) (686)
Oregon
Decoupling(rebate)surcharge $ (3,724) S 2,853
NOTE 17.NOTES RECEIVABLE FROM ASSOCIATED COMPANIES
Avista Capital may borrow up to$80 million from Avista Corp.to cover subsidiary cash needs in accordance with board-approved limits.Avista Capital pays interest on the
outstanding amount at a rate at least equal to the Alternate Base Rate as defined in the Avista Corp.credit facility agreement,which is estimated at the Prime rate.This rate will be reset
when the Agent bank on the Avista Corp.credit facility agreement changes the Prime rate or the margin.
As of December 31,2023,the Company had a note receivable balance from Avista Capital of$20.6 with an applicable interest rate of 8.5 percent.
NOTE 18.SUBSEQUENT EVENTS
The Company has evaluated its subsequent events,noting the following events have occurred subsequent to December 31,2023:
• On April 1,2024,Avista Corporation(Avista Corp.orthe Company)closed on the remarketing of$66.7 million and$17.0 million ofthe City ofForsyth,Montana
Pollution Control Revenue Refunding Bonds due in 2032 and 2034,respectively.These bonds are secured by equal principal amounts ofnon-transferable first
mortgage bonds ofthe Company.The term interest rate on both series ofbonds is 3.875 percent.Avista Corp.purchased the bonds upon original issuance in
December2010,with the intention to hold the bonds until market conditions were favorable forremarketing the bonds to unaffiliated investors.While the Company
was the holder ofthese bonds,the bonds were not reflected as an asset or a liability on the Consolidated Balance Sheets.With the remarketing ofthese bonds,the
Company will recognize long term debt of$83.7 million.The net proceeds from the remarketing ofthese bonds were used to refinance existing short term debt
obligations.
FERC FORM No.1 (ED.12-96)
Page 122-123

This report is:
Name of Respondent: (1)0 An Original Date of Report: Year/Period of Report
Avista Corporation 04/12/2024 End of:2023/Q4
(2) ❑ A Resubmission
I
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME,COMPREHENSIVE INCOME,AND HEDGING ACTIVITIES
Unrealized — Other - - -
Gains and Minimum Cash Other Totals for Net Income
Losses on Pension Foreign Other Flow Cash each category (Carried Total
Tne It
Liability Currency Hedges Flow of items Forward from Comprehensive
Available- Adjustments
o. i (a) For Adjustment Hedges a Interest Hedges recorded in Page 116, Income
Securities (net amount) (d) Rate [Specify) Account 219 Line 78) (j)
(b) (c) Swaps (g) (h) (i)
M
Balance of
1 Account 219 at 0 (11,038,551) (11,038,551)
Beginning of
Preceding Year
Preceding
Quarter/Yearto
Date
2 Reclassifications 0
from Account
219 to Net
Income
Preceding
3 Quarter/Yearto 8,980,326 8,980,326
Date Changes in
Fair Value
4 Total(lines 2 and 8,980,326 8,980,326 155,176,032 164,156,358
Balance of
Account 219 at
5 End of (2,058,225) (2,058,225)
Preceding
Quarter/Year
Balance of
6 Account 219 at (2,058,225) (2,058,225)
Beginning of
Current Year
Current
Quarter/Yearto
Date
7 Reclassifications 0
from Account
219 to Net
Income
Current
8 Quarter/Yearto 1,701,116 1,701,116
Date Changes in
Fair Value
9 Total(lines 7 and 1,701,116 1,701,116 171,180,214 172,881,330
Balance of
10 Account 219at (357,109) (357,109)
End of Current
Quarter/Year
FERC FORM No.1 (NEW 06-02)
Page 122(a)(b)

This report is:
Name of Respondent: (1)0 An Original Date of Report: Year/Period of Report
Avista Corporation 04/12/2024 End of:2023/Q4
(2) El A Resubmission
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS FOR DEPRECIATION.AMORTIZATION AND DEPLETION
Total Company
Line Classification For the Current Electric Gas Other Other Other Common
No. (a) Year/Quarter (c) (d) (Specify) (Specify) (Specify) (h)
Ended (e) (f) (g)
(b)
1 UTILITY PLANT
r
2 In Service
3 Plant in Service 7,781,458,219 5,352,763,952 1,683,865,098 744,829,169
(Classified)
4 Property Under Capital 67,585,264 67,585,264
Leases
5 Plant Purchased or
Sold
Completed
6 Construction not
Classified
7 Experimental Plant
Unclassified
8 Total(3 thru 7) 7,849,043,483 5,352,763,952 1,683,865,098 812,414,433
9 Leased to Others
10 Held for Future Use 3,658,920 2,928,319 180,896 549,705
11 Construction Work in 170,812,964 132,548,007 7,682,114 30,582,843
Progress
12 Acquisition 256,800 256,800
Adjustments
I
13 Tot)alUtility Plant(8thru 8,023,772,167 5,488,497,078 1,691,728,108 843,546,981
12
Accumulated
Provisions for
14 Depreciation, 2,796,332,034 1,969,142,630 513,678,701 313,510,703
Amortization,&
Depletion
15 Net Utility Plant(13 5,227,440,133 3,519,354,448 1,178,049,407 530,036,278
less 14)
DETAIL OF
ACCUMULATED
16 PROVISIONS FOR
DEPRECIATION,
AMORTIZATION AND
DEPLETION
17 In Service:
18 Depreciation I 2,573,168,761 1,928,168,400 512,558,995 132,441,366
Amortization and
19 Depletion of Producing
Natural Gas Land and
Land Rights
FERC FORM No.1 (ED.12-89)
Page 200-201

SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS FOR DEPRECIATION.AMORTIZATION AND DEPLETION
Total Company
For the Current Other Other Other
Line Classification Electric Gas Common
No. (a) Year/Quarter (c) (d) (Specify) (Specify) (Specify) (h)
Ended (e) (f) (g)
(b)
Amortization of
Underground Storage
20 Land and Land Rights
21 Amortization of Other 223,163,273 40,974,230 1,119,706 181,069,337
Utility Plant
22 Total
otI in Service(18 thru 2,796,332,034 1,969,142,630 513,678,701 313,510,703
21)
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
3: Total Accum Prov
333 (equals 14) 2,796,332,034 1,969,142,630 513,678,701 313,510,703
(22,26,30,31,32)
FERC FORM No.1 (ED.12-89)
Page 200-201

This report is:
Name of Respondent: (1)21 An Original Date of Report: Year/Period of Report
Avista Corporation (2)El A Resubmission 04/12/2024 End of:2023/Q4
ELECTRIC PLANT IN SERVICE(Account 101,102,103 and 106)
Balance
Line Account Beginning of Additions Retirements Adjustments Transfers Balance at End
No. (a) Year (c) (d) (e) of Year
(b) (g)
1 1.INTANGIBLE PLANT -
2 (301)Organization
3 (302)Franchise and 46,795,649 42,494
Consents (33,872) 46,804,271
4 (303)Miscellaneous 52,229,864 9,157,151 3,579,985 33,872 57,840,902
Intangible Plant
TOTAL Intangible Plant
5 (Enter Total of lines 2,3, 99,025,513 9,199,645 3,579,985 0 104,645,173
and 4)
6 2.PRODUCTION
PLANT 1
7 A.Steam Production -
Plant _
8 (310)Land and Land 3,857,583 0 3,857,583
Rights
9 (311)Structures and 140,868,863 534,075 11,568 141,391,370
Improvements
10 (312)Boiler Plant 223,993,081 1,626,995 369,020 225,251,056
Equipment
(313)Engines and
11 Engine-Driven (5,008) 236,879 231,871
Generators
12 (314)Turbogenerator 57,991,911 324,774 17,328 58,299,357
Units
13 (315)Accessory Electric 30,595,041 236,877 30,831,918
Equipment
14 (316)Misc.Power Plant 17,129,513 236,878 17,366,391
Equipment
17,463,496
(317)Asset Retirement
15 Costs for Steam 15,536,251 1,927,245
Production
TOTAL Steam
16 Production Plant(Enter 489,967,235 5,123,723 397,916 494,693,042
Total of lines 8 thru 15)
17 B.Nuclear Production
Plant
18 (320)Land and Land
Rights
19 (321)Structures and
Improvements
20 (322)Reactor Plant
Equipment
FERC FORM No.1 (REV.12-05)
Page 204-207

ELECTRIC PLANT IN SERVICE(Account 101,102,103 and 106)
Balance Balance at End
Line Account Beginning of Additions Retirements Adjustments Transfers of Year
No. (a) Year (c) (d) (e) (f) (g)
(b)
(323)Turbogenerator
21 Units
22 (324)Accessory Electric
Equipment
23 (325)Misc.Power Plant
Equipment
(326)Asset Retirement
24 Costs for Nuclear
Production
TOTAL Nuclear
25 Production Plant(Enter
Total of lines 18 thru 24)
C.Hydraulic Production
26 Plant
27 (330)Land and Land 65,888,976 2,520,485 68,409,461
Rights
28 (331)Structures and 111,713,114 5,885,120 797,307 116,800,927
Improvements
29 (332)Reservoirs,Dams, 256,473,521 9,805,966 410 266,279,077
and Waterways
(333)Water Wheels,
30 Turbines,and 235,789,409 848,353 605,126 236,032,636
Generators
31 (334)Accessory Electric 84,873,187 1,261,390 261,085 85,873,492
Equipment
32 (335)Misc.Power Plant 13,734,934 646,716 8,715 14,372,935
Equipment
33 (336)Roads,Railroads, 3,648,611 249,648 10,101 3,888,158
and Bridges
(337)Asset Retirement
34 Costs for Hydraulic
Production
TOTAL Hydraulic
35 Production Plant(Enter 772,121,752 21,217,678 1,682,744 791,656,686
Total of lines 27 thru 34)
36 D.Other Production
Plant
37 (340)Land and Land 905,167 0 905,167
Rights
38 (341)Structures and 17,613,988 23,181 37,331 17,599,838
Improvements
(342)Fuel Holders,
39 Products,and 21,070,907 116 21,071,023
Accessories
r4O (343)Prime Movers 21,443,903 14,110 21,429,793
FERC FORM No.1 (REV.12-05)
Page 204-207

ELECTRIC PLANT IN SERVICE(Account 101,102,103 and 106)
Balance
Line Account Beginning of Additions Retirements Adjustments Transfers Balance at End
No. (a) Year (c) (d) (e) (f) of Year
(b) (9)
41 (344)Generators 237,686,875 718,872 423,966 237,981,781
42 (345)Accessory Electric Equipment 25,712,405 920,937 73,075 26,560,267
43 (346)Misc.Power Plant 1,642,746 58 16,146 1,626,658
Equipment
(347)Asset Retirement
44 Costs for Other 351,683 0 351,683
Production
(348)Energy Storage
44.1 Equipment-Production
TOTAL Other Prod.Plant
45 (Enter Total of lines37 326,427,674 1,663,164 564,628 327,526,210
thru 44)
TOTAL Prod.Plant
46 (Enter Total of lines 16, 1,588,516,661 28,004,565 2,645,288 1,613,875,938
25,35,and 45)
47 3.Transmission Plant
48 (350)Land and Land 30,092,047 168,213 2,024 30,258,236
Rights
I
(351)Energy Storage
48.1 Equipment-
Transmission
49 (352)Structures and Improvements 30,634,477 6,880,190 133,952 37,380,715
50 (353)Station Equipment 365,127,492 25,527,973 2,398,123 388,257,342
51 (354)Towers and 17,217,152 (53,118) 24,566 17,139,468
Fixtures
52 (355)Poles and Fixtures 353,099,994 28,936,574 700,974 381,335,594
53 (356)Overhead 182,973,690 8,224,033 363,594 190,834,129
Conductors and Devices
54 (357)Underground 3,577,440 363,503
Conduit ( ) 3,213,937
55 (358)Underground 7,054,975 363,502
Conductors and Devices ( ) 6,691,473
56 (359)Roads and Trails 2,608,136 0 2,608,136
(359.1)Asset Retirement
57 Costs for Transmission
Plant
TOTAL Transmission
58 Plant(Enter Total of lines 992,385,403 68,956,860 3,623,233 1,057,719,030
48 thru 57)
59 4.Distribution Plant
60 (360)Land and Land 16,392,078 2,097,982 0 (2,068,423) 16,421,637
Rights
FERC FORM No.1 (REV.12-05)
Page 204-207

ELECTRIC PLANT IN SERVICE(Account 101,102,103 and 106)
Balance Balance at End
Line Account Beginning of Additions Retirements Adjustments Transfers of Year
No. (a) Year (c) (d) (e) (f) (g)
(b)
61 (361)Structures and 28,488,284 2,547,182 50,943 30,984,523
Improvements
62 (362)Station Equipment 164,195,204 10,461,576 1,484,822 173,171,958
63 (363)Energy Storage
Equipment—Distribution
64 (364)Poles,Towers,and 538,890,192 48,170,081 1,315,943 585,744,330
Fixtures
65 (365)Overhead 342,545,005 23,934,559 101,045 366,378,519
Conductors and Devices
66 (366)Underground 156,935,860 18,822,448 32,037 175,726,271
Conduit
67 (367)Underground 274,250,687 18,050,349 192,176 292,108,860
Conductors and Devices
68 (368)Line Transformers 327,782,685 30,649,538 83,759 358,348,464
69 (369)Services 214,871,264 11,146,575 38,168 225,979,671
70 (370)Meters 86,339,367 1,322,659 105,626 87,556,400
71 (371)Installations on 6,679,677 4,085,651 132,384 10,632,944
Customer Premises
72 (372)Leased Property
on Customer Premises
73 (373)Street Lighting and 78,377,324 6,208,672 332,915 84,253,081
Signal Systems
(374)Asset Retirement
74 Costs for Distribution
Plant
TOTAL Distribution Plant
75 (Enter Total of lines 60 2,235,747,627 177,497,272 3,869,818 (2,068,423) 2,407,306,658
thru 74)
5.REGIONAL
76 TRANSMISSION AND i
MARKET OPERATION
PLANT
77 (380)Land and Land
Rights
78 (381)Structures and
Improvements
79 (382)Computer
Hardware
80 (383)Computer
Software
81 (384)Communication
Equipment
FERC FORM No.1 (REV.12-05)
Page 204-207

ELECTRIC PLANT IN SERVICE(Account 101,102,103 and 106)
Balance Balance at End
Line Account Beginning of Additions Retirements Adjustments Transfers of Year
No. (a) Year (c) (d) (e) (f) (
(b) 9)
(385)Miscellaneous
82 Regional Transmission
and Market Operation
Plant
(386)Asset Retirement
83 Costs for Regional
Transmission and
Market Oper
TOTAL Transmission
84 and Market Operation
Plant(Total lines 77 thru
83)
85 6.General Plant
86 (389)Land and Land 885,665 197,341 1,083,006
Rights
87 (390)Structures and 20,705,705 561,785 221,982 21,045,508
Improvements
88 (391)Office Furniture 3,316,124 834,587 174,089 3,976,622
and Equipment
89 (392)Transportation 59,454,054 4,943,929 2,118,366 78,214 62,357,831
Equipment
90 (393)Stores Equipment 472,784 0 472,784
91 (394)Tools,Shop and 8,187,992 1,000,962 183,415 9,005,539
Garage Equipment
(395)Laboratory
92 Equipment 3,228,953 90,866 14,532 3,305,287
93 (396)Power Operated 28,073,572 142,813 2,783,853 25,432,532
Equipment
94 (397)Communication 44,938,649 1,462,865 4,122,243 42,279,271
Equipment
95 (398)Miscellaneous 280,797 41,703 63,727 258,773
Equipment
96 SUBTOTAL(Enter Total 169,544,295 9,079,510 9,682,207 275,555 169,217,153
of lines 86 thru 95)
97 (399)Other Tangible
Property
98 (399.1)Asset Retirement
Costs for General Plant
TOTAL General Plant
99 (Enter Total of lines 96, 169,544,295 9,079,510 9,682,207 275,555 169,217,153
97,and 98)
100 TOTAL(Accounts 101 5,085,219,499 292,737,852 23,400,531 (1,792,868) 5,352,763,952
and 106)
101 (102)Electric Plant
Purchased(See Instr.8)
FERC FORM No.1 (REV.12-05)
Page 204-207

ELECTRIC PLANT IN SERVICE(Account 101,102,103 and 106)
Balance Balance at End
Line Account Beginning of Additions Retirements Adjustments Transfers of Year
No. (a) Year (c) (d) (e) (f) (g)
(b)
102 (Less)(102)Electric
Plant Sold(See Instr.8)
103 (103)Experimental Plant
Unclassified
TOTAL Electric Plant in
104 Service(Enter Total of 5,085,219,499 292,737,852 23,400,531 (1,792,868) 5,352,763,952
lines 100 thru 103)
FERC FORM No.1 (REV.12-05)
Page 204-207

This report is:
Name of Respondent: (1)®An Original Date of Report: Year/Period of Report
Avista Corporation (2) El A Resubmission 04/12/2024 End of:2023/Q4
ELECTRIC PLANT HELD FOR FUTURE USE(Account 105)
Line Description and Location of Property Date Originally Included in Date Expected to be used Balance at End of Year
This Account in Utility Service
No. (a) (b) (c) (d)
1 Land and Rights:
2 Distribution Plant Land,Carlin Bay,Idaho 12/01/2010 12/31/2027 162,352
3 Transmission Plant Land,Spokane, 12/01/2011 12/31/2027 411,202
Washington
4 Transmission Plant Land,Spokane, 07/01/2014 12/31/2027 62,168
Washington
5 Transmission Plant Land,Spokane, 01/01/2017 12/31/2027 56,311
Washington
6 Transmission Plant Land,Spokane, 03/01/2019 12/31/2027 323,427
Washington
7 Transmission Plant Land,Spokane, 03/01/2019 12/31/2027 546,503
Washington
8 Distribution Plant Land,Colville,Washington 06/01/2019 12/31/2027 104,527
9 Transmission Plant Land,Sandpoint,Idaho 07/01/2019 12/31/2027 486,299
10 Distribution Plant Land,Coeur d'Alene,Idaho 11/01/2020 12/31/2027 775,530
21 Other Property:
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
FERC FORM No.1 (ED.12-96)
Page 214

ELECTRIC PLANT HELD FOR FUTURE USE(Account 105)
Date Originally Included in Date Expected to be used
Line Description and Location of Property Balance at End of Year
No. a This Account in Utility Service d
39
40
41
42
43
44
45
46
47 TOTAL 2,928,319
FERC FORM No.1 (ED.12-96)
Page 214

This report is:
Name of Respondent: (1)0 An Original Date of Report: Year/Period of Report
Avista Corporation 04/12/2024 End of:2023/Q4
(2) El A Resubmission
CONSTRUCTION WORK IN PROGRESS--ELECTRIC(Account 107)
Description of Project Construction work in progress-Electric
Line No. (a) (Account 107)
(b)
1 Substation Rebuilds 20,828,957
2 Metro 115kV Substation 16,733,242
3 Long Lake Plant Upgrades 13,777,343
4 CG HED Station Service Replacement 12,775,533
5 LL HED Stability Enhancement 8,913,444
6 Coyote Springs 2 CT Rotor Replacement 4,640,784
7 HMI Control Software 3,846,698
8 OMS/ADMS 3,096,493
9 Substation-Capital Spares 2,969,262
10 Low Priority Ratings Mitigation 2,503,720
11 Westside 230 kV Substation-Rebuild 2,498,743
12 Downtown Network-Performance&Capacity 2,397,630
13 Nine Mile Unit Mechanical Overhaul 2,366,619
14 New Substations 2,286,983
15 Garden Springs 230-115 kV Substation 2,040,792
16 PF North Channel Spillway Repl 1,846,082
17 Wildfire Resiliency 1,679,393
18 Distribution-Big Bend,North&West 1,595,001
19 Substation Asset Mgmt Capital Maintenance 1,343,678
20 Distribution Line Transformers 1,260,495
21 Tribal Permits and Settlements 1,256,106
22 Regulating Hydro 1,160,118
23 Generation,Substation&Gas Location Security 1,154,991
24 Transportation Equip 1,152,249
25 CG Stop Log Replacement 1,062,498
26 Minor Projects under$1,000,000 14,024,896
27 R&D/Strategic Initiatives 3,336,257
43 Total 132,548,007
FERC FORM No.1 (ED.12-87)
Page 216

This report is:
Name of Respondent: (1)21 An Original Date of Report: Year/Period of Report
Avista Corporation 04/12/2024 End of:2023/Q4
(2) El A Resubmission
ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT(Account 108)
Line Item Total(c+d+e) Electric Plant in Electric Plant Held for Electric Plant Leased
No. (a) (b) Service Future Use To Others
(c) (d) (e)
Section A.Balances and Changes During Year
1 Balance Beginning of Year 1,814,695,451 1,814,695,451
2 Depreciation Provisions for Year,
Charged to
3 (403)Depreciation Expense 149,272,689 149,272,689
4 (403.1)Depreciation Expense for 0
Asset Retirement Costs
5 (413)Exp.of Elec.Pit.Leas.to
Others
6 Transportation Expenses-Clearing 4,926,093 4,926,093
7 Other Clearing Accounts
8 Other Accounts(Specify,details in
footnote):
9.1
9.2
9.3
9.4
9.5
10 TOTAL Deprec.Prov for Year(Enter 154,198,782 154,198,782 0 0
Total of lines 3 thru 9)
11 Net Charges for Plant Retired:
12 Book Cost of Plant Retired (19,822,225) (19,822,225)
13 Cost of Removal (1,305,366) (1,305,366)
14 Salvage(Credit) 6,963 6,963
15 TOTAL Net Chrgs.for Plant Ret. (21,120,628) (21,120,628)
(Enter Total of lines 12 thru 14)
16 Other Debit or Cr.Items(Describe,
details in footnote):
17.1 Depreciation offset for non- (112,280) (112,280)
recoverable plant for Boulder Park
17.2 Change in APx Accrual (30,001) (30,001)
17.3 ARO Depreciation 2,813,972 2,813,972
17.4 Transfers 110,738 110,738
17.5 Change in RWIP (4,169,754) (4,169,754)
17.6 General Plant Common Allocated (18,217,880) (18,217,880)
FERC FORM No.1 (REV.12-05)
Page 219

ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT(Account 108)
Line Item Total(c+d+e) Electric Plant in Electric Plant Held for Electric Plant Leased
No. (a) (b) Service Future Use To Others
(c) (d) (e)
18 Book Cost or Asset Retirement
Costs Retired
19 Balance End of Year(Enter Totals of 1,928,168,400 1,928,168,400 0 0
lines 1,10,15,16,and 18)
Section B.Balances at End of Year According to Functional Classification
207 Steam Production 394,650,809 394,650,809
21 Nuclear Production
22 Hydraulic Production-Conventional 202,979,974 202,979,974
23 Hydraulic Production-Pumped
Storage
24 Other Production 177,969,738 177,969,738
25 Transmission 285,851,148 285,851,148
26 Distribution 788,670,773 788,670,773
27 Regional Transmission and Market
Operation
28 General 78,045,958 78,045,958
29 TOTAL(Enter Total of lines 20 thru 1,928,168,400 1,928,168,400 0 0
28)
FERC FORM No.1(REV.12-05)
Page 219

This report is:
Name of Respondent: (1)®An Original Date of Report: Year/Period of Report
Avista Corporation 04/12/2024 End of:2023/Q4
(2) ❑A Resubmission
INVESTMENTS IN SUBSIDIARY COMPANIES(Account 123.1)
Amount of Equity in Gain or
Description of Investment at Subsidiary Revenues Amount of Loss from
Line Investment Date Acquired Date of Maturity Beginning of Eamings of for Year Investment at Investment
No. (a) (b) (c) Year Year (f) End of Year Disposed
(d) (e) (g) of
(h)
1 Investment in Avista 01/01/1997 256,138,971 0 256,138,971
Capital
2 Avista Capital- (106,266,632) (4,288,022) (110,554,654)
Equity in Earnings
3 Investment in 07/01/2014 89,816,380 0 89,816,380
AERC
4 AERC-Equity in 21,072,251 8,737,693 29,809,944
Earnings
Total Cost of
42 Account 123.1 $ Total 260,760,970 4,449,671 265,210,641
FERC FORM No.1 (ED.12-89)
Page 224-225

This report is:
Name of Respondent: (1)0 An Original Date of Report: Year/Period of Report
Avista Corporation (2) El A Resubmission 04/12/2024 End of:2023/Q4
MATERIALS AND SUPPLIES
Line Account _ Balance Beginning of(a) (c)Balance End of Year Department or Departments which Use
Year Material
No. j (b) _ (d)
1 Fuel Stock(Account 151) 1 4.252,607 4,683,150
2 Fuel Stock Expenses Undistributed 0 0
(Account 152)
3 Residuals and Extracted Products 0 0
(Account153)
4 Plant Materials and Operating Supplies
(Account154)
5 Assigned to-Construction(Estimated) 51,057,881 58,422,040 (1)Electric
Assigned to-Operations and r
6 Maintenance r
7 Production Plant(Estimated) 5,069,997 5,531,231 (1)Electric
8 Transmission Plant(Estimated) 179,891 114,052 (1)Electric
9 Distribution Plant(Estimated) 806,251 897,097 (1)Electric
10 Regional Transmission and Market
Operation Plant(Estimated)
11 Assigned to-Other(provide details in 16,339,904 14,528,108 (1)Electric,(2)Natural Gas
footnote)
12 TOTAL Account 154(Enter Total of 73,453,924 79,492,528
lines 5 thru 11)
13 Merchandise(Account 155) 0 0
14 Other Materials and Supplies(Account 0 0
156)
15 Nuclear Materials Held for Sale 0 0
(Account 157)(Not applic to Gas Util)
16 Stores Expense Undistributed(Account 0 0
163)
17
18
19
20 TOTAL Materials and Supplies 77,706,531 84,175,678
FERC FORM No.1 (REV.12-05)
Page 227

This report is:
Name of Respondent: (1)21 An Original Date of Report: Year/Period of Report
Avista Corporation 04/12/2024 End of.2023/Q4
(2) ❑AResubmission
Transmission Service and Generation Interconnection Study Costs
Costs incurred During Account Reimbursements Account Credited
Line Description Received During the With
No. (a) Period Charged Period Reimbursement
(b) (c) (d) (e)
I
1 Transmission Studies
2 ENEL Studies forTSR 40,942 186200 0
20 Total 40,942 0
21 Generation Studies
22 Aurora Solar Project#59 100,571 186200 76,515 186210
23 Post Falls HED Project#63 101,121 186200 0
24 Clearwater Wind II Proj#68 12,172 186200 0
25 Clearwater Wind III Proj#69 16,505 186200 0
26 Haymaker Wind Proj#82 8,748 186200 0
27 Marfinsdale Wind Proj#83 4,324 186200 0
28 Jane Wind 2 Proj#96 1,968 186200 0
29 Jane Wind Proj#95 2,127 186200 0
30 Big Sky Connector Line Project 2,752 186200 0
31 Broadview IV Project#107 2,949 186200 0
32 Ursus Wind Project#108 3,240 186200 0
33 Gordon Butte South Wind Q116 3,171 186200 0
34 CS PV Q113 1,820 186200 0
35 CS Wind 2 Q115 1,618 186200 0
36 CS Wind 1 Q114 1,149 186200 0
37 Triple Oak Connector Line 2,545 186200 0
38 North Plains Connector Line 2,154 186200 0
39 Ursiane Wind#118 2,281 186200 0
40 Royal Slope-Juwi-ESA 9,262 186200 0
41 Colstrip Solar 1,537 186200 0
42 CA1 West Plains 45,472 186200 17,037 186210
43 CA1 Phase 1 ReStudy 17,584 186200 0
44 CA1 Phase 2 Study 2,618 186200 0
45 CA5 Palouse 45,634 186200 0
46 CA5 Phase 2 Study 47,956 186200 0
47 CA7 Big Bend 41,599 186200 5,673 186210
FERC FORM No.1 (NEW.03-07)
Page 231

Transmission Service and Generation interccnnection Study Costs
Cos nC ;,a Ac,aunt Reimbursements Account Credite
Line Description Period Chargcd Received During the With
No. (a) (b) (y) Period Reimbursement
(d) (e)
48 CA7 Phase 2 Study 40,404 i 85200 0
49 Kettle Falls Upgrade Proj#66 61,211 f 186200 61,211 186210
50 Big Bend Cluster Phase 2 T7a 47,451 t 186200 47,451 186210
51 CA6 Lewis Clark 37,62?—!k�_ ,86200 37,622 186210
52 CA3 Idaho 27,819 k 186200 27,819 186210
39 Total 697,384 273,328
40 Grand Total 1--1738,326 -273,328
FERC FORM No.1 (NEW.03-07)
Page 231

This report is:
Name of Respondent: (1)®An Original Date of Report: Year/Period of Report
Avista Corporation 04/12/2024 End of:2023/Q4
(2) ❑A Resubmission
FOOTNOTE DATA
La)Concept:StudyCostslncurred
Total life to date costs
Concept:StudyCostsReimbursements
Total life to date reimbursements
FERC FORM No.1 (NEW.03-07)
Page 231

This report is:
Name of Respondent: (1)0 An Original Date of Report: Year/Period of Report
Avista Corporation 04/12/2024 End of:2023/Q4
(2)❑ A Resubmission
OTHER REGULATORY ASSETS(Account 182.3)
CREDITS CREDITS
Balance at Written off
Description and Purpose of Beginning of During Written off During Balance at end of
Line Debits Quarter/Year Current
No. Other Regulatory Assets Current (c} Account the Period Amount Quarter/Year
(a) Quarter/Year Charged (e) (f)
(b) (d)
L
1 WA Excess Nat Gas Line 4,328,385 0 407 1,745,141 2,583,244
Extension Allowance
Lbl
2 Reg Asset Post Ret Liabilility 128,847,130 1,796,907 228 18,181,644 112,462,393
3 Regulatory Asset FAS 109 Utility 80,549,288 1,556,488 283 3,933,322 78,172,454
Plant
4 Regulatory Asset FAS 109 DSIT 4,442,326 593,287 283 2,353,940 2,681,673
Non Plant
L
5 Regulatory Asset Lake CDA 37,809,157 0 407 1,116,805 36,692,352
Settlement-Varies
6 Reg Assets-Decoupling 9,089,302 36,741,461 456,495 43,395,041 2,435,722
Surcharges
LM
7 RegAsset-Colstrip 14,976,471 6,165,968 407 1,713,471 19,428,968
ss
8 Regulatory Asset FAS 143 Asset 2,165,181 1 133,388 0 2,298,569
Retirement Obligation
2)
9 Regulatory Asset Workers Comp 989,028 956,123 242 14,986 1,930,165
10 Interest Rate Swap Asset 185,919,054 1,417,272 Various 7,847,927 179,488,399
Lkj
11 DSM Asset 3,683,352 8,398,035 Various 1,823,901 10,257,486
fil
12 Deferred ITC 3,769,051 0 283,410 166,945 3,602,106
13 Regulatory Asset MDM System 32,380,865 0 407,419 3,035,706 29,345,159
Lnj
14 Regulatory Asset BPA 1,298,948 1,861,113 407 1,609,846 1,550,215
Residential Exchange
15 Regulatory Asset FISERV 406,443 117,683 407,419 353,815 170,311
16 Regulatory Asset AFUDC 59,662,251 30,423,065 Various 31,019,224 59,066,092
(PIS,WIP)&Equity DFIT
17 Regulatory Asset ID PCA 16,341,994 15,169,526 557,419 23,884,029 7,627,491
Deferral
18 Existing Meters/ERTS 19,459,498 0 108,407 1,824,328 17,635,170
Retirement Def
FERC FORM No.1 (REV.02-04)
Page 232

OTHER REGULATORY ASSETS(Account 182.3)
CREDITS CREDITS
Balance at Written off
Description and Purpose of Beginning of During Written off During Balance at end of
Line Debits Quarter/Year Current
No. Other Regulatory Assets Current (c) Account the Period Amount Quarter/Year
(a) Quarter/Year Charged (e) (f)
(b) (d)
u
Regulatory Asset Colstrip
19 Community Fund 1,500,000 562,500 182,407 1,312,500 750,000
u
20 Regulatory Asset COVID-1 9 1,241,772 1,977,642 186,407 2,561,625 657,789
Di
21 Regulatory Asset Energy 699,119 182,407 116,520 582,599
Imbalance Market
L
22 Regulatory Asset Oregon CAT 628,249 12,664 407,419 630,849 10,064
Tax
Li
23 Regulatory Asset-Wildfire 18,186,521 11,788,958 182 6,238,024 23,737,455
Resiliency&Balancing
24 Deferral for CS2&Colstrip 1,874,781 2,238,354 182,407 2,094,878 2,018,257
(O&M,Excess Depr)
25 Regulatory Asset Tax Basis Flow 138,273,552 9,853,657 282,283 2,958,003 145,169,206
through
m
26 Reg Asset-Intervenor Fund 0 307,699 182 201,760 105,939
Deferral
27 Unrealized Currency Exchange 1,492,610 0 143 1,492,610 0
L.
28 Regulatory Asset Commodity 130,274,212 272,303,368 244,175 333,438,131 69,139,449
MTM ST&LT
L
29 Regulatory Asset Energy 219,732 1,817,222 182,908 735,954 1,301,000
Affordability Act
u
30 Reg Asset-Insurance Balancing 0 411,192 182,407 122,403 288,789
Acct
31 Reg Asset-CPP 0 594,833 0 594,833
32 Deferred Regulatory Fees 98,368 2,471,646 407,419 654,598 1,915,416
33 Regulatory Asset Pension 11,827,588 0 182,407 985,632 10,841,956
Settlement Deferral
34 Reg Asset-CCA 0 46,022,329 407 0 46,022,329
35 WA ERM Deferral-Approved for 0 38,639,584 182,557 13,161,287 25,478,297
Rebate
FERC FORM No.1 (REV.02-04)
Page 232

OTHER REGULATORY ASSETS(Account 182.3)
CREDITS CREDITS
Balance at Written off
Description and Purpose of Beginning of During Written off During Balance at end of
Line Debits QuarterNear Current
No. Other Regulatory Assets Current (c) Account the Period Amount Quarter/Year
(a) Quarter/Year Charged (e) (f)
(b) (d)
Lail
36 REG ASSET-MTRIVERBED 0 1,613,960 0 1,613,960
ESCROW INT
37 RegAsset-Depreciation 0 511,800 0 511,800
38 REG ASSET-CPP RNG 0 25,000 0 25,000
44 TOTAL 912,434,228 496,482,724 510,724,845 898,192,107
FERC FORM No.1(REV.02-04)
Page 232

This report is:
Name of Respondent: (1) An Original Date of Report: Year/Period of Report
Avista Corporation 04/12/2024 End of:2023/Q4
(2) ❑ A Resubmission
FOOTNOTE DATA
La)Concept:DescdptionAndPurposeOfOtherRegulatoryAssets
Residential Schedule 101 customers who receive a natural gas line extension as part of conversion to natural gas from another fuel source.Amort fora period of
3 years on the excess allowance exceeding the cost of the line extension.
Concept:DescdptionAndPurposeOfOtherRegulatoryAssets
Recognition of the overfunded and underfunded status of a defined benefit post retirement plan based on ASC 715 for financial reporting.
Lc)Concept:DescdptionAndPurposeOfOtherRegulatoryAssets
:Deferred tax flow through balance on utility plant.Amortization occurs over book life of respective utility plant assets.
Concept:DescdptionAndPurposeOfOtherRegulatoryAssets
Deferred tax flow through balance on utility plant.Amortization occurs over book life of respective utility plant assets.
Le)Concept:DescdptionAndPurposeOfOtherRegulatoryAssets
WA Docket No UE-080416;ID order AVU-E-08-01.Amort thru 2059.
-t Concept:DescdptionAndPurposeOfOtherRegulatoryAssets
Decoupling revenue deferrals are recognized during the period they occur,subject to certain limitations.Revenue is expected to be collected within 24 months
of the deferral.
&Concept:DescdptionAndPurposeOfOtherRegulatoryAssets
For WA Elec,amort period is 33.75yrs as per Order 09,dockets UE-190334,UG-190335,UE-190222(Consolidated).For ID Elec,amort is for 34.75yrs as per
Order 34276,AVU-E-18-03,Amor ends in 2054 for both jurisdictions.
Concept:DescdptionAndPurposeOfOtherRegulatoryAssets
Reg assets related to deferred ARO expenses for Kettle Falls and Coyote Springs thermal plants.The expenses will not be collected from customers until actual
work is performed.
u Concept:DescdptionAndPurposeOfOtherRegulatoryAssets
Quarterly adjustments to workers comp reserve for current unpaid claims.
M Concept:DescdptionAndPurposeOfOtherRegulatoryAssets
Settled swaps are amortized over the life of the associated debt.
.(k)Concept:DescriptionAndPurposeOfOtherRegulatoryAssets
Amort period varies depending on timing of transactions.
jI)Concept:DescdptionAndPurposeOfOtherRegulatoryAssets
Amort period varies depending on underlying transactions.
U Concept:DescdptionAndPurposeOfOtherRegulatoryAssets
WA Docket Nos UE-180418,UG-180419.
U Concept:DescdptionAndPurposeOfOtherRegulatoryAssets
Avista is a participant in the Residential Exchange Program with Bonneville Power Administration.Customers served under Schedules 1,12,22,32,and 48 are
given a rate adjustment based on Schedule 59 for WA and Id.Amort is based on customer usage.
Uo Concept:DescdptionAndPurposeOfOtherRegulatoryAssets
ID Order No 33494,Docket Nos.AVU-E-16-01 and Stipulation and Settlement Docket No AVU-E-19-04.
M Concept:DescriptionAndPurposeOfOtherRegulatoryAssets
Deferring the difference between FERC formula and State approved AFUDC rates from 2010 to present.
Lq)Concept:DescdptionAndPurposeOfOtherRegulatoryAssets
WA Docket No UE-002066 and ID Order No 28648.
Lr)Concept:DescdptionAndPurposeOfOtherRegulatoryAssets
WA Order 09 in Dockets UE-190334,UE-190222.Deferral of customer portion for future rate recovery.The funds are set aside to help the Colstrip community
transition away from economic activity related to coal-fired generation.
U Concept:DescriptionAndPurposeOfOtherRegulatoryAssets

Deferral of COVID-19 costs as per ID PUC Order No 34718,OR PUC Order No 20-401,Docket UM 2069 and WA UTC Order No.01,Dockets UE-
200407 and UG-200408.
Concept:DescdptionAndPurposeOfOtherRegulatoryAssets
ID PUC Order No 34606.Deferral of costs related to Avista's entry in the Energy Imbalance Market in March 2022.
Lu)Concept:DescdptionAndPurposeOfOtherRegulatoryAssets
OR PUC Order No.20-398,Docket UM-2042.
U Concept:DescdptionAndPurposeOfOtherRegulatoryAssets
Deferral of O&M wildfire expenses as per ID PUC Order 34883 and WA Dockets UE-200900,UG-200901,and UE-200894.
U Concept:DescdptionAndPurposeOfOtherRegulatoryAssets
WA Order 09,Docket Nos.UE-190334,UG-190335,and UE-190222.
jx)Concept:DescdptionAndPurposeOfOtherRegulatoryAssets
WA Order 01,Dockets UE-200895 and UG-200896,ID Case Nos.AVU-E-20-12 and AVU-G-20-07 Order No.34906,and OR Docket No UM 2124 Order
0 21-131-Accounting method change for federal income tax expense associated with Industry Director Directive No.5 mixed service costs for meters.
W Concept:Desc6ptionAndPurposeOfOtherRegulatoryAssets
WA Docket No UG-220596 and UE-220151.
Lz)Concept:DescdptionAndPurposeOfOtherRegulatoryAssets
Recognition of other liability related to foreign exchange hedge rates over a two year period.
as Concept:DescdptionAndPurposeOfOtherRegulatoryAssets
WA Docket No UE-002066 and ID Order No 28648.
ab Concept:DescdptionAndPurposeOfOtherRegulatoryAssets
Deferral of costs associated with OR House Bill 2475.
ac Concept:DescdptionAndPurposeOfOtherRegulatoryAssets
To defer costs above or below the baseline in accordance with Order No 10/04 Docket Nos UE-220053,UE-210854,and UG-220054.
ad Concept:DescdptionAndPurposeOfOtherRegulatoryAssets
To defer costs of compliance with the Climate Protection Plan pursuant to ORS 757.259 and OAR 860-027-0300(4).Docket No.UM2254.
ae Concept:DescdptionAndPurposeOfOtherRegulatoryAssets
OR Docket No UG415/Advice No.21-06-G.Amortization of amounts deferred previously in Order No.20-254 in UG 395,WA Docket No UE-220892 and
UG-220893 Order 01.
Jai Concept:DescdptionAndPurposeOfOtherRegulatoryAssets
o defer expected impacts associated with the occurrence of pension events and amortization over 12 years-ID Case Nos.AVU-E-22-16 and AVU-G-22-08,
WA Docket Nos UE-220898 and UG-220899,and OR UM 2267.
kaW Concept:DescdptionAndPurposeOfOtherRegulatoryAssets
To defer costs of compliance with the Climate Commitment Act in accordance with WAC 480-100-203(3)and WAC 480-90-203(3).WA Docket No UG-
220803.
.(ah)Concept:DescdptionAndPurposeOfOtherRegulatoryAssets
WA ERM Amortizing Deferral-Approved for Rebate Balance.Began amortizing 7/1/23.
ai Concept:DescdptionAndPurposeOfOtherRegulatoryAssets
Deferral for the Montana Riverbed land lease agreement escrow release provisions following Avista and State of Montana Agreement on an updated balance
owed.
kC Concept:DesedptionAndPurposeOfOtherRegulatoryAssets
Difference between depreciation rates in GRC verses effective date based on ID Order 35909 Dockets AVU-E-23-01 and AVU-G-23-01.
ak Concept:DescdptionAndPurposeOfOtherRegulatoryAssets
OR Order 23-145
FERC FORM No.I (REV.02-04)
Page 232

This report is:
Name of Respondent: (1)0 An Original Date of Report: Year/Period of Report
Avista Corporation 04/12/2024 End of:2023/Q4
(2) ❑A Resubmission
MISCELLANEOUS DEFFERED DEBITS(Account 186)
CREDITS CREDITS
Description of Miscellaneous Balance at Credits Balance at End of
Line Deferred Debits Beginning of Year Debits Account Credits Amount Year
No. (a) (b) (c) Charged (e) (f)
(d)
1 Reg Asset-Battery Storage 3,422,093 3,422,093
2 Plant Alloc of Clearing Journal 2,344,921 3,863,077 6,207,998
3 Reg Asset-ERM 35,799,197 VAR 23,638,534 12,160,663
4 WA REC Deferral 0 412,639 412,639
5 Reg Asset-Decoupling 4,458,589 4,653,520 9,112,109
Deferred
6 Reg Asset-COVID 19 Deferral 8,551,568 2,932,987 11,484,555
7 Reg Asset-CEIP 67,334 965,873 1,033,207
8 Reg Asset-Williams Outage 0 10,297,716 10,297,716
9 Misc Deferred Debits-Pension 13,381,750 19,622,239 33,003,989
10 Nez Perce Settlement 108,749 557 5,188 103,561
11 City of Post Falls Lease Pay 0 126,851 126,851
12 Post Falls HED Project 63 99,929 1,192 101,121
13 Misc.Deferred Debits<$100,000 686,038 VAR 634,636 51,402
47 Miscellaneous Work in Progress
48 Deferred Regulatory Comm.
Expenses(See pages 350-351)
49 TOTAL 68,920,168 87,517,904
FERC FORM No.1 (ED.12-94)
Page 233

This report is:
Name of Respondent: (1)21 An Original Date of Report: Year/Period of Report
Avista Corporation (2) ❑ A Resubmission 04/12/2024 End of:2023/Q4
ACCUMULATED DEFERRED INCOME TAXES(Account 190)
Line No. Description and Location Balance at Beginning of Year Balance at End of Year
{a) (b) (c)
1 Electric
2 Electric 105,974,248 84,418,866
7 Other 7
8 TOTAL Electric(Enter Total of lines 2 thru 7) 105,974,248 84,418,866
9 Gas
10 Gas 27,957,319 24,041,518
15 Other
16 TOTAL Gas(EnterTotal of lines 10 thru 15) 27,957,319 24,041,518
ll
17.1 Other 135,539,045 105,691,804
17 Other(Specify)
18 TOTAL(Acct 190)(Total of lines 8,16 and 17) 269,470,612 214,152,188
FERC FORM NO.1 (ED.12-88)
Page 234
Notes

This report is:
Name of Respondent: (1)®An Original Date of Report: Year/Period of Report
Avista Corporation 04/12/2024 End of.2023/Q4
(2)❑ A Resubmission
FOOTNOTE DATA
U Concept:Descri pti onOfAccu mu I ated Deferred In comeTax
Beg.Balance End. i
Balance
Pension,Medical,and SERP 39,011,736 34,671,763
Federal Income Tax Carryforwards 32,930,810 27,406,304
State Income Tax Carryforwards 22,175,174 17,952,286
Derivative Instruments 29,450,122 16,269,451
Compensation and Payroll 6,455,693 6,986,432
Plant Excess Deferred Gross Up 5,388,884 3,951,713
Other Common Deferred Tax Assets 126,626 (1,546,146)
Total 135,539,045 105,691,803
FERC FORM NO.1 (ED.12.88)
Page 234

This report is:
Name of Respondent: (1)0 An Original Date of Report: Year/Period of Report
Avista Corporation 04/12/2024 End of:2023/Q4
(2) El A Resubmission
CAPITAL STOCKS(Account 201 and 204)
Outstanding per Outstanding per
Bal.Sheet(Total Bal.Sheet(Total
amount amount
Class and Series of Stock and Number of Shares Par or Stated Value Call Price at End of outstanding outstanding
Line Authorized by without
No. Name of Stock Series Charter per Share Year without reduction reduction for
(a) (c) (d) for amounts held
(b) amounts held by
by respondent) respondent)
Shares Amount
1 Common Stock(Account 201)
2 No Par Value 200.000,000 78,074,587 1,596,986,047
3 Restricted Shares
11 Total 200,000,000 78,074,587 1,596,986,047
12 Preferred Stock(Account 204)
13 Cumulative 10,000,000
16 Total 10,000,000 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)
Held by Respondent As Held by Respondent As Held by Respondent In Sinking Held by Respondent In Sinking
Line Reacquired Stock(Acct 217) Reacquired Stock(Acct 217) and Other Funds Shares and Other Funds Amount
No. Shares Cost
(g) (h) (�) �)
1
2
3 152,140 6,463,455
11
12
13
16
1
2
3
4
5 _
FERC FORM NO.1 (ED.12-91)
Page 250-251

This report is:
Name of Respondent: (1)0 An Original Date of Report: Year/Period of Report
Avista Corporation (2) ❑ A Resubmission 2024-04-12 End of:2023/Q4
Other Paid-in Capital
Line No. Item Amount
(a) (b)
1 Donations Received from Stockholders(Account 208)
2 Beginning Balance Amount
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
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
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 (10,696,711)
15.1 Reclassification of subsidiary APIC 7,964,306
15 Increases(Decreases)Due to Miscellaneous Paid-In Capital 7,964,306
16 Ending Balance Amount (2,732,405)
17 Historical Data-Other Paid in Capital
18 Beginning Balance Amount
19 Increases(Decreases)in Other Paid-In Capital
20 Ending Balance Amount
40 Total (2,732,405)
FERC FORM No.1 (ED.12-87)
Page 253

report is:e This rpo
Name of Respondent: Th Th po Original Date of Report: Year/Period of Report
Avista Corporation 04/12/2024 End of:2023/Q4
(2) ❑ A Resubmission
CAPITAL STOCK EXPENSE(Account 214)
Class and Series of Stock Balance at End of
Line No. (a) Year
(b)
1 Common Stock-no par (50,073,294)
22 TOTAL (50,073,294)
FERC FORM No.1 (ED.12-87)
Page 254b

report is:
Name of Respondent: (1)This21 r An Original Date of Report: Year/Period of Report
Avista Corporation 04/12/2024 End of:2023/Q4
(2) ❑A Resubmission
LONG-TERM DEBT(Account 221,222,223 and 224)
Class and Series of
Obligation,Coupon Rate(For Related Total Expense,
Principal Amount Total
Line new issue,give commission Account Premium or Total Expense Total Premium
No. Authorization numbers and Number of Debt Issued Discount (e) (f) Discount
dates) (b) (c) (d) (g)
(a)
1 Bonds(Account 221)
2 FMBS-SERIES C-6.37% 221300 25,000,000 158,304
DUE 06/18/2028
3 COLSTRIP 2010A PCRBs 221350 66,700,000
DUE 2032
4 COLSTRIP 2010B PCRBs 221360 17,000,000
DUE 2034
5 35 BS-6.25%DUE 12-01- 221400 150,000,000 1,812,935 900,500
6 FMBS-5.70%DUE 07-01- 221420 150,000,000 4,702,304 222,000
2037
7 5.55%SERIES DUE 12-20- 221540 35,000,000 258,834
2040
8 4.45%SERIES DUE 12-14- 221560 85,000,000 692,833
2041
9 4.11%SERIES DUE 12-1- 221610 60,000,000 428,205
2044
10 4.37%SERIES DUE 12-1- 221620 100,000,000 590,761
2045
11 4.23%SERIES DUE 11-29- 221580 80,000,000 730,832
2047 -
12 3.91%SERIES DUE 12-1- 221640 90,000,000 I 552,539
2047
13 4.35%SERIES DUE 6-1- 221650 375,000,000 4,246,448 378,750
2048
14 3.43%SERIES DUE 12-1- 221660 180,000,000 1,108,340
2049
15 3.07%SERIES DUE 9-1- 221670 165,000,000 1,074,990
2050
16 2.90%SERIES DUE 221680 140,000,000 1,083,452
10/01/2051
17 3.54%SERIES DUE 2051 221630 175,000,000 1,042,569
18 4.00%SERIES DUE 221690 400,000,000 4,579,993
4/1/2052
19 5.66%SERIES DUE 04-01- 221710 250,000,000 1,444,302
2053
20 Subtotal - ool 2,543,700,000 24,507,641 0 1,501,250
FERC FORM No.1 (ED.12-96)
Page 256-257

LONG-TERM DEBT(Account 221,222,223 and 224)
Class and Series of
Obligation,Coupon Rate(For Related Principal Amount Total Expense, Total
Line new issue,give commission Account Premium or Total Expense Total Premium
No. Authorization numbers and Number of Debt Issued Discount (e) M Discount
dates) (b) (c) (d) (g)
(a)
21 Reacquired Bonds(Account
222)
COLSTRIP 2010A PCRBs
22 DUE 2032 221350 66,700,000
23 COLSTRIP 2010B PCRBs 221360 17,000,000
DUE 2034
24 Subtotal 83,700,000
25 Advances from Associated
Companies(Account 223)
26 ADVANCE ASSOCIATED 223011 51,547,000 1,296,086
AVISTA CAPITAL II(ToPRS)
27 Subtotal I 51,547,000 1,296,086
28 Other Long Term Debt
(Account 224)
29
30
31
32 Subtotal
33 TOTAL 2,678,947,000 '
FERC FORM No.1 (ED.12-96)
Page 256-257

LONG-TERM DEBT(Account 221,222,223 and 224)
Outstanding(Total
Line Nominal Date of Date of Maturity AMORTIZATION AMORTIZATION amount outstanding without reduction for Interest for Year
Issue PERIOD Date From PERIOD Date To Amount
No. (h) (i) �) (k) amounts held by (m)
respondent)
(I)
1
2 06/19/1998 06/19/2028 06/19/1998 06/19/2028 25,000,000 1,592,500
3 12/15/2010 10/01/2032 12/15/2010 10/01/2032 66,700,000
4 12/15/2010 03/01/2034 12/15/2010 03/01/2034 17,000,000
5 11/17/2005 12/01/2035 11/17/2005 12/01/2035 150,000,000 9,375,000
6 12/15/2006 07/01/2037 12/15/2006 07/01/2037 150,000,000 8,550,000
7 12/20/2010 12/20/2040 12/20/2010 12/20/2040 35,000,000 1,942,500
8 12/14/2011 12/14/2041 12/14/2011 12/14/2041 85,000,000 3,782,500
9 12/18/2014 12/01/2044 12/18/2014 12/01/2044 60,000,000 2,466,000
10 12/16/2015 12/01/2045 12/16/2015 12/01/2045 100,000,000 4,370,000
11 11/30/2012 11/29/2047 11/30/2012 11/29/2047 80,000,000 3,384,000
12 12/14/2017 12/01/2047 12/14/2017 12/01/2047 90,000,000 3,519,000
13 05/22/2018 06/01/2048 05/22/2018 06/01/2048 375,000,000 16,312,500
14 11/26/2019 12/01/2049 11/26/2019 12/01/2049 180,000,000 6,174,000
15 09/30/2020 09/30/2050 09/30/2020 09/30/2050 165,000,000 5,065,500
16 09/28/2021 10/01/2051 09/28/2021 10/01/2051 140,000,000 4,060,000
17 12/15/2016 12/01/2051 12/15/2016 12/01/2051 175,000,000 6,195,000
18 03/17/2022 04/01/2052 03/17/2022 04/01/2052 400,000,000 16,000,000
19 03/29/2023 04/01/2053 03/29/2023 04/01/2053 250,000,000 10,726,613
20 2,543,700,000 103,515,113
21
22 12/15/2010 10/01/2032 12/15/2010 10/01/2032 66,700,000 2,272,812
23 12/15/2010 03/01/2034 12/15/2010 03/01/2034 17,000,000 579,277
24 83,700,000 2,852,089
25
26 06/03/1997 06/01/2037 06/03/1997 06/01/2037 51,547,000 2,503,671
27 51,547,000 2,503,671
28
29
30
31

LONG-TERM DEBT(Account 221,222,223 and 224)
Outstanding(Total
Nominal Date of AMORTIZATION AMORTIZATION amount outstanding Interest for Year
Line Issue Date of Maturity PERIOD Date From PERIOD Date To Without reduction for Amount
No. (i) Ic amounts held by m
O �) O respondent) ( )
(I)
32 ! 0
33 I 2,511,547,000 108,870,873
FERC FORM No.1 (ED.12-96)
Page 256-257

This report is:
Name of Respondent: (1)0 An Original Date of Report: Year/Period of Report
Avista Corporation (2)❑A Resubmission 04/12/2024 End of.2023/Q4
RECONCILIATION OF REPORTED NET INCOME WITH TAXABLE INCOME FOR FEDERAL INCOME TAXES
Line No. Particulars(Details) Amount
(a) (b)
1 Net Income forthe Year(Page 117) 171,180,214
2 Reconciling Items for the Year
3
4 Taxable Income Not Reported on Books
5 Contributions in Aid of Construction 10,754,152
6 Other 36,360,532
9 Deductions Recorded on Books Not Deducted for Return
10 Book Depreciation 269,272,553
11 Federal Income Tax Expense (36,924,664)
12 State Income Tax Expense (31,119)
13 Subsidiary Overheads 360,971
14 Other 16,809,291
14 Income Recorded on Books Not Included in Return
15 Subsidiary Earnings 4,449,671
16 Other 3,328,370
19 Deductions on Return Not Charged Against Book Income
20 Tax Depreciation 234,949,702
21 Plant Basis Adjustments 137,699,340
22 Other 87,001,270
27 Federal Tax Net Income 353,577
28 Show Computation of Tax:
29 Federal Tax at 21% 74,251
30 Business Credits Utilized (989,812)
31 Prior Year True Ups 1,271,341
32 WA Remand at 35% (16,263)
33 Total Federal Current Tax Expense 339,517
FERC FORM NO.1 (ED.12-96)
Page 261

This report is:
Name of Respondent: (1)0 An Original Date of Report: Year/Period of Report
Avista Corporation 04/12/2024 End of:2023/Q4
(2) ❑A Resubmission
TAXES ACCRUED,PREPAID AND CHARGES DURING YEAR
_ BALANCE BALANCE
AT AT
BEGINNING BEGINNING
OF YEAR OF YEAR
Taxes Prepaid
Kind of Tax(See Accrued Taxes
Line Type of Tax State Tax Year (Include in
No. Instruction 5) (b) (c) (d) (Account Account
{a) 23 165)
(e) (fl
1 Income Tax Federal Tax 2021
2 Income Tax Federal Tax 2022
3 Income Tax Federal Tax 2023
4 Subtotal Federal Tax 0 0
5 Property Tax Property Tax WA 2022 18,573,985
6 Property Tax Property Tax WA 2023
7 Property Tax Property Tax ID 2022 2,857,137
8 Property Tax Property Tax ID 2023
9 Property Tax Property Tax MT 2022 4,840,427
10 Property Tax Property Tax MT 2023
11 Property Tax Property Tax OR 2022 4,517,894
12 I Property Tax Property Tax OR 2023
13 Subtotal Property Tax 26,271,549 4,517,894
14 Excise Tax Excise Tax WA 2022 3,980,660
15 Excise Tax Excise Tax WA 2023
16 Corp Activities Tax-CAT Excise Tax OR 2022
17 Corp Activities Tax-CAT Excise Tax OR 2023
18 Subtotal Excise Tax 3,980,660 0
19 Natural Gas Use Tax Sales And Use Tax WA 2022 46,608
20 Use Tax Sales And Use Tax WA 2023
21 Use Tax Sales And Use Tax WA 2022 210,812
22 Use Tax Sales And Use Tax WA 2023
23 Use Tax Sales And Use Tax ID 2022 31,762
24 Use Tax Sales And Use Tax ID 2023
25 Subtotal Sales And Use
289,182 0
Tax
26 Municipal Occupation Tax Local Tax WA 2022 4,001,655
FERC FORM NO.1 (ED.12-96)
Page 262-263

TAXES ACCRUED,PREPAID AND CHARGES DURING YEAR
BALANCE BALANCE'
AT AT
BEGINNING BEGINNING
OF YEAR OF YEAR
Taxes Prepaid
Kind of Tax(See Accrued Taxes
Line Instruction 5) Account Type of Tax State Tax Year (Include in
No. (a) (b) (c) (d) ( 236 Account
(e)) 165)
(f)
27 Municipal Occupation Tax Local Tax WA 2023
28 Subtotal Local Tax 4,001,655 0
29 KWH Tax Other Taxes ID 2022 24,554
30 KWH Tax Other Taxes ID 2023
31 KWH Tax Other Taxes MT 2022 239,401
32 KWH Tax Other Taxes MT 2023
33 WA Renewable Energy Other Taxes 2023
Credits
34 Subtotal Other Taxes 263,955 0
35 Income Tax State Tax ID 2022
36 Income Tax State Tax ID 2023
37 Income Tax State Tax MT 2022
38 Income Tax State Tax MT 2023
39 Income Tax State Tax OR 2022
40 Income Tax State Tax OR 2023
41 Income Tax State Tax Misc 2022
42 Subtotal State Tax 0 0
43 Payroll Taxes Payroll Tax ID 2022 6,943
44 Payroll Taxes Payroll Tax ID 2023
45 Payroll Taxes Payroll Tax MT 2022 528
46 Payroll Taxes Payroll Tax MT 2023
47 Payroll Taxes Payroll Tax OR 2022 14,255
48 Payroll Taxes Payroll Tax OR 2023
49 Payroll Taxes Payroll Tax WA 2022 72,315
50 Payroll Taxes Payroll Tax WA 2023
51 Payroll Taxes Payroll Tax Misc 2022
52 I Payroll Taxes Payroll Tax Misc 2023
53 Payroll Taxes Payroll Tax FED 2021
54 Payroll Taxes Payroll Tax FED 2022 796,213
55 Payroll Taxes Payroll Tax FED 2023
FERC FORM NO.1 (ED.12-96)
Page 262-263

TAXES ACCRUED,PREPAID AND CHARGES DURING YEAR
BALANCE BALANCE
AT AT
BEGINNING BEGINNING
OF YEAR OF YEAR
Taxes Prepaid
Kind of Tax(See Accrued Taxes
Line Type of Tax State Tax Year (Include in
No. Instruction 5) (b) (c) (d) (Account Account
(a) 23 165)
(e) (f)
56 Subtotal Payroll Tax — 890,254 0
57 Franchise Tax ! Franchise Tax ID 2022 1,285,869
58 Franchise Tax Franchise Tax ID 2023
59 Franchise Tax Franchise Tax OR 2022 1,537,313
60 Franchise Tax Franchise Tax OR 2023
61 Subtotal Franchise Tax 2,823,182 0
62 Consumer Council Fee Other License And Fees MT 2022 8
Tax
63 Consumer Council Fee Other License And Fees MT 2023
Tax
64 Public Commission Fee Other License And FeesTax MT 2022 42
65 Public Commission Fee Other License And Fees MT 2023
Tax
66 Subtotal Other License 50 0
And Fees Tax
40 TOTAL 38,520,487 4,517,894
FERC FORM NO.1 (ED.12-96)
Page 262-263

TAXES ACCRUED,PREPAID AND CHARGES DURING YEAR
BALANCE AT END BALANCE AT END DISTRIBUTION OF
OF YEAR OF YEAR TAXES CHARGED
Line Taxes Charged Taxes Paid During Taxes Accrued Prepaid Taxes Electric(Account
During Year Year Adjustments (Account 236) (Included in Account 408.1,409.1)
No. (g) (h)
1 (800,000) (800,000) 0 1
2 1,271,339 238,248 (1,033,091) 0 1 730,140
3 (1,007,626) (1,679,000) � (671,374) 0 (8,445,193)
4 263,713 (2,240,752) (2,504,465)l 0 0 (7,715,053)
5 (2,685,052) 15,889,288 355 0 (2,115,275)
6 14,235,079 1,405 (354) 14,233,320 10,920,067
7 (1,236) 2,857,841 1,940 0
8 4,149,832 2,099,678 (1,940) 2,048,214 3,177,624
9 243 4,840,669 (1) 0 243
10 7,382,564 3,707,034 3,675,530 7,382,564
11 4,517,893 1 0 1,866,618
12 4,233,758 8,467,363 (1) 0 4,233,606 1,690,101
13 31,833,081 37,863,278 0 19,957,064 4,233,606 22,921,942
14 78,882 4,059,542 0 81,744
15 34,977,642 31,016,843 3,960,799 24,313,394
16 (5,020) 5,020 0
17 799,999 700,000 (99,999) 0
18 35,851,503 35,776,385 (94,979) 3,960,799 0 24,395,138
19 709 47,318 1 1 0 709
20 100,177 94,352 (1) 5,824 3,022
21 (7,910) 202,902 0
22 1,830,363 1,588,474 241,889
23 31,761 (1) 0
24 166,826 114,132 1 52,695
25 2,090,165 2,078,939 0 300,408 0 3,731
26 48,832 4,050,487 0 44,370
27 29,728,805 25,905,105 3,823,700 20,889,865
28 29,777,637 29,955,592 0 3,823,700 0 20,934,235
29 1,573 26,126 (1) 0 1,573
30 317,428 295,205 1 22,224 317,428
31 239,401 0
FERC FORM NO.1 (ED.12-96)
Page 262-263

TAXES ACCRUED,PREPAID AND CHARGES DURING YEAR
BALANCE AT END BALANCE AT END DISTRIBUTION OF
OF YEAR OF YEAR TAXES CHARGED
Taxes Charged Taxes Paid During Taxes Accrued Prepaid Taxes Electric(Account
Line Adjustments (Included in Account
During Year Year � (Account 23S) 165 408.1,409.1)
No.
f (g) (h) () (i) )(k) (I)
32 1,009,062 789,685 219,377 1,009,062
33 664,254 664,254 0
34 1,992,317 2,014,671 0 241,601 0 1,328,063
35 0
36 60 (60) 0 51
37 0
38 50 50 0 50
39 0
40 100,000 100,000 0 20,000
41 975 975 0 123
42 101,085 101,025 (60) 0 0 20,224
43 2,310 (4,633) 0
44 46,448 42,701 3,747 16,098
45 350 (178) 0
46 9,910 9,671 239 3,435
47 1,249 (13,006) 0
48 63,273 52,444 10,829 21,929
49 89,303 16,988 0
50 1,119,287 1,244,525 (125,238) 387,927
51 0
52 2,877 2,157 720 997
53 (14,004) (14,004) 0
54 234,843 (8,879) (1,039,935) 0 81,393
55 17,276,344 17,277,550 1,054,060 1,052,854 5,987,700
56 18,752,982 18,699,377 (708) 943,151 0 6,499,479
57 646 1,286,515 0 665
58 5,621,364 4,248,584 1,372,780 3,800,945
59 (107) 1,537,207 1 0
60 5,733,816 4,454,171 (1) 1,279,644
61 11,355,719 11,526,477 0 2,652,424 0 3,801,610
62 7 (1) 0
FERC FORM NO.1 (ED.12-96)
Page 262-263

TAXES ACCRUED,PREPAID AND CHARGES DURING YEAR
BALANCE AT END BALANCE AT END DISTRIBUTION OF
OF YEAR OF YEAR TAXES CHARGED
Taxes Charged Taxes Paid During Taxes Accrued Prepaid Taxes Electric(Account
Line Adjustments (Included in Account
During Year Year (Account 236) 408.1,409.1)
No.
(g) (h) (i) (1) 165) (4
63 35 26 F 1 10 35
64 42 0
65 215 165 50 215
66 250 240 0 60 0 ll 250
40 132,018,452 135,775,232 (2,600,212) 31,879,207 4,233,606 72,189,619
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 Extraordinary Items(Account 409.3) Adjustment to Ret Earnings(Account Other
No. (m) (n)) (o)
2 541,199
3 7,437,567
4 0 0 7,978,766
5 (569,777)
6 3,315,012
7 (1,236)
8 972,208
9
10
11 2,651,275
12 2,543,657
13 0 0 8,911,139
14 (2,862)
15 10,664,248
16 (5,020)
17 799,999
18 0 0 11,456,365
19
20 97,155
21 (7,910)
22 1,830,363
23
24 166,826
25 0 0 2,086,434
26 4,462
27 8,838,940
28 0 0 8,843,402
29
30
31
32
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 Extraordinary Items(Account409.3) Adjustment to Ret.Earnings(AccountOther
439
No. (m) (n)) (o)
33 664,254
34 0 0 664,254
35
36 9
37
38
39
40 80,000
41 852
42 0 0 80,861
43
44 30,350
45
46 6,475
47
48 41,344
49
50 731,360
51
52 1,880
53
54 153,450
55 11,288,644
56 0 0 12,253,503
57 (19)
58 1,820,419
59 (107)
60 5,733,816
61 0 0 7,554,109
62
63
64
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
Earnings(Account
Line Extraordinary Items(Account 409.3) Adjustment to Ret. ) Other
No. (m) fin) (o)
65
66 0 0 0
F4O 0 0 59,828,833
FERC FORM NO.1 (ED.12-96)
Page 262-263

This report is:
Name of Respondent: (1)0 An Original Date of Report: Year/Period of Report
Avista Corporation (2) El A Resubmission 04/12/2024 End of:2023/Q4
ACCUMULATED DEFERRED INVESTMENT TAX CREDITS(Account 255)
Allocations to Allocations to
Deferred for Current
Year Deferred for Year Current Years
Year's
Income
Income
Line Account Subdivisions Balance atAccount No. Amount Account No. Amount
Beginning
of Year
No. (a) (c) (d) (e) (f)
1 Electric Utility
2 3%
3 10%
4 Fed ITC 27,621,711 411.4 520,104
5 Idaho ITC 986,793 411.4 52 411.4 26,510
8 TOTAL Electric(Enter Total of lines 28,608,504 52 546,614
2 thru 7)
9 Other(List separately and show
3%,4%,7%,10%and TOTAL)
10 Gas Property(100%
11 Idaho ITC 175,941 411.4 8 411.4 4,729
47 OTHER TOTAL 175,941 8 4,729
48 GRAND TOTAL 28,784,445
FERC FORM NO.1 (ED.12-89)
Page 266-267

ACCUMULATED DEFERRED INVESTMENT TAX CREDITS(Account 255)
Line Adjustments Balance at End of Average Period of Allocation to Income ADJUSTMENT EXPLANATION
No. (g) Year
(i) (1)
1
2
3
4 27,101,607
5 960,335
8 28,061,942
Eawlu -
10
11 171,220
47 171,220
48 28,233,162
FERC FORM NO.1 (ED.12-89)
Page 266-267

This report is:
Name of Respondent: (1)0 An Original Date of Report: Year/Period of Report
Avista Corporation 04/12/2024 End of:2023/Q4
(2)El A Resubmission
OTHER DEFERRED CREDITS(Account 253)
DEBITS DEBITS
Line Description and Other Deferred Balance at Contra Amount Credits Balance at End of
Credits Beginning of Year Account Year
No. (a) (b) (c) (d) (e) (f)
1 Deferred Gas Exchange 1,406,250 495 5,625,000 5,625,000 1,406,250
2 Bills Pole Rentals 694,497 454 1,360,857 1,332,721 666,361
3 Defer Comp Active Execs 7,540,648 128 1,417,983 1,671,243 7,793,908
4 Unbilled Revenue 3,568,598 908 26,788,651 27,874,080 4,654,027
Lbj
5 Decoupling Deferred Credits 23,415,084 182 49, 5 456, 18,690,227 3,741,826 8,466,683
Lei
6 Reg Liability-COVID-19 Deferral 7,749,100 7,749,100
Ldj
7 WA REC Deferrals 868,759 186,431 1,107,117 238,358 0
8 Timber Harvest 226,796 226,796
9 OtherDefCr-FISERV 791,667 903 416,667 495,702 870,702
.M
10 Accts Pay-Software Licenses- 2,093,461 242 1,658,850 642,885 1,077,496
LT
11 Misc.Deferred Credits 47,742 186,90242 3, 156,225 115,403 6,920
47 TOTAL 48,402,602 57,221,577 41,737,218 32,918,243
FERC FORM NO.1 (ED.12-94)
Page 269

This report is:
Name of Respondent: (1) An Original Date of Report: Year/Period of Report
Avista Corporation 04/12/2024 End of:2023/Q4
(2) ❑A Resubmission
FOOTNOTE DATA
U Concept:DescriptionOfOtherDeferredCredits
FortisBC and Avista exchange volumes of gas on a firm delivery basis during different time periods.Amortization is recorded monthly every
year.This contract ends April 2025.
U Concept:DescdptionOfOtherDeferredCredits
Washington and Idaho Decoupling orders for electric and natural gas thru March 31,2025.Oregon approved similarto Washington and Idaho
(beginning March 1,2016.Decoupling revenue deferrals are recognized during the period they occur,subject to certain limitations.Revenue is
expected to be collected within 24 months of the deferral.
Lc)Concept:DescriptionOfOtherDeferredC red its
Deferral of COVID-19 costs as per Idaho PUC Order No.34718,Oregon PUC Order No.20-401,Docket UM 2069 and WA UTC Order No.01,
Dockets UE-200407 and UG-200408.
Concept:DescdptionOfOtherDeferredCredits
WA Docket UE-190334,Schedule 98.
Le)Concept:Descri ptionOfOtherD eferred Credits
Other Deferred Credit-Fisery
M Concept:DescriptionOfOtherDeferredCredits
Deferred Liability for Software Licenses
FERC FORM NO.1 (ED.12-94)
Page 269

r This report is:
Name of Respondent: (1)®An Original Date of Report: Year/Period of Report
Avista Corporation 04/12/2024 End of:2023/Q4
(2) ❑A Resubmission
ACCUMULATED DEFERRED INCOME TAXES-OTHER PROPERTY(Account282)
CHANGES CHANGES CHANGES CHANGES
DURING YEAR DURING YEAR DURING YEAR DURING YEAR
Balance at Amounts Debited Amounts Credited Amounts Debited Amounts
Line Account Beginning of Year to Account 410.1 to Account 411.1 to Account 410.2 Credited to
No. (a) (b) (c) (d) (e) Account411.2
(f)
1 Account282
2 Electric 422,767,286 13,309,876 645,700
3 Gas 152,279,809 2,154,316 1,414,058
4 Other(Specify) 61,774,590 (5,499,651) 167,210
5 Total(Total of lines 2 thru 4) 636,821,685 9,964,541 2,226,968
6
7
8
9 TOTAL Account282(Total of 636,821,685 9,964,541 2,226,968
Lines 5 thru 8)
10 Classification of TOTAL
11 Federal Income Tax 636,821,685 9,964,541 2,226,968
12 State Income Tax
F13 Local Income Tax
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 Account Credited Amount Account Debited Amount Balance at End of Year
No. (g) (h) (i) Q) (k)
1
2 182.3 3,767,273 439,198,735
3 182.3 I� 4,017,114 157,037,181
4 j 182.3 876,225 56,983,954
5 8,660,612 653,219,870
6
7
8
9 8,660,612 653,219,870
10
11 8,660,612 653,219,870
12
rl 3
FERC FORM NO.1 (ED.12-96)
Page 274-275

This report is:
Name of Respondent: (1)0 An Original Date of Report: Year/Period of Report
Avista Corporation (2)❑A Resubmission 04/12/2024 End of:2023/Q4
ACCUMULATED DEFERRED INCOME TAXES-OTHER(Account283)
CHANGES CHANGES CHANGES CHANGES—
DURINGYEAR DURING YEAR DURINGYEAR DURINGYEAR
Balance at Amounts Debited Amounts Credited Amounts Debited Amounts
Line Account Beginning of Year to Account410.1 to Account 411.1 to Account 410.2 Credited to
No. (a) (b) (c) (d) (e) Account 411.2
1 Account283
2 Electric
3 Electric 46,111,868 5,624,777 796,200 96,298 19,353
9 th TA Electric(Total of lines 3 46,111,868 5,624,777 796,200 96,298 19,353
10 Gas
11 Gas 29,349,984 129,174 8,267,349 1,093,165 4,840
17 TOTAL Gas(Total of lines 11 29,349,984 129,174 8,267,349 1,093,165 4,840
thru 16)
18 TOTAL Other 209,660,847 803,918 3,215,328 73,800
19 TOTAL(Acct 283)(Enter Total 285,122,699 6,557,869 12,278,877 1,263,263 24,193
of lines 9,17 and 18)
y
20 Classification of TOTAL
21 Federal Income Tax 285,122,699 6,557,869 12,278,877 1,263,263 24,193
22 State Income Tax
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 Account Credited Amount Account Debited Amount Balance at End of Year
No. (9) (h) (i) (1) (k)
1
2
3 182/254 861,711 50,155,679
9 861,711 50,155,679
10 1!"_
11 182/254 166,602 22,133,532
17 166,602 22,133,532
18 182/254 22,901,733 184,421,504
19 23,930,046 0 256,710,715
20
21 23,930,046 256,710,715
22
23
NOTES
FERC FORM NO.1 (ED.12-96)
Page 276-277

This report is:
Name of Respondent: (1)®An Original Date of Report: Year/Period of Report
Avista Corporation (2) El A Resubmission 04/12/2024 End of:2023/Q4
OTHER REGULATORY LIABILITIES(Account 254)
DEBITS DEBITS
Balance at Balance at End of
Line Description and Purpose of Beginning of Account Amount Credits Curret
n
No. Other Regulatory Liabilities Current Credited (d) (e) Qu ur en
(a) Quarter/Year (c)
ear
(b) (f)
1 Idaho Investment Tax Credit 10,038,667 2,933,191 0 7,105,476
Lbj
2 Interest Rate Swaps 24,204,062 427,175 8,321,364 7,868,930 23,751,628
3 Nez Perce 462,284 22,008 440,276
4 Idaho Earnings Test 686,970 114,495 572,475
5 Decoupling Rebate 8,378,370 495,182 19,020,610 28,640,582 17,998,342
Ldl
6 WA ERM 5,269,902 5,269,902 0 0
Li
7 Deferred Federal ITC-Varies 7,538,104 333,802 0 7,204,302
s�
8 Plant Excess Deferred 323,181,031 21,561,802 0 301,619,229
9 Reg Liability MDM System 678,843 678,843 0 0
10 11,581,998 1829,0831,
DSM Tariff Rider 17,700,901 11,105,947 4,987,044
11 Low Income Energy Assistance 7,940,357 242,908 28,801,667 26,595,334 5,734,024
12 Reg Liability-OR Tax Strategy 1,283,006 254,407 757,068 43,628 569,566
Deferral
13 Reg Liability-Tax Reform 184,460 407,431 50,873 5,718 139,305
Amortization
tkj
14 RegLiability-WARevDefof 971,669 990,053 18,384 0
Power Supply
U
15 Reg Liability-Energy Efficiency 986,890 254 285,347 13,055 714,598
Assistance
16 Reg Liability-COVID-19 4,124,859 254,407 1,718,235 400,750 2,807,374
Deferral
Lnj
17 Reg Liability-Tax Customer 107,138,114 190,410 60,737,909 9,853,658 56,253,863
Credit
18 CS2 Insurance Proceeds 804,403 254 0 62,834 867,237
Deferral
19 Regulatory Liabilities-Other 9,869,668 190 0 1,277,935 11,147,603
L51
20 Reg Liability-CCA 0 254 0 37,231,122 37,231,122
FERC FORM NO.1(REV 02-04)
Page 278

OTHER REGULATORY LIABILITIES(Account 254)
DEBITS DEBITS
Balance at Balance at End of
Description and Purpose of Beginning of Account
Line Amount Credits Current
Other Regulatory Liabilities Current Credited
No. (d) (e) Quarter/Year
(a) QuarterlYear (c) (�
(b)
21 ki Insurance Balancing Account 0 182,407 14,256 29,110 14,854
22 Misc.Regulatory Liabilities 85,888 143,411 1,571,925 1,561,634 75,597
41 TOTAL 525,409,545 170,884,251 124,708,621 479,233,915
FERC FORM NO.1 (REV 02-04)
Page 278

This report is:
Name of Respondent: (1)0 An Original Date of Report: Year/Period of Report
Avista Corporation (2) El A Resubmission 04/12/2024 End of:2023/Q4
FOOTNOTE DATA
La)Concept:DescdptionAndPurposeOfOtherRegulatoryLiabilities
Not amortized.
Lb)Concept:D escri pti onAnd P u rposeOfOtherReg u latoryl-i abi I it es
Mark-to-Market gains and losses for interest rate swap derivatives.Upon settlement,amortization of Regulatory Assets and Liabilities as a component of interest
expense over the term of the associated debt.
Lc)Concept:DescdptionAndPurposeOfOtherRegulatoryLiabilities
Decoupling rebates are recognized during the period they occur,subject to certain limitations.Rebates are returned to customers within 24 months of the
deferral.
LdJ Concept:DescdptionAndPurposeOfOtherRegulatoryLiabilities
The Washington Energy Recovery Mechanism allows Avista to periodically increase or decrease electric rates.This accounting method tracks differences
between actual power supply costs,net of wholesale sales and sales of fuel,and the amount included in base rates.Avista files yearly on or before April 1 for
prudence review by the commission.
U Concept:DescdptionAndPurposeOfOtherRegulatoryLiabilities
Noxon ITC-65yr amort,ends 2077
Community Solar ITC-20yr amort,ends 2035
Nine Mile ITC-65yr amort,ends 2080.
-M Concept:DescdptionAndPurposeOfOtherRegulatoryLiabilities
Amortized over remaining book life of plant,estimated 36 years.
&Concept:DescdpbonAndPurposeOfOtherRegulatoryLiabilities
WA Orders Dockets UE-190912 and UG-190920,Idaho Docket AVU-E-18-12 and AVU-G-18-08,OR Order No. 19-424.
1h-)Concept:DescdptionAndPurposeOfOtherRegulatoryLiabilities
WA Docket No UE-190912,UG-190920
1D Docket No AVU-E-18-12,AVU-G-18-08
OR RG 81,Docket No ADV 1063(Advice No.19-10-G)
1�Concept:DescdpbonAndPurposeOfOtherRegulatoryLiabilities
OR Docket No UM 2124.Deferral of associated state tax savings.
fi)Concept:DescdptionAndPurposeOfOtherRegulatoryLiabilities
WA Docket No.UG-170486
ID Docket No.AVU-E-23-01
Concept:DescdptionAndPurposeOfOtherRegulatoryLiabilities
Deferred liability for over-collection of authorized power supply cost revenue from Washington retail customers.
.0 Concept:DescdptionAndPurposeOfOtherRegulatoryLiabilities
Avista's contribution in the Energy Assistance Fund as per ID Settlement Stipulation Case#AVU-E-19-04
lm-)Concept:DescdptionAndPurposeOfOtherRegulatoryLiabilities
Deferral of COVID-19 costs as per Idaho PUC Order No.34718,OR PUC Order No.20-401,Docket UM 2069 and WA UTC Order No.01,Dockets UE-
200407 and UG-200408.
Ln)Concept:Descri pti onAnd P u rposeOfOtherReg u I atoryLia bi I it es
WA Order 01,Dockets No UE-200895 and UG-200896,ID Case Nos.AVU-E-20-12 and AVU-G-20-07 Order No.34906,and OR Docket No UM 2124
Order No 21-131.
Accounting method change for federal income tax from normalization flow-through for Industry Director Directive No.5 mixed service costs and meters.
U Concept:DescdptionAndPurposeOfOtherRegulatoryLiabilities
Insurance proceeds for failed transformer at Coyote Springs per WA Order UE-210893 Order 01.
kW Concept:DescdptionAndPurposeOfOtherRegulatoryLiabilities

State inome tax NOL carryforward will reverse over the period in which we are able to utilize the loss to offset taxable income on the ID,MT,and OR tax
returns.
IM Concept:DescdptionAndPurposeOfOtherRegulatoryLiabilities
To defer costs of compliance with the Climate Commitment Act in accordance with WAC 480-100-203(3)and WAC 480-90-203(3).WA Docket No UG-
220803.
Jr)Concept:DescdpbonAndPurposeOfOtherRegulatoryLiabilities
To defer costs above or below the baseline in accordance with Order No 10/04 Docket Nos UE-220053,UE-210854,and UG-220054.
FERC FORM NO.I (REV 02-04)
Page 278

This report is:
Name of Respondent: (1)0 An Original Date of Report: Year/Period of Report
Avista Corporation 04/12/2024 End of:2023/Q4
(2) El A Resubmission
Electric Operating Revenues
MEGAWATT AVG.NO. AVG.NO.
Operating Operating MEGAWATT HOURS SOLD CUSTOMERS CUSTOMERS
Revenues Year to Revenues HOURS SOLD PER MONTH
Line Title of Account Date Previous year(no Year to Date Amount PER MONTH Previous
No. (a) Quarterly/Annual Quarterly) Quarterly/Annual Previous year Current Year Year(no
(b) (c) (d) (no Quarterly) (no Quarterly) Quarterly)
1 Sales of Electricity
2 (440)Residential Sales 425,258,195 414,822,725 4,020,329 , 4,153,697 366,450 361,606
3 (442)Commercial and
Industrial Sales
4 Small(or Comm.)(See 343,522,797 338,656,420 3,159,672 3,200,915 45,341 44,578
Instr.4)
5 Large(or Ind.)(See Instr. 120,123,256 118,350,840 2,096,554 2,131,895 1,188 1,194
6 (444)Public Street and 7,975,679 7,483,091 16,839 16,795 690 681
Highway Lighting
7 (445)Other Sales to 0 0 0 0 0 0
Public Authorities
8 (446)Sales to Railroads 0 0 0 0 0 0
and Railways
9 (448)Interdepartmental 1,606,948 1,571,568 14,475 14,388 162 157
Sales
10 TOTAL Sales to Ultimate 898 486,875 880,884,644 9,307,869 9,517,690 413,831 408,216
Consumers
11 (447)Sales for Resale 253,658,001 184,587,443 3,521,491 3,144,486
12 TOTAL Sales of 1,152,144,876 1,065,472,087 12,829,360 12,662,176 413,831 408,216
Electricity
13 (Less)(449.1)Provision 0 347,000 0 0
for Rate Refunds
14 TOTAL Revenues 1,152,144,876 1,065,125,087 12,829,360 12,662,176 413,831 408,216
Before Prov.for Refunds
15 Other Operating
Revenues
16 (450)Forfeited 0 0
Discounts
-
17 (451)Miscellaneous 129,396 122,226
Service Revenues
18 (453)Sales of Water and 688,332 368,008
Water Power
19 (454)Rent from Electric 7,542,853 4,199,517
Property
20 (455)Interdepartmental 0 0 4
Rents
FERC FORM NO.1 (REV.12-05)
Page 300301

Electric Operating Revenues
MEGAWATT AVG.NO. AVG.NO.
Operating Operating MEGAWATT HOURS SOLD CUSTOMERS CUSTOMERS
Line Title of Account Revenues Year to Revenues HOURS SOLD Amount PER MONTH PER MONTH
No. (a) Date Previous year(no Year to Date Previous year Current Year Previous
Quarterly/Annual Quarterly) Quarterly/Annual Year(no
(b) (c) (d) (no Quarterly) (no Quarterly) Quarterly)
(el (fl (g)
21 (456)Other Electric 2,198,927 67,308,760
Revenues
(456.1)Revenues from
22 Transmission of 30,969,981 30,339,137
Electricity of Others
23 (457.1)Regional Control 0 0
Service Revenues
24 (457.2)Miscellaneous 0 0
Revenues
25 Other Miscellaneous
Operating Revenues
26 TOTAL Other Operating 41,529,489 102,337,648
Revenues
27 TOTAL Electric 1,193,674,365 1,167,462,735
Operating Revenues
Vi
e12,column(b)includes$(6,081,121)of unbilled revenues.
e12,column(d)includes(114,421)MWH relating to unbilled revenues
FERC FORM NO.1 (REV.12-05)
Page 300-301

This report is:
Name of Respondent: (1)0 An Original Date of Report: Year/Period of Report
Avista Corporation 04/12/2024 End of:2023/Q4
(2) ❑A Resubmission
SALES OF ELECTRICITY BY RATE SCHEDULES
Line
Number and Title of Rate MWh Sold Revenue Average Number of KWh of Sales Per Revenue Per
No. Schedule ( ) (c)b Customers Customer KWh Sold
(a) (d) (e) (0
1 01 Residential Service 3,921,898 394,716,078 346,375 11,322.6976 0.1006
2 02 Fixed-Income Senior and 9,328 657,724 653 14,276.2134 0.0705
Disabled Residential Service
3 11 General Service 0 (61,202) 0
4 12 Residential&Farm General 106,518 15,871,570 17,480 6,093.7034 0.149
Service
5 21 Large General Service 0 (19,843) 0
6 22 Residential and Farm Large 39,617 3,918,241 71 558,641.4207 0.0989
General Service
7 30 Pumping Service 47 5,722 7 6,672.1001 0.1225
8 32 Residential and Farm 10,138 1,415,206 1,864 5,439.289 0.1396
Pumping Service
9 48 Residential and Farm Area 2,954 1,291,490 0 0.4371
Lighting
10 58 Tax Adjustment 0 11,472,813 0
11 95 Optional Renewable Power 0 235,157 0
41 TOTAL Billed Residential 4,090,500 429,502,956 366,450 11.162.5051 0.105
Sales
42 TOTAL Unbilled Rev.(See (70,171) (4,244,761) 0.0605
Instr.6)
43 TOTAL 4,020,329 425,258,195 366,450 10,971.0165 0.1058
FERC FORM NO.1 (ED.12-95)
Page 304

This report is:
Name of Respondent: (1)®An Original Date of Report: Year/Period of Report
Avista Corporation 04/12/2024 End of:2023/Q4
(2) ❑A Resubmission
SALES OF ELECTRICITY BY RATE SCHEDULES
Number and Title of Rate - rag ber of KWh of Sales Per Revenue Per
M Line Wh Sold Revenue
Schedule Customers Customer KWh Sold
No. (a) (b) (c) (d) (e) (f)
1 11 General Service 1,083,432 127,520,194 41,787 25,927.6869 0.1177
13 Optional Commercial
2 Electric Vehicle Rate-General 445 60,640 11 40,154.6183 0.1363
Service
3 21 Large General Service 1,643,911 166,275,540 2,166 759,107.9261 0.1011
23 Optional Commercial
4 Electric Vehicle Rate-Large 1,016 122,476 3 348,429.0754 0.1205
General Service
5 25 Extra Large General Service 343,335 24,952,483 13 26,410,369.7989 0.0727
6 31 Pumping Service 115,881 11,412,038 1,361 85,112.8361 0.0985
7 47 Area Light 4,113 1,628,832 0 0.3961
8 49 Area Lighting 2,041 729,152 0 0.3572
9 58 Tax Adjustment 0 12,063,499 0
10 95 Optional Renewable Power 0 139,120 0
TOTAL Billed Small or
41 Commercial 3,194,174 344,903,974 45,341 70,447.8066 0.108
42 TOTAL Unbilled Rev.Small or (34,502) (1,381,177) 0.04
Commercial(See Instr.6)
43 TOTAL Small or Commercial 3,159,672 343,522,797 45,341 69,686.8618 0.1087
FERC FORM NO.1 (ED.12-95)
Page 304

This report is:
Name of Respondent: (1)0 An Original Date of Report: Year/Period of Report
Avista Corporation (2) El A Resubmission 04/12/2024 End of:2023/Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
Number and Title of Rate Average U ber of KWh of Sales Per Revenue Per
Line Schedule MWh Sold Revenue Customers Customer KWh Sold
No. (a) (b) (c) (d) (e) (f)
1 11 General Service 11,527 1,319,053 217 53,139.4555 0.1144
2 21 Large General Service 149,500 14,797,441 110 1,354,988.9561 0.099
3 25 Extra Large General Service 1,864,256 95,869,368 21 88,774,078.4292 0.0514
4 30 Pumping Service 29,062 2,452,598 50 581,241.9924 0.0844
5 31 Pumping Service 47,613 4,811,830 673 70,720.7724 0.1011
6 32 Residential and Farm 4,176 412,482 117 35,797.6351 0.0988
Pumping Service
7 47 Area Light 119 33,386 0 0.281
8 48 Residential and Farm Area 0 267 0 0.5624
Lighting
9 49 Area Lighting 48 14,080 0 0.2955
10 58 Tax Adjustment 0 866,900 0
11 95 Optional Renewable Power 0 1,036 0
41 TOTAL Billed Large(or Ind.) 2,106,301 120,578,441 1,188 1,772,980.6397 0.0572
Sales
42 TOTAL Unbilled Rev.Large(or (9,747) (455,185) 0.0467
Ind.)(See Instr.6)
43 TOTAL Large(or Ind.) 2,096,554 120,123,256 1,188 1,764,776.0943 0.0573
FERC FORM NO.1 (ED.12-95)
Page 304

This report is:
Name of Respondent: (1) An Original Date of Report: Year/Period of Report
Avista Corporation 04/12/2024 End of:2023/Q4
(2) ❑ A Resubmission
SALES OF ELECTRICITY BY RATE SCHEDULES
Ljoe Number and Title of Rate Average Number of KWh of Sales Per Revenue Per
No. Schedule MWh Sold Revenue Customers Customer KWh Sold
No. (a) (b) (c) (d) (e) (f)
1 41 Company Owned Steel 2 323 0 20,766.396 0.1865
Light Service
2 42 Company Owned Steel 14,007 7,341,825 589 23,780.9847 0.5242
Light Service
44 Company Owned Steet
3 Light Energy&Maintenance 403 73,532 24 16,986.4989 0.1823
Service-High Pressure
Sodium Vapor
4 45 Company Owned Steel 694 68,698 12 57,793.4603 0.0991
Light Energy Service
5 46 Company Owned Steel 1,733 215,077 65 26,455.6265 0.1241
Light Energy Service
6 58 Tax Adjustment 0 276,224 0
41 TOTAL Billed Public Street and 16,839 7,975,679 690 24,404.3478 0.4736
Highway Lighting
42 TOTAL Unbilled Rev.(See Instr.
6)
43 TOTAL 16,839 7,975,679 690 24,404.3478 0.4736
FERC FORM NO.1 (ED.12-95)
Page 304

report is:
Name of Respondent: (1)sr This repo po Original Date of Report: Year/Period of Report
Avista Corporation 04/12/2024 End of:2023/Q4
(2) ❑ A Resubmission
SALES OF ELECTRICITY BY RATE SCHEDULES
Line
Number and Title of Rate MWh Sold Revenue Average Number of KWh of Sales Per Revenue Per
No. Schedule c Customers Customer KWh Sold
(a) (b) ( ) (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
30
FERC FORM NO.1 (ED.12-95)
Page 304

SALES OF ELECTRICITY BY RATE SCHEDULES
Number and Title of Rate Average Number of'KWh'ofSales Per Revenue Per
Line Schedule MWh Revr nue Customers_ Customer KWh Sold
No. (a) (b) (c)
31
T-
32
33
34
35
36
37
38
39
40
41 TOTAL Billed Other Sales to
Public Authorities
42 TOTAL Unbilled Rev.(See Instr.
6)
43 TOTAL 0 0 0
FERC FORM NO.1 (ED.12-95)
Page 304

This report is:
Name of Respondent: (1)0 An Original Date of Report: Year/Period of Report
Avista Corporation (2)El A Resubmission 04/12/2024 End of:2023/Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
Number and Title of Rate Average Number of KWh of Sales Per Revenue Per
Line Schedule MWh Sold Revenue Customers Customer KWh Sold
No. (a) - — (b) (c) (d) (e) (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
FERC FORM NO.1(ED.12-95)
Page 304

SALES OF ELECTRICITY BY RATE SCHEDULES
Number and Title erle of Rate Average Numb of KWh of Sales Per Revenue Per
Line Schedule MWh Sold Revenue Customers Customer KWh Sold
No. (a) (b) (c) (d) (e) (�
31
32
33
34
35
36
37
38
39
40
41 TOTAL Billed Sales To
Railroads and Railways
42 TOTAL Unbilled Rev.(See Instr.
6)
43 TOTAL 0 0 0
FERC FORM NO.1 (ED.12-95)
Page 304

This report is: I
Name of Respondent: (1)0 An Original Date of Report: Year/Period of Report
Avista Corporation (2) ❑A Resubmission 04/12/2024 End of.2023/Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
Number and TiUe of Rate Average Number of KWh of Sales Per Revenue Per
Line Schedule MWh Sold Revenue Customers Customer KWh Sold
No. (a) lb) �c) (d) (e) (f)
1 01 Residential Service 191 18,951 15 12,981.8939 0.099
2 11 General Service 4,007 493,841 I 115 34,745.0743 0.1232
3 12 Residential&Farm General 1 211 0 7,773.57 0.1627
Service
13 Optional Commercial
4 Electric Vehicle Rate-General 226 32,024 10 23,335.2983 0.142
Service
5 21 Large General Service 9,155 940,621 16 566,266.8544 0.1027
6 31 Pumping Service 766 71,816 5 161,229.0811 0.0938
7 32 Residential and Farm 39 4,027 1 38,839 0.1037
Pumping Service
8 47 Area Light 86 42,851 0 0.4973
9 48 Residential and Farm Area 1 382 0 0.3891
Lighting
10 49 Area Lighting 3 1,470 0 0.4486
11 58 Tax Adjustment 0 754 0
41 TOTAL Billed Interdepartmental 14,475 1,606,948 162 89,351.8519 0.111
Sales
42 TOTAL Unbilled Rev.(See Instr.
6)
43 TOTAL 14,475 1,606,948 162 89,351.8519 0.111
FERC FORM NO.1 (ED.12-95)
Page 304

This report is:
Name of Respondent: (1)0 An Original Date of Report: Year/Period of Report
Avista Corporation 04/12/2024 End of:2023/Q4
(2) ❑ A Resubmission
SALES OF ELECTRICITY BY RATE SCHEDULES
Line
Number and Title of Rate MWh Sold Revenue Average Number of KWh of Sales Per Revenue Per
No Schedule (b) (c) Customers Customer KWh Sold
(a) (d) (e) (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
FERC FORM NO.1 (ED.12-95)
Page 304

SALES OF ELECTRICITY BY RA.i r_•SCHEDULES
ue
s`�verge Nu;;:her of KWh of Sales Per WWIer
L'ustomiars Customer d
31
32
33
34
35 -�
36 f
37 f
38
39
40
41 TOTAL Billed Provision For
Rate Refunds
42 TOTAL Unbilled Rev.(See Instr.
6)
43 TOTAL 0 (i
FERC FORM NO.1 (ED.12-95)
Page 304

This report is:
Name of Respondent: (1)0 An Original Date of Report: Year/Period of Report
Avista Corporation (2)❑ A Resubmission 04/12/2024 End of.2023/Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
Number and Title of Rate Average Number of KWh of Sales Per Revenue Per
Line Schedule MWh Sold Revenue Customers Customer KWh Sold
No. (a) (b) (c) (d) (e) (f)
41 TOTAL Billed-All Accounts I 9,422,289 904,567,998 � 413,831 22,768.4465 0.096
42 TOTAL Unbilled Rev.(See (114,420) (6,081,123) 0.0531
Instr.6)-All Accounts
43 TOTAL-AlI Accounts 9,307,869 898,486,875 413,831 22,491.9569 0.0965
FERC FORM NO.1 (ED.12-95)
Page 304

This report is:
Name of Respondent: (1)0 An Original Date of Report: Year/Period of Report
Avista Corporation 04/12/2024 End of:2023/Q4
(2) 0 A Resubmission
SALES FOR RESALE(Account"7)
ACTUALDEMAND ACTUALDEMAND
(MW) (MW)
Name of Company or Public Statistical FERC Rate Average Monthly Average Monthly Average Monthly CP
Line Authority(Footnote Affiliations) Classification Schedule or Billing Demand(MW) NCP Demand Demand
No. (a) (b) Tariff Nu)mber (d) (e) (t)
1 Altop Energy Trading SF Tariff 9
2 Avangrid Renewables,LLC SF Tariff
3 Avangrid Renewables,LLC LF
Tariff 12
4 Avangrid Renewables,LLC LF Tariff 9
5 Avangrid Renewables,LLC b
IF Tariff 9
6 BHE Power Watch,LLC LF
Tariff 12
7 BP Energy Company SF Tariff 9
8 Basin Electric Power Cooperative SF Tariff
9 Bonneville Power Administration SF Tariff
10 Bonneville Power Administration LF Tariff 12
11 Bonneville Power Administration F Tariff
12 Bonneville Power Administration Ldl IF Tariff
13 British Columbia Hydro and LF Lbbj
Power Authority Tariff 12
14 Brookfield Energy Marketing LP SF Tariff 9
Lej
15 Brookfield Energy Marketing LP IF Tariff 9
16 CP Energy Marketing(US)Inc. SF Tariff 9
17 CP Energy Marketing(US)Inc. IF Tariff 9
18 California Independent System SF Tariff
Operator Corporation
19 Calpine Energy Services,LP SF Tariff
sbjc
20 Chelan County PUD No.1 LF Tariff 12
21 Clatskanie Peoples PUD SF Tariff 9
22 ConocoPhillips Company SF Tariff
23 Constellation Energy Generation, SF Tariff 9
LLC
24 Constellation Energy Generation, LM Tariff
LLC IF

SALES FOR RESALE(Account 447)
ACTUAL DEMAND ACTUAL DEMAND
(MW) (MW)
Name of Company or Public Statistical FERC Rate Average Monthly Average Monthly Average Monthly CP
Line Authority(Footnote Affiliations) Classification Schedule or Billing Demand(MW) NCP Demand Demand
No. (a) (b) Tariff Number (d) (e) (f)
(c)
25 l Dynasty Power,Inc. SF Tariff 9
26 Dynasty Power,Inc. IF Tariff 9
27 EDF Trading North America,LLC SF Tariff 9
28 EDF Trading North America,LLC IF Tariff 9
29 EDF Trading North America,LLC SF Tariff 9
30 Energy Keepers,Inc. SF Tariff 9
31 Energy Keepers,Inc. LF Tariff 9
32 Eugene Water Electric Board SF Tariff 9
33 Franklin County PUD No.1 SF Tariff
(bd)
34 Grant County PUD No.2 LF Tariff 12
35 Gridforce Energy Management, LF
LLC Tariff 12
36 Guzman Energy,LLC SF Tariff
37 Guzman Energy,LLC Lk)
Tariff
38 Heartland Generation Ltd. SF Tariff
39 Idaho Power Company SF Tariff 9
tto
40 Idaho Power Company LF Tariff 12
41 Idaho Power Company LF Tariff 9
42 Idaho Power Company Balancing SF Tariff 9
43 Idaho Power Company Balancing LMJLF Tariff 9
44 Idaho Power Company Balancing F Tariff 9
t�
45 Idaho Power Company Balancing IF Tariff 9
46 Idaho Power Company Balancing IF Tariff 9
47 J.Aron$Company SF Tariff 9
48 Kootenai Electric Cooperative IF Tariff 9
49 Macquarie Energy LLC SF Tariff 9
m
50 Macquarie Energy LLC LF Tariff 9

SALES FOR RESALE(Account 447)
ACTUALDEMAND ACTUALDEMAND
(MW) (MM
Name of Company or Public Statistical FERC Rate Average Monthly Average Monthly Average Monthly CP
Line Authority(Footnote Affiliations) Classification Schedule or Billing Demand(MW) NCP Demand Demand
No. (a) (b) Tariff Nu)mber (d) (e) (f)
51 Mercuria Energy America,LLC IF Tariff 9
52 Mercuria Energy America,LLC SF Tariff 9
53 Mizuho Securities USA Inc. OS NA
54 Morgan Stanley Capital Group Inc. SF Tariff
55 Morgan Stanley Capital Group Inc. LF Tariff 9
56 Morgan Stanley Capital Group Inc. IF Tariff 9
57 Morgan Stanley Capital Group Inc. SF Tariff 9
58 Morgan Stanley Capital Group Inc. SF Tariff 9
59 NaturEner Power Watch,LLC LF
Tariff 12
60 Nevada Power Company SF Tariff 9
61 NorthWestem Energy SF Tariff 9
62 NorthWestem Energy LF Tariff 9
63 NorthWestem Energy LF
Tariff 12
64 NorthWestem Energy LF Tariff
65 NorthWestem Energy IF Tariff 9
66 PacifiCorp SF Tariff
67 PacifiCorp IF Tariff
68 PacifiCorp LF Tariff 12
69 PacifiCorp IF Tariff 9
70 PacifiCorp LF Tariff 9
71 Pend Oreille County Public Utility LF Tariff 9
District#1
Pend Oreille County Public Utility i-1
72 District#1 LF Tariff9
Pend Oreille County Public Utility Lki 73 District#1 LF Tariff9
74 Pend Oreille County Public Utility SF Tariff 9
District#1
75 Phillips 66 Energy Trading,LLC SF Tariff 9

SALES FOR RESALE(Account 447)
ACTUALDEM AND ACTUAL DEMAND
(MW) (MW)
Name of Company or Public Statistical FERC Rate Average Monthly Average Monthly Average Monthly CP
Line Authority(Footnote Affiliations) Classification Schedule or Billing Demand(MW) NCP Demand Demand
No. (a) (b) Tariff(cut mber (d) (e) (f]
76 Phillips 66 Energy Trading,LLC IF Tariff 9
77 Portland General Electric SF Tariff
78 Portland General Electric LF a
Tariff 12
79 Portland General Electric IF Tariff 9
80 Portland General Electric IF Tariff 9
81 Power Ex SF Tariff 9
82 Power Ex LF Tariff 9
83 Puget Sound Energy LF Tariff 9
84 Puget Sound Energy SF Tariff 9
Au
85 Puget Sound Energy LF Tariff 12
86 Puget Sound Energy IF Tariff 9
87 Rainbow Energy Marketing SF Tariff
u
88 Rainbow Energy Marketing LF Tariff 9
89 Sacramento Municipal Utility LF Lui
District Tariff 12
90 Seattle City Light SF Tariff 9
91 Seattle City Light LF Tariff 9
92 Seattle City Light IF Tariff
s�
93 Seattle City Light LF Tariff 12
94 Shell Energy N.A. SF Tariff
95 Shell Energy N.A. IF Tariff 9
96 Shell Energy N.A. OS Tariff 9
97 Snohomish County PUD SF Tariff 9
98 Sovereign Power LF Tariff 9
99 Sovereign Power LFTariff 9
100 Tacoma Power SF Tariff

SALES FOR RESALE(Account447)
ACTUALDEMAND ACTUALDEMAND
(MW) (MW)
Name of Company or Public Statistical FERC Rate Average Monthly Average Monthly Average Monthly CP
Line Authority(Footnote Affiliations) Classification Schedule or Billing Demand(MW) NCP Demand Demand
No. (a) (b) Tariff Number (d) (e) (fJ
(c)
101 Tacoma Power LF Tariff 9
102 Tacoma Power LF Tariff 12
103 Talen Energy Montana,LLC LF Tariff 9
104 Tenaska Power Services Co. LF Tariff 9
105 The Energy Authority SF Tariff 9
106 The Energy Authority LF Tariff 9
107 TransAlta Energy Marketing SF Tariff 9
108 TransAlta Energy Marketing LF Tariff 9
109 Vitol,Inc. SF Tariff 9
110 Wells Fargo Securities,LLC OS NA
111 IntraCompany Wheeling LF F
112 IntraCompany Generation uLF
113 California Independent System u
Operator Corporation OS Tariff 9
15 Subtotal-RQ
16 Subtotal-Non-RQ
17 Total
FERC FORM NO.1 (ED.12-90)
Page 310311

SALES FOR RESALE(Account 447)
REVENUE REVENUE REVENUE
Line Megawatt Hours Sold Demand Charges(S) Energy Charges($) Other Charges($) Total($)(h+i+J)
No. (g) (h) (i) U) (k)
1 3,200 202,276 I 202,276
2 J 114,800 6,767,366 6,767,366
3 14 1,085 1,085
4 164 9,815 9,815
5 7,816 0 0
6 5 201 201
7 220,554 11,960,142 11,960,142
8 1,400 50,960 50,960
9 156,950 12,737,834 12,737,834
10 55 2,567 2,567
11 62,143 4,489,296 4,489,296
12 121,152 0 0
13 16 1,184 1,184
14 26,533 878,024 878,024
15 6,169 6,169
16 75 2,250 2,250
17 13 590 590
18 4,181 317,595 317,595
19 26,920 1,900,933 1,900,933
20 11 1,345 1,345
21 778 47,061 47,061
22 53,158 4,356,249 4,356,249
23 31,381 2,397,559 2,397,559
24 72 555 555
25 25,561 2,594,907 2,594,907
26 156 12,898 12,898
27 10,338 507,270 507,270
28 318 14,568 14,568
29 0 LM760 760
30 13,885 1,070,835 1,070,835
31 975 71,551 71,551
32 4,011 316,902 316,902
33 4 0 0
FERC FORM NO.1 (ED.12-90)
Page 310-311

SALES FOR RESALE(Account 447)
REVENUE REVENUE REVENUE
Line Megawatt Hours Sold Demand Charges(S) Energy Charges(S) Other Charges(S) Total($)(h+i+j)
No. (g) (h) W (j) (k)
34 18 983 983
35 447 34,708 f 34,708
36 4,049 305,097 305,097
37 6,565 622,414 622,414
38 75 7,500 7,500
39 275 34,200 34,200
40 43 2,240 2,240
41 2 114 114
42 400 21,100 21,100
43 10,121 857,956 857,956
44 255 0 0
45 86,718 0 0
46 121,002 0 0
47 274 31,535 31,535
48 495 30,636 30,636
49 36,392 1,982,419 1,982,419
50 1,460 183,751 183,751
51 249 19,071 19,071
52 14,000 1,423,100 1,423,100
53 0 11,931,625 11,931,625
54 386,264 19,059,884 19,059,884
55 5,367 424,104 424,104
56 365,097 25,049,365 25,049,365
57 0 -275,940 275,940
58 0 -275,940 275,940
59 25 1,775 1,775
60 1,050 110,375 110,375
61 16,233 1,956,765 1,956,765
62 48 3,512 3,512
63 5 428 428
64 9,014 690,916 690,916
65 90,086 0 0
66 232,560 23,897,675 23,897,675
FERC FORM NO.1 (ED.12-90)
Page 310-311

SALES FOR RESALE(Account 447)
REVENUE REVENUE REVENUE
Line Megawatt Hours Sold Demand Charges(S) Energy Charges($) Other Charges($j Total($)(h+i+j)
No. (g) (h) (i) U) (k)
67 49,283 0 0
68 33 4,250 4,250
69 1,816 93,858 93,858
70 6,010 460,611 460,611
71 0 -511,006 511,006
72 11,692 849,146 849,146
73 44 3,929 3,929
74 5,663 817,525 817,525
75 10,550 614,236 614,236
76 3,553 170,032 170,032
77 108,263 11,440,822 11,440,822
78 34 2,356 2,356
79 660 47,285 47,285
80 2,051 126,204 126,204
81 381,983 22,697,641 22,697,641
82 14,356 707,286 707,286
83 15,024 1,151,527 1,151,527
84 55,935 4,488,653 4,488,653
85 18 1,670 1,670
86 3,707 205,636 205,636
87 12,682 993,218 993,218
88 431 26,565 26,565
89 32 2,034 2,034
90 37,585 2,394,338 2,394,338
91 635 40,340 40,340
92 8 458 458
93 6 387 387
94 112,642 8,010,476 8,010,476
95 116 7,703 7,703
96 Iw6,000 6,000
97 35,580 3,324,903 3,324,903
98 0 -148,528 148,528
FERC FORM NO.1 (ED.12-90)
Page 310-311

SALES FOR RESALE(Account 447)
REVENUE REVENUE REVENUE
Line Megawatt Hours Sold Demand Charges(S) Energy Charges(5) Other Charges(S) Total($)(h+i+j)
No- (g) (h) (i) U) (k)
99 15,167 926,987 926,987
100 4,240 276,750 l 276,750
101 1,553 100,417 111 I 100,417
102 14 463 463
103 9,014 690,916 690,916
� 104 19 178 178
105 96,777 6,585,535 6,585,535
106 271 21,625 21,625
107 236,859 16,007,509 16,007,509
108 197 18,548 18,548
109 11,760 611,932 611,932
110 0 14,517,377 14,517,377
111 (35,503,866) 35,503,866 0
112 1,173,595 1,173,595
113 13,421,671 13,421,671
15 0
16 3,521,491 1,212,174 175,891,693 76,554,134 253,658,001
r17 3,521,491 1,212,174 175,891,693 76,554,134 253,658,001
FERC FORM NO.1 (ED.12-90)
Page 310-311

This report is:
Name of Respondent: (1)®An Original Date of Report: Year/Period of Report
Avista Corporation 04/12/2024 End of.2023/Q4
(2) ❑A Resubmission
FOOTNOTE DATA
4W Concept:StatisticalClassificationCode
Financially Settled Transmission Losses effective 01/01/2016-12/31/2024
�b)Concept:StatisticalClassificationCode
06/06/2023-12/31/2024 ETSR is an export resource associated with EIM.
4.c)Concept:StatisticalClassificationCode
Financially Settled Transmission Losses
4.d)Concept:StatisticalClassificationCode
03/02/2022-12/31/2024 ETSR is an export resource associated with EIM.
Le)Concept:StatisticalClassificationCode
Financially Settled Transmission Losses
ft Concept:StatisticalClassificationCode
Financially Settled Transmission Losses
(g)Concept:StatisticalClassificationCode
Financially Settled Transmission Losses
Concept:StatisticalClassificationCode
Financially Settled Transmission Losses
Concept:StatisticalClassificationCode
Financially Settled Transmission Losses
jj,)Concept:StatisticalClassificationCode
Financially Settled Transmission Losses effective 01/01/2016-12/31/2024
Concept:StatisticalClassificationCode
Financially Settled Transmission Losses
0 Concept:StatisticalClassificationCode
Financially Settled Transmission Losses effective 01/01/2016-12/31/2024
(m)Concept:StatisticalClassificationCode
Financially Settled Transmission Losses effective 01/01/2016-12/31/2024
u Concept:StatisticalClassificationCode
03/02/2022-12/31/2024 ETSR is an export resource associated with EIM.
4p1 Concept:StatisticalClassificationCode
03/02/2022-12/31/2024 ETSR is an export resource associated with EIM.
(p.)Concept:StatisticalClassificationCode
03/02/2022-12/31/2024 ETSR is an export resource associated with EIM.
4W Concept:StatisticalClassificationCode
Financially Settled Transmission Losses
W Concept:StatisticalClassificationCode
Financially Settled Transmission Losses effective 07/18/2018-12/31/2024
W Concept:StatisticalClassificationCode
Financially Settled Transmission Losses
ft)Concept:StatisticalClassificationCode
Financial SWAP
U Concept:StatisticalClassificationCode
Financially Settled Transmission Losses effective 01/01/2016-12/31/2024

L1 Concept:StatisticalClassificationCode
Resource Contingent Bundled REC-Energy and Green Attributes 03/01/2019-12/31/2023
W Concept:StatisticalClassificationCode
Financially Settled Transmission Losses effective 01/01/2016-12/31/2024
W Concept:StatisticalClassificationCode
NorthWestem Energy LLC sale expires December 31,2025
fy)Concept:StatisticalClassificationCode
01/26/2022-12/31/2024 ETSR is an export resource associated with EIM.
4z1 Concept:StatisticalClassificationCode
01/27/2022-12/31/2024 ETSR is an export resource associated with EIM.
as Concept:StatisticalClassificationCode
Financially Settled Transmission Losses
ab Concept:StatisticalClassificationCode
PacifiCorp sale expires December 31,2025
ac Concept:StatisticalClassificationCode
Deviation Energy
ad Concept:StatisticalClassificationCode
Contract expires September 30,2026
ae Concept:StatisticalClassificationCode
Financially Settled Transmission Losses
aaf Concept:StatisticalClassificationCode
Financially Settled Transmission Losses
Lag)Concept:StatisticalClassificationCode
Portland General Electric sale expires December 31,2025
4h Concept:StatisticalClassificationCode
Financially Settled Transmission Losses effective 05/01/2019-12/31/2024
Concept:StatisticalClassificationCode
Puget Sound Energy sale expires December 31,2025
W Concept:StatisticalClassificationCode
Financially Settled Transmission Losses
48)Concept:StatisticalClassificationCode
Financially Settled Transmission Losses effective 01/01/2016-12/31/2024
Concept:StatisticalClassificationCode
Financially Settled Transmission Losses effective 03/19/2008-12/31/2024
am Concept:StatisticalClassificationCode
Financially Settled Transmission Losses
kn Concept:StatisticalClassificationCode
Financially Settled Transmission Losses
ao Concept:StatisticalClassificationCode
Deviation Energy
1,aW Concept:StatisticalClassificationCode
Financially Settled Transmission Losses effective 03/19/2008-12/31/2024
4aM Concept:StatisticalClassificationCode
Talen Energy Montana,LLC sale expires December 31,2025
ka-r)Concept:StatisticalClassificationCode
Financially Settled Transmission Losses effective 01/0112016-12/31/2024

as Concept:StatisticalClassificationCode
Financially Settled Transmission Losses effective 01/01/2016-12/31/2024
at Concept:StatisticalClassificationCode
Financially Settled Transmission Losses effective 01/01/2016-12/31/2024
au Concept:StatisticalClassificationCode
Financial SWAP
av Concept:StatisticalClassificationCode
Infra Company Wheeling
aw Concept:StatisticalClassificationCode
lntra Company Generation-Sale of Ancillary Services
ax Concept:Statist cal CIassificationCode
(Energy Imbalance Market(EIM)Sales
(ay)Concept:RateScheduleTariffN umber
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement
az Concept:RateScheduleTariffN umber
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement
U Concept:RateScheduleTadffN umber
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement
Concept:RateScheduleTariffN umber
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement
Concept:RateScheduleTariffN umber
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement
Concept:RateScheduleTariffN umber
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement
Jbe)Concept:RateScheduleTariffNumber
;Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement
bt Concept:RateScheduleTariffN umber
(Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement
fbW Concept:RateScheduleTariffN umber
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement
Concept:RateScheduleTariffNumber
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement
fbi)Concept:RateScheduleTadffN umber
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement
bf�Concept:RateScheduleTariffNumber
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement
kUk Concept:RateScheduleTariffN umber
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement
Concept:RateScheduleTadffN umber
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement
Concept:RateScheduleTariffN umber
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement
(bn)Concept:RateScheduleTariffN umber
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement
f,bLoj Concept:DemandChargesRevenueSalesForResale
Reserves
bM Concept:DemandChargesRevenueSalesForResale

Capacity
bhW Concept:DemandChargesRevenueSalesForResale
Capacity
Concept:DemandChargesRevenueSalesForResale
Contract expires September 30,2026
bs Concept:DemandChargesRevenueSalesForResale
Sovereign Power contract terminates September 30,2026
bt Concept:OtherChargesRevenueSalesForResale
IPondage
FERC FORM NO.1(ED.12-90)
Page 310-311

report is:e This rpo
Name of Respondent: Th Th po Original Date of Report: Year/Period of Report
Avista Corporation 04/12/2024 End of:2023/Q4
(2) ❑A Resubmission
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
Line No. Acc6)jgllllllllll[V AfilounffoirCurrent ear Amount for Previous Year(c)
(a) (b) (c)
1 1.POWER PRODUCTION EXPENSES
2 A.Steam Power Generation
3 Operation
4 (500)Operation Supervision and Engineering 177,149 342,883
5 (501)Fuel 46,052,299 41,707,542
6 (502)Steam Expenses 4,221,985 3,674,482
7 (503)Steam from Other Sources 0 0
8 (Less)(504)Steam Transferred-Cr. 0 0
9 (505)Electric Expenses 754,146 884,248
10 (506)Miscellaneous Steam Power Expenses 6,447,460 5,888,310
11 (507)Rents 0 0
12 (509)Allowances 662,437 0
13 TOTAL Operation(Enter Total of Lines 4 thru 12) 58,315,476 52,497,465
14 Maintenance
15 (510)Maintenance Supervision and Engineering 408,706 704,474
16 (511)Maintenance of Structures 869,388 898,565
17 (512)Maintenance of Boiler Plant 7,090,052 6,596,152
18 (513)Maintenance of Electric Plant 849,384 883,060
19 (514)Maintenance of Miscellaneous Steam Plant 1,345,536 786,396
20 TOTAL Maintenance(Enter Total of Lines 15 thru 19) 10,563,066 9,868,647
21 TOTAL Power Production Expenses-Steam Power(Enter 68,878,542 62,366,112
Total of Lines 13&20)
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
FERC FORM NO.1 (ED.12-93)
Page 320-323

ELECTRIC OPERATION AND MAINTENANCE EXPENSES
Line No. Account Amount for Current Year Amount for Previous Year(c)
(a) (b) (c)
31 (524)Miscellaneous Nuclear Power Expenses 0 0
32 (525)Rents 0 0
33 TOTAL Operation(Enter Total of lines 24 thru 32) 0 i
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 0 0
(Enter Total of lines 33&40)
42 C.Hydraulic Power Generation
43 Operation
44 (535)Operation Supervision and Engineering 2,459,290 2,724,681
45 (536)Water for Power 1,184,579 1,223,862
46 (537)Hydraulic Expenses 9,863,917 9,475,818
47 (538)Electric Expenses 6,629,557 6,827,422
48 (539)Miscellaneous Hydraulic Power Generation 2,203,306 1,731,229
Expenses
49 (540)Rents 7,611,335 7,200,284
50 TOTAL Operation(Enter Total of Lines 44 thru 49) 29,951,984 29,183,296
51 C.Hydraulic Power Generation(Continued)
52 Maintenance
53 (541)Mainentance Supervision and Engineering 714,032 819,291
54 (542)Maintenance of Structures 498,079 1,044,569
55 (543)Maintenance of Reservoirs,Dams,and Waterways 497,535 888,287
56 (544)Maintenance of Electric Plant 3,128,062 3,607,944
57 (545)Maintenance of Miscellaneous Hydraulic Plant 663,385 752,814
58 TOTAL Maintenance(Enter Total of lines 53 thru 57) 5,501,093 7,112,905
59 TOTAL Power Production Expenses-Hydraulic Power 35,453,077 36,296,201
(Total of Lines 50&58)
60 D.Other Power Generation
61 Operation
62 (546)Operation Supervision and Engineering 893,882 379,621
FERC FORM NO.1 (ED.12-93)
Page 320-323

ELECTRIC OPERATION AND MAINTENANCE EXPENSES
Line No. Account Amount for Current Year Amount for Previous Year(c)
(a) (b) (c)
63 (547)Fuel 116,227,146 171,864,307
64 (548)Generation Expenses 3,899,765 2,572,735
64.1 (548.1)Operation of Energy Storage Equipment 0 0
65 (549)Miscellaneous Other Power Generation Expenses 945,276 779,929
66 (550)Rents 103,105 87,122
67 TOTAL Operation(Enter Total of Lines 62 thru 67) 122,069,174 175,683,714
68 Maintenance
69 (551)Maintenance Supervision and Engineering 768,609 751,930
70 (552)Maintenance of Structures 138,993 93,800
71 (553)Maintenance of Generating and Electric Plant 2,012,409 3,975,265
71.1 (553.1)Maintenance of Energy Storage Equipment 0 0
72 (554)Maintenance of Miscellaneous Other Power 862,263 535,519
Generation Plant
73 TOTAL Maintenance(Enter Total of Lines 69 thru 72) 3,782,274 5,356,514
74 TOTAL Power Production Expenses-Other Power(Enter 125,851,448 181,040,228
Total of Lines 67&73)
75 E.Other Power Supply Expenses
76 (555)Purchased Power 209,295,625 191,412,443
76.1 (555.1)Power Purchased for Storage Operations 7,132,090 252,740
77 (556)System Control and Load Dispatching 764,664 1,044,735
78 (557)Other Expenses 38,247,947 43,909,712
79 TOTAL Other Power Supply Exp(Enter Total of Lines 76 255,440,326 236,619,630
thru 78)
80 TOTAL Power Production Expenses(Total of Lines 21, 485,623,393 516,322,171
41,59,74&79)
81 2.TRANSMISSION EXPENSES
82 Operation
83 (560)Operation Supervision and Engineering 2,084,569 1,947,022
85 (561.1)Load Dispatch-Reliability 45,236 18,859
86 (561.2)Load Dispatch-Monitor and Operate 1,503,318 1,727,109
Transmission System
87 (561.3)Load Dispatch-Transmission Service and 965,836 916,919
Scheduling
88 (561.4)Scheduling,System Control and Dispatch 0 0
Services
89 (561.5)Reliability,Planning and Standards Development 565,721 596,438
90 (561.6)Transmission Service Studies 0 3,944
FERC FORM NO.1 (ED.12-93)
Page 320�323

ELECTRIC OPERATION AND MAINTENANCE EXPENSES
Line No. Account Amount for Current Year Amount for Previous Year(c)
(a) (b) (c)
91 (561.7)Generation Interconnection Studies 0 5,704
92 (561.8)Reliability,Planning and Standards Development 0 0
Services
93 (562)Station Expenses 397,216 455,206
93.1 (562.1)Operation of Energy Storage Equipment 0 0
94 (563)Overhead Lines Expenses 324,854 524,834
95 (564)Underground Lines Expenses 0 0
96 (565)Transmission of Electricity by Others 19,063,436 20,220,629
97 (566)Miscellaneous Transmission Expenses 4,242,693 4,423,684
98 (567)Rents 97,830 89,654
99 TOTAL Operation(Enter Total of Lines 83 thru 98) 29,290,709 30,930,002
100 Maintenance
101 (568)Maintenance Supervision and Engineering 369,375 423,695
102 (569)Maintenance of Structures 572,864 707,438
103 (569.1)Maintenance of Computer Hardware 0 0
104 (569.2)Maintenance of Computer Software 0 0
105 (569.3)Maintenance of Communication Equipment 0 0
106 (569.4)Maintenance of Miscellaneous Regional 0 0
Transmission Plant
107 (570)Maintenance of Station Equipment 1,160,838 1,209,445
107.1 (570.1)Maintenance of Energy Storage Equipment 0 0
108 (571)Maintenance of Overhead Lines 2,198,739 2,223,133
109 (572)Maintenance of Underground Lines 965 773
110 (573)Maintenance of Miscellaneous Transmission Plant 72,128 84,498
111 TOTAL Maintenance(Total of Lines 101 thru 110) 4,374,909 4,648,982
112 TOTAL Transmission Expenses(Total of Lines 99 and 33,665,618 35,578,984
111)
113 3.REGIONAL MARKET EXPENSES
114 Operation
115 (575.1)Operation Supervision 0 0
116 (575.2)Day-Ahead and Real-Time Market Facilitation 0 0
117 (575.3)Transmission Rights Market Facilitation 0 0
118 (575.4)Capacity Market Facilitation 0 0
119 (575.5)Ancillary Services Market Facilitation 0 0
120 (575.6)Market Monitoring and Compliance 0 0
FERC FORM NO.1 (ED.12-93)
Page 320-323

ELECTRIC OPERATION AND MAINTENANCE EXPENSES
I-ine No. Account Amount for Current Year Amountfor Previous Year(c)
(a) (b) (c)
121 (575.7)Market Facilitation,Monitoring and Compliance 0 0
Services
122 (575.8)Rents 0 0
123 Total Operation(Lines 115 thru 122) 0 0
124 Maintenance
125 (576.1)Maintenance of Structures and Improvements 0 0
126 (576.2)Maintenance of Computer Hardware 0 0
127 (576.3)Maintenance of Computer Software 0 0
128 (576.4)Maintenance of Communication Equipment 0 0
129 (576.5)Maintenance of Miscellaneous Market Operation 0 0
Plant
130 Total Maintenance(Lines 125 thru 129) 0 0
131 TOTAL Regional Transmission and Market Operation 0 0
Expenses(Enter Total of Lines 123 and 130)
132 4.DISTRIBUTION EXPENSES
133 Operation
134 (580)Operation Supervision and Engineering 4,183,113 4,538,302
135 (581)Load Dispatching 0 0
136 (582)Station Expenses 945,603 934,752
137 (583)Overhead Line Expenses 3,151,705 2,894,198
138 (584)Underground Line Expenses 2,546,406 1,566,750
138.1 (584.1)Operation of Energy Storage Equipment 0 0
139 (585)Street Lighting and Signal System Expenses 6,950 5,888
140 (586)Meter Expenses 2,133,258 2,170,353
141 (587)Customer Installations Expenses 801,450 859,014
142 (588)Miscellaneous Expenses 9,401,777 7,747,059
143 (589)Rents 258,811 196,608
144 TOTAL Operation(Enter Total of Lines 134 thru 143) 23,429,073 20,912,924
145 Maintenance
146 (590)Maintenance Supervision and Engineering 1,361,055 1,632,916
147 (591)Maintenance of Structures 411,657 593,149
148 (592)Maintenance of Station Equipment 779,672 887,699
148.1 (592.2)Maintenance of Energy Storage Equipment 0 0
149 (593)Maintenance of Overhead Lines 27,486,692 26,152,322
150 (594)Maintenance of Underground Lines 861,884 756,582
FERC FORM NO.1 (ED.12-93)
Page 320-323

ELECTRIC OPERATION AND MAINTENANCE EXPENSES
Line No. Account Amount for Current Year Amount for Previous Year(c)
(a) (b) (c)
151 (595)Maintenance of Line Transformers 443,255 520,693
152 (596)Maintenance of Street Lighting and Signal Systems 91,567 115,351
153 (597)Maintenance of Meters 60,470 57,877
154 (598)Maintenance of Miscellaneous Distribution Plant 1,099,461 981,461
155 TOTAL Maintenance(Total of Lines 146 thru 154) 32,595,713 31,698,050
156 1 TOTAL Distribution Expenses(Total of Lines 144 and 56,024,786 52,610,974
157 5.CUSTOMER ACCOUNTS EXPENSES
158 Operation
159 (901)Supervision 135,418 130,813
160 (902)Meter Reading Expenses 643,428 736,380
161 (903)Customer Records and Collection Expenses 8,464,586 8,085,755
162 (904)Uncollectible Accounts 5,102,188 42,879
163 (905)Miscellaneous Customer Accounts Expenses 277,721 259,554
164 TOTAL Customer Accounts Expenses(Enter Total of 14,623,341 9,255,381
Lines 159 thru 163)
165 6.CUSTOMER SERVICE AND INFORMATIONAL
EXPENSES
166 Operation
167 (907)Supervision 0 0
168 (908)Customer Assistance Expenses 31,870,071 33,220,677
169 (909)Informational and Instructional Expenses 866,879 899,673
170 (910)Miscellaneous Customer Service and Informational 229,071 124,273
Expenses
171 TOTAL Customer Service and Information Expenses 32,966,021 34,244,623
(Total Lines 167 thru 170)
172 7.SALES EXPENSES
173 Operation
174 F(91 1)Supervision 0 0
175 (912)Demonstrating and Selling Expenses 43,646 108,681
176 (913)Advertising Expenses 0 0
177 (916)Miscellaneous Sales Expenses 0 0
178 1 TOTAL Sales Expenses(Enter Total of Lines 174 thru 43,646 108,681
179 8.ADMINISTRATIVE AND GENERAL EXPENSES I„
180 Operation
FERC FORM NO.1 (ED.12-93)
Page 320-323

ELECTRIC OPERATION AND MAINTENANCE EXPENSES
Line No. Account Amount for Current Year Amount for Previous Year'(04—
(a) (b) (c)
181 (920)Administrative and General Salaries 32,491,999 31,951,930
182 (921)Office Supplies and Expenses 3,924,958 4,208,908
183 (Less)(922)Administrative Expenses Transferred-Credit 114,022 95,466
184 (923)Outside Services Employed 14,933,869 14,506,894
185 (924)Property Insurance 2,806,701 2,435,764
186 (925)Injuries and Damages 10,784,299 10,487,107
187 (926)Employee Pensions and Benefits 28,096,654 37,144,003
188 (927)Franchise Requirements 1,200 1,200
189 (928)Regulatory Commission Expenses 8,387,545 6,789,206
190 (929)(Less)Duplicate Charges-Cr. 0 0
191 (930.1)General Advertising Expenses 0 0
192 (930.2)Miscellaneous General Expenses 5,644,865 5,342,709
193 (931)Rents 938,930 778,114
194 TOTAL Operation(Enter Total of Lines 181 thru 193) 107,896,998 113,550,369
195 Maintenance
196 (935)Maintenance of General Plant 14,630,422 14,984,639
197 TOTAL Administrative&General Expenses(Total of 122,527,420 128,535,008
Lines 194 and 196)
198 TOTAL Electric Operation and Maintenance Expenses 745,474,225 776,655,822
(Total of Lines 80,112,131,156,164,171,178,and 197)
FERC FORM NO.1 (ED.12-93)
Page 320�323

This report is:
Name of Respondent: (1)0 An Original Date of Report: Year/Period of Report
Avista Corporation (2) ❑A Resubmission 04/12/2024 End of:2023/Q4
PURCHASED POWER(Account 555)
Actual Demand Actual Demand
Ab (NIV+) (MW)
MegaWatt
Name of Company or Public Ferc Rate Average Monthly Hours
Line Authority(Footnote Statistical Schedule or Billing Demand Average Monthly Average Monthly Purchased
No. Affiliations) Classification Tariff Number (MW) NCP Demand CP Demand (Excluding
(a) (b) (c) (d) (e) (f) for Energy
Storage)
(g)
1 Adams Nielson Solar,LLC LU PURPA 36,961
2 Altop Energy Trading SF Tariff 9 1,200
3 Arizona Public Service OS APS OATT
Company
4 Avangrid Renewables,LLC SF Tariff 9 38,231
5 Avangrid Renewables,LLC LF NWPP 6
i
6 Avangrid Renewables,LLC IF Tariff 9 13,716
7 BP Energy SF Tariff 4,800
a
8 Bonneville Power OS BPA OATT
Administration
A
9 Bonneville Power LF Tariff 440
Administration
Bonneville Power
10 Administration SF Tariff 116,145
co
11 Bonneville Power LF NWPP 140
Administration
to
12 Bonneville Power OS BPA OATT
Administration
13 Bonneville Power IF Tariff 9 23,601
Administration
14 Bonneville Power OS BPA OATT
Administration
15 Bonneville Power OS BPA OATT
Administration
skj
16 Bonneville Power IF Tariff 9 96,717
Administration
17 Brookfield Energy Marketing SF Tariff 1,443
LP
18 CP Energy Marketing(US) SF Tariff 1,300
Inc.
FERC FORM NO.1 (ED.12-90)
Page 326327

PURCHASED POWER(Account 555)
Actual Demand Actual Demand
(MW) (MW)
MegaWatt
Name of Company or Public Ferc Rate Average Monthly Hours
Line Authority(Footnote
Statistical Schedule or Billing Demand Average Monthly Average Monthly Purchased
Classification NCP Demand CP Demand (Excluding)I
No. Affiliations) (b) Tariff Number (MW) (e) (f} for Energy)
(a) (c) (d) Storage)
(g)
19 California Independent SF Tariff 51.155
System Operator
20 Calpine Energy Services,LP SF Tariff 9 175
21 Chelan County PUD IU Rocky Reach 22,575
22 Chelan County PUD IU Rocky Reach (23,686)
23 Chelan County PUD SF Tariff 9 2,800
u
24 Chelan County PUD LF NWPP 5
25 Chelan County PUD IU Chelan Sys 351,170
26 City of Spokane IU PURPA 38,502
27 City of Spokane IU PURPA 124,696
28 Clark Fork Hydro LU PURPA 635
29 Clatskanie PUD SF Tariff 190
30 Clearwater Paper Company IU PURPA 425,877
31 Community Solar LU PURPA 478
32 ConocoPhillips Company SF Tariff9 10,200
33 Constellation Energy SF Tariff 9 5,736
Generation,LLC
34 Deep Creek Energy,LLC IU PURPA 50
35 Douglas County PUD No.1 LU Wells 379,055
tnj
36 Douglas County PUD No.1 LF NWPP 1
37 Douglas County PUD No.1 EX Tariff9
38 Dynasty Power,Inc. SF Tariff 41,188
East,South,Quincy
39 Columbia Basin Irrigation LU PURPA 22,586
Districts
40 EDF Trading No America SF Tariff 9 9,015
41 Enel X North America,Inc. LU PURPA 5
42 Energy Keepers,Inc. SF Tariff 9 19,913
43 Eugene Water&Electric SF Tariff 9 2,021
Board
44 Ford Hydro Limited LU PURPA 3,093
Partnership
FERC FORM NO.1 (ED.12-90)
Page 326-327

PURCHASED POWER(Account 555)
Actual Demand Actual Demand
(MW) (MW)
MegaWatt
Name of Company or Public Ferc Rate Average Monthly Hours
Line Authority(Footnote Schedule or Billing Demand
Statistical Average Monthly Average Monthly Purchased
No. Affiliations) Classification Tariff Number (MW) NCP Demand CP Demand (Excluding
(a) (b) (c) (d) (e) (f) for Energy
Storage)
(9)
45 Grant County PUD No.2 LU Priest Rapids 255,042
t�
46 Grant County PUD No.2 LF NWPP 9
47 Grant County PUD No.2 EX FERC#104
48 Gridforce Energy LF NWPP 6
Management,LLC
49 Guzman Energy,LLC SF Tariff9 2,408
50 Heartland Generation Ltd. SF Tariff 4,642
51 Hydro Technology Systems IU PURPA 9,528
52 Idaho County Power&Light LU PURPA 1,267
Idaho Power
53 Idaho Power Company OS Co OATT
54 Idaho Power Company SF Tariff9 44,154
L
55 Idaho Power Company LF Tariff 9 96
56 Idaho Power Company IF Tariff 9 1,024
Balancing
57 Idaho Power Company IF Tariff 9 341,750
Balancing
58 Inland Power&Light RQ 208 155
Company
59 J.Aron&Company,LLC SF Tariff 9 274
60 Kootenai Electric Cooperative EX Tariff 8
61 Macquarie Energy,LLC SF Tariff 9 36,730
62 M r uriaEnergyAmerica, SF Tariff9 1,216
LLC
LD
63 Mizuho Securities USA,Inc. OS NA
64 Morgan Stanley Capital SF Tariff 9 20,600
Group
65 Nevada Power Company SF Tariff 9 100
66 Nevada Power Company LF Tariff 9 1
67 NorthWestem Energy SF Tariff 26,785
FERC FORM NO.1 (ED.12-90)
Page 326-327

PURCHASED POWER(Account 555)
Actual Demand Actual Demand
(MW) (MW)
Megawatt
Name of Company or Public Ferc Rate Average Monthly Hours
Line Authority(Footnote
Statistical Schedule or Billing Demand Average Monthly Average Monthly Purchased
No. Affiliations) Classification Tariff Number (MW) NCP Demand CP Demand (Excluding
(a) (b) (c) (d) (e) (f) for Energy
Storage)
(g)
68 NorthWestem Energy LF NWPP 16
69 NorthWestem Energy IF Tariff 4,711
70 NorthWestem Energy IF Tariff 221,363
NorthWestem
71 NorthWestem Energy OS Energy OATT
72 PacifiCorp SF Tariff 1,415
73 PacifiCorp IF Tariff 9 95,771
74 PacifiCorp LF NWPP 31
t�
75 PacifiCorp LF Tariff 9 1
PacifiCorp
76 PacifiCorp OS OATT
77 Palouse Wind,LLC LU PPA 294,887
78 Pend Oreille County PUD No. SF Pend O' 42,481
79 Pend Oreille County PUD No. LF Pend O' 7,457
1
Pend Oreille County PUD No.
80 1 LF Pend O' 301
81 Portland General Electric EX Tariff 9
Company
82 Portland General Electric SF Tariff 9 5,160
Company
Lv)
83 Portland General Electric LF NWPP 41
Company
84 Portland General Electric LF Tariff 2,102
Company
ss Portland
85 Portland General Electric OS General
Company OATT
86 Powerex Corp SF Tariff 9 4,850
87 Puget Sound Energy SF Tariff 9 22,387
88 Puget Sound Energy LF NWPP 39
FERC FORM NO.1 (ED.12-90)
Page 326-327

PURCHASED POWER(Account 555)
Actual Demand Actual Demand
(MW) (MW)
MegaWatt
Name of Company or Public Ferc Rate Average Monthly Hours
Line Authority(Footnote Schedule or Billing Demand
Statistical Average Monthly Average Monthly Purchased
Classification NCP Demand CP Demand (Excluding
No. Affiliations) (b) Tariff Number (MW) (e) M for Energ
(a) (c) (d) Storage),
(g)
89 Puget Sound Energy LF Tariff 9 278
90 Puget Sound Energy OS Puget Sound Energy OATT
91 Puget Sound Energy OS Tariff 9
92 CoRainbow Energy Marketing SF Tariff 9 60,140
93 Rathdrum Power,LLC LU Lancaster 1,806,400
94 Rattlesnake Flat,LLC LU PPA 343,410
95 Sacramento Municipal Utility SF Tariff 270
District
96 Seattle City Light SF Tariff 9 8,750
i-i
97 Seattle City Light LF NWPP 14
98 Sheep Creek Hydro IU PURPA 5,473
99 Shell Energy SF Tariff 9 8,514
100 Snohomish County PUD No. SF Tariff 9 6,655
101 Sovereign Power LF Sovereign 8,134
102 Stimson Lumber IU PURPA 8,784
103 Tacoma Power SF Tariff 12,461
tit
104 Tacoma Power LF NWPP 6
105 The City of Cove LU PURPA 2,114
106 The Energy Authority SF Tariff 9 18,717
107 TransAlta Energy Marketing SF Tariff 9 23,120
108 Turlock Irrigation District SF Tariff 9 663
109 Vitol Inc. SF Tariff 9 16,212
110 Wells Fargo Securities,LLC OS NA
111 IntraCompany Generation OS OATT
Services
112 Other-Inadvertent EX
Interchange
FERC FORM NO.1 (ED.12-90)
Page 326327

PURCHASED POWER(Account 555)
Actual Demand Actual Demand
(MIM (MM
MegaWatt
Name of Company or Public Ferc Rate Average Monthly Hours
Line Authority(Footnote
Statistical Schedule or Rifling Demand Average Monthly Average Monthly Purchased
No. Affiliations) Classification Tariff Number (MW) NCP Demand CP Demand (Excluding
(a) (b) (c) (d) (e) (f) for Energy
Storage)
(g)
Ll
113 California Independent OS Tariff 9
System Operator
15 TOTAL 5,601,050
FERC FORM NO.1(ED.12-90)
Page 326-327

PURCHASED POWER(Account 555)
POWER POWER COST/SETTLEMENTCOSTISETTLEMENTCOST/SETTLEMENTCOST/SETTLEME
EXCHANGES EXCHANGES OF POWER OF POWER OF POWER OF POWER '
MegaWatt
Hours MegaWatt MegaWatt Total(k+
Line Purchased Hours Hours Demand Charges($) Energy Charges($) Other Charges($) Settlement(S)
No. for Energy Received Delivered (k) (1) (m)
Storage (i) G) (�)
(h)
1 1,556,428 1,556,428
2 68,800 68,800
3 0 0
4 2,412,851 2,412,851
5 472 472
6 0
7 64,500 64,500
8 (502,871) (502,871)
9 0
10 4,565,427 4,565,427
11 9,019 9,019
12 47,401 47,401
13 1,340,218 1,340,218
14 264 264
15 1,302 1,302
16 0
17 124,621 124,621
18 92,250 92,250
19 3,001,346 3,001,346
20 21,875 21,875
21 0
22 0
23 183,428 183,428
24 361 361
25 15,466,880 15,466,880
26 1,938,259 1,938,259
27 5,886,485 5,886,485
28 41,380 41,380
29 2,550 2,550
30 10,433,987 10,433,987
FERC FORM NO.I (ED.12-90)
Page 326-327

PURCHASED POWER(Account 555)
POWER POWER COST/SETTLEMENTCOST/SETTLEMENTCOSTISETTLEMENTCOST/SETTLEMENT
EXCHANGES EXCHANGES OF POWER OF POWER OF POWER OF POWER
MegaWatt
Hours MegaWatt MegaWatt Total(k+I+m)of
Line Purchased Hours Hours Demand Charges($) Energy Charges($) Other Charges($) Settlement($)
No. for Energy Received Delivered (k) (I) (m) (n)
Storage (1) Q)
(h)
31 0
32 814,188 814,188
33 292,690 292,690
34 5,351 5,351
35 3,627,412 3,627,412
36 84 84
37 411,720 0
38 5,185,314 5,185,314
39 975,038 975,038
40 588,281 588,281
41 0
42 1,634,168 1,634,168
43 40,355 40,355
44 158,570 158,570
45 34,065,844 34,065,844
46 596 596
47 94,328 94,328
48 473 473
49 283,485 283.485
50 425,804 425,804
51 424,640 424,640
52 59,029 59,029
53 (373) (373)
54 2,804,211 2,804,211
55 3,337 3,337
56 0
57 0
58 10,565 10,565
59 49,105 49,105
60 0
FERC FORM NO.1 (ED.12-90)
Page 326-327

PURCHASED POWER(Account 555)
POWER POWER COST/SETTLEMENTCOST/SETTLEMENTCOSTlSETTLEMENTCOST/SETTLEME
EXCHANGES EXCHANGES OF POWER OF POWER OF POWER OF POWER !.
MegaWatt
Hours MegaWatt MegaWatt Total(k+i+m)of4
Line Purchased Hours Hours Demand Charges(5) Energy Charges($) Other Charges($) Settlement(5)
No. for Energy Received Delivered (k) (1) (m)
(n)
Storage (i) (j)
61 2,585,009 2,585,009
62 140,824 140,824
63 4,350,932 4,350,932
64 1,334,144 1,334,144
65 500 500
66 155 155
67 1,336,980 1,336,980
68 1,041 1,041
69 276,133 276,133
70 0
71 (245,932) (245,932)
72 46,375 46,375
73 0
74 1,995 1,995
75 (177) (177)
76 (48) (48)
77 19,574,599 19,574,599
78 2,776,687 2,776,687
79 451,508 451,508
80 4,139 4,139
81 9,973 9,969 0
82 228,925 228,925
83 2,699 2,699
84 87,235 87,235
85 3,499 3,499
86 724,500 724,500
87 1,764,002 1,764,002
88 2,651 2,651
89 30,004 30,004
90 5,257 5,257
FERC FORM NO.1 (ED.12-90)
Page 326327

PURCHASED POWER(Account 555)
POWER POWER COSTISETTLEMENTCOST/SETTLEMENTCOSTISETTLEMENTCOST/SETTLEME
EXCHANGES EXCHANGES OF POWER OF POWER OF POWER OF POWER
MegaWatt
Hours MegaWatt MegaWatt Total(k
Line Purchased Hours Hours Demand Charges($) Energy Charges($) Other Charges($) Settlement
No. for Energy Received Delivered (k) (1) (m)
Storage (i) (j) (n)
(h)
91 8,560 8,560
92 5,538,203 5,538,203
93 30,466,404 30,466,404
94 10,349,387 10,349,387
95 14,140 14,140
96 320,662 320,662
97 914 914
98 226,497 226,497
99 474,188 474,188
100 183,375 183,375
101 613,916 613,916
102 313,557 313,557
103 374,845 374,845
104 430 430
105 91,319 91,319
106 1,276,188 1,276,188
107 1,573,266 1,573,266
108 29,735 29,735
109 1,578,790 1,578,790
110 2,781,158 2,781,158
111 1,173,595 1,173,595
112 1,852 0
E113 25,255,222 25,255,222
15 0 11,825 421,689 53,160,136 130,295,285 32,972,294 216,427,715
FERC FORM NO.1 (ED.12-90)
Page 326-327

This report is:
Name of Respondent: (1)21 An Original Date of Report: Year/Period of Report
Avista Corporation (2) ❑ A Resubmission 04/12/2024 End of:2023/Q4
FOOTNOTE DATA
(a)Concept:NameOfCompanyOrPublicAuthorityProvi ding Purchased Power
Energy Imbalance Charges.
Concept:NameOfCompanyOrPubIIcAuthorityProvi ding Purchased Power
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement.
(c)Concept:NameOfCompanyOrPublicAuthodtyProvidingPurchasedPower
06/26/2023-12/31/2024 ETSR is an import resource associated with an EIM intertie with another EIM BAA,or a CISO intertie with the CISO.
Concept:NameOfCompanyOrPublicAuthorityProviding Purchased Power
Energy Imbalance Charges.
(e)Concept:NameOfCompanyOrPublicAuthorityProvidingPurchasedPower
BPA Self Supply for N ITSA customers.
f�f Concept:NameOfCompanyOrPublicAuthodtyProvidingPurchasedPower
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement.
Lq)Concept:NameOfCompanyOrPublicAuthorityProvidingPurchasedPower
Ancillary Services-Spinning&Supplemental Reserves.
Concept:NameOfCompanyOrPublicAuthodtyProvidingPurchasedPower
Financially Settled Transmission Losses.
Concept:NameOfCompanyOrPublicAuthorityProvidingPurchasedPower
Financial Inaccuracy Penalty.
_W Concept:NameOfCompanyOrPublicAuthorityProvidingPurchasedPower
Oversupply Charges.
Concept:NameOfCompanyOrPublicAuthodtyProvidingPurchasedPower
03/02/2022-12/31/2024 ETSR is an import resource associated with an EIM intertie with another EIM BAA,or a CISO intertie with the CISO.
Concept:NameOfCompanyOrPublicAuthodtyProvidingPurchasedPower
Canadian Entitlement
(m)Concept:NameOfCompanyOrPublIcAuthorityProvidIng Purchased Power
Reserve Sharing underthe NorthWest Power Pool Reserve Sharing Agreement.
(n)Concept:NameOfCompanyOrPublicAuthorityProvidingPurchasedPower
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement.
(o)Concept:NameOfCompanyOrPublicAuthodtyProvidingPurchasedPower
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement.
(p)Concept:NameOfCompanyOrPublicAuthorityProvidingPurchasedPower
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement.
LM Concept:NameOfCompanyOrPublicAuthodtyProvidingPurchasedPower
Energy Imbalance Charges.
(r)Concept:NameOfCompanyOrPublicAuthodtyProvidingPurchasedPower
Financially Settled Transmission Losses.
(s)Concept:NameOfCompanyOrPublicAuthodtyProvidingPurchasedPower
03/02/2022-12/31/2024 ETSR is an import resource associated with an EIM intertie with another EIM BAA,or a CISO intertie with the CISO.
Concept:NameOfCompanyOrPublicAuthodtyProvidingPurchasedPower
03/02/2022-12/31/2024 ETSR is an import resource associated with an EIM intertie with another EIM BAA,or a CISO interne with the CISO.
U Concept:NameOfCompanyOrPublicAuthorityProvidingPurchasedPower
Service to Deer Lake from Inland Power and Light.No demand charges associated with the agreement.

M Concept:NameOfCompanyOrPublicAuthodtyProvidingPurchasedPower
Financial SWAP.
(w)Concept:NameOfCompanyOrPubl icAuthorityProvidi ngPurchased Power
Financially Settled Transmission Losses.
(x)Concept:NameOfCompanyOrPublicAuthodtyProvidingPurchasedPower
Reserve Sharing underthe NorthWest Power Pool Reserve Sharing Agreement.
W Concept:NameOfCompanyOrPublicAuthodtyProvidingPurchasedPower
Financially Settled Transmission Losses.
(z)Concept:NameOfCompanyOrPublicAuthorityProvidingPurchasedPower
01/26/2022-12/31/2024 ETSR is an import resource associated with an EIM intertie with another EIM BAA,or a CISO intertie with the CISO.
as Concept:NameOfCompanyOrPubl icAuthorityProvid ing Purchased Power
Energy Imbalance Charges.
(ab)Concept:NameOfCompanyOrPublicAuthodtyProvidingPurchasedPower
01/27/2022-12/31/2024 ETSR is an import resource associated with an EIM intertie with another EIM BAA,or a CISO intertie with the CISO.
ac Concept:NameOfCompanyOrPublicAuthodtyProvidingPurchasedPower
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement.
fated Concept:NameOfCompanyOrPublicAuthorityProviding Purchased Power
(Financially Settled Transmission Losses.
ae Concept:NameOfCompanyOrPublicAuthodtyProvidingPurchasedPower
Energy Imbalance Charges.
of Concept:NameOfCompanyOrPubl icAuthorityProvidi ngPurchased Power
Pend Oreille County PUD contract expires September 30,2026.
Laag)Concept:NameOfCompanyOrPublicAuthodtyProvidingPurchasedPower
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement.
ah Concept:NameOfCompanyOrPublicAuthorityProvid1ngPurchasedPower
Financially settled Transmission Losses.
ai Concept:NameOfCompanyOrPublicAuthorityProvidingPurchasedPower
(Energy Imbalance Charges.
(aj)Concept:NameOfCompanyOrPublicAuthodtyProvidingPurchasedPower
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement.
ak Concept:NameOfCompanyOrPublicAuthodtyProvidingPurchasedPower
Financially Settled Transmission Losses.
(al)Concept:N ameOfCompanyOrPubl icAuthorityProvidi ngPurchased Power
Energy Imbalance Charges.
Lam)Concept:NameOfCompanyOrPublicAuthodtyProvidingPurchasedPower
Pondage.
an Concept:NameOfCompanyOrPublicAuthodtyProvidingPurchasedPower
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement
ao Concept:NameOfCompanyOrPublicAuthodtyProvidingPurchasedPower
Sovereign contract terminates September 30,2026.
(ap)Concept:NameOfCompanyOrPublicAuthodtyProvidingPurchasedPower
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement
(ag)Concept:NameOfCompanyOrPublicAuthodtyProvidingPurchasedPower
Financial SWAP.
ar Concept:NameOfCompanyOrPublicAuthodtyProvidingPurchasedPower
Ancillary Services.
as Concept:NameOfCompanyOrPubl icAuthorityProvidi ng Purchased Power

Energy Imbalance Market Purchases.
FERC FORM NO.1 (ED.12-90)
Page 326-327

This report is:
Name of Respondent: (1)0 An Original Date of Report: Year/Period of Report
Avista Corporation 04/12/2024 End of:2023/Q4
(2) ❑A Resubmission
TRANSMISSION OF ELECTRICITY FOR OTHERS(Account 456.1)(Including transactions referred to as"wheeling")
Energy Received Fro nergy Delivered o Ferc Rate Point of Point of
Payment By(Company (Company of Public (Company of Public Statistical Schedule Receipt Delivery
Line of Public Authority) (Substation (Substation
Authority)(Footnote Authority)(Footnote Classification of Tariff
No. (Footnote Affiliation) or Other or Other
Affiliation) Affiliation) (d) Number
(a) (b) (c) (e) Designation)Designation)
(f) (g)
Bonneville Power Bonneville Power Bonneville Power FNO FERC Trf AVA.BPAT AVA.SYS
1 Administration Administration Administration No 8
2 Bonneville Power Bonneville Power Bonneville Power OS IRS No.
Administration Administration Administration T1110
3 Bonneville Power Bonneville Power Idaho Power Company NF FERC Trf
Administration Administration No.8
4 Brookfield Renewable NorthWestem Montana Puget Sound Energy NF FERC Trf
Trading and Marketing No.8
5 City of Spokane City of Spokane Avista Corporation OLF PURPA
6 Consolidated Irrigation Bonneville Power Consolidated Irrigation LFP FERC Trf AVA.BPAT AVA.SYS
Administration No.8
Shell Energy North Bonneville Power FERC Trf
7 America Administration NorthWestem Montana NF No.8
8 Shell Energy North NorthWestem Montana Bonneville Power NF FERC Trf
America Administration No.8
9 Shell Energy North NorthWestem Montana Grant County PUD NF FERC Trf
America No.8
10 Shell Energy North Idaho Power Company Bonneville Power NF FERC Trf
America Administration No.8
11 Shell Energy North Idaho Power Company NorthWestem Montana NF FERC Trf
America No.8
12 I Shell Energy North Idaho Power Company Grant County PUD NF FERC Trf
America No.8
13 Shell Energy North Idaho Power Company PacifiCorp NF FERC Trf
America No.8
14 Deep Creek Hydro Deep Creek Hydro Avista Corporation OLF PURPA
Bonneville Power FERC Trf
15 Dynasty Power Administration Idaho Power Company NF No.8
16 Dynasty Power Bonneville Power NorthWestem Montana NF FERC Trf
Administration No.8
17 Dynasty Power Bonneville Power PacifiCorp NF FERC Trf
Administration No.8
18 Dynasty Power NorthWestem Bonneville Power Montana Administration NF FERC Trf
No.8
19 Dynasty Power Idaho Power Company Bonneville Power Administration NF FERC Trf
No.8
20 Dynasty Power Idaho Power Company PacifiCorp SFP FERC Trf
No.8
FERC FORM NO.1 (ED.12-90)
Page 328330

TRANSMISSION OF ELECTRICITY FOR OTHERS(Account 456.1)(Including transactions referred to as"wheeling")
Energy Received From Energy Delivered To Ferc Rate Point of Point of
Payment By(Company (Company of Public (Company of Public Statistical Schedule Receipt Delivery
Line of Public Authority) Authority)(Footnote Authority) (Substation (Substation
No. (Footnote Affiliation) Affiliation)
( oono ty)(Footnote Classification of Tariff or Other or Other
Affiliation) Affiliation) (d) Number
(a) (b) (c) (e) Designation)Designation)
(f) (g)
EDR Trading North Bonneville Power FERC Trf
21 America Administration NorthWestem Montana NF No.8
EDR Trading North Bonneville Power FERC Trf
22 America Administration NorthWestem Montana SFP No.8
EDR Trading North Bonneville Power FERC Trf
23 America NorthWestem Montana Administration NF No.8
24 EDR Trading North NorthWestem Montana Bonneville Power SFP FERC Trf
America Administration No.8
25 EDR Trading North NorthWestem Montana PacifiCorp NF FERC Trf
America No.8
26 EDR Trading North Puget Sound Energy NorthWestem Montana SFP FERC Trf
America No.8
EPCOR Energy Bonneville Power NF FERC Trf
27 Marketing NorthWestem Montana Administration No.8 J.
28 EPCOR Energy NorthWestem Montana NorthWestem Montana NF FERC Trf
Marketing No.8
29 EPCOR Energy Idaho Power Company Bonneville Power SFP FERC Trf
Marketing Administration No.8
30 Energy Keepers Bonneville Power NorthWestem Montana NF FERC Trf
Administration No.8
31 Energy Keepers Bonneville Power NorthWestem Montana SFP FERC Trf
Administration No.8
32 Energy Keepers NorthWestem Montana Bonneville Power NF FERC TrF
Administration No.8
33 Energy Keepers NorthWestem Montana Bonneville Power SFP FERC Trf
Administration No.8
34 Energy Keepers NorthWestem Montana Idaho Power Company NF FERC Trf
No.8
35 Energy Keepers NorthWestem Montana PacifiCorp NF FERC Trf
No.8
36 Energy Keepers Idaho Power Company Bonneville Power NF FERC Trf
Administration No.8
37 Energy Keepers Idaho Power Company NorthWestem Montana NF FERC Trf
No.8
38 Energy Keepers Idaho Power Company NorthWestem Montana SFP FERC Trf
No.8
39 Energy Keepers Idaho Power Company Avista Corporation NF FERC Trf
No.8
40 Energy Keepers Idaho Power Company Avista Corporation SFP FERC Trf
No.8
41 Exelon NorthWestem Montana Bonneville Power NF FERC Trf
Administration No.8
FERC FORM NO.1 (ED.12-90)
Page 328-330

TRANSMISSION OF ELECTRICITY FOR OTHERS(Account 456.1)(Including transactions referred to as"wheeling")
Energy Received From Energy Delivered To Ferc Rate Point of Point of
Payment By(Company (Company of Public (Company of Public Statistical Schedule Receipt Delivery
Line of Public Authority) Authority)(Footnote Authority)(Footnote Classification of Tariff (Substation (Substation
No. (Footnote Affiliation) or Other or Other
Affiliation) Affiliation) (d) Number
(a) (b) (c) (e) Designation)Designation)
(f) (g)
42 Exelon NorthWestem Montana Bonneville Power SFP FERC Trf
Administration No.8
l 43 Grant County PUD Grant County PUD Grant County PUD OLF 104 RS No. Stratford Coulee
CityMilson
44 Guzman Energy Bonneville Power Idaho Power Company SFP FERC Trf
Administration No.8
45 Guzman Energy Bonneville Power NorthWestem Montana NF FERC Trf
Administration No.8
46 Guzman Energy Bonneville Power NorthWestem Montana SFP FERC Trf
Administration No.8
Bonneville Power FERC Trf
47 Guzman Energy Administration Avista Corporation SFP No 8
i
48 Guzman Energy NorthWestem Montana Bonneville Power NF FERC Trf
Administration No.8
49 Guzman Energy NorthWestem Montana Bonneville Power SFP FERC Trf
Administration No.8
50 Guzman Energy Idaho Power Company Bonneville Power NF FERC Trf
I Administration No.8
51 Guzman Energy Idaho Power Company Bonneville Power SFP FERC Trf
Administration No.8
52 Guzman Energy Idaho Power Company NorthWestem Montana NF FERC Trf
No.8
53 Guzman Energy Idaho Power Company NorthWestem Montana SFP FERC Trf
No.8
54 Guzman Energy Idaho Power Company Avista Corporation SFP FERC Trf
No.8
55 Hydro Tech Industries Meyers Falls Avista Corporation OLF PURPA
56 Idaho Power Company Bonneville Power Idaho Power Company LFP FERC Trf MIDC LOLO
Administration No.8
I
57 I Idaho Power Company Bonneville Power Idaho Power Company LFP FERC Trf AVA.BPAT LOLO
Administration No.8
58 Idaho Power Company Bonneville Power Idaho Power Company NF FERC Trf
Administration No.8
59 Idaho Power Company Bonneville Power Idaho Power Company SFP FERC Trf
Administration No.8
60 Idaho Power Company Bonneville Power NorthWestem Montana SFP FERC Trf
Administration No.8
61 Idaho Power Company Grant County PUD Idaho Power Company SFP FERC Trf
No.8
62 Idaho Power Company Idaho Power Company NorthWestem Montana NF FERC Trf
No.8
FERC FORM NO.1 (ED.12-90)
Page 328-330

TRANSMISSION OF ELECTRICITY FOR OTHERS(Account 456.1)(Including transactions referred to as"wheeling")
Energy Received From Energy Delivered To Ferc Rate Point of Point of
Payment By(Company (Company of Public (Company of Public Statistical Schedule Receipt Delivery
Line of Public Authority) Authority)(Footnote Authority)(Footnote Classification of Tariff (Substation (Substation
No. (Footnote Affiliation) or Other or Other
Affiliation) Affiliation) (d) Number
(a) (b) (c) (e) Designation)Designation)
(f) (g)
63 Idaho Power Company Bonneville Power Idaho Power Company LFP FERC Trf
Administration No.8
64 Idaho Power Company Idaho Power Company Bonneville Power NF FERC Trf
Administration No.8
65 Kootenai Electric Avista Corporation Idaho Power Company LFP FERC Trf AVA.SYS LOLO
No.8
66 MAG Energy Administration No.8
Solutions Idaho Power Company Bonneville Power NF FERC Trf
67 Macquarie Energy Bonneville Power NorthWestem Montana NF FERC Trf
Administration No.8
68 Macquarie Energy Bonneville Power NorthWestem Montana SFP FERC Trf
Administration No.8
69 Macquarie Energy Bonneville Power Avista Corporation NF FERC Trf
Administration No.8
70 Macquarie Energy NorthWestem Montana Bonneville Power NF FERC Trf
Administration No.8
71 Macquarie Energy NorthWestern Montana Bonneville Power SFP FERC Trf
Administration No.8
72 Macquarie Energy NorthWestem Montana Idaho Power Company SFP FERC Trf
No.8
73 Macquarie Energy Idaho Power Company Bonneville Power NF FERC Trf
Administration No.8
74 Macquarie Energy Idaho Power Company Bonneville Power SFP FERC Trf
Administration No.8
75 Macquarie Energy Idaho Power Company NorthWestem Montana NF FERC Trf
No.8
76 Macquarie Energy Idaho Power Company NorthWestern Montana SFP FERC Trf
No.8
77 Macquarie Energy Idaho Power Company Avista Corporation SFP FERC Trf
No.8
78 Mercuria Energy Bonneville Power NorthWestem Montana NF FERC Trf
America Administration No.8
79 Morgan Stanley Capital Bonneville Power Idaho Power Company NF FERC Trf
Group Administration No.8
80 Morgan Stanley Capital Bonneville Power Idaho Power Company SFP FERC Trf
Group Administration No.8
81 Morgan Stanley Capital Bonneville Power NorthWestem Montana NF l FERC Trf
Group Administration No.8
82 Morgan Stanley Capital NorthWestem Montana Bonneville Power NF FERC Trf
Group Administration No.8
83 Morgan Stanley Capital NorthWestem Montana Bonneville Power SFP FERC Trf
Group Administration No.8
FERC FORM NO.1 (ED.12-90)
Page 32&330

TRANSMISSION OF ELECTRICITY FOR OTHERS(Account456.1)(Including transactions referred to as"wheeling")
Energy Received From Energy Delivered To Ferc Rate Point of Point of
Payment By(Company Receipt Delivery
(Company of Public (Company of Public Statistical Schedule
Line of Public Authority) (Substation (Substation
Authority)(Footnote Authority)(Footnote Classification of Tariff
No. (Footnote Affiliation) Affiliation) Affiliation) (d) Number or Other or Other
(a) (b) (c) (e) Designation)Designation)
M (g)
84 Morgan Stanley Capital NorthWestem Montana Idaho Power Company NF FERC Trf
Group No.8
85 Morgan Stanley Capital NorthWestem Montana Idaho Power Company SFP FERC Trf
Group No.8
86 Morgan Stanley Capital NorthWestem Montana Grant County PUD NF FERC Trf
Group No.8
87 Morgan Stanley Capital NorthWestem Montana Grant County PUD SFP FERC Trf
(� Group No.8
88 Morgan Stanley Capital Grant County PUD Idaho Power Company NF FERC Trf
Group No.8
89 Morgan Stanley Capital Grant County PUD Idaho Power Company SFP FERC Trf
Group No.8
90 Morgan Stanley Capital Grant County PUD NorthWestem Montana NF FERC Trf
Group No.8
91 Morgan Stanley Capital Grant County PUD NorthWestem Montana SFP FER NoC8 Trf
92 Morgan Stanley Capital Idaho Power Company Bonneville Power NF FERC Trf
Group Administration No.8
93 Morgan Stanley Capital Idaho Power Company Bonneville Power SFP FERC Trf
Group Administration No.8
94 Morgan Stanley Capital Idaho Power Company NorthWestem Montana NF FERC Trf
Group No.8
95 Morgan Stanley Capital Idaho Power Company NorthWestem Montana SFP FERC Trf
Group No.8
96 Morgan Stanley Capital Idaho Power Company Grant County PUD NF FERC Trf
Group No.8
97 Morgan Stanley Capital Idaho Power Company Grant County PUD SFP FERC Trf
Group No.8
98 NorthWestem Energy Bonneville Power NorthWestem Montana NF FERC Trf
Administration No.8
99 NorthWestem Energy NorthWestem Montana Bonneville Power NF FERC Trf
Administration No.8
100 NorthWestem Energy Idaho Power Company NorthWestem Montana NF FERC Trf
No.8
101 NorthWestern Energy Avista Corporation NorthWestem Montana NF FERC Trf
No.8
102 Phillips 66 Energy Bonneville Power Idaho Power Company SFP FERC Trf
Trading Administration No.8
103 Phillips 66 Energy Bonneville Power NorthWestem Montana LFP FERC Trf
Trading Administration No.8
104 Phillips 66 Energy Bonneville Power NorthWestem Montana SFP FERC Trf
Trading Administration No.8
FERC FORM NO.1 (ED.12-90)
Page 328-330

TRANSMISSION OF ELECTRICITY FOR OTHERS(Account 456.1)(Including transactions referred to as"wheeling")
Energy Received From Energy Delivered To Ferc Rate Point of Point of
Payment By(Company (Company of Public (Company of Public Statistical Schedule Receipt Delivery
Line of Public Authority) Authority)(Footnote Authority)(Footnote Classification of Tariff (Substation (Substation
No. (Footnote Affiliation) or Other or Other
Affiliation) Affiliation) (d) Number
(a) (b) (c) (e) Designation)Designation)
M (g)
105 Phillips 66 Energy NorthWestem Montana PacifiCorp NF FERC Trf
Trading No.8
106 Phillips 66 Energy NorthWestem Montana PacifiCorp SFP FERC Trf
Trading No.8
107 Phillips 66 Energy Idaho Power Company Bonneville Power LFP FERC Trf
Trading Administration No.8
Phillips 66 Energy Bonneville Power SFP FERC Trf
108 Trading Idaho Power Company Administration No.8
109 Phillips 66 Energy Idaho Power Company NorthWestem Montana LFP FERC Trf
Trading No.8
110 Phillips 66 Energy Idaho Power Company NorthWestem Montana NF FERC Trf
Trading No.8
111 Phillips 66 Energy Idaho Power Company NorthWestem Montana SFP FERC Trf
Trading No.8
112 Phillips 66 Energy Idaho Power Company Grant County PUD NF FERC Trf
Trading No.8
113 Phillips 66 Energy Idaho Power Company PacifiCorp LFP FERC Trf
Trading No.8
i
114 Phillips 66 Energy Idaho Power Company PacifiCorp NF FERC Trf
Trading No.8
115 Phillips 66 Energy Idaho Power Company PacifiCorp SFP FERC Trf
Trading No.8
116 PacifiCorp Bonneville Power PacifiCorp NF FERC Trf
Administration No.8
117 PacifiCorp PacifiCorp Bonneville Power NF FERC Trf
Administration No.8
118 PacifiCorp PacifiCorp PacifiCorp OLF RS82o' Dry Gulch Dry Gulch
119 PacifiCorp Idaho Power Company Bonneville Power SFP FERC Trf
Administration No.8
120 PacifiCorp Idaho Power Company PacifiCorp NF FERC Trf
N o.8
121 PacifiCorp Idaho Power Company PacifiCorp SFP FERC Trf
No.8
Portland General Bonneville Power FERC Trf
122 Electric Administration Idaho Power Company NF No.8
Portland General Bonneville Power FERC Trf
123 Electric Administration NorthWestem Montana SFP No.8
Portland General Bonneville Power NF FERC Trf
124 Electric NorthWestem Montana Administration No.8
Portland General Portland General FERC Trf
125 NF Electric NorthWestem Montana Electric No.8
FERC FORM NO.1(ED.12-90)
Page 328-330

TRANSMISSION OF ELECTRICITY FOR OTHERS(Account 456.1)(Including transactions referred to as"wheeling")
Energy Received From Energy Delivered To Ferc Rate Point of Point of
Payment By(Company (Company of Public (Company of Public Statistical Schedule Receipt Delivery
Line of Public Authority) Authority)(Footnote Authority)(Footnote Classification of Tariff (Substation (Substation
No. (Footnote Affiliation) or Other or Other
Affiliation) Affiliation) (d) Number
(a) (b) (c) (e) Designation)Designation)
_ M (g)
126 Portland General Idaho Power Company Bonneville Power NF FERC Trf
Electric Administration No.8
127 Avangrid Renewables Bonneville Power Idaho Power Company NF FERC Trf
Administration No.8
I
128 Avangrid Renewables Bonneville Power NorthWestem Montana NF FERC Trf
Administration No.8
129 Avangrid Renewables NorthWestem Montana Bonneville Power NF FERC Trf
Administration No.8
130 Avangrid Renewables Idaho Power Company Bonneville Power NF FERC Trf
Administration No.8
131 Puget Sound Energy NorthWestem Montana Bonneville Power NF FERC Trf
Administration No.8
132 Puget Sound Energy NorthWestern Montana Bonneville Power SFP FERC TrF
Administration No.8
133 Puget Sound Energy NorthWestem Montana Puget Sound Energy NF FERC Trf
No.8
134 Puget Sound Energy NorthWestem Montana Puget Sound Energy SFP FERC Trf
No.8
135 Puget Sound Energy Idaho Power Company Bonneville Power Administration NF FERC Trf
No.8
136 Powerex Bonneville Power Idaho Power Company LFP FERC Trf AVA.BPAT LOLO
Administration No.8
137 Powerex Bonneville Power Idaho Power Company NF FERC TrF
Administration No.8
138 Powerex Bonneville Power Idaho Power Company SFP FERC Trf
Administration No.8
139 Powerex Bonneville Power NorthWestem Montana LFP FERC Trf
Administration No.8
140 Powerex Bonneville Power NorthWestem Montana NF FERC Trf
Administration No.8
Bonneville Power FERC Trf
141 Powerex Administration NorthWestem Montana SFP No.8
142 Powerex Bonneville Power PacifiCorp NF FERC Trf
Administration No.8
143 Powerex Bonneville Power PacifiCorp SFP FERC Trf
Administration No.8
144 Powerex NorthWestem Montana Bonneville Power LFP FERC Trf
Administration No.8
145 Powerex NorthWestem Montana Bonneville Power NF FERC Trf
Administration No.8
146 Powerex NorthWestem Montana Bonneville Power SFP FERC Trf
Administration No.8
FERC FORM NO.1 (ED.12-90)
Page 328-330

TRANSMISSION OF ELECTRICITY FOR OTHERS(Account 456.1)(Including transactions referred to as"wheeling")
Energy Received From Energy Delivered To Ferc Rate Point of Point of
Payment By(Company (Company of Public (Company of Public Statistical Schedule Receipt Delivery
Line of Public Authority) Authority)(Footnote Authority)(Footnote Classification of Tariff (Substation (Substation
No. (Footnote Affiliation) or Other or Other
Affiliation) Affiliation) (d) Number
(a) (b) (c) (e) Designation)Designation)
(f) (g)
147 Powerex Idaho Power Company Bonneville Power LFP FERC Trf
Administration No.8
Bonneville Power FERC Trf
148 Powerex Idaho Power Company Administration NF No.8
149 Powerex Idaho Power Company Bonneville Power Administration SFP FERC Trf
No.8
150 Powerex Idaho Power Company NorthWestem Montana LFP FERC Trf
No.8
151 Rainbow Energy Bonneville Power Idaho Power Company NF FERC Trf
Marketing Corporation Administration No.8
152 Rainbow Energy Bonneville Power NorthWestem Montana NF FERC Trf
Marketing Corporation Administration No.8
Rainbow Energy Bonneville Power FERC Trf
153 LFP Marketing Corporation NorthWestem Montana Administration No.8
Rainbow Energy Bonneville Power FERC Trf
154 NF Marketing Corporation NorthWestem Montana Administration No.8
Rainbow Energy Bonneville Power FERC Trf
155 Marketing Corporation NorthWestem Montana SFP Administration No.8
Rainbow Energy FERC Trf
156 Marketing Corporation NorthWestem Montana Chelan County PUD SFP No.8
157 Rainbow Energy NorthWestem Montana Grant County PUD SFP FERC Trf
Marketing Corporation No.8
I,
158 Rainbow Energy NorthWestem Montana PacifiCorp SFP FERC Trf
Marketing Corporation No.8
Rainbow Energy Portland General FERC Trf
159 Marketing Corporation NorthWestem Montana SFP Electric No.8
Rainbow Energy Bonneville Power FERC Trf
160 Marketing Corporation Idaho Power Company Administration NF No.8
Rainbow Energy Bonneville Power FERC Trf
161 SFP Marketing Corporation Idaho Power Company Administration No.8
Rainbow Energy FERC Trf
162 Marketing Corporation Idaho Power Company PacifiCorp SFP No.8
163 Seattle City Light Seattle City Light Grant County PUD OLF FERC Trf Chelan- Stratford
No.8 Stratford
164 Seattle City Light NorthWestem Bonneville Power Montana Administration NF FERC Trf
No.8
Bonneville Power FERC Trf
165 Spokane Tribe Administration Spokane Tribe LFP No 8 AVA.BPAT AVA.SYS
166 Stimson Plummer Avista Corporation OLF PURPA
167 The Energy Authority Bonneville Power Idaho Power Company NF FERC Trf
Administration No.8
FERC FORM NO.1 (ED.12-90)
Page 328-330

TRANSMISSION OF ELECTRICITY FOR OTHERS(Account456.1)(Including transactions referred to as"wheeling")
Energy Received From Energy Delivered To Ferc Rate Point of Point of
Payment By(Company (Company of Public (Company of Public Statistical Schedule Receipt Delivery
Line of Public Authority) Authority)(Footnote Authority)(Footnote Classification of Tariff (Substation (Substation
No. (Footnote Affiliation) or Other or Other
Affiliation) Affiliation) (d) Number
(a) (b) (c) (e) Designation)Designation)
(� (g)
168 The Energy Authority Bonneville Power Idaho Power Company SFP FERC Trf
Administration No.8
169 The Energy Authority Bonneville Power I NorthWestem Montana NF FERC Trf
Administration No.8
170 The Energy Authority Bonneville Power Avista Corporation NF FERC Trf
Administration No.8
171 The Energy Authority NorthWestem Bonneville Power Montana Administration NF FERC Trf
No.8
172 The Energy Authority NorthWestem Montana PacifiCorp NF FERC Trf
No.8
173 The Energy Authority Idaho Power Company Bonneville Power NF FERC Trf
Administration No.8
174 The Energy Authority Idaho Power Company Bonneville Power Administration SFP FERC Trf
No.8
TransAlta Energy Bonneville Power FERC Trf
175 Marketing Administration Idaho Power Company NF No 8
176 TransAlta Energy Bonneville Power NorthWestem Montana NF FERC Trf
Marketing Administration I No.8
TransAlta Energy Bonneville Power NF FERC Trf
177 Marketing NorthWestem Montana Administration No.8
178 TransAlta Energy NorthWestem Montana Idaho Power Company NF FERC Trf
Marketing No.8
179 TransAlta Energy Puget Sound Energy NorthWestem Montana NF FERC Trf
Marketing No.8
TransAlta Energy Bonneville Power NF FERC Trf
180 Marketing Idaho Power Company Administration No.8
181 TransAlta Energy Idaho Power Company NorthWestem Montana NF FERC Trf
Marketing No.8
TransAlta Energy FERC Trf
182 Marketing Idaho Power Company Avista Corporation NF No.8
183 Services e Power NorthWestem Montana Idaho Power Company NF FERC Trf
S No.8
184 Tacoma Power Tacoma Power Grant County PUD OLF FERC Trf Chelan- Stratford
No.8 Stratford
185 East Greenacres Bonneville Power East Greenacres LFP FERC Trf AVA.BPAT AVA.SYS
Administration No.8
35 TOTAL —
FERC FORM NO.1 (ED.12-90)
Page 328330

TRANSMISSION OF ELECTRICITY FOR OTHERS(Account 456.1)(Including transactions referred to as"wheeling")
REVENUE
REVENUE FROM REVENUE FROM REVENUE FROM FROM
TRANSFER OF TRANSFER OF TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION
ENERGY ENERGY OF ELECTRICITY OF ELECTRICITY OF ELECTRICITY OF
FOR OTHERS FOR OTHERS FOR OTHERS ELECTRICITY
FOR OTHERS
Line
Billing Demand Megawatt Hours Megawatt Hours Demand Charges Energy Charges Other Charges($) Total Revenues
No. (MW) Received Delivered ($) ($) ($)(k+l+m)
(h) W G) (k) (I) ("') (n)
1 2,204,529 2,204,529 9,755,950 1,127,795 10,883,745
2 924,000 924,000
3 11,460 11,460 99,165 99,165
4 119 119
5 L1227,973 27,973
6 4 6,924 6,924 32,980 L5110,021 43,001
7 33 33 325 325
8 350 350 2,977 2,977
9 401 401 4,011 4,011
10 1,526 1,526 17,647 17,647
11 263 263 3,017 3,017
12 604 604 6,217 6,217
13 424 424 4,972 4,972
14 22603 603
15 200 200 1,903 1,903
16 994 994 10,275 10,275
17 110 110 1,660 1,660
18 50 50 397 397
19 489 489 5,067 5,067
20 3,334 3,334 29,037 29,037
21 1,513 1,513 12,029 12,029
22 624 624 3,297 3,297
23 6,924 6,924 57,287 57,287
24 960 960 5,072 5,072
25 80 80 666 666
26 504 504 2,663 2,663
27 60 60 476 476
28 3 3
29 400 400 3,170 3,170
30 1,444 1,444 11,803 11,803
FERC FORM NO.1(ED.12-90)
Page 328-330

TRANSMISSION OF ELECTRICITY FOR OTHERS(Account 456.1)(Including transactions referred to as"wheeling")
REVENUE
REVENUEFROM REVENUEFROM REVENUEFROM FROM
TRANSFER OF TRANSFER OF TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION
ENERGY ENERGY OF ELECTRICITY OF ELECTRICITY OF ELECTRICITY OF
FOR OTHERS FOR OTHERS FOR OTHERS ELECTRICITY
FOR OTHERS
Line
Billing Demand Megawatt Hours Megawatt Hours Demand Charges Energy Charges Other Charges Total Revenues
(5)
No. (MW) Received Delivered (s) (5) (m) ($)(k+l+m)
(h) W U) (k) (1) (n)
31 400 400 3,170 3,170
32 2,446 2,446 20,745 20,745
33 21,334 21,334 127,554 127,554
34 302 302 2,404 2,404
35 400 400 3,208 3,208
36 122 122 1,209 1,209
37 475 475 4,708 4,708
38 545 545 2,988 2,988
F39 275 275 2,726 2,726
40 4,775 4,775 25,808 25,808
41 1,200 1,200 9,516 9,516
42 1,200 1,200 6,340 6,340
43 92,191 92,191 26,793 26,793
44 32 32 375 375
45 1,525 1,525 14,643 14,643
46 9,595 9,595 112,188 112,188
47 25 25 293 293
48 2,132 2,132 52,357 52,357
49 132,579 132,579 669,304 669,304
50 10,712 10,712 96,453 96,453
51 60,571 60,571 322,295 322,295
52 100 100 949 949
53 359 359 2,415 2,415
54 319 319 1,438 1,438
55 005,772 5,772
56 100 232,681 232,681 3,298,000 3,298,000
57 100 93,599 93,599 3,294,400 3,294,400
58 528 528 4,187 4,187
59 4,600 4,600 17,735 17,735
60 2,400 2,400 104,383 104,383
FERC FORM NO.1 (ED.12-90)
Page 328-330

TRANSMISSION OF ELECTRICITY FOR OTHERS(Account 456.1)(Including transactions referred to as"wheeling")
REVENUE
REVENUE FROM REVENUE FROM REVENUE FROM FROM
TRANSFER OF TRANSFER OF TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION
ENERGY ENERGY OF ELECTRICITY OF ELECTRICITY OF ELECTRICITY OF
FOR OTHERS FOR OTHERS FOR OTHERS ELECTRICITY
FOR OTHERS
Line
Billing Demand Megawatt Hours Megawatt Hours Demand Charges Energy Charges Other Charges(S) Total Revenues
No. (MW) Received Delivered (S) N (m) (�)(k+l+m)
(h) (i) U) (k) (I) (n)
61 400 400 1,542 1,542
62 111 111 1,118 1,118
63 3,0000 3,000 (40,200) (40,200)
64 75 75 595 595
65 3 16,269 16,269 98,940 -U22,549 121,489
66 8 - 8
67 564 564 4,869 4,869
68 676 676 6,555 6,555
69 6 6 60 60
70 4,069 4,069 57,131 57,131
71 36,588 36,588 338,379 338,379
72 766 766 6,864 6,864
73 697 697 9,516 9,516
74 3,559 3,559 82,594 82,594
75 342 342 5,337 5,337
76 1,128 1,128 17,815 17,815
77 272 272 7,238 7,238
78 8,319 8,319 66,641 66,641
79 814 814 8,996 8,996
80 1,000 1,000 6,343 6,343
81 9,086 9,086 82,770 82,770
82 35,240 35,240 355,397 355,397
83 34,513 34,513 246,302 246,302
84 3,748 3,748 37,681 37,681
85 8,484 8,484 61,848 61,848
86 8,514 8,514 86,169 86,169
87 23,538 23,538 161,303 161,303
88 1,456 1,456 14,456 14,456
89 6,516 6,516 53,581 53,581
FERC FORM NO.1 (ED.12-90)
Page 328-330

TRANSMISSION OF ELECTRICITY FOR OTHERS(Account 456.1)(Including transactions referred to as"wheeling")
REVENUE
REVENUE FROM REVENUE FROM REVENUE FROM FROM
TRANSFER OF TRANSFER OF TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION
ENERGY ENERGY OF ELECTRICITY OF ELECTRICITY OF ELECTRICITY OF
FOR OTHERS FOR OTHERS FOR OTHERS ELECTRICITY
FOR OTHERS
Billing Demand Megawatt Hours Megawatt Hours Demand Charges Energy Charges Other Charges(S) Total Revenues
Line (MW) Received Delivered ($) ($) (�)(k+I+m)
No. (h) (i) �) (k) (I) (m) (n)
90 7,817 7,817 74,310 74,310
91 1,372 1,372 10,252 10,252
92 3,820 3,820 41,351 41,351
93 24,884 24,884 111 146,097 146,097
94 1,987 1,987 19,688 19,688
95 2,830 2,830 17,619 17,619
96 1,861 1,861 17,377 17,377
97 1,206 1,206 8,511 8,511
98 1,332 1,332 10,964 10,964
99 110 110 3,251 3,251
100 34 34 270 270
101 198 198
102 1,200 1,200 6,714 6,714
103 6,556 6,556 4,997 4,997
104 2,200 2,200 12,310 12,310
105 400 400 3,281 3,281
106 2,302 2,302 10,586 10,586
107 6,556 6,556 1,904 1,904
108 1,000 1,000 3,600 3,600
109 7,996 7,996 16,051 16,051
110 749 749 6,021 6,021
111 15,610 15,610 86,106 86,106
112 250 250 1,983 1,983
113 6,556 6,556 13,649 13,649
114 400 400 3,172 3,172
115 87,738 87,738 460,330 460,330
116 5,137 5,137 64,591 64,591
117 20,221 20,221 270,481 270,481
118 40,399 40,399 193,137 193,137
119 6,340 6,340
FERC FORM NO.1 (ED.12-90)
Page 328330

TRANSMISSION OF ELECTRICITY FOR OTHERS(Account 456.1)(Including transactions referred to as"Wheeling")
REVENUE
REVENUE FROM REVENUE FROM REVENUE FROM FROM
TRANSFER OF TRANSFER OF TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION
ENERGY ENERGY OF ELECTRICITY OF ELECTRICITY OF ELECTRICITY OF
FOR OTHERS FOR OTHERS FOR OTHERS ELECTRICITY
FOR OTHERS
Line Billing Demand Megawatt Hours Megawatt Hours Demand Charges Energy Charges Other Charges Total Revenues
(MW) Received Delivered (g) (�) (5) O(k+I+m)
No. (h) (I) (k) (I) (m) (n)
120 67 67 593 593
121 34,985 34,985 212,010 212,010
122 18 18 206 206
123 13 13 49,326 49,326
124 17,978 17,978 167,468 167,468
125 448 448 4,899 4,899
126 3,396 3,396 35,653 35,653
127 101 101 1,225 1,225
128 30 30 238 238
129 5,261 5,261 44,424 44,424
130 100 100 821 821
131 2,368 2,368 25,408 25,408
132 2,883 2,883 15,688 15,688
133 6,711 6,711 61,141 61,141
134 109,868 109,868 625,413 625,413
135 1,820 1,820 16,081 16,081
136 137 423,850 423,850 3,533,603 3,533,603
137 1,281 1,281 11,830 11,830
138 64,007 64,007 78,992 78,992
139 60 60 910 910
140 4,881 4,881 41,528 41,528
141 722 722 29,153 29,153
142 68 68 624 624
143 3,736 3,736 52,910 52,910
144 38,209 38,209 414,480 414,480
145 1,787 1,787 15,734 15,734
146 1,008 1,008 18,589 18,589
147 41,672 41,672 553,986 553,986
148 5,991 5,991 51,478 51,478
149 5,213 5,213 141,132 141,132
FERC FORM NO.1 (ED.12-90)
Page 328-330

TRANSMISSION OF ELECTRICITY FOR OTHERS(Account456.1)(Including transactions referred to as"wheeling")
REVENUE
REVENUE FROM REVENUE FROM REVENUE FROM FROM
TRANSFER OF TRANSFER OF TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION
ENERGY ENERGY OF ELECTRICITY OF ELECTRICITY OF ELECTRICITY OF
FOR OTHERS FOR OTHERS FOR OTHERS ELECTRICITY
FOR OTHERS
Line
Billing Demand Megawatt Hours Megawatt Hours Other Charges(S)
Demand Charges Energy Charges Total Revenues
No. (MW) Received Delivered ($) ($) (m) ($)(k+l+m)
(h) W ll) (k) (l) (n)
150 1,008 1,008 15,282 T
15,282
151 108 108 1,091 1,091
152 282 282 2,508 2,508
153 267 267 3,600 3,600
154 1,441 1,441 12,506 12,506
155 267 267 2,417 2,417
156 200 200 1,280 1,280
157 125 125 800 800
158 400 400 2,559 2,559
159 266 266 1,702 1,702
160 3,788 3,788 35,385 35,385
161 5,497 5,497 45,214 45,214
162 1,560 1,560 14,121 14,121
163 122,807 122,807 203,814 -90,228 294,042
164 I 295 295 2,339 2,339
165 3 ! 3,038 3,038 24,735 -6,362 31,097
166 111 08,448 8,448
167 621 621 14,827 14,827
168 50 50 482 482
169 64 64 1,221 1,221
170 5 5 103 103
171 2,093 2,093 19,214 19,214
172 289 289 2,774 2,774
173 2,399 2,399 22,025 22,025
174 3,359 3,359 31,862 31,862
175 82 82 1,021 1,021
176 440 440 6,460 6,460
177 3,954 3,954 37,721 37,721
178 20 20 161 161
179 106 106 1,320 1,320
FERC FORM NO.1 (ED.12-90)
Page 328-330

TRANSMISSION OF ELECTRICITY FOR OTHERS(Account 456.1)(Including transactions referred to as"wheeling")
REVENUE
REVENUE FROM REVENUE FROM REVENUE FROM FROM
TRANSFER OF TRANSFER OF TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSION
ENERGY ENERGY OF ELECTRICITY OF ELECTRICITY OF ELECTRICITY OF
FOR OTHERS FOR OTHERS FOR OTHERS ELECTRICITY
FOR OTHERS
Line Billing Demand Megawatt Hours Megawatt Hours Demand Charges Energy Charges Total Revenues
MW) Received Delivered Other Charges(5)
No. ( (5) ($) ( )m (5)(k+l+m)
(h) (i) U) (k) (I) (n)
180 1,688 1,688 19,023 19,023
181 34 34 369 369
182 266 266 2,884 2,884
183 609 609 5,710 5,710
184 122,793 122,793 296,820 2190,228 387,048
185 3 3,705 3,705 14,841 u6,510 21,351
35 350 4,446,353 4,446,353 28,649,492 OT
2,320,489 30,969,981
FERC FORM NO.1 (ED.12-90)
Page 328-330

This report is:
Name of Respondent: (1)0 An Original Date of Report: Year/Period of Report
Avista Corporation 04/12/2024 End of:2023/Q4
(2) ❑ A Resubmission
FOOTNOTE DATA
U Concept:OtherChargesRevenueTransmissionOfElectricityForOthers
Ancillary services
U Concept:OtherChargesRevenueTransmissionOfElectricityForOthers
Parallel Capacity Support agreement
U Concept:OtherChargesRevenueTransmissionOfElectricityForOthers
Use of facilities
Ld)Concept:OtherChargesRevenueTransmissionOfElectricityForOthers
Ancillary services
Le)Concept:OtherChargesRevenueTransmissionOfElectricityForOthers
Use of facilities
Mf Concept:OtherChargesRevenueTransmissionOfElectricityForOthers
Use of facilities
kW Concept:OtherChargesRevenueTransmissionOfElectricityForOthers
Ancillary services
Concept:OtherChargesRevenueTransmissionOfElectricityForOthers
Use of facilities
0 Concept:OtherChargesRevenueTransmissionOfElectdcityForOthers
Ancillary services
Concept:OtherChargesRevenueTransmissionOfElectdcityForOthers
Use of facilities
Concept:OtherChargesRevenueTransmissionOfElectricityForOthers
Use of facilities
Concept:OtherChargesRevenueTransmissionOfElectricityForOthers
Ancillary services
FERC FORM NO.1(ED.12-90)
Page 328-330

This report is:
Name of Respondent: (1)0 An Original Date of Report: Year/Period of Report
Avista Corporation 04/12/2024 End of:2023/Q4
(2) ❑ A Resubmission
TRANSMISSION OF ELECTRICITY BY OTHERS(Account 565)
'TRANSFER OF ENERGY TRANSFER OF ENERGY
Line Name of Company or Public Authority(Footnote Statistical
Affiliations) Classification Megawatt Hours Received Megawatt Hours Delivered
No.
No. Ic) (d)
(a) (b)
1 Bonneville PowerAdmin LFP
2 Bonneville PowerAdmin LFP
3 Bonneville PowerAdmin OS
4 Bonneville PowerAdmin FNS
5 Bonneville PowerAdmin NF 79,027 79,027
6 Benton County PUD No 1 NF 100 100
7 Energy Keepers,Inc. NF 19,152 19,152
8 Grays Harbor County PUD No 1 NF 100 100
9 Idaho Power Company NF 3,002 3,002
10 Kootenai Electric Coop LFP
11 Nevada Power Company NF 50 50
12 Northern Lights,Inc LFP
13 NorthWestem Energy NF 33,498 33,498
14 NorthWestem Energy SFP
15 PacifiCorp NF 30 30
16 Portland General Elect NF 2,457 2,457
17 Portland General Elect LFP
18 Puget Sound Energy NF 10,657 10,657
19 Seattle City Light NF 11,713 11,713
20 Shell Energy North America NF 55 55
21 Snohomish County PUD NF 44,599 44,599
22 The Energy Authority NF 675 675
TOTAL 205,115 205,115
FERC FORM NO.1(REV.02-04)
Page 332

TRANSMISSION OF ELECTRICITY BY OTHERS(Account 565)
EXPENSES FOR EXPENSES FOR EXPENSES FOR EXPENSES FOR
TRANSMISSION OF TRANSMISSION OF TRANSMISSION OF TRANSMISSION OF
ELECTRICITY BY OTHERS ELECTRICITY BY OTHERS ELECTRICITY BY OTHERS ELECTRICITY BY OTHERS
Line Demand Charges(S) Energy Charges(S) Other Charges(S) Total Cost of Transmission(S)
No. (e) (f) (g) (h)
1 1,445,942 1,445.942
2 12,069,727 -2,311,100 14,380,827
3 -54,432 54,432
4 1,453,332 -297,670 1,751,002
5 440,023 440,023
6 125 125
7 82,896 82,896
8 125 125
9 12,920 12,920
10 51,525 51,525
11 303 303
12 152,439 152,439
13 174,757 174,757
14 656,735 -26,994 683,729
15 141 141
16 3,265 3,265
17 1,195,044 -(1,470,237) (275,193)
18 25,479 lm1,711 27,190
19 20,400 20,400
20 83 83
21 55,749 55,749
22 756 756
17,024,744 817,022 1,221,670 19,063,436
FERC FORM NO.1 (REV.02-04)
Page 332

FOOTNOTE DATA
La)Concept:OtherChargesTransmissionOfElectricityByOthers
Ancillary Services
U Concept:OtherChargesTransmissionOfElectricityByOthers
Use of Facilities
U Concept:OtherChargesTransmissionOfElectricityByOthers
Ancillary Services
JW Concept:OtherChargesTransmissionOfElectricityByOthers
Ancillary Services and Regulation&Frequency Response
Je Concept:OtherChargesTransmissionOfElectricityByOthers
Ancillary Services of$75,713,and Redirect Credit of($1,545,950)equals($1,470,237)
M Concept:OtherChargesTransmissionOfElectricityByOthers
Schedule 11 WATax Rider
FERC FORM NO.1 (REV.02-04)
Page 332

This report is:
Name of Respondent: (1)0 An Original Date of Report: Year/Period of Report
Avista Corporation 04/12/2024 End of:2023/Q4
(2) El A Resubmission
MISCELLANEOUS GENERAL EXPENSES(Account 930.2)(ELECTRIC)
Line No. Description Amount
(a) (b)
1 Industry Association Dues 925,831
2 Nuclear Power Research Expenses
3 Other Experimental and General Research Expenses
4 Pub and Dist Info to Stkhldrs...expn servicing outstanding Securities 688,834
5 Oth Expn greater than or equal to 5,000 show purpose,recipient,amount.Group
if less than$5,000
6 Community Relations 633,259
7 Compliance 60,097
8 Board of Director Activities 1,758,100
9 Education,Information,&Training 705,943
10 Emergency Operating Procedure Events 6,931
11 Misc Employee Expenses 115,331
12 Misc Legal,Professional&General Services 184,897
13 Misc Transportation 214,058
14 Other Misc Expenses<$5,000 10,107
15 Misc.Labor 341,477
46 TOTAL 5,644,865
FERC FORM NO.1 (ED.12-94)
Page 335

This report is:
Name of Respondent: (1)0 An Original Date of Report: Year/Period of Report
Avista Corporation (2) El A Resubmission 04/12/2024 End of:2023/Q4
Depreciation and Amortization of Electric Plant(Account 403,404,405)
A.Summary of A.Summary of A.Summary of A.Summary of A.Summary of
A.Summary of Depreciation Depreciation and Depreciation and Depreciation and Depreciation and Depreciation
and Amortization Charges Amortization Amortization Amortization Amortization and
Charges Charges Charges Charges Amortization
Charges
Depreciation Depreciation Amortization of Amortization of
Line Functional Classification Expense(Account Expense for Asset Limited Term Other Electric Plant Total
No. (a)
Retirement Costs Electric Plant (Ac ) M
�b�) (Account403.1) (Account404) ( 05 e)
- - - (c) (d)
1 Intangible Plant 9,850,589 9,850,589
2 Steam Production Plant 17,056,563 17,056,563
3 Nuclear Production Plant
4 Hydraulic Production Plant- 16,632,247 16,632,247
Conventional
5 Hydraulic Production Plant-
Pumped Storage
6 Other Production Plant 11,041,726 11,041,726
7 Transmission Plant 21,064,671 21,064,671
8 Distribution Plant 60,509,580 60,509,580
9 Regional Transmission and
Market Operation
10 General Plant 4,750,023 422,432 5,172,455
11 Common Plant-Electric 18,217,879 36,465,620 54,683,499
12 TOTAL 149,272,689 46,738,641 196,011,330
FERC FORM NO.1 (REV.12-03)
Page 336-337
B.Basis for Amortization Charges
C.Factors Used in Estimating Depreciation Charges
Depreciable Net
Applied —
Estimated Avg. Depr. Mortality Average
Line Account No. Plant Base(in Salvage
No. a I Service Life Rates Curve Type Remaining Life
( ) Thousands) ( ) (Percent) (Percent)
12 STEAM PLANT
13 Colstrip No.3
14 311 57.697 70 years (6)% 1.99% S1.5 8 years
15 312 86.809 60 years (6)% 2.67% R1 8 years
16 313 0.106 (6)% 9.22% R2.5 8 years
17 314 23.214 40 years (6)% 8.34% R0.5 8 years
18 315 10.794 50 years (6)% 2.97% R3 8 years
19 316 10.254 53 years (6)% 3.9574% R2 8 years

20 Subtotal 188.874
21 Colstrip No.4
22 311 54.164 70 years (7)% 2.95% S1.5 8 years
23 312 60.035 60 years (7)% 4.79% R1 8 years
24 313 0.126 (7)% 9.34% R2.5 8 years
25 314 16.53 40 years (7)% 7.59% R0.5 8 years
26 315 7.548 50 years (7)% 3.72% R3 8 years
27 316 4.637 53 years (7)% 4.74% R2 8 years
28 Subtotal 143.041
29 Kettle Falls
30 310 0.427 1.32% SQ 12 years
31 311 29.62 70 years (4)% 2.49% S1.5 12 years
32 312 79.695 55 years (4)% 3.18% R1 11 years
33 314 18.703 35 years (4)% 2.25% R0.5 10 years
34 315 12.605 50 years (4)% 4.06% R3 11 years
35 316 2.477 55 years (4)% 2.97% R2 11 years
36 Subtotal 143.527
37 HYDRO PLANT
38 Cabinet Gorge
39 330 9.383 100 years 1.9% R4 38 years
40 331 27.321 55 years (16)% 1.7275% R2 42 years
41 332 112.278 60 years (16)% 2.0275% R1 43 years
42 333 47.871 65 years (16)% 2.59% R1.5 41 years
43 334 20.114 40 years (16)% 2.1% S1 29 years
44 335 6.452 50 years (16)% 1.8925% R1 41 years
45 336 1.865 55 years (16)% 2% S2.5 29 years
46 Subtotal 225.284
47 Noxon Rapids
48 330 30.747 100 years 1.64% R4 53 years
49 331 25.083 55 years (24)% 2.2325% R2 45 years
50 332 41.685 60 years (24)% 2.2225% R1 47 years
51 333 89.308 65 years (24)% 2.41% R1.5 45 years
52 334 20.622 40 years (24)% 4.09% S1 27 years
53 335 4.57 50 years (24)% 2.0375% R1 42 years
54 336 0.306 55 years (24)% 2.96% S2.5 26 years
55 Subtotal 212.32
56 Post Falls

57 330 2.908 80 years 1.905% R4 24 years
58 331 8.103 55 years (4)% 1.53% R2 38 years
59 332 26.064 60 years (4)% 2.48% R1 37 years
60 333 2.234 65 years (4)% 0.79% R1.5 34 years
61 334 2.304 40 years (4)% 1.2% S1 23 years
62 335 1.047 60 years (4)% 2.39% R1 37 years
63 336 0.578 55 years (4)% 2.62% S2.5 26 years
64 Subtotal 43.237
[65 Long Lake
330 0.418 80 years 1.91% R4 26 years
331 11.286 55 years (7)% 1.64% R2 34 years
68 332 39.074 60 years (7)% 1.85% R1 34 years
69 333 8.897 65 years (7)% 0.45% R1.5 34 years
70 334 4.59 40 years (7)% 0.85% S1 29 years
71 335 0.881 60 years (7)% 1.69% R1 33 years
72 336 0 55 years (7)% 2.62% S2.5 26 years
73 Subtotal 65.146
74 Little Falls
75 330 4.217 80 years 1.28% R4 20 years
76 331 5.533 110 years (7)% 1.87% R2 42 years
77 332 6.408 110 years (7)% 1.17% R1 40 years
78 333 39.332 65 years (7)% 1.4% R1.5 39 years
79 334 13.959 40 years (7)% 2.72% S1 32 years
80 335 0.549 60 years (7)% 1.674% R1 36 years
81 Subtotal 69.998
82 Upper Falls
83 330 0.064 100 years 1.38% R4 19 years
84 331 4.96 50 years (7)% 3.36% R2 31 years
85 332 10.046 110 years (7)% 1.82% R1 41 years
86 333 0.768 65 years (7)% 0.22% R1.5 38 years
87 334 4.568 40 years (7)% 3.11% S1 30 years
88 335 0.113 60 years (7)% 2.14% R1 35 years
89 336 0.508 55 years (7)% 2.53% S2.5 26 years
90 Subtotal 21.027
91 Nine Mile
92 330 0.011 100 years 1.495% R4 25 years
93 331 24.157 110 years (4)% 2.41% R2 40 years

94 332 30.934 110 years (4)% 2.095% R1 37 years
95 333 41.143 65 years (4)% 2.58% R1.5 39 years
96 334 18.732 40 years (4)% 2.92% S1 33 years
97 335 1.041 60 years (4)% 2.68% R1 38 years
98 336 0.595 55 years (4)% 2.7% S2.5 26 years
99 Subtotal 116.612
100 Monroe Street
101 331 12.262 55 years (7)% 2.39% R2 41 years
102 332 10.009 110 years (7)% 1.91% R1 50 years
103 333 11.68 65 years (7)% 2.22% R1.5 41 years
104 334 3.568 40 years (7)% 3.66% S1 26 years
105 335 0.034 60 years (7)% 2.3% R1 41 years
106 336 0.05 55 years (7)% 2.89% R2.5 31 years
107 Subtotal 37.603
108 OTHER
PRODUCTION
109 Northeast
Turbine
110 341 0.746 55 years (5)% 30.78% S4 2 years
111 342 0.037 55 years (5)% 0% R3 0 years
112 343 9.058 60 years (5)% 2.51% S2.5 2 years
113 344 2.857 45 years (5)% 2.56% R1 2 years
114 345 1.249 20 years (5)% 16.94% S1 2 years
115 346 0.399 35 years (5)% 23.28% R2.5 2 years
116 Subtotal 14.346
117 Rathdrum
Turbine El
118 341 3.74 55 years (4)% 3.7% S4 16 years
119 342 1.696 55 years (4)% 3.56% R3 18 years
120 343 3.652 60 years (4)% 3.77% S2.5 18 years
121 344 51.225 45 years (4)% 3.94% R1 16 years
122 345 4.845 20 years (4)% 8.22% S1 12 years
123 346 0.249 35 years (4)% 5.69% R2.5 17 years
124 Subtotal 65.407
125 Kettle Falls CT
126 341 0.013 55 years (1)% 1.36% S4 11 years
127 342 0.089 55 years (1)% 3.33% R3 12 years
128 343 8.67 60 years (1)% 3.45% S2.5 12 years

129 344 0.234 45 years (1)% 4.11% R1 11 years
130 345 0.539 20 years (1)% 8% S1 11 years
131 Subtotal 9.545
132 Boulder Park
133 341 1.312 55 years (2)% 2.56% S4 26 years
134 342 0.162 55 years (2)% 2.62% R3 25 years
135 343 0.049 60 years (2)% 2.38% S2.5 25 years
136 344 31.538 45 years (2)% 2.43% R1 22 years
137 345 0.961 20 years (2)% 6.42% S1 15 years
138 346 0.065 35 years (2)% 3.99% R2.5 24 years
139 Subtotal 34.088
140 Coyote Springs 2
141 341 11.801 55 years (3)% 2.37% S4 27 years
142 342 19.002 55 years (3)% 2.45% R3 26 years
143 344 154.187 45 years (3)% 3.36% R1 23 years
144 345 18.7 20 years (3)% 5.25% S1 12 years
145 346 0.92 35 years (3)% 4.268% R2.5 22 years
146 Subtotal 204.609
147 Solar Power
148 344 0.449 25 years (3)% 7.455% S2.5 13 years
149 345 0.033
150 Subtotal 0.482
151 Lancaster
152 342 0.092 � 55 years (5)% 3.07% R3 23 years
153 344 0.209 45 years (5)% 3.52% R1 22 years
154 345 0.308 20 years (5)% 6.19% S1 17 years
155 Subtotal 0.609
156 TRANSMISSION
PLANT
157 350 23.374 80 years 1.13% R4 56 years
158 352 38.466 65 years (10)% 1.63% S1.5 53 years
159 353 395.869 44 years (10)% 2.41% R2 33 years
160 354 17.139 75 years (15)% 1.51% R4 42 years
161 355 385.031 63 years (30)% 1.93% R2.5 52 years
162 356 192.195 70 years (30)% 1.9% R3 46 years
163 357 3.214 60 years 1.64% R4 47 years
164 358 6.834 50 years 2.06% S3 29 years

165 359 2.626 70 years 1.41% R4 43 years
166 Subtotal 1,064.749
167 DISTRIBUTION
PLANT
168 360 4.536 75 years 1.34% R4 69 years
169 361 31.548 60 years (10)% 1.72% S1.5 47 years
170 362 174.515 42 years (10)% 2.68% R1.5 30 years
171 363 0 15 years 6.8% L3 14 years
172 364-WA 388.861 67 years (60)% 2.47% R2.5 52 years
173 364-ID 197.636 65 years (60)% 2.57% R2.5 52 years
174 365-WA 230.652 68 years (50)% 2.27% R3 44 years
175 365-ID 136.566 65 years (50)% 2.45% R3.5 44 years
176 366-WA 117.367 75 years (30)% 1.56% R1.5 47 years
177 366-ID 58.78 60 years (30)% 2.14% S2.5 47 years
178 367-WA 194.46 35 years (30)% 3.44% S1.5 25 years
179 367-ID 98.328 35 years (20)% 2.99% S1.5 25 years
180 368 358.439 47 years (10)% 2.16% R2 36 years
181 369 226.734 65 years (40)% 2.1% R4 50 years
182 370-AN 0.157 35 years (2)% 2.89% SO 0 years
183 370-ID 24.639 15 years 9.06% S2.5 8 years
184 370-WA 62.831 35 years 2.89% SO 27 years
185 371 11.203 10 years 10.36% S1 10 years
186 373 49.686 37 years (20)% 1.87% R2.5 28 years
187 373.4 19.074 37 years (20)% 3.04% R2.5 29 years
188 373.5 15.536 37 years (20)% 3.17% R2.5 36 years
189 Subtotal 2,401.551
190 GENERAL
PLANT
191 390.1 21.103 50 years (5)% 1.9% R2.5 42 years
192 391 0.033 15 years 6.67% SQ 15 years
193 391.1 4.055 5 years 20% SQ 2 years
194 393 0.473 25 years 4% SQ 15 years
195 394 9.011 20 years 5% SQ 11 years
196 395 3.361 15 years 6.67% SQ 7 years
197 397 43.279 15 years 6.67% SQ 9 years
198 398 0.259 10 years 10% SQ 7 years
199 Subtotal 81.574

200 MISC POWER
EQUIPMENT
201 392 11.413 16 years 5.48% L2.5 12 years
202 396 3.838 22 years 3.75% S1 15 years
203 Subtotal 15.251
204 Total Company 5,158.88

This report is:
Name of Respondent: (1)®An Original Date of Report: Year/Period of Report
Avista Corporation 04/12/2024 End of:2023/Q4
(2) El A Resubmission
REGULATORY COMMISSION EXPENSES
EXPENSES EXPENSES'
INCURRED INCURRED
DURING YEAR DURING
YEAR
CURRENTLY CURRENTLY
CHARGED TO CHARGED
TO
Description(Furnish name Deferred in
of regulatory commission Assessed by Expenses of .3 at Total Expenses Account 182
Line or body the docket or case Regulatory for Current Year Department Account No.
No. number and a description Commission Utility (b)+(c) Beginning of (� (g)
of the case) (b) (c) (d) Year
(a) (e)
Federal Energy
Regulatory Commission-
Charges include annual
1 fee and license fees for the 3,651,398 200,949 3,852,347 Electric 928
Spokane River Project,the
Cabinet Gorge Project and
the Noxon Rapids Project
Washington Utilities and
2 Transportation
Commission
Electric-Includes annual
3 fee and various other 2,376,954 488,941 2,865,895 Electric 928
electric dockets
l
Gas-Includes annual fee
4 and various other natural 887,457 143,367 1,030,824 Gas 928
gas dockets
5 Idaho Public Utilities
Commission
Electric-Includes annual
6 fee and various other 578,031 312,522 890,553 Electric 928
electric dockets
Gas-Includes annual fee
7 and various other natural 179,872 71,625 251,497 Gas 928
gas dockets
8 Public Utility Commission
of Oregon
Includes annual fees and
9 various other natural gas 903,979 306,869 1,210,848 98,369 Gas 928
dockets
10 Not directly assigned 778,751 778,751 Electric 928
Electric
11 Not directly assigned 341,241 341,241 Gas 928
Natural Gas
46 TOTAL 8,577,691 2,644,265 11,221,956 98,369
FERC FORM NO.1 (ED.12-96)
Page 350-351

REGULATORY COMMISSION EXPENSES
EXPENSES INCURRED EXPENSES INCURRED AMORTIZED AMORTIZED DURING AMORTIZED DURING
DURING YEAR DURING YEAR DURING YEAR YEAR YEAR
CURRENTLY CHARGED
TO
Line Amount Deferred to Account 182.3 Contra Account Amount Deferred in Account 182.3
No. (h) (i) (k) End of Year
(I)
1 3,852,347
2
3 2,865,895 1,264,383 407 1,264,383
4 1,030,824 571,217 407 571,217
5
6 890,553
7 251,497
8
9 1,210,848 100,648 407 119,201 79,816
10 778,751
11 341,241
46 11,221,956 1,936,248 119,201 1,915,416
FERC FORM NO.1 (ED.12-96)
Page 350-351

This report is:
Name of Respondent: (1)®An Original Date of Report: Year/Period of Report
Avista Corporation 04/12/2024 End of:2023/Q4
(2) ❑A Resubmission
RESEARCH,DEVELOPMENT,AND DEMONSTRATION ACTIVITIES
Costs Incurred Costs Incurred
Line Classification - Description Internally Current Year Externally Current Year
No. (a) (b)
(c) (d)
1 A.Electric(3)Distribution Clean Energy and Electric Vehicle 1,376,226 2,688,686
Supply Equipment
2 A.Electric(3)Distribution Clean Energy and Electric Vehicle 4,390 0
Supply Equipment
3 A.Electric(3)Distribution Clean Energy and Electric Vehicle 14,147 0
Supply Equipment
4 A.Electric(3)Distribution Clean Energy and Electric Vehicle 22,494 (168,454)
Supply Equipment
5 A.Electric(3)Distribution Clean Energy and Electric Vehicle 0 41,162
Supply Equipment
6 A.Electric(3)Distribution Clean Energy and Electric Vehicle 207,393 0
Supply Equipment
7 A.Electric(3)Distribution Clean Energy and Electric Vehicle 0 8,763
Supply Equipment
8 A.Electric(3)Distribution Clean Energy and Electric Vehicle 30,937 43,260
Supply Equipment
9 A.Electric(3)Distribution Clean Energy and Electric Vehicle 17,370 51,294
Supply Equipment
10 A.Electric(3)Distribution Clean Energy and Electric Vehicle 214 43,432
Supply Equipment
11 A.Electric(3)Distribution Clean Energy and Electric Vehicle 37,025 0
Supply Equipment
12 A.Electric(3)Distribution Clean Energy and Electric Vehicle 2,362 3,258
Supply Equipment
13 A.Electric(6)Other-Testing Lab& HUB-Moms Center Lab Test Facility 79,505 276,892
Facility
14 A.Electric(6)Other-Testing Lab& HUB-Moms Center Lab Test Facility 1,002 0
Facility
FERC FORM NO.1 (ED.12-87)
Page 352-353

RESEARCH,DEVELOPMENT,AND DEMONSTRATION ACTIVITIES
AMOUNTS CHARGED IN AMOUNTS CHARGED IN CURRENT YEAR
CURRENT YEAR
Amounts Charged In Current Amounts Charged In Current Year:Amount Unamortized Accumulation
Line No. Year.Account (� �9)
(e)
1 107 4,064,912
2 108 4,390
3 182 14,147
4 186 (145,960)
5 557 41,162
6 580 207,393
7 587 8,763
8 598 74,197
9 909 68,664
10 912 43,646
11 920 37,025
12 930 5,620
13 107 356,397
14 182 1,002
FERC FORM NO.1 (ED.12-87)
Page 352353

This report is:
Name of Respondent: (1)21 An Original Date of Report: Year/Period of Report
Avista Corporation 04/12/2024 End of:2023/Q4
(2) ❑ A Resubmission
DISTRIBUTION OF SALARIES AND WAGES
Allocation of Payroll
Line Classification Direct Payroll Distribution Charged for Clearing Total
No. (a) (b) Accounts (d)
(c)
1 Electric
2 Operation
3 Production 15,180,372
4 Transmission 5,610,502
5 Regional Market 0
6 Distribution 12,299,941
7 Customer Accounts 6,507,117
8 Customer Service and Informational 422,600
9 Sales 0
10 Administrative and General 29,427,473
11 1 O TAL Operation(Enter Total of lines 3 thru 69,448,005
12 Maintenance
13 Production 4,713,472
14 Transmission 1,001,293
15 Regional Market 0
16 Distribution 4,725,477
17 Administrative and General 0
18 1)TAL Maintenance(Total of lines 13 thru 10,440,242
19 Total Operation and Maintenance
20 Production(Enter Total of lines 3 and 13) 19,893,844
21 Transmission(Enter Total of lines 4 and 14) 6,611,795
22 Regional Market(Enter Total of Lines 5 and 0
15)
23 Distribution(Enter Total of lines 6 and 16) 17,025,418
24 Customer Accounts(Transcribe from line 7) 6,507,117
25 Customer Service and Informational 422,600
(Transcribe from line 8)
26 Sales(Transcribe from line 9) 0
27 Administrative and General(Enter Total of 29,427,473
lines 10 and 17)
FERC FORM NO.1 (ED.12-88)
Page 354-355

DISTRIBUTION OF SALARIES AND WAGES
Allocation of Payroll
Line Classification Direct Payroll Distribution Charged for Clearing Total
No. (a) (b) Accounts (d)
(c)
28 TOTAL Oper.and Maint.(Total of lines 20 thru 79,888,247 9,629,046 89,517,293
27)
29 Gas
I
30 Operation
31 Production-Manufactured Gas 0
32 Production-Nat.Gas(Including Expl.And 0
Dev.)
33 Other Gas Supply 1,176,409
34 Storage,LNG Terminaling and Processing 0
35 Transmission 0
36 Distribution 9,858,961
37 Customer Accounts 3,088,460
38 Customer Service and Informational 288,019
39 Sales 0
40 Administrative and General 11,927,195
41 TOTAL Operation(Enter Total of lines 31 thru 26,339,044
40)
42 Maintenance
43 Production-Manufactured Gas 0
44 Production-Natural Gas(Including 0
Exploration and Development)
45 Other Gas Supply 0
46 Storage,LNG Terminaling and Processing 0
47 Transmission 2,433,655
48 Distribution 3,689,066
49 Administrative and General
50 TOTAL Maint.(Enter Total of lines 43 thru 49) 6,122,721
51 Total Operation and Maintenance
52 Production-Manufactured Gas(Enter Total of
lines 31 and 43) 0
53 Production-Natural Gas(Including Expl.and 0
Dev.)(Total lines 32,
54 Other Gas Supply(Enter Total of lines 33 and 1,176,409
45)
55 Storage,LNG Terminaling and Processing 0
(Total of lines 31 thru
56 Transmission(Lines 35 and 47) 2,433,655
FERC FORM NO.1 (ED.12-88)
Page 354-355

DISTRIBUTION OF SALARIES AND WAGES
Allocation of Payroll
Line Classification Direct Payroll Distribution Charged for Clearing Total
No. (a) (b) Accounts (d)
(c)
57 Distribution(Lines 36 and 48) 13,548,027
58 Customer Accounts(Line 37) 3,088,460
59 Customer Service and Informational(Line 38) 288,019
60 Sales(Line 39) 0
61 Administrative and General(Lines 40 and 49) 11,927,195
62 TOTAL Operation and Maint.(Total of lines 52 32,461,765 2,737,908 35,199,673
thru61)
63 Other Utility Departments
64 Operation and Maintenance 0
65 TOTAL All Utility Dept.(Total of lines 28,62, 112,350,012 12,366,954 124,716,966
and 64)
66 Utility Plant
67 Construction(By Utility Departments)
68 Electric Plant 53,228,480 8,231,597 61,460,077
69 Gas Plant 15,228,319 2,355,006 17,583,325
70 Other(provide details in footnote): 0
71 TOTAL Construction(Total of lines 68 thru 70) 68,456,799 10,586,603 79,043,402
72 Plant Removal(By Utility Departments)
73 Electric Plant 2,754,050 219,243 2,973,293
74 Gas Plant 991,983 78,969 1,070,952
75 Other(provide details in footnote): 0
76 TOTAL Plant Removal(Total of lines 73 thru 3,746,033 298,212 4,044,245
1 75)
77 Other Accounts(Specify,provide details in
footnote):
78 Stores Expense(163) 3,033,814 (3,033,814) 0
79 Preliminary Survey and Investigation(183) 0 0 0
80 Small Tool Expense(184) 5,526,184 (5,526,184) 0
81 Miscellaneous Deferred Debits(186) 1,274,251 1,274,251
82 Non-operating Expenses(417) 743,935 743,935
83 Retirement Bonus/SERP/HRA(228) 39,474 39,474
84 Other Income Deductions(426) 974,987 974,987
85 Employee Incentive Plan(232380) 12,261,080 (12,261,080) 0
86 DSM Tariff Rider(242600) 2,430,691 (2,430,691) 0
FERC FORM NO.1 (ED.12-88)
Page 354-355

DISTRIBUTION OF SALARIES AND WAGES
Allocation of Payroll
Line Classification Direct Payroll Distribution Charged for Clearing Total
No. (a) (b) Accounts (d)
(c)
87 Incentive/Stock Compensation(238000) 250,528 250,528
88 Payroll Equalization Liability(242700) 29,517,696 29,517,696
89
90
91
92
93
94
95 TOTAL Other Accounts 56,052,640 (23,251,769) 32,800,871
96 TOTAL SALARIES AND WAGES 240,605,484 0 240,605,484
FERC FORM NO.1 (ED.12-88)
Page 354355

This report is:
Name of Respondent: (1)0 An Original Date of Report: Year/Period of Report
Avista Corporation 04/12/2024 End of:2023/Q4
(2) ❑ A Resubmission
COMMON UTILITY PLANT AND EXPENSES
1. Describe the property carried in the utility's accounts as common utility plant and show the book cost of such plant at end of year
classified by accounts as provided by Electric Plant Instruction 13,Common Utility Plant,of the Uniform System of Accounts.Also
show the allocation of such plant costs to the respective departments using the common utility plant and explain the basis of allocation
used,giving the allocation factors.
2. Furnish the accumulated provisions for depreciation and amortization at end of year,showing the amounts and classifications of such
accumulated provisions,and amounts allocated to utility departments using the common utility plant to which such accumulated
provisions relate,including explanation of basis of allocation and factors used.
3. Give for the year the expenses of operation,maintenance,rents,depreciation,and amortization for common utility plant classified by
accounts as provided by the Uniform System of Accounts.Show the allocation of such expenses to the departments using the common
utility plant to which such expenses are related.Explain the basis of allocation used and give the factors of allocation.
4. Give date of approval by the Commission for use of the common utility plant classification and reference to the order of the Commission
or other authorization.

1&2.Common Plant in service and accumulated provision for depreciation
Acct-No. Description
303 Intangible 316,359,812
389 Land and Land Rights 14,462,378
390 Structures and Improvements 164,979,693
391 Office Furniture and Equipment 74,182,694
392 Transportation Equipment 14,898,130
393 Stores Equipment 6,073,212
394 Tools,Shop&Garage Equipment 17,935,919
395 Laboratory Equipment 1,325,251
396 Power Operated Equipment 1,895,320
397 Communications Equipment 131,869,530
398 Miscellaneous Equipment 847,230
399 Asset Retirement Cost 0
Total Common Plant 744,829,169
Const.Work in Progress 30,582,843
Total Utility Plant 775,412,012
Acc.Prov.for Dep.&Amort. 313,510,703
Net Utility Plant 461,901,309
3.Common Expenses allocated to Electric and Gas departments:
Allocation to Allocated to
Acct.No. Description Total Electric Dept Gas Dept Basis of Allocation
901 Cust acct/collect supervision 259,884 135,418 124,466 #of Customers
902 Meter reading expenses 1,066,532 643,428 423,104 #of Customers
903 Cust rec&collectn expenses 15,808,108 8,346,776 7,461,332 #of Customers
904 Uncollectible accounts 163,701 85,300 78,401 #of Customers
905 Misc cust acct expenses 532,984 277,722 255,262 #of Customers
907 Cust svice&Info exp supervision 0 0 0 #of Customers
908 Cust assistance expenses 553,100 333,680 219,420 #of Customers
909 Info&instruct advert expenses 1,319,909 789,269 530,640 #of Customers
910 Misc cust sery&info expenses 439,617 229,071 210,546 #of Customers
911 Sales expense-supervision 0 0 0 #of Customers
912 Demo and selling expenses 0 0 0 #of Customers
913 Advertising expenses 0 0 0 #of Customers
916 Misc sales expenses 0 0 0 #of Customers
920 Admin&gen salaries 41,320,659 29,103,335 12,217,324 Four Factor
921 Office supplies&expenses 5,542,105 3,889,002 1,653,103 Four Factor
922 Admin expenses tranf-credit 0 0 0 Four Factor
923 Outside services employed 18,561,047 13,029,115 5,531,932 Four Factor
924 Property insurance 3,228,379 2,263,481 964,898 Four Factor
925 Injuries and damages 11,169,583 8,000,113 3,169,470 Four Factor
926 Employee pensions&benefits 80,949,342 56,832,975 24,116.367 Four Factor
927 Franchise requirement 0 0 0 Four Factor
928 Regulatory commission expenses 1,824,864 1,329,667 495,197 Four Factor
929 Duplicate charges-credit 0 0 0 Four Factor
930.1 General advertising expenses 0 0 0 Four Factor
930.2 Misc general expenses 6,252,505 4,407,862 1,844,643 Four Factor
931 Rents 737,859 522,629 215,230 Four Factor
935 Maint of general plant 17,501,188 12,440,091 5,061,097 Four Factor
403 Depreciation 25,657,540 18,217,879 7,439,661 Four Factor
404 Amort of LTD term plant 51,706,694 36,465,621 15,241,073 Four Factor
Note 1:The 4 factor allocator is made up of 25%each-customer counts,direct labor,direct O&M&Net direct plant
4.Letters of approval received from staffs of State Regulatory Commissions in 1993
FERC FORM NO.1 (ED.12-87)
Page 356

This report is:
Name of Respondent: (1)0 An Original Date of Report: Year/Period of Report
Avista Corporation 04/12/2024 End of:2023/Q4
(2) El A Resubmission
AMOUNTS INCLUDED IN ISO/RTO SETTLEMENT STATEMENTS
.ane Description of Item(s) Balance at End of Balance at End of Balance at End of Balance at End of
No. (a) Quarter 1 Quarter 2 Quarter 3 Year
(b) (c) (d) (e)
1 Energy
2 Net Purchases(Account 555) 14,114,368 16,749,174 23,078,449 29,878,795
2.1 Net Purchases(Account 555.1)
3 Net Sales(Account 447) (4,665,163) m(6,160,591) lw(8,524,549) (9,911,431)
4 Transmission Rights
5 Ancillary Services 1,441 (69,773) (67,481) (67,732)
6 Other Items(list separately)
7 Other Charges-MRTU 415,938 711,443 1,027,499 1,029,411
8 OtherCharges-EIM (1,278,894) (1,796,245) (1,592,413) (2,190,861)
46 TOTAL 8,587,690 9,434,008 13,921,505 18,738,182
FERC FORM NO.1 (NEW.12-05)
Page 397

This report is:
Name of Respondent: (1)0 An Original Date of Report: Year/Period of Report
Avista Corporation 04/12/2024 End of.2023/Q4
(2) ❑ A Resubmission
FOOTNOTE DATA
(a)Concept:IsoOrRtoS ettl ementsE n ergyN etP u rchasesP u rchased Power
CAISO-MRTU Purchases=$4,638,846
CAISO-EIM Purchases=$9,475,522
Concept:IsoOrRtoSetUementsEnergyNetPurchasesPurchasedPower
CAISO-MRTU Purchases=$4,897,181
CAISO-EIM Purchases=$11,851,993
(c)Concept:IsoOrRtoSettiementsEnergyNetPurchasesPurchasedPower
CAISO-MRTU Purchases=$6,354,235
CAISO-EIM Purchases=$16,724,214
Concept:IsoOrRtoSettlementsEnergyNetPurchasesPurchasedPower
CAISO-MRTU Purchases=$6,382,082
CAISO-EIM Purchases=$23,496,713
(e)Concept:IsoOrRtoSettiementsEnergyNetSales
CAISO-MRTU Sales=$301,222
CAISO-EIM Sales=$4,363,941
Mf Concept:IsoOrRtoSetdementsEnergyNetSales
CAISO-MRTU Sales=$338,911
CAISO-EIM Sales=$5,821,680
Lq)Concept:IsoOrRtoSettlementsEnergyNetSales
CAISO-MRTU Sales=$420,000
CAISO-EIM Sales=$8,104,549
Concept:IsoOrRtoSettlementsEnergyNetSales
CAISO-MRTU Sales=$439,129
CAISO-EIM Sales=$9,472,302
FERC FORM NO.1 (NEW.12-05)
Page 397

This report is:
Name of Respondent: (1)0 An Original Date of Report: Year/Period of Report
Avista Corporation 04/12/2024 End of:2023/Q4
(2) El A Resubmission
PURCHASES AND SALES OF ANCILLARY SERVICES
Amount Purchased forthe Amount Purchased for the Amount Purchased for the
Year Year Year
Usage-Related Billing Usage-Related Billing Usage-Related Billing
Determinant Determinant Determinant
Line Type of Ancillary Service Number of Units Unit of Measure Dollar
No. (a) (b) (c) (d)
1 Scheduling,System Control and Dispatch
2 Reactive Supply and Voltage F
3 Regulation and Frequency Response
4 Energy Imbalance
5 Operating Reserve-Spinning
6 Operating Reserve-Supplement
7 Other 861 MW L=10,786,373
8 Total(Lines 1 thru 7) 861 10,786,373
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 Number of Units Unit of Measure Dollars
No. (e) (f) (g)
1
2
3 89 MW 1,146,770
4
5 1 MW 13,962
6 1 MW 12,863
7 861 MW L'110,786,373
8 952 11,959,968
FERC FORM NO.1 (New 2-04)
Page 398

This report is:
Name of Respondent: (1)0 An Original Date of Report: Year/Period of Report
Avista Corporation (2)❑ A Resubmission 04/12/2024 End of:2023/Q4
FOOTNOTE DATA
Ua)Concept:AncillaryServicesPurchasedAmount
Amounts reported are offsetting imputed amounts reflecting the self-provison of ancillary service for bundled retail native load customers under state
Jurisdiction.
(b)Concept:AncillaryServicesSoldAmount
.Amounts reported are offsetting imputed amounts reflecting the self-provison of ancillary service for bundled retail native load customers under state
jurisdiction.
FERC FORM NO.1 (New 2-04)
Page 398

This report is:
Name of Respondent: (1)Z An Original Date of Report: Year/Period of Report
Avista Corporation 04/12/2024 End of.2023/Q4
(2) El A Resubmission
MONTHLY TRANSMISSION SYSTEM PEAK LOAD
Finn Long-Term Other Short Term
Monthly Day of Hour of Firm Network Network Finn Point- Long- Firm Point- Other
Line Month Peak MW- Monthly Monthly Service for Tenn
Service for to-point to-pb}nt Service
No. (a) Total Peak Peak Self Firm
Others Reservations Reservation (�
(b) (c) (d) (e) (1) (9) Service (i)
(h)
NAME OF
SYSTEM:Avista
Corporation
1 January 3,134 30 8 1,672 458 619 15 385 85
2 February 2,871 24 8 1,621 450 619 14 181 426
3 March 2,571 6 8 1,355 345 627 12 244 0
4 Total for Quarter 1 4,648 1,253 1,865 41 810 511
5 April 2,844 19 8 1,261 312 632 13 639 345
6 May 2,438 21 18 1,285 274 637 19 242 642
7 June 2,741 28 18 1,389 299 631 21 422 373
8 Total for Quarter 2 3,935 885 1,900 53 1,303 1,360
9 July 2,853 6 18 1,479 321 634 31 419 99
10 August 3,055 16 18 1,701 377 636 27 341 285
11 September 2,353 14 18 1,173 247 627 23 306 389
12 Total for Quarter 3 4,353 945 1,897 81 1,066 773
13 October 2,919 30 8 1,341 328 626 28 624 323
14 November 2,906 29 18 1,635 363 619 10 289 371
15 December 2,827 10 18 1,309 317 619 11 582 152
16 Total for Quarter 4,285 1,008 1,864 49 1,495 846
17 Total 17,221 4,091 7,526 224 4,674 3,490
FERC FORM NO.1 (NEW.07-04)
Page 400

Name of Respondent: This report is:
(1)�An Original Date of Report: Year/Period of Report
Avista Corporation 2024-04-12 End of.2023/Q4
(2) ❑ A Resubmission
ELECTRIC ENERGY ACCOUNT
Line Item MegaWatt Hours Line kem MegaWatt Hours
No. (a) (b) No. (a) (b)
1 SOURCES OF ENERGY 21 DISPOSITION OF ENERGY
2 Generation(Excluding Station Use - 22 Sales to Ultimate Consumers 9,307,869
(Including Interdepartmental Sales)
3 Steam 1,950,137 23 Requirements Sales for Resale(See
instruction 4,page 311.)
Non-Requirements Sales for Resale
4 Nuclear 0 24 3,521,491
(See instruction 4,page 311.)
5 Hydro-Conventional 3,024,124 25 Energy Furnished Without Charge
Energy Used by the Company
6 Hydro-Pumped Storage 0 26 (Electric Dept Only,Excluding 13,342
Station Use)
7 Other 3,134,299 27 Total Energy Losses 457,044
8 Less Energy for Pumping 0 27.1 Total Energy Stored
Net Generation(Enter Total of lines 3 TOTAL(Enter Total of Lines 22
9 through 8) 8,108,560 28 Through 27.1)MUST EQUAL LINE 13,299,746
20 UNDER SOURCES
10 Purchases(other than for Energy 5,601,050
Storage)
10.1 Purchases for Energy Storage 0
11 Power Exchanges:
12 Received 11,825
13 Delivered 421,689
14 Net Exchanges(Line 12 minus line (409,864)
13)
15 Transmission For Other(Wheeling)
16 Received 4,446,353
17 Delivered 4,446,353
18 Net Transmission for Other(Line 16 0
minus line 17)
19 Transmission By Others Losses
20 TOTAL(Enter Total of Lines 9,10, 13,299,746
10.1,14,18 and 19)
FERC FORM NO.1 (ED.12-90)
Page 401a

This report is:
Name of Respondent: (1)21 An Original Date of Report: Year/Period of Report
Avista Corporation (2) ❑ A Resubmission 04/12/2024 End of:2023/Q4
MONTHLY PEAKS AND OUTPUT
Monthly Non-
Line Month Total Monthly Requirement Sales Monthly Peak- Monthly Peak-Day Monthly Peak-
No. (a) Energy for Resale& Megawatts of Month Hour
(b) Associated Losses (d) (e) (f)
- - - (c) - I
NAME OF SYSTEM:Avista
Corporation
29 January 1,090,534 144,645 1,771 30 8
30 February 1,015,923 154,156 1,726 23 9
31 March 1,126,304 267,999 1,515 1 8
32 April 1,115,577 374,774 1,394 5 8
33 May 1,247,605 513,971 1,438 19 18
34 June 1,258,860 503,470 1,535 29 17
35 July 1,108,405 243,144 1,716 21 18
36 August 1,051,266 207,705 1,809 15 17
37 September 977,324 284,691 1,309 10 18
38 October 1,018,136 285,864 1,402 30 9
39 November 1,111,401 264,324 1,546 29 18
40 December 1,178,411 276,748 1,463 1 18
41 Total 13,299,746 3,521,491
FERC FORM NO.1 (ED.12-90)
Page 401 b

This report is:
Name of Respondent: (1) An Original Date of Report: Year/Period of Report
Avista Corporation 04/12/2024 End of:2023/Q4
(2) ❑ A Resubmission
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 Mcf.
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.
Plant Name: Plant
Line Item Plant Name: Plant Name: Plant Name: Plant Name: Name:
No. (a) Boulder Park Coistrip Coyote Kettle Falls Rathdrum Spokane
Springs 2 N.E.
bw
Kind of Plant(Internal Gas
1 Comb,Gas Turb, Internal Comb Steam Gas Turbine Steam Gas Turbine Turbine
Nuclear)
Type of Constr Not Not
2 (Conventional,Outdoor, Conventional Conventional Not Applicable Conventional Applicable Applicable
Boiler,etc)
3 Year Originally 2002 1984 2003 1983 1995 1978
Constructed
I
4 Year Last Unit was 2002 1984 2003 1983 1995 1978
Installed
Total Installed Cap
5 (Max Gen Name Plate 25 233 286 51 167 62
Ratings-MW)
Net Peak Demand on
6 Plant-MW(60 26 228 319 95 172 53
minutes)
7 Plant Hours Connected 3,221 8,758 8,011 7,209 6,063 3
to Load
8 Net Continuous Plant 25 222 322 54 167 65
Capability(Megawatts)
E9When Not Limited by 0 222 322 54 0 0
Condenser Water
10 When Limited by 0 222 322 54 0 0
Condenser Water
11 Average Number of 2 252 32 26 1 1
Employees

Net Generation,
Exclusive of Plant Use-
12 kWh 63,905,000 1,641,846,000 2,265,353,000 308,291,000 779,307,000 112,000
13 Cost of Plant:Land and 144,733 1,289,395 0 2,568,188 621,682 138,753
Land Rights
14 Structures and 1,312,452 111,860,988 11,800,944 29,619,893 3,739,982 746,178
Improvements
15 Equipment Costs 32,775,846 220,053,648 192,808,126 113,479,534 61,667,377 13,596,464
16 Asset Retirement Costs 0 17,139,710 351,682 323,787 0 0
17 2ot lcost(total13thru 34,233,031 350,343,741 204,960,752 145,991,402 66,029,041 14,481,395
Cost per KW of
18 Installed Capacity(line 1,369.32 1,503.62 716.65 2,862.58 395.38 233.57
17/5)Including
19 Production Expenses: 24,753 74,600 660,721 102,576 23,440 22,796
Oper,Supv,&Engr
20 Fuel 1,982,207 34,049,395 46,437,759 11,997,451 28,638,414 (4,255)
21 Coolants and Water
(Nuclear Plants Only)
22 Steam Expenses 0 3,592,098 0 629,880 0 0
23 Steam From Other 0 0 0 0 0 0
Sources
24 Steam Transferred(Cr) 0 0 0 0 0 0
25 Electric Expenses 246,972 (144,667) 3,281,653 896,152 232,300 25,137
Misc Steam(or
26 Nuclear)Power 30,548 5,887,656 594,939 481,021 23,881 9,010
Expenses
27 Rents 0 0 103,105 0 0 0
28 Allowances 0 0 0 0 0 0
Maintenance
29 Supervision and 66,187 274,399 295,267 99,377 83,153 28,570
Engineering
30 Maintenance of 2,577 744,875 89,483 125,790 46,898 ` 91
Structures
31 Maintenance of Boiler 0 5,125,679 0 1,964,813 0 0
(or reactor)Plant
32 Maintenance of Electric 537,456 632,517 1,248,997 217,091 143,872 31,300
Plant
Maintenance of Misc
33 Steam(or Nuclear) 131,656 901,840 651,821 443,266 51,734 16,945
Plant
34 Total Production 3,022,356 51,138,392 53,363,745 16,957,417 29,243,692 129,594
Expenses
35 Expenses per Net kWh 0.05 0.03 0.02 0.06 0.04 1.16
Boulder Coyote Kettle Spokane
35 Plant Name Park Colstrip Colstrip Springs 2 Kettle Falls Falls Rathdrum N.E.
36 Fuel Kind Gas Coal Oil Gas Gas Wood Gas Gas

37 Fuel Unit MCF Ton BBL MCF MCF Ton MCF MCF
38 Quantity(Units) 577,226 1,026,440 2,634 14,841,519 10,164 519,633 9,176,931 1,398
of Fuel Burned
Avg Heat Cont-
39 Fuel Burned 1,020,000 16,970,000 5,880,000 1,020,000 1,020,000 8,600,000 1,020,000 1,020,000
(btuAndicate if
nuclear)
Avg Cost of
40 Fuel/unit,as 3.43 32.8 145.36 3.13 0.76 23.07 3.12 (3.04)
Delvd f.o.b.
during year
Average Cost of
41 Fuel per Unit 3.43 32.8 145.36 3.13 0.76 23.07 3.12 (3.04)
Bum
ed
Average Cost of
42 Fuel Burned per 3.37 1.93 24.72 3.07 0.75 2.68 3.06 (2.98)
Million BTU
Average Cost of
43 Fuel Burned per 0.03 0.02 0 0.02 0.01 0.04 0.04 0
kWh Net Gen
Average BTU per
44 kWh Net 9,213 10,619 0 6,683 0 14,540 12,011 12,732
Generation
FERC FORM NO.1 (REV.12-03)
Page 402-403

This report is:
Name of Respondent: (1)21 An Original Date of Report: Year/Period of Report
Avista Corporation (2) ❑A Resubmission 04/12/2024 End of:2023/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.
Hydroelectric Generating Plant Statistics
FERC Licensed Project FERC Licensed Project FERC Licensed Project
Line Item No. No. No.
No. (a) 2058 2545 2545
Plant Name: Plant Name: Plant Name:
Cabinet Gorge Little Falls Long Lake
1 Kind of Plant(Run-of-River or Storage) Storage Run-of-River Storage
2 Plant Construction type(Conventional or Outdoor Conventional Conventional
Outdoor)
3 Year Originally Constructed 1952 1910 1915
4 Year Last Unit was Installed 1953 1911 1924
5 Total installed cap(Gen name plate Rating in 265 43 71
MW)
6 Net Peak Demand on Plant-Megawatts(60 264 42 98
minutes)
7 Plant Hours Connect to Load 8,748 6,830 7,034
8 Net Plant Capability(in megawatts)
9 (a)Under Most Favorable Oper Conditions 255 43 90
10 (b)Under the Most Adverse Oper Conditions 295 43 90
11 Average Number of Employees 1 1 1
12 Net Generation,Exclusive of Plant Use-kWh 815,740,000 175,811,000 412,958,000
13 Cost of Plant
- u
14 Land and Land Rights 18,630,413 4,325,371 2,421,233
15 Structures and Improvements 27,320,551 5,533,346 11,205,708
16 Reservoirs,Dams,and Waterways 112,278,157 6,407,917 39,058,591
17 Equipment Costs 74,437,083 53,839,549 14,352,281
18 Roads,Railroads,and Bridges 1,864,637
19 Asset Retirement Costs
20 Total cost(total 13 thni 20) 234,530,841 70,106,183 67,037,813
FERC FORM NO.1 (REV.12-03)
Page 406-407

Hydroelectric Generating Plant Statistics
FERC Licensed Project FERC Licensed Project FERC Licensed Project
Line Item No. No. No.
No. (a) 2058 2545 2545
Plant Name: Plant Name: Plant Name:
Cabinet Gorge Little Falls Long Lake
21 Cost per KW of Installed Capacity(line 20/5)7
885.02 1,630.38 944.19
22 Production Expenses
23 Operation Supervision and Engineering 63,004 43 41,352
24 Water for Power
25 Hydraulic Expenses 3,430 7,932 7,932
26 Electric Expenses 1,045,515 720,542 800,519
27 Misc Hydraulic Power Generation Expenses 250,024 29,699 141,742
28 Rents 41 1,232,674
29 Maintenance Supervision and Engineering 9,023 66 15,494
30 Maintenance of Structures 187,725 25,215 65,337
31 Maintenance of Reservoirs,Dams,and 185,833 102,811 40,102
Waterways
32 Maintenance of Electric Plant 272,093 340,440 554,195
33 Maintenance of Misc Hydraulic Plant 50,256 1,006 14,181
34 Total Production Expenses(total 23 thru 33) 2,066,944 2,460,428 1,680,854
35 Expenses per net kWh 0 0.01 0
FERC FORM NO.1 (REV.12-03)
Page 406-407

Hydroelectric Generating Plant Statistics
FERC Licensed Project No. FERC Licensed Project No. FERC Licensed Project No. FERC Licensed Project No.
Line 2545 2545 2058 2545
No. Plant Name: Plant Name: Plant Name: Plant Name:
Monroe Street Nine Mile Falls Noxon Rapids Post Falls
1 Run-of--River Run-of-River Storage Storage
2 Conventional Conventional Outdoor Conventional
3 1890 1908 1959 1906
4 1992 1994 1977 1980
5 15 38 488 15
6 117 26 548 22
7 8,325 8,752 6,531 8,165
9 15 38 581 18
10 15 38 623 18
11 4 6 11 5
12 89,124,000 118,300,000 1,304,311,000 47,966,000
13 -
14 51,600 33,429 37,469,198 4,161,522
15 12,241,336 23,778,869 25,082,690 8,103,381
16 10,008,937 30,933,636 41,684,508 26,063,988
17 14,926,724 60,915,210 114,499,641 5,584,416
18 50,448 594,870 305,777 577,944
19
20 37,279,045 116,256,014 219,041,814 44,491,251
21 2,485.27 3,059.37 448.86 2,966.08
22
23 18,737 27,626 250,431 20,378
24
25 88,094 3,195
26 588,796 890,537 1,034,512 839,497
27 17,286 155,938 831,554 114,711
28
29 165,870 12,903 24,582 36,235
30 8,607 1,900 13,331 25,924
31 4,830 16,193 51,299 46,612
32 53,164 214,142 928,077 137,132
FERC FORM NO.1 (REV.12-03)
Page 406-407

Hydroelectric Generating Plant Statistics
FERC Licensed Project No. FERC Licensed Project No. FERC Licensed Project No. FERC Licensed Project No.
Line 2545 2545 2058 2545
No. Plant Name: Plant Name: Plant Name: Plant Name:
Monroe Street Nine Mile Falls Noxon Rapids Post Falls
33 2,727 4,837 61,528 2,475
34 860,017 1,324,076 3,283,408 1,226,159
35 0.01 0.01 0 0.03
FERC FORM NO.1 (REV.12-03)
Page 406-407

Hydroelectric Generating Plant Statistics
FERC Licensed Project No.
Line No. 2545
Plant Name:
Upper Falls
1 Run-0f--River
2 Conventional
3 1922
4 1922
5 10
6 20
7 8,760
8
9 10
10 10
11 4
12 59,914,000
13
14 1,081,854
15 4,960,136
16 10,046,229
17 5,449,312
18 508,242
19
20 22,045,773
21 2,204.58
22
23 18,214
24
25 202
26 580,773
27 48,188
28
29 17,818
30 32,444
31 13,957
32 46,892
FERC FORM NO.1 (REV.12-03)
Page 406-407

Hydroelectric Generating Plant Statistics
FERC Licensed Project No.
Line No. 2545
Plant Name:
Upper Falls
33 2,309
34 760,797
35 0.01
FERC FORM NO.I (REV.12-03)
Page 406-407

This report is:
Name of Respondent: (1)0 An Original Date of Report: Year/Period of Report
Avista Corporation (2)❑ A Resubmission 04/12/2024 End of:2023/Q4
GENERATING PLANT STATISTICS(Small Plants)
1n e" apac Net Peak Demand Net Generation
Line Name of Plant Year Orig.Const. Name Plate Rating MW( Excluding Plant Cost of Plant
(d min)
No. (a) (b) (MW) Use (f)
(c) ) (e)
1 Kettle Falls CT 2002 7.2 15 25,622,000 9,571,547
FERC FORM NO.1(REV.12-03)
Page 410-411

GENERATING PLANT STATISTICS(Small Plants)
Production Production
Expenses Expenses
Plant Cost(Incl Maintenance Fuel Costs(in
Operation Exc'I. Fuel Production
Line Asset Retire. Fuel Expenses Production Kind of Fuel cents(per
No. Costs Per MW Expenses p enses (k) Million Btu)
(9) O 0) (1)
1 1,323,903 105,528 986,744 57,050 Natural Gas 342.01
FERC FORM NO.1 (REV.12-03)
Page 410-411

GENERATING PLANT STATISTICS(Small Plants)
Line No. Generation Type
(m)
1 Gas Turbine
FERC FORM NO.1(REV.12-03)
Page 410-411

This report is:
Name of Respondent: (1)0 An Original Date of Report: Year/Period of Report
Avista Corporation (2) ❑A Resubmission 04/12/2024 End of:2023/Q4
TRANSMISSION LINE STATISTICS
LENGTH LENGTH
VOLTAGE(KV) VOLTAGE(KV) (Pole miles)-(Pole miles)-
-(Indicate -(Indicate (In the case (In the case
DESIGNATION DESIGNATION where other where other of of
than 60 cycle, than 60 cycle,3 underground underground
3 phase) phase) lines report lines report
circuit miles) circuit miles)
Line Type of On Structure On Number
No From To Operating Designated Supporting of Line Structures of of
Structure Designated Another Line Circuits
(a) (b) (c) (d) (e) (f) (g) (h)
1 Group Sum-60kV 60 60 1
2 Group Sum-115kV 115 115 1,569
3 Beacon Sub#4 BPA Bell Sub 230 230 Steel Pole 1 1
4 Beacon Sub#4 BPA Bell Sub 230 230 H Type 5 1
5 Beacon Sub#5 BPA Bell Sub 230 230 Steel 3 1
Tower
6 Beacon Sub#5 BPA Bell Sub 230 230 H Type 3 1
7 Beacon Cabinet Gorge Plant 230 230 Steel 1 1
Tower
8 Beacon Cabinet Gorge Plant 230 230 Steel Pole 41 2
9 Beacon Cabinet Gorge Plant 230 230 H Type 52 1
10 Beacon Sub Lolo Sub 230 230 Steel 1 1
Tower
11 Beacon Sub Lolo Sub 230 230 Steel Pole 22 2
12 Beacon Sub Lolo Sub 230 230 H Type 78 1
13 Beacon Sub Lolo Sub 230 230 H Type 8 1
14 Benewah Shawnee 230 230 Steel Pole 1 1
15 Benewah Shawnee 230 230 Steel Pole 59 1
16 Noxon Plant Pine Creek Sub 230 230 Steel Pole 29 1
17 Noxon Plant Pine Creek Sub 230 230 H Type 1 1
18 Noxon Plant Pine Creek Sub 230 230 H Type 14 1
19 Cabinet Gorge Plant Noxon 230 230 H Type 2 1
20 Cabinet Gorge Plant Noxon 230 230 H Type 17 1
21 Benewah Sw.Station Pine Creek Sub 230 230 H Type 43 1
22 Divide Creek Lolo Sub 230 230 H Type 10 1
23 Divide Creek Lolo Sub 230 230 H Type 33 1
24 North Lewiston Walla Walla 230 230 H Type 40 1
25 North Lewiston Walla Walla 230 230 H Type 4 1
FERC FORM NO.1 (ED.12-87)
Page 422-423

TRANSMISSION LINE STATISTICS
LENGTH LENGTH
VOLTAGE(KV) VOLTAGE(KV) (Pole miles)-(Pole miles)-
-(Indicate -(Indicate (In the case (In the case
DESIGNATION DESIGNATION where other where other of of
than 60 cycle, than 60 cycle,3 underground underground
3 phase) phase) lines report lines report
circuit miles) circuit miles)
Line Type of On Structure On Number
No. From To Operating Designated Supporting of Line Structures of of
Structure Designated Another Line Circuits
(a) (b) (c) (d) (e) (f) (g) (h)
26 North Lewiston Walla Walla 230 230 Steel Pole 4 1
27 North Lewiston Shawnee 230 230 Steel Pole 7 1
28 North Lewiston Shawnee 230 230 H Type 27 1
29 Saddle Mtn-Walla Wanapum 230 230 Steel 2 1
Walla Tower
30 Saddle Mtn-Walla Wanapum 230 230 H Type 33 1
Walla
31 Saddle Mtn-Walla Wanapum 230 230 H Type 46 1
Walla
32 BPA(Libby) Noxon Plant 230 230 Steel Pole 1 1
33 BPA/Hot Springs#1 Noxon Plant 230 230 Steel Pole 1 1
34 BPA/Hot Springs#2 Noxon Plant 230 230 Steel Pole 2 1
35 BPA/Hot Springs#2 Noxon Plant 230 230 H Type 1 1
36 BPA/Hot Springs#2 Noxon Plant 230 230 H Type 66 1
37 Coulee West Side Sub 230 230 Steel Pole 2 2
38 BPA Line West Side Sub 230 230 Steel Pole 2 2
39 Hatwai N.Lewiston Sub 230 230 H Type 7 1
40 Divide Creek Imnaha 230 230 H Type 2 1
41 Divide Creek Imnaha 230 230 H Type 2 1
42 Divide Creek Imnaha 230 230 H Type 16 1
43 Colstrip Plant Broadview 500 500 0
36 TOTAL 2,259 0 44
FERC FORM NO.1 (ED.12-87)
Page 422-423

TRANSMISSION LINE STATISTICS
COST OF COST OF LINE COST OF LINE
LINE(Include (Include in (Include in EXPENSES, EXPENSES, EXPENSES, EXPENSES,
in column Q) column 0) column 6) EXCEPT EXCEPT EXCEPT EXCEPT
Land,Land Land.Land Land,Land DEPRECIATION DEPRECIATION DEPRECIATION DEPRECIATION
rights,and rights,and rights,and AND TAXES AND TAXES AND TAXES AND TAXES
clearing right- clearing right- clearing right-
of-way) of-way) of-way)
Line Size of Construction Operation Maintenance
No. Conductor and Land Costs Total Costs Expenses Expenses Rents Total Expenses
Material
(i) G) (k) (1) (m) (n) (o) (p)
1 136,038 636,193 772,231 0
2 12,853,612 358,575,110 371,428,722 1,009,657 1,877,624 2,887,281
3 1272 ACSS 0 0
4 1272 ACSS 17,912 1,428,560 1,446,472 0 8,605 8,605
5 1272 ACSS 0 0
6 1272 ACSS 30,323 3,271,116 3,301,439 0 0 0
7 1590 ACSS 0 0
8 1590 ACSS 0 0
9 1590 ACSR 1,156,196 41,768,911 42,925,107 0 42,141 42,141
10 1590 ACSS 0 0
11 1590 ACSS 0 0
12 1272 AAC 0 0
13 1272 ACSS 456,162 33,607,469 34,063,631 0 9,298 9,298
14 1622 ACSS 0 0
15 1590 ACSS 570,207 47,971,774 48,541,981 0 0 0
16 1272 ACSR 0 0
17 1590 ACSS 0 0
18 954 AAC 1,098,606 17,920,790 19,019,396 3,453 89,645 93,098
19 795 ACSR 0 0
20 954 AAC 184,528 2,571,300 2,755,828 8,884 33,313 42,197
21 954 AAC 399,821 5,257,051 5,656,872 0 31,903 31,903
22 1590 ACSR 0 0
23 1272 AAC 167,484 21,687,001 21,854,485 0 72 72
24 1272 AAC 0 0
25 1272 ACSR 0 0
26 1272 ACSR 623,984 6,805,680 7,429,664 0 13,017 13,017
27 1272 ACSR 0 0
28 1272 ACSR 872,150 10,040,291 10,912,441 0 2,579 2,579
29 1590 ACSS 0 0
FERC FORM NO.1 (ED.12-87)
Page 422-423

TRANSMISSION LINE STATISTICS
COST OF COST OF LINE COST OF LINE
LINE(Include (Include in (Include In EXPENSES, EXPENSES, EXPENSES, EXPENSES,
in column 0) column 0) column 0) EXCEPT EXCEPT EXCEPT EXCEPT
Land,Land Land,Land Land,Land DEPRECIATION DEPRECIATION DEPRECIATION DEPRECIATION
rights,and rights,and rights,and AND TAXES AND TAXES AND TAXES AND TAXES
clearing right- clearing right- clearing right-
of-way) of-way) of-way)
Line Size of Construction Operation Maintenance
No Conductor and Land Costs Total Costs Expenses Expenses Rents Total Expenses
Material
(I) 0) (k) (I) (m) (n) (o) (p)
30 1272 ACSR 0 0
31 1272 AAC 314,998 14,079,914 14,394,912 0 3,239 3,239
32 1272 ACSR 0 0
33 1272 ACSR 0 18,772 18,772 0 14,200 14,200
34 1272 ACSR 0 0
35 1622 ACSS 0 0
36 1272 AAC 3,604,460 11,242,280 14,846,740 6,932 17,748 24,680
37 1272 ACSR 8,482 0 8,482 0 0 0
38 1272 ACSR 36,461 1,442,964 1,479,425 0 0 0
39 1590 ACSR 155,244 2,221,192 2,376,436 0 128 128
40 1622 ACSS 0 0
41 1590 ACSR 0 0
42 1272 AAC 205,262 1,312,224 1,517,486 0 0 0
43 595,789 39,009,258 39,605,047 81,495 140,057 80,425 301,977
36 23,487,719 620,867,850 644,355,569 1,110,421 2,283,569 80,425 3,474,415
FERC FORM NO.1 (ED.12-87)
Page 422-423

This report is:
Name of Respondent: (1)®An Original Date of Report: Year/Period of Report
Avista Corporation 04/12/2024 End of:2023/Q4
(2) ❑A Resubmission
TRANSMISSION LINES ADDED DURING YEAR
SUPPORTING SUPPORTING CIRCUITS
LINE DESIGNATION LINE DESIGNATION PER
STRUCTURE STRUCTURE
STRUCTURE
Line From To Line Length in Type Average Number Present
No. Miles per Miles
(a) (b) (c) (d) (e) (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
FERC FORM NO.1 (REV.12-03)
Page 424-425

TRANSMISSION LINES ADDED DURING YEAR
' SUPPORTING SUPPORTING CIRCUITS
LINE DESIGNATION LINE DESIGNATION PER
STRUCTURE STRUCTURE
STRUCTURE
Line Type Line Length in Average Number Present
No. From To Miles per Miles
(a) (b) (c) (d) (e) M _
30
31
32
33
34
35
36
37
38
39
40
41
42
43
F447
TOTAL 1
FERC FORM NO.1(REV.12-03)
Page 424-425

TRANSMISSION LINES ADDED DURING YEAR
CIRCUITS PER CONDUCTORS CONDUCTORS CONDUCTORS LINE COST
STRUCTURE
Line Voltage KV Land and Lan
No. Ultimate Size Specification Configuration and Spacing (Operating) Rights
(9) (h) (i) G) (k) (I)
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
FERC FORM NO.1 (REV.12-03)
Page 424-425

TRANSMISSION LINES ADDED DURING YEAR
CIRCUITS PER CONDUCTORS CONDUCTORS CONDUCTORS LINE COST
STRUCTURE
Line Voltage KV Land and Land
No. Ultimate Size Specification Configuration and Spacing (Operating) Rights
(g) (h) (i) G) (k) (1)
33
34
35
36
37
38
39
40
41
42
43
44
FERC FORM NO.1 (REV.12-03)
Page 424-425

TRANSMISSION LINES ADDED DURING YEAR
LINE COST LINE COST LINE COST LINE COST
Line Poles,Towers and Conductors and Asset Retire.Costs Total Construction
No. Fixtures Devices
(m) (n) (o) (P) (9)
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
FERC FORM NO.1 (REV.12-03)
Page 424-425

TRANSMISSION LINES ADDED DURING YEAR
LINE COST LINE COST LINE COST LINE COST
Line Poles,Towers and Conductors and Asset Retire.Costs Total Construction
No. Fixtures Devices
(m) (n) (o) (p) (G)
33
34
35
36
37
38
39
40
41
42
43
[44
FERC FORM NO.1(REV.12-03)
Page 424-425

This report is:
Name of Respondent: (1) An Original Date of Report: Year/Period of Report
Avista Corporation 04/12/2024 End of:2023/Q4
(2) ❑A Resubmission
SUBSTATIONS
Character of Character of VOLTAGE(In VOLTAGE VOLTAGE(In MVa)
Substation Substation MVa) (In MVa)
Capacity
Primary Secondary
of
Name and Location Transmission or Attended or Voltage(In Voltage(In Tertiary Voltage(In Substation
Line
of Substation Distribution Unattended MVa) (In
No. (a) (b) (b-1) MC,) d�) (e) Service)
(In MVa)
(f)
1 Airway Heights(WA) Distribution Unattended 115 13.8 2
2 Barker Road(WA) Distribution Unattended 115 13.8 12
3 Beacon(Trans.& Transmission Unattended 230 115 13.8 536
Dist.)(WA)
4 Boulder(Trans.& Transmission Unattended 230 115 13.8 318
Dist.)(WA)
5 Chester(WA) Distribution Unattended 115 13.8 24
6 Chee>elah 115Kv Distribution Unattended 115 13.2 12
(WA7 Colbert(WA) Distribution Unattended 115 13.8 12
8 Colllljge&Walnut Distribution Unattended 115 13.8 36
9 Colville 115 Kv(WA) Distribution I Unattended 115 13.8 32
10 Critchfield(WA) Distribution Unattended 115 13.8 12
11 Davenport(WA) Distribution Unattended 115 13.8 12
12 Deer Park(WA) Distribution Unattended 115 13.8 12
13 Downriver(WA) Distribution Unattended 115 13.8 24
14 Dry Creek(WA) Transmission Unattended 230 115 13.8 150
15 Dry Gulch(WA) Distribution Unattended 115 13.8 12
16 East Colfax(WA) Distribution Unattended 115 13.8 12
17 East Farms(WA) Distribution Unattended 115 13.8 12
18 Flint Rd(WA) Distribution Unattended 115 13.8 36
19 (Fran)is and Cedar Distribution Unattended 115 13.8 36
20 Gifford(WA) Distribution Unattended 115 34 16
21 Glenrose(WA) Distribution Unattended 115 13.8 12
22 Greenacres(WA) Distribution Unattended 115 13.8 18
23 Greenwood(WA) Distribution Unattended 115 13.8 12
24 Hallett&White(WA) Distribution Unattended 115 13.8 36
25 Indian Trail(WA) Distribution Unattended 115 13.8 12
FERC FORM NO.1 (ED.12-96)
Page 426-427

SUBSTATIONS
Character of Character of VOLTAGE(In VOLTAGE
Substation Substation MVa) (In MVa) VOLTAGE(In MVa)
Capacity
Primary Secondary of
Line
Name and Location Transmission or Attended or Voltage(In Voltage(In Tertiary Voltage(In Substation
of Substation Distribution Unattended MVa) (In
No. (a) (b) (b-1) (c) (d�) (e) Service)
(In MVa)
_ (f)
I
26 Kettle Falls(WA) Distribution Unattended 115 13.8 12
Lee&Reynolds
27 (WA) Distribution Unattended 115 13.8 36
28 Liberty Lake(WA) Distribution Unattended 115 13.8 24
29 Lind(WA) Distribution Unattended 115 13.8 12
30 Little Falls 115/34 Distribution Unattended 115 34 12
Kv 31 LyoAn)s&Standard Distribution Unattended 115 13.8 36
32 Mead(WA) Distribution Unattended 115 13.8 18
33 Metro(WA) Distribution Unattended 115 13.8 24
34 Milan(WA) Distribution Unattended 115 13.8 24
35 Millwood(WA) Distribution Unattended 115 13.8 24
36 (WA&Central Distribution Unattended 115 13.8 36
37 Northeast(WA) Distribution Unattended 115 13.8 24
38 Northwest(WA) Distribution Unattended 115 13.8 24
39 Opportunity(WA) Distribution Unattended 115 13.8 12
40 Othello(WA) Distribution Unattended 115 13.8 36
41 Post Street(WA) Distribution Unattended 115 13.8 60
42 Pound Lane(WA) Distribution Unattended 115 13.8 24
43 Ross Park(WA) Distribution Unattended 115 13.8 33
44 Roxboro(WA) Distribution Unattended 115 24 24
45 SadA)le Mountain Transmission Unattended 230 115 13.8 150
46 Shawnee(WA) Transmission Unattended 230 115 13.8 150
47 Silver Lake(WA) Distribution Unattended 115 13.8 12
48 Southeast(WA) Distribution Unattended 115 13.8 36
49 South Othello(WA) Distribution Unattended 115 13.8 12
50 South Pullman(WA) Distribution Unattended 115 13.8 30
51 Spokane Industrial Distribution Unattended 115 13.8 24
Park(WA)
52 Sunset(WA) Distribution Unattended 115 13.8 36
FERC FORM NO.1 (ED.12-96)
Page 426-427

SUBSTATIONS
Character of Character of VOLTAGE(In VOLTAGE
Substation Substation MVa) (In MVa) VOLTAGE(In MVa)
Capacity
Primary Secondary of
Name and Location Transmission or Attended or Tertiary Voltage(In Substation
Line Voltage(In Voltage(In
of Substation Distribution Unattended MVa) (In
No. (a) (b) (b-1) Mv)) MVa)
(e) Service)
(In MVa)
(9
754Thrird'&
iew(WA) Distribution Unattended 115 13.8 12
Hatch(WA) Distribution Unattended 115 13.8 54
55 Turner(WA) Distribution Unattended 115 13.8 36
56 Waikiki(WA) Distribution Unattended 115 13.8 24
57 West Side(WA) Transmission Unattended 230 115 13.8 300
58 Other:26 Subs.less Distribution Unattended 157
than 10MVA(WA)
59 Appleway(ID) Distribution Unattended 115 13.8 36
60 Avondale(ID) Distribution Unattended 115 13.8 12
61 Benewah(ID) Transmission Unattended 230 115 13.8 150
62 Big Creek(ID) Distribution Unattended 115 13.8 17
63 Blue Creek(ID) Distribution Unattended 115 13.8 12
64 Bunker Hill Limited Distribution Unattended 115 13.8 12
65 Cabinet Gorge Transmission Unattended 230 115 13.8 75
(Switchyard)(ID)
66 Clark Fork(ID) Distribution Unattended 115 21.8 10
67 Coeur d'Alene 15th Distribution Unattended 115 13.8 36
Ave.(ID)
68 Cottonwood(ID) Distribution Unattended 115 24.9 12
69 Dalton(ID) Distribution Unattended 115 13.8 36
70 Grangeville(ID) Distribution Unattended 115 13.8 24
71 Holbrook(ID) Distribution Unattended 115 13.8 12
72 Huetter(ID) Distribution Unattended 115 13.8 12
73 Idaho Road(ID) Distribution Unattended 115 13.8 12
74 Juliaetta(ID) Distribution Unattended 115 13.8 12
75 Kamiah(ID) Distribution Unattended 115 13.8 12
76 Kooskia(ID) Distribution Unattended 115 13.8 15
77 Lewiston Mill Rd Distribution Unattended 115 13.2 18
(ID78 Lolo(ID) (Trans.&Dist.) Transmission Unattended 230 115 13.8 262
79 Moscow(ID) Distribution Unattended 115 13.8 24
FERC FORM NO.1 (ED.12-96)
Page 426-427

SUBSTATIONS
Character of Character of VOLTAGE(tn VOLTAGE VOLTAGE(In MVa)
Substation Substation MVa) (In MVa)
Capacity
Primary Secondary of
Line Voltage(In Voltage(In
Name and Location Transmission or Attended or Tertiary Voltage(In Substation
No. of Substation Distribution Unattended MVa) MVa MVa) (In
(a) (b) (b-1) (c) (d)) (e) Service)
(In MVa)
80 Moscow 230 kV Transmission Unattended 230 115 13.8 162
(Trans.&Dist.)(ID)
North Lewiston
81 230kV(Trans.& Transmission Unattended 230 115 158
Dist.)(ID)
82 North Moscow(ID) Distribution Unattended 115 13.8 12
83 Oden(ID) Distribution Unattended 115 21.8 10
84 Oldtown(ID) Distribution Unattended 115 21.8 17
85 Orofino(ID) Distribution Unattended 115 24 20
86 Osbum(ID) Distribution Unattended 115 13.8 12
87 Pine Creek(Trans. Transmission Unattended 230 115 13.8 212
&Dist.)(ID)
88 Pleasant View(ID) Distribution Unattended 115 13.8 12
89 Plummer(ID) Distribution Unattended 115 13.8 12
90 Post Falls(ID) Distribution Unattended 115 13.8 18
91 Potlatch(ID) Distribution Unattended 115 24.9 15
92 Prairie(ID) Distribution Unattended 115 13.8 12
93 Priest River(ID) Distribution Unattended 115 20.8 10
94 Rathdrum(Trans.& Transmission Unattended 230 115 13.8 474
Dist.)(ID)
95 Sagle(ID) Distribution Unattended 115 21.8 12
96 Sandpoint(ID) Distribution Unattended 115 20.8 30
97 South Lewiston(ID) Distribution Unattended 115 13.8 27
98 Sweetwater(ID) Distribution Unattended 115 24.9 12
99 St.Manes(ID) Distribution Unattended 115 23.9 24
100 Tenth&Stewart(ID) Distribution Unattended 115 13.8 30
101 Other:13 Subs less Distribution Unattended 72
than 10 MVA(ID)
102 Other:1 Sub less Distribution Unattended 5
than 10 MVA(MT)
103 Boulder Park(WA Transmission Attended 115 13.8 36
Gen.Plant)
104 Kettle Falls(WA Transmission Attended 115 13.8 34
Gen.Plant)
FERC FORM NO.1 (ED.12-96)
Page 426-427

SUBSTATIONS
Character of Character of VOLTAGE(In VOLTAGE
Substation Substation MVa) (In MVa) VOLTAGE(In MVa)
Capacity
Primary Secondary of Voltage(In Voltage(In
Name and Location Transmission or Attended or Tertiary Voltage(In Substation
Line
of Substation Distribution Unattended MVa) (In
No. (a) (b) (b-1) MVa) MVa) (e) Service)
(c) (d) (In MVa)
(fl
105 Long Lake(WA Gen. Transmission Attended 115 4 80
Plant)
106 Nine Mile(WA Gen Transmission Attended 115 13.8 42
Plant)
107 Little Falls(WA Gen. Transmission Attended 115 4 24
Plant)
108 Northeast(WA Gen. Transmission Attended 115 13.8 36
Plant)
109 Post Street(WA Transmission Attended 13.8 4 35
Gen.Plant)
Cabinet Gorge
110 (HED)(ID Gen. Transmission Attended 230 13.8 300
Plant)
i
111 Post Falls(ID Gen. Transmission Attended 115 2.3 12
Plant)
112 Rathdrum(ID Gen. Transmission Attended 115 13.8 114
Plant)
113 Noxon(MT Gen. Transmission Attended 230 13.8 435
Plant)
114 Coyote Springs II Transmission Attended 500 13.8 18 270
(OR Gen.Plant)
115 Distribution 9,890 1,335.8 0 2,040
Substations
Distribution
116 Substations 9,890 1,335.8 0 2,040
Unattended
117 Transmission 4,883.8 1,619.7 183.60000000000002 4,515
Substations
Transmission
118 Substations 1,893.8 124.7 18 1,418
Attended
Transmission
119 Substations 2,990 1,495 165.60000000000002 3,097
Unattended
120 Total 6,555
FERC FORM NO.1 (ED.12-96)
Page 426-427

SUBSTATIONS
Conversion Apparatus and Special Conversion Conversion
Apparatus and Apparatus and
Equipment
Special Equipment Special Equipment
Number of Number of Spare Total Capacity(In
Line Transformers In Transformers Type of Equipment Number of Units MVa)
No. Service (h) (i)
(g)
1 2 Frcd Oil&Air Fan&Caps 39 40
2 1 Two Stage Fan 1 20
3 4 Two Stage Fan 2 560
4 3 Two Stage Fan 3 I 530
5 2 Frcd Oil&Air Fan 2 40
6 1 Two Stage Fan 1 20
7 1 Frcd Oil&Air Fan&Caps 16 20
8 2 Two Stage Fan 2 60
9 3 Frcd Oil&Air Fan 3 49
10 1 Two Stage Fan 1 20
11 1 Frcd Oil&Air Fan 1 20
12 1 Two Stage Fan 1 20
13 2 Frcd Oil&Air&Two Stage Fan 2 40
14 1 Two Stage Fan&Caps 224 250
15 1 Frcd Oil&Air Fan 1 20
16 1 Frcd Oil&Air Fan �1 20
17 1 Two Stage Fan 1 20
18 2 Two Stage Fan 2 60
19 2 Two Stage Fan 2 60
20 2 One Stage Fan 1 17
21 1 Frcd Oil&Air Fan 1 20
22 1 Two Stage Fan 1 30
23 1 Two Stage Fan 1 20
24 2 Two Stage Fan 2 60
25 1 Two Stage Fan 1 20
26 1 Frcd Oil&Air Fan 1 20
27 2 Two Stage Fan 2 60
28 2 Two Stage Fan 2 40
29 1 Two Stage Fan 1 20
30 1
31 2 Two Stage Fan 2 60
FERC FORM NO.1 (ED.12-96)
Page 426-427

SUBSTATIONS
Conversion Apparatus and Special Conversion Conversion
Equipment Apparatus and Apparatus and
Special Equipment Special Equipment
Number of Number of Spare Total Capacity(In
Line Transformers In Transformers Type of Equipment Number of Units Mva)
No. Service (h) (i) (j) (k)
(9)
32 1 Two Stage Fan 1 30
33 2 Two Stage Fan 2 40
34 2 Frcd Oil&Air Fan 2 40
35 2 Two Stage Fan 2 40
36 2 Two Stage Fan 2 60
37 2 Two Stage Fan 2 40
38 2 Two Stage Fan 2 40
39 1 Two Stage Fan 1 20
40 2 Two Stage Fan 2 60
41 2 Frcd Oil 2 60
42 2 Two Stage Fan 2 40
43 2 Two Stage Fan 2 57
44 2 Two Stage Fan 2 40
45 1 Two Stage Fan 1 250
46 1 Two Stage Fan 1 250
47 1 Two Stage Fan 1 20
48 2 Two Stage Fan 2 60
49 1 Two Stage Fan 1 20
50 2 Two Stage Fan 2 50
51 2 Two Stg,Frcd Oil Fan&Caps 14 40
52 2 Two Stage Fan&Caps 50 60
53 1 Two Stage Fan 1 20
54 3 Two Stage Fan&Caps 103 90
55 2 Two Stage Fan 2 60
56 2 Two Stage Fan 2 40
57 2 Two Stage Fan 2 500
58 27
59 2 Two Stage Fan 2 60
60 1 Two Stage Fan 1 20
61 1 Two Stage Fan&Caps 224 250
62 2 Portable Fan 2 22
FERC FORM NO.1 (ED.12-96)
Page 426.427

SUBSTATIONS
Conversion Apparatus and Special Conversion Conversion
Equipment Apparatus and Apparatus and
Special Equipment Special Equipment
Number of Number of Spare Total Capacity(in
Line Transformers In Type of Equipment Number of Units
No. Service Transformers (i) Mk)
63 1 Two Stage Fan 1 20
64 1 Frcd Air Fan 1 16
65 1 Two Stage Fan 1 125
66 1 Frcd Air Fan 1 12
67 2 Two Stage Fan 2 60
68 1 Two Stage Fan 1 20
69 2 Two Stage Fan 2 60
70 4 Frcd Oil&Air&Pt Fan&Caps 17 34
71 1 Two Stage Fan 1 20
72 1 Two Stage Fan 1 20
73 1 Two Stage Fan 1 20
74 1 Frcd Oil&Air Fan 1 20
75 1 Two Stage Fan 1 20
76 3 Frcd Air Fan 3 20
77 1 Two Stage Fan 1 30
78 3 Frcd Oil&Air Fan&Two Stage Fan 1 270
79 2 Frcd Oil&Air&Two Stage 2 40
80 2 Two Stage Fan&Caps 76 270
81 2 Frcd Air Fan&Caps&Two Stage 50 259
Fan
82 1 Two Stage Fan 1 20
83 1 Frcd Air Fan 1 12
84 2 Frcd Air Fan 2 22
85 2 Frcd Oil&Air Fan 1 28
86 1 Portable Fan 1 15
87 3 Two Stage Fan&Caps 47 270
88 1 Two Stage Fan 1 20
89 1 Two Stage Fan 1 20
90 1 Two Stage Fan 1 30
91 2 Portable Fan 2 19
92 1 ` Frcd Oil&Air Fan 1 20
FERC FORM NO.1 (ED.12-96)
Page 426-427

SUBSTATIONS
Conversion Apparatus and Special Conversion Conversion
Equipment Apparatus and Apparatus and
Special Equipment Special Equipment
Number of Number of Spare Total Capacity(In
Line Transformers In Transformers Type of Equipment Number of Units MVa)
No. Service (h) W (j) (k)
(g)
93 1 Frcd Air Fan 1 13
94 4 Frcd Oil&Air Fan&Caps 39 490
95 1 Two Stage Fan 1 20
96 3 Frcd Air Fan 3 38
97 4 j Portable Fan,Frcd Oil&Air 4 39
98 1 I Frcd Oil&Air Fan 1 20
99 2 Two Stage Fan 2 40
100 2 Frcd Oil&Air&Two Stage 2 50
101 13
102 1
103 1 Two Stage Fan 1 60
104 1 1 Two Stage Fan 1 62
105 4 1
106 2 Two Stage Fan 1 56
107 2 Frcd Oil&Air Fan 2 40
108 1 Two Stage Fan 1 60
109 2
110 6 1
111 1 Frcd Air&Oil&Air Fan 1 16
112 2 1 Two Stage Fan 2 190
113 9 1 Two Stage Fan 6 635
114 3 2 Two Stage Fan 3 450
115 179 0 360 2,863
116 179 0 360 2,863
117 62 7 689 5,843
118 34 7 18 1,569
119 28 0 671 4,274
120
FERC FORM NO.1 (ED.12-96)
Page 426-427

This report is:
Name of Respondent: (1)0 An Original Date of Report: Year/Period of Report
Avista Corporation (2) ❑A Resubmission 04/12/2024 End of:2023/Q4
TRANSACTIONS WITH ASSOCIATED(AFFILIATED)COMPANIES
Account(s) Amount Charged or
Line Description of the Good or Servio. Name of Associated/Affiliated Company Charged or Credited
No. (a) (b) Credited
( (d1
c)
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 Corporate Support Avista Development 146000 200,750
22 Corporate Support Avista Capital 146000 65,093
23 Corporate Support AELP 146000 34,020
24 Corporate Support AJT Mining 146000 1,561
25 Corporate Support Avista Edge 146000 160,199
42
FERC FORM NO.1 ((NEW))
Page 429