2024Avista FERC Form No. 1 - Electric.pdf

THIS FILING IS
Item 1: An Initial(Original)Submission OR ❑ Resubmission No.
FERC FINANCIAL REPORT
FERC FORM No. 1 : Annual Report of
Major Electric Utilities, Licensees
and Others and Supplemental
Form 3-Q: Quarterly Financial Report
These reports are mandatory under the Federal Power Act,Sections 3,4(a),
304 and 309,and 18 CFR 141.1 and 141.400.Failure to report may result in
criminal fines,civil penalties and other sanctions as provided by law.The
Federal Energy Regulatory Commission does not consider these reports to be
f confidential nature
Exact Legal Name of Respondent(Company) Year/Period of Report
End of:2024/Q4
Avista Corporation
FERC FORM NO.1 (REV.02-04)

INSTRUCTIONS FOR FILING FERC FORM NOS. 1 and 3-Q
GENERAL INFORMATION
Purpose
FERC Form No.1 (FERC Form 1)is an annual regulatory requirement for Major electric utilities,licensees and others(18 C.F.R.§141.1).
FERC Form No.3-Q(FERC Form 3-Q)is a quarterly regulatory requirement which supplements the annual financial reporting
requirement(18 C.F.R.§141.400).These reports are designed to collect financial and operational information from electric utilities,
licensees and others subject to the jurisdiction of the Federal Energy Regulatory Commission.These reports are also considered to be
non-confidential public use forms.
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).
Ill. What and Where to Submit
a. Submit FERC Form Nos.1 and 3-Q electronically through the eCollection portal at hnps1/eCollection.ferc.gov,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. Forthe CPA Certification Statement,submitwithin 30 days afterfiling 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 Paaes
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 asset 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 h#gs://www,ferc.govfferc-online/ferc-online/frequently-asked-questions-fags-
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-indu try-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.
Il. Enter in whole numbers(dollars or MWH)only,except where otherwise noted.(Enter cents for averages and figures per unit where cents
are important.The truncating of cents is allowed except on the four basic financial statements where rounding is required.)The amounts
shown on all supporting pages must agree with the amounts entered on the statements that they support.When applying thresholds to
determine significance for reporting purposes,use for balance sheet accounts the balances at the end of the current reporting period,and
use for statement of income accounts the current year's year to date amounts.
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.
N F-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.§791 a-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 other things,full information as to assets and Liabilities,capitalization,net investment,and
reduction thereof,gross receipts,interest due and paid,depreciation,and other reserves,cost of project and other facilities,cost of
maintenance and operation of the project and other facilities,cost of renewals and replacement of the project works and other facilities,
depreciation,generation,transmission,distribution,delivery,use,and sale of electric energy.The Commission may require any such
person to make adequate provision for currently determining such costs and other facts.Such reports shall be made under oath unless
the Commission otherwise specifies'.10

"Sec.309.
The Commission shall have power to perform any and all acts,and to prescribe,issue,make,and rescind such orders,rules and
regulations as it may find necessary or appropriate to carry out the provisions of this Act.Among other things,such rules and regulations
may define accounting,technical,and trade terms used in this Act;and may prescribe the FERC Form or FERC Forms of all statements,
declarations,applications,and reports to be filed with the Commission,the information which they shall contain,and the time within which
they shall be field..."
GENERAL PENALTIES
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:2024/Q4
03 Previous Name and Date of Change(If name changed during year)
04 Address of Principal Office at End of Period(Street,City,State,Zip Code)
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 10 Date of Report(Mo,Da,Yr)
Code (1)0 An Original
04/18/2025
[phone]
(2) ❑ A 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 04/18/2025
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 04/18/2025 End of:2024/Q4
LIST OF SCHEDULES(Electric Utility)
Line Title of Schedule Reference Page No. Remarks
No. (a) (b) (c)
Identification 1
List of Schedules
1 General Information 101
2 Control Over Respondent 102
3 Corporations Controlled by Respondent 103
4 Officers 104
5 Directors 105
6 Information on Formula Rates 106
7 Important Changes During the Year 108
8 Comparative Balance Sheet 110
9 Statement of Income for the Year 114
10 Statement of Retained Earnings for the Year 118
12 Statement of Cash Flows 120
12 Notes to Financial Statements 122
13 Statement of Accum Other Comp Income,Comp 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
I
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
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)
26 Transmission Service and Generation 231
Interconnection Study Costs
27 Other Regulatory Assets 232
28 Miscellaneous Deferred Debits 233
29 Accumulated Deferred Income Taxes 234
30 Capital Stock 250
31 Other Paid-in Capital 253
32 Capital Stock Expense 254b
33 Long-Term Debt 256
34 Reconciliation of Reported Net Income with Taxable 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 335
52 Depreciation and Amortization of Electric Plant 336
(Account 403,404,405)
53 Regulatory Commission Expenses 350
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)
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 —
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)0 An Original Date of Report: Year/Period of Report
Avista Corporation 04/18/2025 End of:2024/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 differentfrom 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 Property 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 furnished 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)®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 (2) A Resubmission
04/18/2025 End of:2024/Q4
❑
CORPORATIONS CONTROLLED BY RESPONDENT
Percent
Line Name of Company Controlled Kind of Business Voting Stock Footnote Ref.
No. (a) (b) Ownod (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 Property 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
Right to Purchase Snettisham 100% 14
14 FSnettisham Electric Company
FERC FORM No.1 (ED.12-96)
Page 103

This report is:
Name of Respondent: (1)0 An Original Date of Report: Year/Period of Report
Avista Corporation 04/18/2025 End of.2024/Q4
(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 895,500 2024-01-01 2024-12-31
2 President and Chief Operating H.L.Rosentrater 506,808 2024-01-01 2024-12-31
Officer
Senior Vice President,Chief
3 Financial Officer,Treasurer and K.J.Christie 428,770 2024-01-01 2024-12-31
Regulatory Affairs Officer
Senior Vice President,Chief
4 Strategy and Clean Energy J.R.Thackston 398,478 2024-01-01 2024-12-31
Officer
Senior Vice President,General
5 Council,Corporate Secretary G.C.Hesler 417,942 2024-01-01 2024-12-31
and Chief Ethics/Compliance
Officer
6 Senior Vice President,Safety B.A.Cox 365,026 2024-01-01 2024-12-31
and Chief People Officer
Vice President Community
7 Affairs and Chief Customer L.D.Hill 341,471 2024-01-01 2024-12-31
Officer
8 Vice President,Controller,and R.L.Krasselt 285,488 2024-01-01 2024-12-31
Principal Accounting Officer
Vice President and Chief
9 Counsel for Regulatory and D.J.Meyer 340,469 2024-01-01 2024-12-31
Governmental Affairs
10 Vice President,Energy S.J.Kinney 311,808 2024-01-01 2024-12-31
Resources
11 Vice President,Energy Delivery J.D.DiLuciano 262,906 2024-01-01 2024-12-31
Vice President,Chief Information
12 Officer,and Chief Security W.O.Manuel 372,616 2024-01-01 2024-12-31
Officer
FERC FORM No.1 (ED.12-96)
Page 104

This report is:
Name of Respondent: (1)Z An Original Date of Report: Year/Period of Report
Avista Corporation (2) ❑A Resubmission 04/18/2025 End of:2024/Q4
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.Morris(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 Donald C.Burke 16 Ivy Court,Langhorne,PA true false
19047
4 Scott H.Maw 115 NW 78th St.,Seattle,WA false false
98117
5 Rebecca A.Klein 611 S.Congress Ave.,Suite false false
125,Austin,TX 78704
6 Je P.O.Box 9000,Spokane,WA
ffiY L.Philipps PP 99209 false false
7 Heidi B.Stanley P.O.Box 2884,Spokane,WA true false
99220
8 Janet D.Widmann 26 Sanford Ln.,Lafayette,CA false false
94549
9 Julie A.Bentz 38748 Lulay Rd,Scio,OR false false
97374
10 Sena M.Kwawu 2507 101st Lane NE,Bellevue, false false
WA 98004
11 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 04/18/2025 End of:2024/Q4
(2) ❑ A Resubmission
IMPORTANT CHANGES DURING THE QUARTERIYEAR
Give particulars(details)concerning the matters indicated below.Make the statements explicit and precise,and numberthem in accordance
with the inquiries.Each inquiry should be answered.Enter"none,""not applicable,"or"NA"where applicable.If information which answers
an inquiry is given elsewhere in the report,make a reference to the schedule in which it appears.
1. Changes in and important additions to franchise rights:Describe the actual consideration given therefore and state from whom the
franchise rights were acquired.If acquired without the payment of consideration,state that fact.
2. Acquisition of ownership in other companies by reorganization,merger,or consolidation with other companies:Give names of
companies involved,particulars concerning the transactions,name of the Commission authorizing the transaction,and reference to
Commission authorization.
3. Purchase or sale of an operating unit or system:Give a brief description of the property,and of the transactions relating thereto,and
reference to Commission authorization,if any was required.Give date journal entries called for by the Uniform System of Accounts
were submitted to the Commission.
4. Important leaseholds(other than leaseholds for natural gas lands)that have been acquired or given,assigned or surrendered:Give
effective dates,lengths of terms,names of parties,rents,and other condition.State name of Commission authorizing lease and give
reference to such authorization.
5. Important extension or reduction of transmission or distribution system:State territory added or relinquished and date operations
began or ceased and give reference to Commission authorization,if any was required.State also the approximate number of
customers added or lost and approximate annual revenues of each class of service.Each natural gas company must also state major
new continuing sources of gas made available to it from purchases,development,purchase contract or otherwise,giving location and
approximate total gas volumes available,period of contracts,and other parties to any such arrangements,etc.
6. Obligations incurred as a result of issuance of securities or assumption of liabilities or guarantees including issuance of short-term
debt and commercial paper having a maturity of one year or less.Give reference to FERC or State Commission authorization,as
appropriate,and the amount of obligation or guarantee.
7. Changes in articles of incorporation or amendments to charter:Explain the nature and purpose of such changes or amendments.
8. State the estimated annual effect and nature of any important wage scale changes during the year.
9. State briefly the status of any materially important legal proceedings pending at the end of the year,and the results of any such
proceedings culminated during the year.
10. Describe briefly any materially important transactions of the respondent not disclosed elsewhere in this report in which an officer,
director,security holder reported on Pages 104 or 105 of the Annual Report Form No.1,voting trustee,associated company or known
associate of any of these persons was a party or in which any such person had a material interest.
11. (Reserved.)
12. If the important changes during the year relating to the respondent company appearing in the annual report to stockholders are
applicable in every respect and furnish the data required by Instructions 1 to 11 above,such notes may be included on this page.
13. Describe fully any changes in officers,directors,major security holders and voting powers of the respondent that may have occurred
during the reporting period.
14. In the event that the respondent participates in a cash management program(s)and its proprietary capital ratio is less than 30 percent
please describe the significant events or transactions causing the proprietary capital ratio to be less than 30 percent,and the extent to
which the respondent has amounts loaned or money advanced to its parent,subsidiary,or affiliated companies through a cash
management program(s).Additionally,please describe plans,if any to regain at least a 30 percent proprietary ratio.
1. None
2.None
3.None
4.None
5.None

6.Reference is made to Notes 10,11 and 12 of the Notes to the Financial Statements
7.None
8. Average annual wage increases were 3.7 percent for non-exempt employees and 3.9 percent for exempt employees,effective February 26,2024.Officers
received average increases of 4.5 percent effective February 12,2024.Bargaining Unit employees annual wage increase is retroactively effective on March
26,2024 in the amount of 5 percent.
9.Reference is made to Note 15 of the Notes to the Financial Statements
10.None
13. In August 2024,Chief Executive Officer Dennis Vermillion announced he will retire from the Company in the first quarter of 2025.Avista President
and Chief Operating Officer Heather Rosentrater has been appointed CEO by the board of directors,effective January 1,2025.She has also been appointed
to the board of directors,effective January 1,2025.
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)0 An Original Date of Report: Year/Period of Report
Avista Corporation 04/18/2025 End of:2024/Q4
(2) El 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) O Quarter/Year Balance (d)
(c)
1 UTILITY PLANT
2 Utility Plant(101-106,114) 200 8,212,758,967 7,852,959,203
3 Construction Work in Progress(107) 200 206,589,639 170,812,964
4 TOTAL Utility Plant(Enter Total of lines 2 and 3) 8,419,348,606 8,023,772,167
5 (Less)Accum.Prov.for Depr.Amort.Depl.(108, 200 2,959,941,113 2,796,332,034
110,111,115)
6 Net Utility Plant(Enter Total of line 4 less 5) 5,459,407,493 5,227,440,133
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) 5,459,407,493 5,227,440,133
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) 22,724,548 22,796,933
19 (Less)Accum.Prov.for Depr.and Amort.(122) 114,549 110,345
20 Investments in Associated Companies(123) 11,547,000 11,547,000
21 Investment in Subsidiary Companies(123.1) 224 261,742,212 265,210,641
23 Noncurrent Portion of Allowances 228
24 Other Investments(124) 14,094 14,094
25 Sinking Funds(125) 0 0
26 Depreciation Fund(126) 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/Year Balance (d)
(c)
27 Amortization Fund-Federal(127) 0 0
28 Other Special Funds(128) 21,331,917 15,335,490
29 Special Funds(Non Major Only)(129) 0 0
30 Long-Term Portion of Derivative Assets(175) 0 0
31 Long-Term Portion of Derivative Assets-Hedges 0 0
(176)
32 TOTAL Other Property and Investments(Lines 317,245,222 314,793,813
18-21 and 23-31)
33 CURRENT AND ACCRUED ASSETS
34 Cash and Working Funds(Non-major Only) 0 0
(130)
35 Cash(131) 2,733,182 11,843,507
36 Special Deposits(132-134) 0 0
37 Working Fund(135) 1,108,576 758,362
38 Temporary Cash Investments(136) 19,917,239 15,991,036
39 Notes Receivable(141) 0 0
40 Customer Accounts Receivable(142) 189,162,196 199,763,204
41 Other Accounts Receivable(143) i 43,278,432 38,651,095
42 (Less)Accum.Prov.for Uncollectible Acct.-Credit 4,804,889 4,905,146
(144)
43 Notes Receivable from Associated Companies 29,187,996 20,584,744
(145)
44 Accounts Receivable from Assoc.Companies 85,106 978,859
(146)
45 Fuel Stock(151) 227 6,331,080 4,683,150
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) 227 101,576,700 79,492,528
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 1,175,388 30,071,678
53 (Less)Noncurrent Portion of Allowances 228
54 Stores Expense Undistributed(163) 227 0 0
FERC FORM No.1 (REV.12-03)
Page 110-111

COMPARATIVE BALANCE SHEET(ASSETS AND OTHER DEBITS)
Line Title of Account Re1.Page No. Quarter/Year Balance Prior YcarEnd Balance 12131
No. (a) (b) (c) (d)
55 Gas Stored Underground-Current(164.1) 10,258,810 16,271,620
56 Liquefied Natural Gas Stored and Held for 0 0
Processing(164.2-164.3)
57 Prepayments(165) 29,781,526 50,221,552
58 Advances for Gas(166-167) 0 0
59 Interest and Dividends Receivable(171) 4,053,293 2,627,341
60 Rents Receivable(172) 6,058,492 7,380,742
61 Accrued Utility Revenues(173) 0 0
62 Miscellaneous Current and Accrued Assets(174) 10,090 0
63 Derivative Instrument Assets(175) 11,061,997 11,821,033
64 (Less)Long-Term Portion of Derivative 0 0
Instrument Assets(175)
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 34 450,975,214 486,235,305
through 66)
68 DEFERRED DEBITS
69 Unamortized Debt Expenses(181) 21,102,539 21,586,301
70 Extraordinary Property Losses(182.1) 230a 0 0
i
71 Unrecovered Plant and Regulatory Study Costs 230b 0 0
(182.2)
72 Other Regulatory Assets(182.3) 232 893,411,579 898,192,107
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) 691,571 858,506
77 Temporary Facilities(185) 0 0
78 Miscellaneous Deferred Debits(186) 233 104,072,323 87,517,904
79 Def.Losses from Disposition of Utility Pit.(187) 0 0
80 Research,Devel.and Demonstration Expend. 352 0 0
(188)
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/Year Balance (d)
(c)
81 Unamortized Loss on Reaquired Debt(189) 5,232,161 5,701,051
82 Accumulated Deferred Income Taxes(190) 234 154,122,918 214,152,188
83 Unrecovered Purchased Gas Costs(191) (24,996,804) 51,370,535
84 Total Deferred Debits(lines 69 through 83) 1,153,636,287 1,279,378,592
85 TOTAL ASSETS(lines 14-16,32,67,and 84) 7,388,256,292 7,314,839,919
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 04/18/2025 End of:2024/Q4
(2) El A Resubmission
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) QuarterNear Balance (d)
1 PROPRIETARY CAPITAL u,.., ��i�;ra i.�:' r�; ,r?
2 Common Stock Issued(201) 250 1,667,222,874 1,596,986,047
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) (2,732,405)
i
8 Installments Received on Capital Stock(212) 252 0
9 (Less)Discount on Capital Stock(213) 254 0
10 (Less)Capital Stock Expense(214) 254b (55,172,369) (50,073,294)
11 Retained Earnings(215,215.1,216) 118 831,698,463 798,215,179
12 Unappropriated Undistributed Subsidiary 118 39,097,599 43,138,900
Earnings(216.1)
13 (Less)Reacquired Capital Stock(217) 250 0 0
14 Noncorporate Proprietorship(Non-major only) 0 0
(218)
15 Accumulated Other Comprehensive Income 122(a)(b) 355,480 (357,109)
16 Total Proprietary Capital(lines 2 through 15) 2,590,814,380 2,485,323,906
17 LONG-TERM DEBT
18 Bonds(221) 256 2,543,700,000 2,543,700,000
19 (Less)Reacquired Bonds(222) 256 0 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) 97,717 106,600
23 (Less)Unamortized Discount on Long-Term 749,866 795,576
Debt-Debit(226)
24 Total Long-Term Debt(lines 18 through 23) 2,594,594,851 2,510,858,024
25 OTHER NONCURRENT LIABILITIES
26 Obligations Under Capital Leases-Noncurrent 61,843,479 63,558,661
(227)
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 12131
No. (a) (b) Quarter/Year Balance (d)
(c)
27 Accumulated Provision for Property Insurance 0 0
(228.1)
28 Accumulated Provision for Injuries and Damages 1,245,000 995,000
(228.2)
Accumulated Provision for Pensions and
29 Benefits(228.3) 74,523,208 89,829,937
30 Accumulated Miscellaneous Operating 0 0
Provisions(228.4)
31 Accumulated Provision for Rate Refunds(229) 447,773 618,329
32 Long-Term Portion of Derivative Instrument 11,967,539 17,902,180
Liabilities
33 Long-Temi Portion of Derivative Instrument 0 0
Liabilities-Hedges
34 Asset Retirement Obligations(230) 18,173,105 18,058,399
35 Total Other Noncurrent Liabilities(lines 26 168,200,104 190,962,506
through 34)
36 CURRENT AND ACCRUED LIABILITIES
37 Notes Payable(231) 342,000,000 349,000,000
38 Accounts Payable(232) 122,286,620 136,101,468
39 Notes Payable to Associated Companies(233) 0 0
40 Accounts Payable to Associated Companies 0 0
(234)
41 Customer Deposits(235) 13,883,447 11,208,693
42 Taxes Accrued(236) 262 33,241,269 31,879,207
43 Interest Accrued(237) 22,596,692 22,318,892
44 Dividends Declared(238) 0
45 Matured Long-Term Debt(239) 0 0
46 Matured Interest(240) 0 0
47 Tax Collections Payable(241) 397,222 40,534
48 Miscellaneous Current and Accrued Liabilities 75,770,212 99,744,896
(242)
49 Obligations Under Capital Leases-Current(243) 4,519,343 4,490,212
50 Derivative Instrument Liabilities(244) 26,352,702 35,118,959
51 (Less)Long-Term Portion of Derivative
Instrument Liabilities 11,967,539 17,902,180
52 Derivative Instrument Liabilities-Hedges(245) 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. n e8r n o Prior Year End Balance 12131
No. (a) (b) Quarter/Year Balance (d)
(c)
53 (Less)Long-Term Portion of Derivative 0 0
Instrument Liabilities-Hedges
54 Total Current and Accrued Liabilities(lines 37 629,079,968 672,000,681
through 53)
55 DEFERRED CREDITS
56 Customer Advances for Construction(252) 6,506,104 4,436,513
57 Accumulated Deferred Investment Tax Credits 266 28,097,819 28,233,162
(255)
58 Deferred Gains from Disposition of Utility Plant 0 0
(256)
59 Other Deferred Credits(253) 269 33,705,422 32,918,243
60 Other Regulatory Liabilities(254) 278 452,664,319 479,233,915
61 Unamortized Gain on Reacquired Debt(257) 820,535 942,384
62 Accum.Deferred Income Taxes-Accel.Amort. 272 0 0
(281)
63 Accum.Deferred Income Taxes-Other Properly 657,327,906 653,219,870
(282)
64 Accum.Deferred Income Taxes-Other(283) 226,444,884 256,710,715
65 Total Deferred Credits(lines 56 through 64) 1,405,566,989 1,455,694,802
66 TOTAL LIABILITIES AND STOCKHOLDER 7,388,256,292 7,314,839,919
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 (2) ❑ A Resubmission 04/18/2025 End of:2024/Q4
STATEMENT OF INCOME
Current 3 Prior 3
Total Current Total Prior Year Months Months Electric Utility Electric Utility
Line Title of Account to Date Balance Current Year to
(Ref.) Year to Date Ended- Ended- Previous Year
Page No. Balance for Quarter) Quarter) to Date in
No. (a) b for QuarterNear y y Date(in dollars)
O Quarter/Year (d) Only-No 4th Only-No 4th (g) dollars}
(c) Quarter Quarter (h)
(e) (�
UTILITY
1 OPERATING
INCOME
2 Operating00 Revenues 300 1,932,090,931 1,813,140,867 1,326,892,156 1,193,674,365
3 Operating Expenses
4 Operation
er tion Expenses 320 1,151,916,199 1,129,074,478 753,625,794 674,026,748
01)
5 Maintenance 320 86,506,944 86,720,955 71,891,225 71,447,477
Expenses(402)
6 Depreciation 336 199,439,998 194,611,959 153,386,157 149,272,689
Expense(403)
Depreciation
7 336 0 0
Expense for Asset 0 0
Retirement Costs
(403.1)
8 Amort.&Depl.of 336 64,711,332 62,239,993 49,179,154 46,738,641
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
Expenses(407.2)
12 Regulatory Debits 92,390,929 64,155,411 29,114,169 21,751,021
(407.3)
13 (Less)Regulatory 102,105,265 102,019,225 50,294,571 43,048,247
Credits(407.4)
14 Taxes Other Than 262 120,874,933 118,141,439 83,037,800 79,882,775
Income Taxes(408.1)
Income Taxes-
15 Federal(409.1) 262 8,736,878 2,419,168 (11,228,757) (7,715,052)
16 Income Taxes-Other 262 1,186,219 895,264 20,284 20,224
(409.1) l
FERC FORM No.1 (REV.02-04)
Page 114-117

STATEMENT OF INCOME
- . -- --- Current 3 Prior 3 -
Total ant Months Months Electric Utility
Total Prior Year Electric Utility
(Ref.) Yearta'Claite Ended- Ended• Previous Year
Line Title of Account to Date Balance Current Year to Page No. Balance for Quarterly Quarterly to Date(in
No. (a) (b) Quarter/Year for Quarter/Year Only-No 4th Only-No 4th Date(in dollars) dollars)
(c) (d) Quarter Quarter (g) (h)
(e) (f)
17 Provision for Deferred 234, 58,356,281 36,404,931 45,633,776 29,355,257
Income Taxes(410.1) 272
(Less)Provision for
Deferred Income 234,
18 65,245,950 74,741,597 31,152,894 47,088,945
Taxes-Cr.(411.1) 272
19 Investment Tax Credit 266 (135,343) (551,283) (130,623) (546,563)
Adj.-Net(411.4)
(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)
24 Accretion Expense 0 0
(411.10)
TOTAL Utility
25 Operating Expenses 1,616,633,155 1,517,351,493 1,093,081,514 974,096,025
(Enter Total of lines 4
thru 24)
Net Util Oper Inc
27 (Enter Tot line 2 less 315,457,776 295,789,374 233,810,642 219,578,340
25)
28 Other Income and
Deductions
29 Other Income
Nonutilty Operating
30 Income
Revenues From
31 Merchandising,
Jobbing and Contract
Work(415)
(Less)Costs and Exp.
32 of Merchandising, 0 0
Job.&Contract Work
(416)
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
Line Title of Account to Date Balance Current Year to
No. (a) Page No. Balance for for QuarterNear Quarterly Quarterly Date(in dollars) to Date(in
(b) Quarter/Year (d) Only-No 4th Only-No 4th (g) dollars)
(c) Quarter Quarter (h)
(e) (f)
Revenues From
33 Nonutility Operations 11,937 0
(417)
(Less)Expenses of
34 Nonutility Operations 13,762,536 7,891,784
(417.1)
35 Nonoperating Rental (1,513) (1,034)
Income(418)
Equity in Earnings of
36 Subsidiary 119 1,531,571 4,449,671
Companies(418.1)
37 Interest and Dividend 17,033,145 15,537,184
Income(419)
Allowance for Other
38 Funds Used During 127,811 (39,011)
Construction(419.1)
Miscellaneous
39 Nonoperating Income 17,486 16,773
(421)
40 Gain on Disposition 1,974,406 0
of Property(421.1)
TOTAL Other Income
41 (Enter Total of lines 6,932,307 12,071,799
31 thru 40)
42 Other Income
Deductions
Loss on Disposition
43 of Property(421.2) 0 40,896
44 Miscellaneous 5,617 5,616
Amortization(425)
45 Donations(426.1) 2,807,938 2,755,476
46 Life Insurance(426.2) 2,491,193 2,661,064 I
47 Penalties(426.3) 41,895 25,450
Exp.for Certain Civic,
48 Political&Related 1,728,138 1,775,518
Activities(426.4)
49 Other Deductions 2,480,852 1,410,301 -
(426.5)
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
Line Two of Account to Date Balance Current Year to
Page No. Balance for Quarterly Quarterly to Date('►ir
No. (a) (b) Quarter/Year for QuarterNear Only-No 4th Only-No 4th Date(in dollars) dollars)
(c) (d) Quarter Quarter (9) (h)
(e) M
TOTAL Other Income
50 Deductions(Total of 9,555,633 8,674,321
lines 43 thru 49)
Taxes Applic.to Other
51 Income and
Deductions
52 Taxes Other Than 262 2,046,797 462,271
Income Taxes(408.2)
53 Income Taxes- 262 (4,610,911) (2,079,651)
Federal(409.2)
54 Income Taxes-Other 262 (151,483) (75,004)
(409.2)
55 Provision for Deferred 234, 7,514,751 3,954,988
Inc.Taxes(410.2) 272
(Less)Provision for 234,
56 Deferred Income 272 4,206,684 2,286,595
Taxes-Cr.(411.2)
F5857 Investment Tax Credit 0 0
Adj:Net(411.5)(Less)Investment Tax
Credits(420)
TOTAL Taxes on
59 Other Income and 592,470 (23,991)
Deductions(Total of
lines 52-58)
Net Other Income and
60 Deductions(Total of (3,215,796) 3,421,469
lines 41,50,59)
61 Interest Charges
62 Interest on Long-Term 115,125,685 110,131,468
Debt(427)
63 Amort.of Debt Disc. 612,619 1,544,188 '
and Expense(428) f
Amortization of Loss
64 on Reaquired Debt 1,420,427 1,317,067
(428.1) ;
(Less)Amort.of
65 Premium on Debt- 8,883 8,883
Credit(429)
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
Line Title of Account to Date Balance Current Year to
No, a Page No. Balance for (d) Quarterly Quarterly to Date(in
( ) (b) QuarterNear for Quarter/Year Only-No 4th Only-No 4th Date(in dollars) dollars)
(c) Quarter Quarter (9) (h)
(e) (f)
(Less)Amortization of
66 Gain on Reaquired
Debt-Credit(429.1)
Interest on Debt to
67 Assoc.Companies 2,575,297 2,503,671
(430)
68 Other Interest 23,608,892 21,435,607
Expense(431)
(Less)Allowance for
69 Borrowed Funds 11,227,623 8,892,489
Used During
Construction-Cr.(432)
Net Interest Charges
70 (Total of lines 62 thru 132,106,414 128,030,629
69)
Income Before
71 Extraordinary Items 180,135,566 171,180,214
(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) I
Extraordinary Items
77 After Taxes(line 75 0 0
less line 76)
78 Net Income(Total of 180,135,566 171,180,214
line 71 and 77)
FERC FORM No.1 (REV.02-04)
Page 114-117

STATEMENT OF INCOME
Line teas Unify 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)
(i) (j) (k) ll1
1
2 605,198,775 619,466,502
3
4 398,290,405 455,047,730
5 14,615,719 15,273,478
6 46,053,841 45,339,270
7 0 0
8 15,532,178 15,501,352
9 0 0
10
11 0
12 63,276,760 42,404,390
13 51,810,694 58,970,978
14 37,837,133 38,258,664
15 19,965,635 10,134,220
16 1,165,935 875,040
17 12,722,505 7,049,674
18 34,093,056 27,652,652
19 (4,720) (4,720)
20
21
22
23
24
25 523,551,641 543,255,468 0 0
27 81,647,134 76,211,034 0 0
28
29
30
31
FERC FORM No.1 (REV.02-04)
Page 114-117

STATEMENT OF INCOME
Line Gas Utiity Current Year to Date Gas Utility Previous Yearto Other Utility Current Year to Other Utility Previous Year to
No. (in dollars) Date(in dollars) Date(in dollars) Date(in dollars)
W G) (k) (I)
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59 1
60 1
61
FERC FORM No.1 (REV.02-04)
Page 114-117

STATEMENT OF INCOME
Line Gas Utiity Current Year to Date Gas Utility Previous Yearto Other Utility Current Year to Other Utility Previous Year to
No. (in dollars) Date(in dollars) Date(in dollars) Date(in dollars)
62
63
64
65
66
67 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)®An Original Date of Report: p
Avista Corporation 04/18/2025
(2) ❑A Resubmission End of:2024/Q4
STATEMENT OF RETAINED EARNINGS
Item Contra Primary Current Quarter/Year Year to Previous QuarterNearYear
Line No. (a) Account Affected Date Balance to Date Balance
(b) (c) (d)
UNAPPROPRIATED RETAINED EARNINGS
(Account 216)
1 Balance-Beginning of Period 741,321,490 717,509,955
2 Changes
3 Adjustments to Retained Earnings(Account
439)
4 Adjustments to Retained Earnings Credit
4.1 Dividends Received from Subs 5,000,000
4.2
4.3
4.4
4.5
4.6
4.7
4.8
4.9
4.10
4.11
9 TOTAL Credits to Retained Earnings(Acct.439) 5,000,000
10 Adjustments to Retained Earnings Debit kAdHA:L, -MAR
10.1
10.2
10.3
10.4
10.5
10.6
10.7
10.8
10.9
FERC FORM No.1 (REV.02-04)
Page 118-119

STATEMENT OF RETAINED EARNINGS
Item Contra Primary Current Quarter/Year Year to Previous Quarter/Year Year
Line No. (a) Account Affected Date Balance to Date Balance
(b) (c) (d)
10.10
10.11
15 TOTAL Debits to Retained Earnings(Acct.439)
16 Balance Transferred from Income(Account433 178,603,995 166,730,543
less Account 418.1)
17 Appropriations of Retained Earnings(Acct.436)
17.1 Excess Earnings (2,537,300) (1,835,879)
17.2
17.3
17.4
22 TOTAL Appropriations of Retained Earnings (2,537,300) (1,835,879)
(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 (150,693,583) (141,368,296)
30.2
30.3
30.4
30.5
36 TOTAL Dividends Declared-Common Stock (150,693,583) (141,368,296)
(Acct.438)
37 Transfers from Acct 216.1,Unapprop.Undistrib. 572,872 285,167
Subsidiary Earnings
38 Balance-End of Period(Total 772,267,474 741,321,490
1,9,15,16,22,29,36,37)
FERC FORM No.1 (REV.02-04)
Page 118-119

STATEMENT OF RETAINED EARNINGS
Item Contra Primary Current Quarter/Year Year to Previous QuarterNear Year
Line No. (a) Account Affected Date Balance to Date Balance
(b) (c) (d)
39 APPROPRIATED RETAINED EARNINGS
(Account215)
39.1 Appropriated Retained Earnings 59,430,989 56,893,689
39.2
39.3
39.4
39.5
39.6
45 TOTAL Appropriated Retained Earnings 59,430,989 56,893,689
(Account215)
APPROP.RETAINED EARNINGS-AMORT.
Reserve,Federal(Account 215.1)
46 TOTALApprop.Retained Eamings-Amort.
Reserve,Federal(Acct.215.1)
47 TOTAL Approp.Retained Earnings(Acct.215, 59,430,989 56,893,689
215.1)(Total 45,46)
48 TOTAL Retained Earnings(Acct.215,215.1, 831,698,463 798,215,179
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) 43,138,900 38,974,396
50 Equity in Earnings for Year(Credit)(Account 418.1) 1,531,571 4,449,671
51 (Less)Dividends Received(Debit) 5,000,000
52 TOTAL other Changes in unappropriated (572,872) (285,167)
undistributed subsidiary earnings for the year
52.1 Corporate Costs Allocated to Subsidiaries (572,872) (285,167)
53 Balance-End of Year(Total lines 49 thru 52) 39,097,599 43,138,900
FERC FORM No.1 (REV.02-04)
Page 118-119

This report is:
Name of Respondent: (1)®An Original Date of Report: Year/Period of Report
Avista Corporation 04/18/2025 End of 20241 Q4
(2) El A Resubmission
STATEMENT OF CASH FLOWS
Description(See Instnictions No.1 for explanation of Current Year to Date OuarterlYear Previous Year to Date
Line No. codes) ( )b Quartcr,Year
(a) (c)
1 Net Cash Flow from Operating Activities
Net Income Line 78 c on page 117 180,135,566 171,180,214
2 ( ( ) P 9 )
3 Noncash Charges(Credits)to Income:
4 Depreciation and Depletion 264,151,330 256,851,952
5 Amortization of(Specify)(footnote details)
5.1 Amortization of Deferred Power and Natural Gas Costs 104,279,052 7,171,847
5.2 Amortization of Debt Expense 2,024,163 2,852,372
5.3 Amortization of Investment in Exchange Power
8 Deferred Income Taxes(Net) (3,581,603) (36,037,425)
9 Investment Tax Credit Adjustment(Net) (135,343) (551,283)
10 Net(Increase)Decrease in Receivables (376,114) 39,845,414
11 Net(Increase)Decrease in Inventory (17,719,292) 4,047,260
12 Net(Increase)Decrease in Allowances Inventory 9,815,601 (30,071,678)
13 Net Increase(Decrease)in Payables and Accrued (3,490,756) (50,860,477)
Expenses
14 Net(Increase)Decrease in Other Regulatory Assets (47,639,430) (53,098,758)
15 Net Increase(Decrease)in Other Regulatory Liabilities (7,394,628) 34,302,152
16 (Less)Allowance for Other Funds Used During 8,294,329 6,340,790
Construction
17 (Less)Undistributed Earnings from Subsidiary 1,531,571 4,449,671
Companies
18 Other(provide details in footnote):
18.1 Cash Received for Settlement of Interest Rate Swaps 4,397,000 7,868,930
18.2 Other(provide details in footnote): ll39,582,709 -101,860,887
18.3 Allowance for Doubtful Accounts 7,250,703 3,917,172
18.4 Changes in Other Non-Current Assets and Liabilities 646,854 (13,741,356)
18.5 Cash Paid for Settlement of Interest Rate Swaps 0 (409,000)
22 Net Cash Provided by(Used in)Operating Activities 522,119,912 434,337,762
(Total of Lines 2 thru 21)
24 Cash Flows from Investment Activities:
FERC FORM No.1 (ED.12-96)
Page 120-121

STATEMENT OF CASH FLOWS
Description(See Instructions No.1 for explanation of Previous Year to Date
Line No. codes Current Year to Date QuarterJYear
) QuarterlYear
(a) (b) (c)
25 Construction and Acquisition of Plant(including land):
26 Gross Additions to Utility Plant(less nuclearfuel) -(518,461,489) -(490,335,100)
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) (518,461,489) (490,335,100)
36 Acquisition of Other Noncurrent Assets(d)
37 Proceeds from Disposal of Noncurrent Assets(d) 2,047,651
39 Investments in and Advances to Assoc.and Subsidiary (7,709,499) (11,411,922
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 815,210 1,199,766
53.2 Dividends Received from Subsidiaries 5,000,000 0
57 Net Cash Provided by(Used in)Investing Activities(Total (518,308,127) (500,547,256)
of lines 34 thru 55)
59 Cash Flows from Financing Activities:
FERC FORM No.1 (ED.12-96)
Page 120-121

STATEMENT OF CASH FLOWS
Description(See Instructions No.1 for exp a}na dr+of Current I—- 77-Date Quarter/Year Previous Year to Date
Line No. codes) Quarter/Year
(a) (b) (c)
60 Proceeds from Issuance of: ' `., , fr;:- �I �".+ r•�fi t,
61 Long-Term Debt(b) 83,700,000 250,000,000
62 Preferred Stock
63 Common Stock 67,725,000 112,308,131
64 Other(provide details in footnote):
66 Net Increase in Short-Term Debt(c)
67 Other(provide details in footnote):
70 Cash Provided by Outside Sources(Total 61 thru 69) 151,425,000 362,308,131
72 Payments for Retirement of:
73 Long-term Debt(b) (13,500,000)
74 Preferred Stock
75 Common Stock
76 Other(provide details in footnote):
76.1 Debt Issuance Costs (1,156,533) (3,323,740)
76.2 Minimum Tax Witholdings L"(1,585,004) L(1,497,107)
78 Net Decrease in Short-Term Debt(c) (7,000,000) (114,000,000)
80 Dividends on Preferred Stock
81 Dividends on Common Stock (150,329,156) (140,922,959)
83 Net Cash Provided by(Used in)Financing Activities (8,645,693) 89,064,325
(Total of lines 70 thru 81)
85 Net Increase(Decrease)in Cash and Cash Equivalents low
86 Net Increase(Decrease)in Cash and Cash Equivalents (4,833,908) 22,854,831
(Total of line 22,57 and 83)
88 Cash and Cash Equivalents at Beginning of Period 28,592,905 5,738,074
90 Cash and Cash Equivalents at End of Period 23,758,997 28,592,905
FERC FORM No.1 (ED.12-96)
Page 120-121

This report is:
Name of Respondent: (1)21 An Original Date of Report: Year/Period of Report
Avista Corporation (2) ❑ A Resubmission 04/18/2025 End of:2024/Q4
FOOTNOTE DATA
La)Concept:NetlncreaseDecreaselnPayablesAndAccruedExpensesOperatingActivities
Cash paid(received)during the period for:
Income taxes:$7,555,015
Interest:$135,301,539
U Concept:OtherAdjustmentsToC ash Flows FromOperatingActivities
Power and natural gas deferrals(2,094,117);Change in special deposits 18,067,069;Change in other current assets 20,326,234;Non-cash stock compensation
9.195,907;gain on sale of property and equipment(1,975,266);Other(3,937,118).
U Concept:GrossAdditionsToUtilityPlantLessNuclearFuellnvestingActivities
Additions to PPE in Accounts Payable:$22,779,844
Concept:OtherRetirementsOfBalanceslmpactingCashFlowsFromFinancingActivities
Payment of minimum tax withholdings for share-based payment awards
Ue)Concept:NetlncreaseDecreaselnPayablesAndAccruedExpensesOperatingActivities
Cash paid(received)during the period for:
Income taxes:$(1,439,727)
Interest:$125,249,194
_f Concept:OtherAdjustmentsToC ash Flows FromOperatingActivities
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).
kW Concept:GrossAdditionsToUtilityPlantLessNuclearFuellnvestingActivities
Additions to PPE in Accounts Payable:$33,691,044
jh�Concept:OtherRetirementsOfBaIances Impact ngCash 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 04/18/2025 End of.2024/Q4
(2) El A Resubmission
NOTES TO FINANCIAL STATEMENTS
1. Use the space below for important notes regarding the Balance Sheet,Statement of Income for the year,Statement of Retained
Earnings for the year,and Statement of Cash Flows,or any account thereof.Classify the notes according to each basic statement,
providing a subheading for each statement except where a note is applicable to more than one statement.
2. Furnish particulars(details)as to any significant contingent assets or liabilities existing at end of year,including a brief explanation of
any action initiated by the Internal Revenue Service involving possible assessment of additional income taxes of material amount,or
of a claim for refund of income taxes of a material amount initiated by the utility.Give also a brief explanation of any dividends in
arrears on cumulative preferred stock.
3. For Account 116,Utility Plant Adjustments,explain the origin of such amount,debits and credits during the year,and plan of
disposition contemplated,giving references to 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 ofBusiness
Avista Corp.(the Company)is primarily an electric and natural gas utility with certain other business ventures.Avista Corp.provides electric distribution and transmission,and
natural gas distribution services in parts ofeastem Washington and northern Idaho.Avista Corp.also provides natural gas distribution service in partsofnortheastetn and southwestern
Oregon.Avista Corp.has electric generating facilities in Washington,Idaho,Oregon and Montana.Avista Corp.also supplies electricity to a small number ofcustometsin Montana.
Alaska Electric and Resource Company(AERC)is a wholly-owned subsidiary ofAvista Corp.The primary subsidiary ofAERC is Alaska Energy 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)asset forth in its applicable Uniform System of Accounts and published accounting releases,which is a comprehensive basis ofaccounting
other than accounting principles generally accepted in the United States ofAmerica(GAAP).As required by the FERC,the Company accounts for its investment in majority owned
subsidiaries as required by GAAP.The accompanying financial statements include the Company's proportionate share ofutility plant and related operations associated with its
interests in jointly owned plants.In addition,underthe requirements ofthe FERC,there are differences from GAAP in the presentation of(1)current portion of long-term debt,(2)
assets and liabilities for cost ofremoval 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 otherpostretiremant benefit costs,(10)emissions allowance inventory and liabilities,and(I I)leases.
Use ofEstinrates
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 ofcontingent assets and liabilities at the date ofthe financial statements and the reported amounts of revenues 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,
obligations under the Climate Commitment Act(CCA),
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 differfrom the
amounts reported and disclosed herein.

System ofaccounts
The accounting records ofthe Company's utility operations are maintained in accordance with the uniform system ofaccounts 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 of depreciation accounting utilizing composite rates forutility plant.Such rates are designed to provide for
retirements ofproperties at the expiration of their service lives.For utility operations,the ratio ofdepreciation provisions to average depreciable property was as follows for the years
ended December 31:
2024 2023 2022
Avista Corp. 3.45% 3.52% 3.50%
The average service lives forthe following broad categories ofutility plant in service are(in years):
Electric thermal/otberproduction 27
Hydroelectric production 81
Electric transmission 44
Electric distribution 42
Natural gas distribution property 44
Other shorter-lived general plant g
Allowance for Funds Used During Construction(AFUDC)
AFUDC represents the cost ofboth 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 cost ofutility plant.The debt component ofAFUDC is credited against total interest expense in the Statements oflncome in the line item"capitalized
interest."The equity component ofAFUDC is included in the Statements of hrcome in the line item"other income-net."The Company is permitted,under established regulatory rate
practices,to recoverthe capitalized AFUDC,and a reasonable return thereon,through its inclusion in rate base and the provision fordepreciation afterthe 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 Washington Utilities and Transportation Commission(WUfC)and the Idaho Public Utilities Commission(IPUC)have authorized Avista Corp.to calculate AFUDC using its
allowed rate ofreturo on rate base.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 overthe 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:
2024 2023
Avista Corp. 7.03% 7.03%
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 ofitems fortax and accounting purposes.Adeferred 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 carving amounts and tax basis ofexisting 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 overa longerperiod oftime.The Company establishes a valuation allowance when it is more likely than not that all,ora portion,ofa deferred tax
asset will not be realized.Deferred income tax assets and liabilities and regulatory assets and liabilities are established forincome tax benefits flowed through to customers.
The Company has elected to account fortransferable tax credits as a component ofthe income tax provision.The Company recognizes the benefit ofproduction tax credits as a
reduction ofincome 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).Underthis method,ITCs are amortized as a reduction to income tax expense over the estimated useful lives ofthe 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 latertax year;.
The Company did not incurpenalties on income tax positions in 2024 or 2023.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 overthe 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 millions):
2024 2023
Stock-based compensation expense $g S 7
Income tax benefits 2 2
Restricted share awards vest in equal thirds each year over3 years and are payable in Avista Corp.common stock at the end of each year ifthe 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 ofawards vest after a period of
3 years and are payable in cash or Avista Corp.comma Mock at the end ofthe three-year period.The method ofsettlement is at the discretion ofthe Company and historically the
Company has settled these awards through issuariceofAvista Corp.common stock and intends to continue this practice.Both types ofawards entitle the recipients to dividend
equivalent rights,are subject to forfeiture under certain circumstances,and are subject to meeting specific market orperformance conditions.Based on the level ofattainment ofthe
market orperformance conditions,the amount ofcash 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 forthese awards is recognized overthe requisite service period,provided
the requisite service period is rendered.For TSR awards,ifthe market condition is not met at the end ofthe three-year service period,there will be no change in the cumulative amount
ofcompensation 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,
iflhe internal performance metric ofcumulative earnings per share is not met,all compensation cost forthese 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 numberofgrants,vested and unvested shares,earned shares(based on market metrics),and otherpertinent information related to the Company's

stock compensation awards for the years ended December 31:
2024 2023
Restricted Shares
Shares granted during the year 82,433 76,806
Shares vested during the year 75,107 75,007
Unvested shares at end ofyear 158,464 152,140
Unrecognized compensation expense at end ofyear
(in millions) $3 $3
TSR Awards
TSR shares granted during the year 45,739 34,912
TSR shares vested during the year 64,640 61,456
TSR shares earned based on market metrics 35,552 44,863
Unvested TSR shares at end of year 77,530 96,915
Unrecognized compensation expense at end ofyear
(in millions) S 2 S 2
CEPS Awards
CEPS shares granted during the year 137,161 104,685
CEPS shares vested during the year 64,640 61,456
CEPS shares earned based on performance metrics 29,088 33,801
Unvested CEPS shares at end ofyear 232,486 161,235
Unrecognized compensation expense at end ofyear
(in millions) S 3 $2
Dutstanding restricted,TSR and CEPS share awards include a dividend component paid in cash.Aliability for the dividends payable related to these awards is accrued as dividends
are announced throughout the life ofthe award.As of December 31,2024 and 2023,the Company had recognized a liability of$3 million and$2 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 ofthree months or less when purchased to be cash equivalents.
Accounts Receivable and Allowance for Doubtful 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 other customer accounts receivable based on historical write-offs as compared to accounts receivable and operating revenues.Additionally,the Company establishes specific
allowances for certain individual accounts.
The Company has received grants from various government agencies to assist customers with their energy bills.The Company received these grant funds and applied them to
customer accounts,reducing accounts receivable balances.These grants totaled$10 million in 2024 and$2 million in 2023.
Utility Plant in Service
The cost ofadditions to utility plant in service,including AFUDC and replacements ofunits ofproperty and improvements,is capitalized.The cost of depreciable 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 ofthc ARO are
capitalized as pan ofthc carrying amount ofthe related long-lived asset.The liability is secreted to its present value each period and the related capitalized costs are depreciated over
the useful life of the related asset.In addition,ifthere are changes in the estimated timing orestimated costs ofthc AROs,adjustments are 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 surcharged/refunded to customers through the ratemaking process.The Company
records regulatory assets and liabilities for the 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 of the 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 WUTC and the tPUC 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 oftecovery through future
rates.
Substantially all forward contracts to purchase or sell powerand natural gas are recorded as derivative assets or liabilities at estimated fairvalue 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 fairvalue 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 tire mtemaking
process.
The Company has multiple master netting agreements with a variety ofentities 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 for presentation in the Balance Sheets.
Fair Value Measurements
Fair value represents the price that would be received when selling an asset or paid 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 fair value 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 recoverthe cost ofproviding the regulated services,and
in view ofdemand for the regulated services and the level ofcompetition,it is reasonable to assume that rates can be charged to and collected from

customers at levels that will recover costs.
Regulatory accounting practices 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 hrcome 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 offits 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 overthe 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,if new debt is issued in connection with the repurchase,these amounts are amortized over the life ofthe new debt.
In the Company's 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 are recovered or returned to customers through retail rates as a component
ofinterest expense.
Appropriated Retained Earnings
hi accordance with the hydroelectric licensing requirements of section 10(d)ofthe Federal Power Act(FPA),the Company maintains an appropriated retained earnings account for
earnings in excess of the specified rate ofretum on the Company's investment in the licenses for its various hydroelectric projects.Per section 10(d)ofthe 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 millions):
2024 2023
Appropriated retained earnings $59 $57
Contingencies
The Company has unresolved regulatory,legal and tax issues which have inherently uncertain outcomes.The Company accrues a loss contingency if it 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 foraccmal,if
there is a reasonable possibility that a material loss may be incurred.As of December 31,2024,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)ofits subsidiaries for the
years ended December 31(dollars in millions):
2024 2023
Avista Capital $ (6) $ (4)
AERC g g
Total equity in earnings ofsubsidiary companies S 2 $ 4
Subsequent Events
Management has evaluated the impact ofevents occurring after-December 31,2024 up to February 25,2025,the date that Avista Corp.'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 ofelectricity and natural gas to retail customers,which has two performance obligations,(I)having service
available for a specified period(typically a month at a time)and(2)the delivery ofenergy 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 ofenergy.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 ofenergy to customers,revenue is recognized immediately.
In addition,the sale ofelectricity 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 ereditsand 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 ofthe relevant tariffdetermine the charges the Company may bill the customer,payment due date,and otherpertinent rights and obligations of
both parties.Generally,tariffsales do not involve a written contract.Since all revenue recognition criteria are met upon the delivery ofenergy to customers,revenue is recognized at
that time.
Unbilled Revenue from Contracts with Customers
The determination ofthe volume ofenergy sales to individual customers is based on the reading oftheir meters,which occurs on a systematic basis throughout the month(once per
month for each individual customer).At the end ofeach calendar month,the amount ofenergy delivered to customers since the date ofthe last meter reading is estimated and the

corresponding unbilled revenue is estimated and recorded.The Company's estimate ofunbilled revenue is based on:
the number o f customers,
tariff rates,
meter reading dates,
actual native load for electricity,
actual throughput for natural gas,and
electric line losses and natural gas system losses.
Any difference between actual and estimated revenue is recorded in the following month when the meterreading and customerbilling occurs.
Accounts receivable includes unbilled energy revenues ofthe following amounts as of December 31(dollars in millions):
2024 2023
Unbilled accounts receivable $ 72 S 76
Nan-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 a specified period oftime,consistent with the discussion ofrate regulated sales above.
Alternative Revenue Programs(Decoupling)
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 oflncome.The Company's decoupling mechanisms(also
known as a FCAin Idaho)qualify as alternative revenueprograms.Decoupling revenue deferrals are recognized in the Statements ofhtcome during the period they occur(i.e.during
the period ofrevenue shortfall orexeess due to fluctuatiorta in customerusage),subject to certain limitations,and a regulatory asset orliability is established which will be surcharged
orrebated to customers in future periods.GAAPrequires that for an alternative revenue pmgmm,like decoupling,the revenue must be expected to be collected from customers within
24 months ofthe deferral to qualify forrecognition in the Statements oflncome.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 underthe 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 or refunded to customers.The cash passing between the Company and the customers is prcscmed in revenue from contracts with
customers since it is a portion ofthe overall tariff paid 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 whether the previous deferral balance being amortized was a regulatory asset or regulatory liability,and
depending on the size and direction ofthe current year deferral of surcharges 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 of fuel 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 ofmaterials,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 with 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 grass 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 December3l(dollars in millions):
2024 2023
Utility-related taxes $81 $75
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 ornatural gas capacity to its customers fora 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 agmement Where the customer makes payments throughout the year.As ofDecember 31,2024,the Company estimates it had unsatisfied capacity performance obligations of
$2 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 forthese services.
NOTE 3.LEASES
The core principle oflease 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 ofcash flows from leases.For
regulatory reporting,the FERC provided prescribed accounts forthe 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 ifan 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 oflease payments over the lease tern.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 oflease 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 or terminate the lease when it is reasonably certain the Company will exercise that option.Lease expense is recognized on a straight-line
basis overthe lease term.The difference between lease expense and cash paid for leased assets is recognized as a regulatory asset orregulatory 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 Claris 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 ptematwapending the outcome ofthe ongoing litigation between the State ofMontana and NortbWestem.Any reduction in future
lease payments or the retem to Avista Corp.of amounts previously paid will be included in the future ratemaking 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 69 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 or material restrictive covenants.
In March 2023,the Company entered into an agreement with Rathdrum Power LLC amending and restating a PPAforthe output ofthe Lancaster Plant.The restated PPAmeets the
accounting definition ofa lease,and all payments are variable in nature,based on capacity,usage,orporfomtance ofthe plant.Therefore,there is no lease obligation orcorresponding
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-term lease costs for 2024 are immaterial.
Operating Lease Balances in the Financial Statements
The components oflease expense were as follows for the year ended December 31(dollars in millions):
2024 2023 2022
Operating lease cost:
Fixed lease cost(Other operating expenses) $5 $5 $5
Variable lease cost(Other operating expenses and Resource costs) 31 25 2
Total operating lease cost $36 $30 $7
Supplemental cash flow information related to leases was as follows for the year ended December 31(dollars in millions):
2024 2023
Cash paid for amounts included in the measurement oflease liabilities:
Operating cash outflows:
Operating lease payments $5 $5
Supplemental balance sheet information related to leases was as follows for December 3l(dollars in millions):
December 3l, December 3l,
2024 2023
Operating Leases
Operating lease ROU assets(Other property and investments-net
and other non-current assets) $66 $68
Other current liabilities $4 $4
Other noncurrent liabilities and deferred credits 62 64
Total operating lease liabilities $66 $68
Weighted Average Remaining Lease Term
Operating leases 21 years 22 years
Weighted Average Discount Rate
Operating leases 4.30 % 4.29
Maturities oflease liabilities(including principal and interest)were as follows as of December 31,2024(dollars in millions):
Operating Leases
2025 S 5
2026 5
2027 5
2028 5
2029 5
Thereafter 79
Total lease payments $104
Less:imputed interest (38
Total
$66
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 ofassociated
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 ofAvista Corp.'s resource procurement and management operations in the electric business,Avista Corp.engages in an ongoing process ofresouree optimization,which
involves the economic selection from available energy resources to serve Avista Corp.'s load obligations and the use of these resources to capture available economic value through

wholesale market transactions.These include sales and purchases ofelectric 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 ofits resource procurement and management ofits natural gas business,Avista Corp.makes continuing projections ofits 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 ofits 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 ofits natural gas supply requirements unhedged for purchase 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;ifmarket 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 ofsurplus 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 ofDecember 31,2024 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 Mwh mmBTUs mmBTUs
2025 7 — 27,993 39,483 427 420 1,897 1,963
2026 — — 17,560 13,175 — — — —
2027 — — 7,555 2,250 — — —As ofDecember 31,2024,there are no expected deliveries ofenergy commodity derivatives after2027.
The following table presents the underlying energy commodity derivative volumes as ofDecember 31,2023 that were expected to be delivered in each respective year(in thousands
ofMWhs and mniBTUs):
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 MWh mmBTUs 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 — — 5,570 3,940 — — — —
As ofDecember 31,2023,there were no expected deliveries ofenergy commodity derivatives after 2026.
(])Physical transactions represent commodity transactions in which Avista Corp.will take or make delivery of either electricity or natural gas;financial transactions represent
derivative instruments with delivery ofcash 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 gasdetivalive contracts above will be included in either power supply costs or natural gas supply costs during the period they are scheduled to be delivered
and will be included in the vatiou6 deferral and recovery mechanisms(ERM,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
Asignifrcant portion ofAvista Corp.'s natural gas supply(including fuel for power generation)is obtained from Canadian sources.Most ofthose 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 are 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 unhedged foreign currency risk have not
had a material effect on Avista Corp.'s financial condition,results ofoperations 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 millions):
2024 2023
Number of contracts 22 5
Notional amount(in United States dollars) $2 $—
Notional amount(in Canadian dollars) 2 —
Interest Rate Swap Derivatives
Avista Corp.is affected by fluctuating interest rates related to a portion ofits existing debt,and future borrowing requirements.Avista Corp.may hedge a portion ofits 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 millions):
Mandatory Cash
Balance Sheet Date Number of Contracts Notional Amount Settlement Date
December 31.2024 1 $ 10 2025
December 31,2023 2 $ 20 2024
1 10 2025
The fairvalue 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 ofsettlement.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 ofDecember 31,2024 and December 31,2023 reflect the offsetting of derivative assets and liabilities where a legal right ofoffset
exists.
The following table presents the fairvalues and locations ofderivative instruments recorded on the Balance Sheets as ofDecember 31,2024(dollars in millions):
Fair Value
Net Asset
(Liability)

Gross Gross Collateral on Balance
Derivative and Balance Sheet Location Asset Liability Netting Sheet
Interest rate swap derivatives
Derivative instrument assets current $ 1 $ — S
Energy commodity derivatives
Derivative instrument assets current 10 — — 10
Derivative instrument liabilities current 11 (48) 23 (14)
Long-term portion ofderivative liabilities 2 (16) 1 (13)
Total derivative instruments recorded on the
balance sheet $ 24 $ (64) $ 24 $ (16)
The following table presents the fairvalues and locations ofderivative instruments recorded on the Balance Sheets as ofDecember 31,2023(dollars in millions):
Fair value
Net Asset
(Liability)
Gross Gross Collateral on Balance
Derivative and Balance Sheet Location Asset Liability Netting Sheet
Interest rate swap derivatives
Derivative instrument assets current $4 $— $— $4
Energy commodity derivatives
Derivative instrument assets current 9 _ _ 9
Derivative instrument liabilities current 20 (79 ) 42 (17 )
Long-term portion ofderivativeliabilities 3 (21 ) (18 )
Total derivative instruments recorded on the
balance sheet $36 $(100 ) $42 $(22 )
Exposure to Demands for Collateral
Avista Corp.'s derivative contracts often require collateral(in the form ofcash or letters of credit)or other credit enhancements,or reductions or terminations ofa portion ofthe
contract through cash settlement.In the event ofchanges in market prices or downgrade in Avista Corp.'s credit ratings or other established credit criteria,additional collateral may
be required.In periods ofprice volatility,the level ofexposure 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 ofDecember 31(dollars in millions):
2024 2023
Energy commodity derivatives
Cash collateral posted $ 24 $ 43
Letters of credit outstanding 12 20
There was no collateral or letters oferedit outstanding related to interest rate swap derivatives as ofDecember 31,2024 and December 31,2023.
Certain ofAvista CorpArlarivative instruments contain provisions requiring Avista Corp.to maintain an"investment grade"credit rating from the major credit rating agencies.If
AvISM Corp.'s credit ratings won to fall below"investment grade;'it would be in violation ofthese provisions,and the counterparties to the derivative instruments could request
immediate payment or demand immediate and ongoing collateralization on derivative instruments in net liability positions.
The following table presents the aggregate fair value ofall derivative instruments with credit-risk-related contingent features in a liability position and the amount ofadditional
collateral Avista Corp.could be required to post as ofDecember 31(dollars in millions):
2024
Energy commodity derivatives
Liabilities with credit-risk-related contingent features $ 33
Additional collateral to post 22
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.In January 2023,the Company entered
into an agreement to transfer its ownership in Colstrip Units 3 and 4 to Northwestern on December 31,2025.The Company will retain responsibility for remediation obligations in
existence at the time the transaction closes.See further discussion ofthe transaction within Note 15.
Pursuant to the ownership and operating agreements among the c00%mers,the Company's share ofrelated fuel costs as well as operating expenses for plant in service are included in
the corresponding accounts in the Statements ofincome.The Company's share ofutility plant in service for Colstrip and accumulated depreciation(inclusive ofthe ARO assets and
accumulated amortization)were as follows as ofDecember 31(dollars in millions):
2024 2023
Utility plant in service S 401 $ 394
Accumulated depreciation P (355) (334)
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-tata basis,many ofthe environmental liabilities are joint and several under
the law,so that ifany co-owner failed to pay its share ofsuch liability,the olhero0ociwners(or any one ofthem)could be required to pay the defaulting co-owner's share(or the entire
liability),
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 ofsettlement 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 EPAissued a final rule regarding CCRs.Colstrip produces this byproduct.The CCR rule has been the subject ofongoing litigation.In August 2018,the D.C.Circuit
struck down provisions ofthe rule.The rule includes technical requirements forCCR landfills and surface impoundments.The Colstrip owners developed a multi-year compliance
plan to address the CCR requirements and existing state obligations.
In April 2024 and January 2025,the EPA issued additional final rules building on the 2015 regulations and regulating CCR management units at active and inactive powerplants.
The Colstrip owners are performing analyses to determine whether any potential changes to the existing remediation efforts are required.Based on the results ofthese analyses to date,
the Company believes there will not be a material change to the asset retirement obligation for Colstrip related to these final rules.
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 of fill 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 rule 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 ofColstrip are
required to provide financial assurance,primarily in the form of surety bonds,to secure each owner's pro-rata share ofvarious anticipated closure and remediation ofthe ash ponds and
coal holding areas.The amount offinancial assurance required of each ownermay,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 millions):
2024 2023
Asset retirement obligation at beginning ofyear $ 18 $ 16
Liabilities incurred 2
Liabilities settled (1) —
Accretion expense I —
Asset retirement obligation at end ofyear $ 18 $ 18
NOTE 7.PENSION PLANS AND OTHER POSTRETIREMENT BENEFIT PLANS
The Company has a defined benefit pension plan covering the majority ofregular full-time non-union employees at Avian Corp.hired prior to January 1,2014 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 ofhire aadavetage compensation as specified in the plan.Non-union employees hindd on orafterJanuary 1.2014 and union employees hired on or
after January 1,2024 participate in a defittedoontribution 401(k)plan in lieu of a defined benefit pension plan.The Company's ftmding policy is to contribute at]cast the minimum
amounts required to be funded under the Employee Retirement Income Security Act,but not more than the maximum amounts currently deductible forincome tax purposes.The
Company contributed$10 million in cash each year to the pension plan in 2024 and 2023.The Company expects to contribute$10 million in cash to the pension plan in 2025.
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$12 million for the previously unrecognized losses in 2022.This loss was deferred as a regulatory asset and is being amortized over 12 years in
accordance with regulatory accounting orders.
In 2024,the Company offered pension participants an election to leave the pension plan for an alternative defined contribution 401(k)plan.In April 2024,it was determined that due
to the number ofparticipants electing to leave the pension plan,as well as the resulting decrease in expected future service,this event resulted in a curtailment ofthe pension plan,
and an associated gain ofSl million for the mduetion in the benefit obligation.This gain was offset against the unrecognized net actuarial loss(and recorded within a regulatory
asset).The curtailment triggered a remeasumment ofpension plan.The remeasurement did not have a material impact on the Company's financial condition or results of operations.
The Company has a SERP providing 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 ofthe Internal Revenue Code of 1986 and the deferral ofsalary under deferred
compensation plans.The liability and expense for this plan are included as pension benefits in the tables included in this Note.
The Company expects benefit payments under the pension plan and the SERP will total(dollars in millions):
Total 2030-
2025 2026 2027 2028 2029 2034
Expected benefit payments $ 44 $ 45 $ 45 $ 46 $ 46 $ 242
The expected long-term rate ofretum on plan assets is based on past performance and economic forecasts for the types ofinvestments 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 arc included as otherpostretirement benefits.Non-union
employees hired on orafterJanuary 1,2014.will have access to the retiree medical plan upon retirement;however,Avista Corp.will no longer provide 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 ofthe HRAare included as other
postretirement benefits.
The Company provides death benefits to beneficiaries ofexecutive officers who die during their term of office 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 ofdeath(or ifdeath occurs after retirement,a payment equal to twice the
executive officer's total annual pension benefit).The liability and expense for this plan are included as otherpostretirement benefits.
The Company expects benefit payments under other postretirement benefit plans will total(dollars in millions):
Total 2030-
2025 2026 2027 2028 2029 2034
Expected benefit payments $ 7 $ 7 $ 7 $ 7 $ 7 S 38
The Company expects to contribute$7 million to other postretirement benefit plans in 2025.The Company uses a December 31 measurement date for its pension and other
postretirement benefit plans.
The following tables set forth the pension and other postretirement benefit plan disclosures as of December 31,2024 and 2023 and the components ofnet periodic benefit costs for
the years ended December 31,2024 and 2023(dollars in millions):
Other Post-
Pension Benefits retirement Benefits
2024 2023 2024 2023
Change in benefit obligation:
Benefit obligation as ofbeginning ofyear S 585 S 558 $ 122 S 116
Service cost 16 14 3 2
Interest cost 34 33 7 7
Actuarial(gain)/loss(1) 2 21 (9) 4
Benefits paid (36) (41) (6) (7)
Curtailments (1) —
Benefit obligation as ofend ofyear(2) $ 600 S 585 S 117 S 122
Change in plan assets:
Fair value ofptan assets as ofbeginning ofyear S 590 $ 541 $ 58 $ 49
Actual return on plan assets 42 79 9 9
Employer contributions 10 10 —
Benefits paid (34) (40) —
Fair value ofplan assets asofendofyear(2) $ 608 $ 590 $ 67 S 58
Funded status $ 8 $ s $ (50) $ (64)
Amounts recognized in the Balance Sheets:
Noncurrent assets $ 35 $ 33 $ — $
Current liabilities (2) (2) (1) (1)
Non-current liabilities (25) (26) (49) (03)
Net amount recognized $ 8 $ 5 $ (50) S (64)

Accumulated pension benefit obligation(2) $ 522 S 514
Accumulated postretirement benefit obligation:
Forretirees $ 67 $ 68
For fully eligible employees S 16 S 16
For other participants $ 34 $ 38
Included in accumulated other comprehensive loss(income)(net of tax):
Unrecognized prior service cost(credit) $ 3 S 4 S — $ (1)
Unrecognized net actuarial loss 70 69 2 13
Total 73 73 2 12
Less regulatory asset (73) (72) (2) (13)
Accumulated other comprehensive loss for unfunded benefit
obligation forpensions and other postretirement benefit plans S — $ I $ $ (1)
(1)The change in the pension benefit obligation related to actuarial loss is primarily related to changes in demographic experience,partially offset by financial assumption changes.
(2)As of December 31,2024,the SERPhad a projected benefit obligation of$27 million and an accumulated benefit obligation of$26 million,with no plan assets.
Other Post-
Pension Benefits retirement Benefits
2024 2023 2024 2023
Weighted-average assumptions as of December 31:
Discount rate forbenefit obligation 6.13% 5.86% 6.09% 5.83%
Discount rate for annual expense 5.86% 6.10% 5.83% 6.10%
Expected long-term return on plan assets 7.80% 8.30% 6.70% 7.20%
Rate ofcompensation increase 5.19% 4 87%
Medical cost trend pre-age 65-initial 6.50% 6.50%
Medical cost trend pre-age 65-ultimate 5.00% 5.00%
Ultimate medical cost trend year pre-age 65 2031 2030
Medical cost trend post-age 65-initial 6.50% 6.50%
Medical cost trend post-age 65-ultimate 5.00% 5.00%
Ultimate medical cost trend year post-age 65 2031 2030
Pension Benefits Other Post-retirement Benefits
2024 2023 2024 2023
Components of net periodic benefit cost:
Service cost(1) $ 16 S 14 $ 3 S 2
Interest cost 34 33 7 7
Expected return on plan assets (45) (44) (4) (3)
Amortization ofprior service cost(credit) — 1 (1) (1)
Net loss recognition 2 5 _ _
Settlement loss(2) _
Net periodic benefit cost $ 7 $ 9 $ 5 $
(1)Total service cost in the table above is 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 project or an operating expense.Approximately 45 percent ofall labor and benefits is capitalized to utility property and 55 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.
Pension costs other than service costs are presented in the Statements of htcome in the line item"Other income-net."
Plan Assels
The Finance Committee ofthe Board of Directors approves investment policies,objectives and strategies that seek an appropriate return for the pension plan and other postretiremen t
benefit plans and reviews and approves changes to the investment and Finding 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 theiradoption by the Finance Committee.The Finance Committee has established target investment allocation percentages by asset
classes and investment ranges for each asset class of 55 percent in equity securities,40 percent in debt securities,and 5 percent in real estate.The target investment allocation
percentages are typically the midpoint ofthe established range.
The fair value ofpension plan assets invested in debt and equity securities was based primarily on fair value(market prices).The fair value ofinvestment 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 other inputs(including valuations of securities comparable in coupon,rating,maturity and industry).
Pension plan and other postretirement plan assets with fair values are measured using net asset value(NAV)are excluded from the fair value 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 oftheplon's
investments in closely held investments and partnership interests have redemption limitations ranging from bi-monthiy 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 fora description ofthe fair value hierarchy)ofthe pension plan's assets measured and reported as of
December 31,2024 at fair value(dollars in millions):
Levell Leve12 Leve13 Total
Cash equivalents $ — $ 8 $ -- S 8
Fixed income securities:
U.S.government issues — 37 — 37
Corporate issues — 213 — 213
International issues — 33 — 33
Municipal issues — 11 11
Mutual funds:
U.S.equity securities 160 — — 160
International equity securities 63 — — 63
Plan assets measured at NAV(not subject to hierarchy
disclosure)
Common/collective trusts:real estate — — — 24

Partnership/closely held investments:
International equity securities — — — 52
Real estate 7
Total S 223 $ 302 $ — $ 608
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
December 31,2023 at fair value(dollars in millions):
Level Level2 Level3 Total
Cash equivalents $ — $ 7 $ — $ 7
Fixed income securities:
U.S.government issues — 19 — 19
Corporate issues — 175 — 175
International issues — 27 — 27
Municipal issues — 14 — 14
Mutual funds:
U.S.equity securities 170 — — 170
International equity securities 75 — — 75
Plan assets measured at NAV(not subject to hierarchy
disclosure)
Common/collective trusts:real estate — — — 25
Partnership/closely held investments:
International equity securities — — — 71
Real estate — — 7
Total S 245 $ 242 S — S 590
The fairvalue of otherpostretirement plan assets invested in debt and equity securities was based primarily on market prices.The fairvalue ofinvestment 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 ofsecurities
comparable in coupon,rating,maturity and industry).The target asset allocation was 60 percent equity securities and 40 percent debt securities in both 2024 and 2023.
The fairvalue ofotherpostretirement plan assets was determined to be$67 million as of December 31,2024 and$58 million as of December 31,2023.The assets consist ofa
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 18 for a description ofthe fairvalue hierarchy).
401(k)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 of the 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 millions):
2024 2023
Employer 401(k)matching contributions $ 16 $ 15
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 ofthe following amounts as of December 31(dollars in millions):
2024 2023
Deferred compensation assets and liabilities $ 9 $ 8
NOTE 8.ACCOUNTING FOR INCOME TAXES
Income Tax Expense
Areconciliation offederal income taxes derived from the statutory federal tax rate of21 percent applied to income before income taxes is as follows forthe years ended December 31
(dollars in millions):
2024 2023
Federal income taxes at statutory rates S 38 21.0% $ 27 21.0%
Increase(decrease)in tax resulting from:
Tax effect ofregulatory treatment ofutility
plant differences (12) (6.6) (12) (9.2)
State income tax expense 1 0.5 1 0.5
Flow through related to deduction of meters
and mixed service costs(1) (23) (12.6) (48) (36.7)
Tax credits (1) (0.6) (2) (1.6)
Other (2) (0.9) (2) (1.6)
Total income tax expense(benefit) $ 1 0.8% S (36) (27.6)%
(1)The Company's general rate cases included approval ofbase rate increases,offset by tax customer credits.As the tax customer credits are returned to customers,this results in
a decrease to income tax expense due to flowing through the benefits related to meters and mixed service costs.Once these tax customer credits have been applied to
customers and are exhausted,income tax expense will increase.
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 of December 31,2024,the Company had S 19 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$11 million ofthe state tax credits.As such,the Company has recorded a valuation allowance of S8 million against the state tax credit canyforwards and reflected the
net amount of S11 million as an asset as of December 31,2024.State tax credits expire from 2025 to 2038.
Status oflnternal Revenue Service(IRS)and State Examinations
The Company and its eligible subsidiaries file consolidated federal income tax returns.All tax years afier2020 are open foran 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 orcredited with the tax effects oftheir
operations on a stand-alone basis.

All tax years after 2020 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 forthe purchase offuel for thermal generation,natural gas for resale and various agreements forthe purchase orexchange ofelectric energy with other
entities.The remaining term ofthe contracts range from one month to twenty-five years.
Total expenses forpowerpntehased,natural gaspurchased,fuel forgeneration and other fuel costs,which are included in utility resource costs in the Statements of Income,were as
follows forthe years ended December 31(dollm in millions):
2024 2023
Utility power resources $ 548 $ 607
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 millions):
2025 2026 2027 2028 2029 Thereafter Total
Power resources $ 333 $ 31] $ 285 $ 263 $ 264 $ 2,570 $ 4,026
Natural gas resources 108 81 64 55 50 249 607
Total $ 441 $ 392 $ 349 $ 318 $ 314 $ 2,819 $ 4,633
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 far 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 powertesources include fixed contractual amounts related to the Company's contracts with Public Utility Districts(PUDs)to purchase portions
ofthe output ofcertain generating facilities.Although Avista Corp.has no investment in the PUD generating facilities,the contracts obligate Avista Corp.to pay certain minimum
amounts whetherornot the facilities are operating,The cost ofpower obtained underthe contracts,including payments made when a facility is not operating,is included in utility
resource costs in the Statements of Income.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 underthese contracts are based in part on the proportionate share ofthe debt service requirements ofthe
PUD's revenue bonds forwhich the Company is indirectly responsible.The Company's total future debt service obligation associated with the revenue bonds outstanding at
December 31,2024(principal and interest)was$267 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 millions):
2025 2026 2027 2028 2029 Thereafter Total
Contractual obligations $ 39 $ 40 $ 18 $ 18 $ 9 $ 165 $ 289
NOTE 10.SHORT-TERM BORROWINGS
Lines of Credit
Avista Corp.has a committed lincofcredit in the total amount ofS500 million with an expiration date ofJune 2028.The Company has the option to extend for two additional one
yearperiods(subject to customary conditions).The committed line ofcredit is secured by non-transfemble 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 underthe committed line ofcredit.
Balances outstanding and interest rates on borrowings(excluding letters ofcredit)under the Company's revolving committed line ofcredit were as follows as of December 31(dollars
in millions):
2024 2023
Balance outstanding at end ofperiod S 342 $ 349
Letters ofcredit balance outstanding at end ofperiod 5 5
Average interest rate at end ofperiod 5.52% 6.46%
As of December 31,2024 and 2023,the borrowings outstanding under Avista Corps committed lines ofcredit were classified as short-term borrowings on the Balance Sheets.
Letter of Credit Facility
In December2022,the Company entered into a continuing letter ofcredit agreement in the aggregate amount of$50 million.Eitherparty may terminate the agreement at any time.
The Company had S 12 million and$20 million in letters ofcredit outstanding under this agreement as of December 31,2024 and December 31,2023,respectively.Letters ofcredit
are not reflected on the Balance Sheets.Ifa 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 Previsions
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 agreements also
include a covenant which does not permit the ratio of"consolidated total debt"to"consolidated total capitalization"ofAvista Corp.to be greater than 65 percent at any time.As of
December 31,2024,the Company complied with this covenant.
NOTE 11.BONDS
The following details long-term debt outstanding as of December 31(dollars in millions):
Maturity Interest
Year 9!5gptipn Rate 2024 2023
Avista Corp.Secured Long-Term Debt
2028 Secured Medium-Term Notes 6.37% $ 25 S 25
2032 Secured Pollution Control Bonds(1) 3.88% 67 67
2034 Secured Pollution Control Bonds(1) 3.88% 17 17
2035 First Mortgage Bonds 6.25% 150 150
2037 First Mortgage Bonds 5.70% 150 150
2040 First Mortgage Bonds 5.55% 35 35
2041 First Mortgage Bonds 4.45% 85 85
2044 First Mortgage Bonds 4.11% 60 60
2045 First Mortgage Bonds 4.37% 100 100
2047 First Mortgage Bonds 4.23% 80 80
2047 First Mortgage Bonds 3.91% 90 90
2048 First Mortgage Bonds 4.35% 375 375
2049 First Mortgage Bonds 3.43% 180 180
2050 First Mortgage Bonds 3.07% 165 165
2051 First Mortgage Bonds 3.54% 175 175

2051 First Mortgage Bonds 2.90% 140 140
2052 First Mortgage Bonds 4.00% 400 400
2053 First Mortgage Bonds 5.66% 250 250
Total Avista Corp.secured long-term debt 2,544 2,544
Secured Pollution Control Bonds held by Avista
Corporation(1) — (84)
Total long-term debt $ 2,544 $ 2.460
(1)ln April 2024,the Company remarketed the City of Forsyth,Montana Pollution Control Revenue Refunding Bonds.The bonds arc not subject to ordinary optional redemption.
The bonds are secured by equal principal amounts of non-transferable first mortgage bonds of the Company.Avista Corp.had purchased the Forsyth bonds upon original
issuance in December2010 and held the bonds until market conditions were favorable for remarketing the bonds to unaffiliated investors.In connection with the pricing of
the Forsyth bonds,the Company cash-settled two interest rate swap derivatives(notional aggregate amount of S20 million)and received a net amount ofS4 million.See note
8 for a 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 millions):
2025 2026 2027 2028 2029 Thereafter Total
Debt maturities $ — S — S — $ 25 $ — $ 2,571 $ 2,596
Substantially all ofAvista Corp:s owned properties are subject to the lien oftheir respective mortgage indentures.Underthe Mortgages and Deeds ofTnist(Mortgages)securing their
first rnottgage bonds(including secured medium-t rin 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 fairvalue to the Company(whichever is lower)ofproperty additions of that 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 ofthat entity which have not previously been made the basis ofany application underthat entity's Mortgage,or
deposit ofcash.
Avista Corp.may not individually issue any additional first mortgage bonds(with certain exceptions in the case ofbonds issued on the basis ofredred bonds)unless the particular
entity issuing the bonds has"net earnings"(as defined in that entity's Mortgage)forany 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 of December 31,2024,property additions and retired bonds would have allowed,and the net earnings test would not have prohibited,the issuance of$1.5 billion by Avista Corp.
in an aggregate principal amount of additional 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$52 million to Avista Capital 11,an affiliated
business trust formed by the Company.Avista Capital 11 issued$50 million ofPreferred Trust Securities.The distribution rate on the Preferred Trust Securities is three-month CME
Term SOFR plus 1.137 percent.
The distribution rates paid were as follows during the years ended December 31:
2024 2023
Low distribution rate 3.64% 5.64%
High distribution rate 6.51% 6.55%
Distribution rate at the end ofthe year 5.64% 6.51%
Concurrent with the issuance ofthe Preferred Trust Securities,Avista Capital II issued$2 million of Common Trust Securities to the Company.These Preferred Tust Securities may be
redeemed at the option of Avista Capital 11 at any time and mature on June 1,2037.In December2000,the Company purchased$10 million ofthese Preferred Trust Securities.
The Company owns 100 percent of Avista Capital II and has solely and unconditionally guaranteed the payment ofdistrlbutions 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 orprior 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 as shown on the Balance Sheets are reasonable
estimates oftheir fair values.The carrying values ofbonds and advances from associated companies as shown on the Balance Sheets may be different from the estimated fair value.See
below for the estimated fair value ofbonds and advances from associated companies.
The fairvalue 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 fair values derived from unobservable inputs(Level 3 measurements).
The three levels ofthe fairvalue 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 occurwith
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 citherdirectly orindirectly observable as ofthe reporting date.Level 2
includes financial instruments valued using models orother valuation methodologies.These models are primarily industry-standard models that considervarious assumptions,
including quoted forward prices forcommoditics,time value,volatility factors,and current market and contractual prices forthe underlying instruments,as well as other relevant
economic measures.Substantially all of these assumptions are observable in the marketplace throughout the full term ofthe instrument,can be derived from observable data or are
supported by observable levels at which transactions are executed in the marketplace.
Level 3-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 of fair value.
Financial assets and liabilities are classified in thcirentirety based on the lowest level ofinput that is significant to the fair value measurement.The,Company's assessment ofthe
significance ofa particularinput to the fairvalue measurement requires judgmentand may affect the valuation of fairvalue assets and liabilities and theirplacement within the fair
value hicmrchy levels.The determination ofthe rairvalues incorporates various factors that include not only the credit standing ofthe eounterparties involved and the impact of
credit enhancements(such as cash deposits and letters oferediq,but also the impact of Avista Corp.s nonperformance risk on its liabilities.
The following table sets forth the carrying value and estimated fair value ofthe Company's financial instruments not reported at estimated fairvalue on the Balance Sheets as of
December 31(dollars in millions):
2024 2023
Carrying Estimated Carrying Estimated
Value Fair Value Value Fair Value
Bonds(Level 2) $ 1,100 S 938 $ 1,100 $ 969
Bonds(Level 3) 1,444 1,089 1,360 1,089
Advances from associated companies(Level 3) 52 47 52 46
These estimates of fair value of long-term debt and long-tear debt to affiliated trusts were primarily based on available market information,which generally consists ofestimated
market prices from third party brokers for debt with similar risk and terms.The price ranges obtained from the third party brokers consisted ofmarket prices of 57.68 to 105.474 percent
ofthe principal amount,where 100.00 represents the carrying value recorded on the Balance Sheets.Level 2 long-term debt represents publicly issued bonds with quoted market
prices;however,due to their limited trading activity,they are classified as Level 2 because brokers must generate quotes and make estimates ifthere 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.Fairvalues in Level 3 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 ofDecember 31,2024 at
fairvalue on a recurring basis(dollars in millions):
Counterparty
and Cash
Collateral
December 31,2024 Level Level Level Netting(1) Total
Assets:
Energy commodity derivatives(2) $ — $ 23 $ $ (13) $ 10
Interest rate swap derivatives — 1 — — I
Deferred compensation assets:
Mutual Funds:
Fixed income securities 2 — — — 2
Equity securities 7 — — 7
Total =9 $ 24 $ _ $ (13) $ 20
Liabilities:
Energy commodity derivatives(2) $ — $ 61 $ 3 $ (3 7) S 27
Total $—$ 61 $ 3 S (37) $ 27
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 ofDecember 31,2023 at
fairvalue on a recurring basis(dollars in millions):
Counter-party
and Cash
Collateral
December 31,2023 Levell Level2 Level Netting(1) Total
Assets:
Energy commodity derivatives(2) $ — $ 31 $ — $ (23) $ 8
Interest rate swap derivatives — 4 — — 4
Deferred compensation assets:
Mutual Funds:
Fixed income securities I _ _ _ I
Equity securities 7 — _ 7
Total 8 $ 35 S — $ (23) $ 20
Liabilities:
Energy commodity derivatives(2) $ $ 92 S 8 $ (65) $ 35
Total S — $ 92 S 8 $_ (65) $ 35
(1)The Company is permitted io 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 forcash collateral held or placed with these same counterparties.
(2)The Level 3 energy commodity derivative balances are associated with a natural gas exchange agreement.
The difference between the amount ofderivative assets and liabilities disclosed in respective levels in the table above and the amount ofderivative assets and liabilities disclosed on
the Balance Sheets is due to netting arrangements with Certain counterparties.See Note 4 for additional discussion ofderivative netting.
To establish fair value for energy commodity derivatives,the Company uses quoted market prices and forward price curves to estimate the fair value ofenergy commodity derivative
instruments included in Level 2.Electric derivative valuations are performed using market quotes,adjusted forperiods 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 arc available for
substantially the full term ofthe contract,the derivative asset orliability 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 consideraUOn given to the potential non-performance risk by the Company.Future cash flows of the 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.
Deferred compensation assets and liabilities represent funds held by the Company in a Rabbi Trost for an executive deferral plan.These funds consist ofactively traded equity and
bond funds with quoted prices in active markets.
Level Fair Value
Natural Gas Exchange Agreement
For the natural gas commodity exchange agreement,the Company uses the same Level 2 market quotes described above;however,the Company also estimates the purchase and sales
volumes(within contractual limits)as well as the timing ofthose transactions.Changing the timing ofvolume estimates changes the timing of purchases and sales,impacting which
brokered quote is used.Because the brokered quotes can vary significantly from period to period,the unobservable estimates ofthe timing and volume oftmnsactions can have a
significant impact on the calculated fair value.The Company currently estimates volumes and timing oftmnsactions based on a most likely scenario using historical data.Historically,
the timing and volume oftmnsactions are not highly correlated with market prices and market volatility.
As of December 31,2024,expected remaining transactions underthe agreement were sales.The contract expires in April 2025.
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 31,2024(dollars in
millions,except mmBTU amounts):
Fair Value(Net)at
December 31,2024 %bluasion Technique Unobservable Input Range
Natural gas exchange $ (3) Internally derived Forward sales prices $2.28-$4.57/mmBTU
weighted average $3.18 Weighted Average
cost of gas
Sales volumes 280,000-600,000 mmBTUs
The valuation methods,significant inputs and resulting fairvalues described above were developed by the Company 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 forassets and liabilities measured at fair value using significant unobservable inputs(Level 3)for the years ended December 31(dollars in
millions):
Natural Gas Exchange
2024: Agreement(1)
Balance as of January 1,2024 $ (8)

Total gains or(losses)(realized/unrealized):
Included in regulatory assets 5
Ending balance as of December31,2024 S (3)
2023:
Balance as of January 1,2023 $ (18)
Total gains or(losses)(realized/unrealized):
Included in regulatory assets 10
Ending balance as of December 31,2023 $ (8)
(I)There were no purchases,issuances or transfers from other categories of derivatives instruments during the periods presented in the table above.
NOTE 14.COMMON STOCK
The payment ofdividends 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 oferedit agreements,
the hydroelectric licensing requirements ofsection 10(d)ofthe FPA(see Note 1),and
certain requirements underthe Oregon Public Utility Commission(OPUC)approval ofthe AERC acquisition in 2014.The OPUC's AERC acquisition order
requires Avista Corp.to maintain a capital structure ofno less than 40 percent common equity(inclusive of short-term debt).This limitation may be revised upon request
by the Company with approval from the OPUC.
The requirements oftbe OPUC approval ofthe AERC acquisition are the most restrictive.Under the OPUC restriction,the amount available for dividends at December 31,2024 was
$326 million.
The Company has 10 million authorized shares ofpreferred stock.The Company did not have preferred stock outstanding as of December 31,2024 and 2023.
Common Stock Issuances
The Company issued common stock for total net proceeds of$68 million in 2024.Most ofthese issuances were made through sales agency agreements under which the Company may
offer and sell new shares of common stock from time to time through its sales agents.In 2024,1.8 million shares were issued under these agreements.
NOTE 15.COMMITMENTS AND CONTINGENCIES
In the course of its business,the Company becomes involved in vari ous claims,controversies,disputes and other contingent matters,including the items described in this Note.Some
ofthese 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 ofany matterbecause litigation and other contested proceedings are subject to
numerous uncertainties.Formatters affecting Avista Corp.'s,the Company intends to seek,to the extent appropriate,recovery ofincurred costs through the ratemaking process.
Climate Commitment Act
The CCArequires the Company to submit greenhouse gas emission reports to the Washington State Department of Ecology(Ecology)annually for its electric and natural gas entities.
The CCAthen requires the Company to contract with a third-party verifierto audit the emissions data in the emissions reports.In August 2024,the Company's third-party verifier
submitted to Ecology its verification report on the Company's 2023 emissions report.The verification report was issued with an adverse emissions data verification statement.In
September2024,in the absence of a positive verification statement,Ecology assigned an emission level(AEL)to Avista Corp.based on information submitted by the Company's
third-party verifier.In late October2024,the Company resubmitted a revised emissions report to the third-party verifierand Ecology.In November2024,the third-party verifier issued
a revised 2023 emissions report with a positive verification statement.In December 2024 Ecology issued a revised AELforthe 2023 emissions reporting yearthat was in line with the
Company's estimates.
Collective Bargaining Agreements
The Company's collective bargaining agreement with the IBEW represents 36 percent of all Avista Corp.'s employees.The Company%largest represented group,representing
approximately 90 percent ofAvista Corp.'s bargaining unit employees in Washington and Idaho,are covered under a fouryearagreement which expires in Mawh 2025.The Company
and the IBEW began negotiations on a new collective bargaining agreement in the first quarter of2025.
Boyds Fire(State of Washington Department of Natural Resources v.Avista)
In August 2019,the Company was served with a complaint,captioned"State of Washington Department ofNatural Resources v.Avista Corporation,"seeking recovery ofup 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 rite,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$0.8 million in property damages as well as potential non-economic damages,and holders ofinsurance subrogation claims seeking recovery of
$1.8 million in insurance proceeds purportedly paid to theirinsureds.
The lawsuits were filed in the Superior Court ofFeny County,Washington,and is scheduled for trial on July 7,2025.The Company continues to vigorously defend itself in the
litigation.However,at this time the Company is unable to predict the likelihood ofan adverse outcome orestimate a range ofpotential loss in the event ofsuch an outcome.
Labor Day 2020 WndstormlBabb Road Fire
In September202O,a severe windstorm occurred in eastern Washington and northern Idaho.The extreme weather event resulted in customer outages and multiple wildfires in the
region,including the Babb Road Fire,which occurred nearthe town of Malden,Washington.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.
In May 2021 the Company learned the Washington Department of Natural Resources(DNR)had completed its investigation and issued a report on the Babb Road Fire.
The DNR report concluded,among otherthings,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 of Avista Corp.'s distribution line and approximately 20 feet beyond Avista Corp.'s right-of-way;
the tree showed some evidence of insect damage,a small area ofscaring where a lateral branch/leader(LBL)had broken offin the past,and some past signs of
Gall Rust disease.
The DNR report concluded that:"because ofthe unusual configuration ofthe tree,and its proximity to the powerline,a closer inspection was warranted.Anearer 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 DNR report acknowledged that,other than the multi-dominant nature ofthe tree,the conditions mentioned above would not have been easily visible without close-up inspection
of,orcutting into,the tree.The report also acknowledged that,while the presence of multiple 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,nor was the
Company negligent with respect to its maintenance,inspection or vegetation management practices.
Eleven lawsuits have been filed in connection with the Babb Road rite.Asplundh Tree Company and CN 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 51 insurance companies seeking
to recover approximately S21 million purportedly paid to insureds to date;and five actions on behalfof 128 individual plaintiffs.One ofthe private plaintiffactions was originally
filed as a class action lawsuit,but has since been amended to assert direct claims on behalfof 10 individual plaintiffs.In the course ofdiscovery,approximately 80 private plaintiffs
have provided information about thciralleged damages.Based on information received to date,the 80 private plaintiffs claim damages ofapproximately S60 million.$21 million of
this claim is alleged noneconomic damages(i.e.emotional distress).The Company does not believe noneconomic damages are applicable in this case and will vigorously dispute

such claims.Approximately$6 million ofprivate plaintiffs'claimed damages have been covered by insurance or other forms ofreimbursement.
All proceedings,except forone action filed on September 1,2023 on behalfofthree individual plaintiffs(the"Widman Action")have been consolidated in the Superior Court of
Spokane County Washington underthe lead action Blakeley v.Avista Corporation et al.,and variously assert causes of action fornegligence,private nuisance,and trespass(the
"Blakeley Proceeding").
In November 2023,all panics 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 for trial(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 arc legally responsible for the Babb Road Fire.Atrial date on the liability phase is currently set for May 5,2025,but may
be continued given the current status ofdiscovery.The Widman Action is set fortrial on October 6,2025.
In addition,the stipulated order relating to the Blakeley Proceeding memorializes the plaintifFb'agmement to voluntarily dismiss all claims asserting inverse condemnation as a theory
ofliability,without prejudice to their ability to seek permission from the Court to refile those claims at a laterdate if they can show good cause to do so.The Ridman Action does not
include claims for inverse condemnation.The parties to the Blakeley Proceeding agreed to a preliminary mediation no later than 60 days prior to the liability trial,and,ifthere 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.
The preliminary mediation is scheduled for the first quarter of2025.Finally,the plaintiffs agreed to complete a damages questionnaire identifying all claimed damages being sought
in connection with the litigation.
Based on the facts and circumstances available to the Company through February 25,2025,the date through which the Company has evaluated the impacts ofevents occurring after
December 31,2024 as indicated under"Subsequent Events",the Company was unable to predict the likelihood ofan adverse outcome or estimate a range ofpotential loss in the event
ofsuch an outcome,and did not record an accrual forlosses.Subsequent to February 25.2025,the Company has engaged in mediation discussions with the plaintiffs.Any
information associated with the Babb Road fire arising subsequent to February 25.2025 will be considered in a future period.
Orofnno Fire
In August 2023,a fire subsequently referred to as the"Hospital Fire"started in windy conditions near 0rofino,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.The Company has to date found no evidence suggesting negligence on its part.Except for
two minor claims for damage to personal property which were resolved,the Company has not,at this time,received any claims in connection with the fire.The Company will
vigorously defend itself in the event any additional claims are asserted;however,at this time,it is unable to estimate the likelihood ofan adverse outcome nor the amount or range of a
potential loss in the event ofan adverse outcome.
Colstrip
Colstrip Owners Arbitration and Litigation
Colstrip Units 3 and 4 are owned by the Company,PacifrCorp,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 underan Ownership and Operating Agreement,dated May 6,1981,as amended(O&O Agreement),in the
percentages set forth below:
c�� Usk 3 URN 4
Avista 15% 15%
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 benc6ts associated with coal-fired resources,such as Colstrip.The practical impact ofCETAis electricity from such resources,including Colstrip,may no
longerbe delivered to Washington retail customers after2025.
Agreement Between Avista and North Western
In January 2023,the Company entered into an agreement with NorthWestem under which,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 31,
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)site remediation expenses except certain costsrelating
to post closing activities.In addition,the Company would enterinto an agreement underwhich 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.
The transaction is subject to the satisfaction ofcustomary closing conditions.Although the agreement was also contingent upon NorthWestem's ability to enter into a new coal supply
agreement by December 31,2024,NorthWestem has since waived that contingency.
The Company does not expect this transaction to have a direct material impact on its financial results.
Agreement Between PSE and Northwestern
In July 2024,PSE entered into an agreement with NorthWestem under which,PSE will transfer its 25 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 December3 1,2025.
Burnett et 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,PncifrCorp,PGE,
Avista Corp.,NorthWestem,and Westmoreland Rosebud Mining.The plaintiffs allege a failure to contain coal dust in connection with the operation ofColsitip,and seek unspecified
damages.The Colstrip owners reached a settlement with one ofthe litigants,Richard Burnett,for an amount oflcss than S0.1 million.The settlement does not involve or implicate the
claims ofany other litigants.The Company will vigorously defend itselfin the litigation,but at this time is unable to predict the outcome,nor an amount or range ofpolenlial impact
in the event ofan 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 of the 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.In 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 ofthe Interior,approving expansion ofthe mine into a new area,pending furtheranalysis ofpotential environmental
impact.An initial appeal ofthat decision to the Ninth Circuit was dismissed for lack ofjunsdiction,pending further proceedings before the Department ofthe Interior.Avista Corp.is
not a party to eitherof these proceedings,but continues to monitorthe progress ofboth issues and assess the impact,ifany,ofthe proceedings on Westmoreland's ability to meet its
contractual coal supply obligations.
Rathdrum,Idaho Natural Gas Incident
In October2021,there was an incident in Rathdrum,Idaho involving the Company's natural gas infrastructure.The incident occurred after a third party damaged those facilities
during excavation work.The incidentresnitod in a fire which destroyed one residence and resulted in minor injuries to the occupants.hi 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 received 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 will vigorously defend itself in the
legal proceedings;however,at this time the Company is unable to predict the likelihood ofan adverse outcome orestimate a range ofpotential loss in the event of such an outcome.
Complaint of Consumersforindependent Regional Transmission PlanningforAll FERC-Jurisdictional Transmission Facilities at 100kV and Above

In December 2024,the Company received notice ofs complaint filed with the FERC by Consumers for Independent Regional Transmission Planning against all FERC jurisdictional
Transmission providers with local planning tariffs utilizing facilities at 100 kV and above,which includes the Company.The complaint alleges that the local transmission planning
process allows individual transmission owners to plan FERC jurisdictional transmission facilities without regard to whether that planning is the more efficient or cost-effective project
for the interconnected grid and cost effective for customers.The Company intends to vigorously defend itselfin this action;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.
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
oramount of a 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 ofcontaminated sites,including
assessments ofranges and probabilities ofrecoveries from other responsible parties who either have orhave 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 ofinvestigation,cleanup and
monitoring costs to be incurred.
The Company has potential liabilities underthe Endangered Species Act and similar state statutes for species offish,plants and wildlife that have eitheralready been added to the
endangered species list,listed as"threatened"orpetitioned 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 ratemaking process,ofall operating and capitalized costs related to these issues.
Underthe 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 waterrights.The States of Montana and Idaho are each conducting general adjudications ofwaterrights in areas that include the Company's facilities in these states.Claims
within the Clark Fork Riverbasin and the Spokane Riverbasin could adversely affect the energy production ofthe 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 ofany outcome at this time.The Company will continue to seek recovery,through the ratemaking process,ofall costs related to this
issue.
NOTE 16.REGULATORY MATTERS
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 orrebate 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 ofsurplus transmission capacity.
h 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
rccounting method used to track certain differences between actual power supply costs,net ofwholesale sales and sales offuel,and the amount included in base retail rates for
Washington customers.Under the ERM,the Company defers these differences(over the$4 million deadband and sharing bands)for future surcharge or rebate to customers.
the following is a summary ofthe ERM:
Deferred for
Furore
Surcharge or Expense or
Rebate Benefit
Annual Powcr Supply Cod y'rriability to Customers to the Company
within+/-$0 to$4 million(deadband) 0% 100%
higherby$4 million to$10 million 50% 50%
lowerby$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$36 million as ofDecember 31,2024 and S38 million as ofDecember 31,2023.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,or before,April 1 ofeach yearto provide
the opportunity for the WUTC staffand other interested parties to review the prudence of,and audit,the ERM deferred power cost transactions for the prior cal end aryear.In June
2023,the Company received approval from the WUTC for a rate surcharge to customers over a two-yearperiod,effective July 1,2023.
Avista Corp.has a PCAmechanism in Idaho allowing forthe modification of electric rates on October 1 ofeach 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 orrebate powcrcosts deferred during the preceding July-June twelve-month period.Total net powersupply costs deferred underthe PCAmechanism were
liabilities of$15 million as ofDecember 31,2024 and assets of$8 million as ofDeccmber 31,2023.Deferred powercost assets represent amounts due from customers and liabilities
represent amounts due to customers.
Natural Gas Cost Deferrals and Recovery Mechanisms
Avista Corp.files a PGA in 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 or benefit)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 a liability of$25
million as Of December 31,2024 and an asset of$52 million as of December 31,2023.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 of Avista Corp:s
jurisdictions,Avista Corp.'s electric and natural gas revenues are adjusted so as to be based on the number ofcustomers in certain customer rate classes and assumed"normal"kilowatt
hour and therm sales,rather than 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 December2026.
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 tamed forward for
recovery in a future period.There is no limit on the level ofrebate rate adjustments.New customers added aRera 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 ofeach calendar year,separate electric and natural gas earnings calculations are made for the
calendar yearjust 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 cams more than 0.5 percent higherthan the rate ofretum 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.Apending application would extend the mechanism through August
31,2029.
Oregon Decoupling Mechanism
In Oregon,the Company has a decoupling mechanism for natural gas.An eamings review is conducted on an annual basis.In the annual eamings review,iftbe Company cams more
than 100 basis points above its allowed return on equity,one-third ofthe eamings 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 31,2024 and December 31,2023,the Company had the following cumulative balances outstanding related to decoupling and earnings sharing mechanisms in its
various jurisdictions(dollars in millions):
December 31, December 31,
2024 2023
Washington
Decoupling surcharge(rebate) S 18 $ (3)
Idaho
Decoupling surcharge(rebate) $ 1 S (8)
Provision for earnings sharing rebate _ (1)
Oregon
Decoupling surcharge(rebate) S 1 $ (4)
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 orthe margin.
As ofDecember 31,2024,the Company had a note receivable balance from Avista Capital of$29 million with an applicable interest rate of 7.5 percent.
FERC FORM No.1 (ED.12-96)
Page 122-123

This report is:
Name of Respondent: (1)21 An Original Date of Report: Year/Period of Report
Avista Corporation 04/18/2025 End of:2024/Q4
(2) ❑ A Resubmission
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME,COMPREHENSIVE INCOME,AND HEDGING ACTIVITIES
Other Totals for
Unrealized Minimum Cash Other Net Income
Losses on Other category of
Gains and pension Foreign Flow Cash each (Carried Total
Line Item Available Adjustments items Liability Currency Hedges Flow Forward from Comprehensive
No. (a) For-Sale- (e) recorded in Adjustment Hedges Interest Hedges Page 116, Income
(net amount) (d) Rate [Specify]Account 219 Line 78) ())
Securities (c) Swaps (g) (i)
Balance of
1 Account 219 at (2,058,225) (2,058,225)
Beginning of
Preceding Year
Preceding
Quarter/Year to
Date
2 Reclassifications 0
from Account
219 to Net
Income
Preceding
3 Quarter/Year to 1,701,116 1,701,116
Date Changes in
Fair Value
4 Total(lines 2 and 1,701,116 1,701,116 171,180,214 172,881,330
Balance of
Account 219 at
5 End of (357,109) (357,109)
Preceding
Quarter/Year
Balance of
6 Account 219 at (357,109) (357,109)
Beginning of
Current Year
Current
Quarter/Year to
Date
7 Reclassifications 0
from Account
219 to Net
Income
i
Current
8 Quarter/Year to 712,589 712,589
Date Changes in
Fair Value
9 Total(lines 7 and 712,589 712,589 180,135,566 180,848,155
8)
Balance of
10 Account 219 at 355,480 355,480
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 04/18/2025 End of:2024/Q4
(2) El A Resubmission
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS FOR DEPRECIATION.AMORTIZATION AND DEPLETION
Total Company
For the Current Other Other Other
Line Classification LNe�tric Gas Common
No. (a) Ycar/Quarter (o) (d) (Specify) (Specify) (Specify) (h)
Ended (e)
(b)
1 UTILITY PLANT
2 In Service
3 Plant in Service 8,137,295,369 5,594,245,021 1,776,159,609 766,890,739
(Classified)
4 Property Under Capital 65,812,604 65,812,604
Leases
5 Plant Purchased or
Sold
Completed
6 Construction not
Classified
7 Experimental Plant
Unclassified
8 Total(3thru 7) 8,203,107,973 5,594,245,021 1,776,159,609 832,703,343
9 Leased to Others
10 Held for Future Use 9,399,810 8,669,209 180,896 549,705
11 Construction Work in 206,589,639 184,887,514 5,603,100 16,099,025
Progress
12 Acquisition 251,184 251,184
Adjustments
13 Total Utility Plant(8 8,419,348,606 5,788,052,928 1,781,943,605 849,352,073
thru 12)
Accumulated
Provisions for
14 Depreciation, 2,959,941,113 2,086,904,096 547,115,726 325,921,291
Amortization,&
Depletion
15 Net Utility Plant(13 5,459,407,493 3,701,148,832 1,234,827,879 523,430,782
less 14)
DETAIL OF
ACCUMULATED
16 PROVISIONS FOR
DEPRECIATION,
AMORTIZATION AND
DEPLETION
17 In Service:
18 Depreciation 2,717,635,837 2,038,316,809 545,577,268 133,741,760
FERC FORM No.1 (ED.12-89)
Page 200-201

SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS FOR DEPRECIATION.AMORTIZATION AND DEPLETION
- total Company - —- - - - -Electric Gas -
For the Current Elect Other Other Other
Line Classification
Line
(a) Year/Quarter Ic (d) (Specify) (Specify) (Specify) Common
(h)
Ended (e) (� (g)
(b)
Amortization and
Depletion of Producing
Natural Gas Land and
19 Land Rights
Amortization of
20 Underground Storage
Land and Land Rights
21 Amortization of Other 242,305,276 48,587,287 1,538,458 192,179,531
Utility Plant
22 Total in Service(18 2,959,941,113 2,086,904,096 547,115,726 325,921,291
th ru 21)
23 Leased to Others - -'I:i' - ► : '
24 Depreciation
25 Amortization and
Depletion
26 Total Leased to Others
(24&25)
27 Held for Future
28 Depreciation
29 Amortization
30 Total Held for Future
Use(28&29)
31 Abandonment of
Leases(Natural Gas)
32 Amortization of Plant
Acquisition Adjustment
Total Accum Prov
33 (equals 14) 2,959,941,113 2,086,904,096 547,115,726 325,921,2 11
(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 04/18/2025 End of.2024/Q4
(2) El A Resubmission
ELECTRIC PLANT IN SERVICE(Account 101,102,103 and 106)
Balance Balance at End
Lime Account Beginning of Additions Retirements Adjustments Transfers of Year
No. (a) Year (c) (d) (e) (f) (g)
(n)
1 1.INTANGIBLE PLANT
2 (301)Organization
3 (302)Franchise and 46,804,271 187,021 46,991,292
Consents
4 (303)Miscellaneous 57,840,902 7,288,976 3,929,608 61,200,270
Intangible Plant
TOTAL Intangible Plant
5 (Enter Total of lines 2,3, 104,645,173 7,475,997 3,929,608 108,191,562
and 4)
2.PRODUCTION - -
6 PLANT _ I'I yi r F '•rii . ai i`� —' -
7 A.Steam Production ; .. FI
1
Plant
8 ,
310 Land and Land
1 3 857 5 3857
83 3,857,583
Righ
ts
9 (311)Structures and 141,391,370 1,134,264 736,128 141,789,506
Improvements
10 (312)Boiler Plant 225,251,056 5,771,994 4,776,147 226,246,903
Equipment
(313)Engines and
11 Engine-Driven 231,871 995,760 1,227,631
Generators
12 (314)Turbogenerator 58,299,357 1,075,117 32,262 59,342,212
Units
13 (315)Accessory Electric 30,831,918 995,742 58,659 31,769,001
Equipment
14 (316)Misc.Power Plant 17,366,391 1,327,482 185,459 18,508,414
Equipment
(317)Asset Retirement
15 Costs for Steam 17,463,496 17,463,496
Production
TOTAL Steam
16 Production Plant(Enter 494,693,042 11,300,359 5,788,655 500,204,746
Total of lines 8 thru 15)
17 B.Nuclear Production
Plant
18 (320)Land and Land
Rights
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) M of Year
(b) (g)
19 (321)Structures and
Improvements
20 (322)Reactor Plant
Equipment
21 (323)Turbogenerator
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)
26 C.Hydraulic Production
Plant
27 (330)Land and Land 68,409,461 13,269 68,422,730
Rights
28 (331)Structures and 116,800,927 4,032,998 678,977 120,154,948
Improvements
29 (332)Reservoirs,Dams, 266,279,077 3,483,887 179,858 269,583,106
and Waterways
(333)Water Wheels,
30 Turbines,and 236,032,636 369,297 33,355 236,368,578
Generators
31 (334)Accessory Electric 85,873,492 10,895,156 600,881 96,167,767
Equipment
32 (335)Misc.Power Plant 14,372,935 313,809 26,680 14,660,064
Equipment
33 (336)Roads,Railroads, 3,888,158 32,687 3,920,845
and Bridges
(337)Asset Retirement
34 Costs for Hydraulic
Production
TOTAL Hydraulic
35 Production Plant(Enter 791,656,686 19,141,103 1,519,751 809,278,038
Total of lines 27 thru 34)
36 D.Other Production
Plant -
37 (340)Land and Land I 905,167
905,167
Rights
FERC FORM No.1 (REV.12-05)
Page 204-207

ELECTRIC PLANT IN SERVICE(Account 101,102,103 and 106)
62lan J Balance at End
Line Account Beginning of Additions Retiremonts Adjustments Transfers of Year
No. (a) Year (c) (d) (e) (f) (01
(b)
38 (341)Structures and 17,599,838 88,506 98,085 17,590,259
Improvements
(342)Fuel Holders,
39 Products,and 21,071,023 2,047 21,073,070
Accessories
40 (343)Prime Movers 21,429,793 34,648 21,395,145
41 (344)Generators 237,981,781 2,204,079 293,252 239,892,608
(345)Accessory Electric
42 Equipment 26,560,267 831,177 33,552 27,357,892
43 (346)Misc.Power Plant 1,626,658 1,028 2,069 1,625,617
Equipment
(347)Asset Retirement
44 Costs for Other 351,683 351,683
Production
44.1 (348)Energy Storage
Equipment-Production
TOTAL Other Prod.
45 Plant(Enter Total of 327,526,210 3,126,837 461,606 330,191,441
lines 37 thru 44)
TOTAL Prod.Plant
46 (Enter Total of lines 16, 1,613,875,938 33,568,299 7,770,012 1,639,674,225
25,35,and 45)
47 3.Transmission Plant
48 (350)Land and Land 30,258,236 48,266 259,326 30,047,176
Rights
(351)Energy Storage
48.1 Equipment-
Transmission
49 (352)Structures and 37,380,715 2,481,837 100,573 39,761,979
Improvements
50 (353)Station Equipment 388,257,342 25,731,014 6,006,609 407,981,747
51 (354)Towers and 17,139,468 131,475 3,476 17,267,467
Fixtures
52 (355)Poles and Fixtures 381,335,594 19,526,695 1,006,673 399,855,616
53 (356)Overhead 190,834,129 3,583,877 200,138 194,217,868
Conductors and Devices
54 (357)Underground 3,213,937 513,423 3,727,360
Conduit
55 (358)Underground 6,691,473 513,424 7,204,897
Conductors and Devices
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
o{Year
No. (a) Year (c) (d) (e) (f)
(b) (9)
56 (359)Roads and Trails 2,608,136 25,038 2,633,174
(359.1)Asset
57 Retirement Costs for
Transmission Plant
TOTAL Transmission
58 Plant(Enter Total of 1,057,719,030 52,555,049 7,576,795 1,102,697,284
lines 48 thru 57)
59 4.Distribution Plant
60 (360)Land and Land 16,421,637 2,868,176 (2,534,734) 16,755,079
Rights
61 (361)Structures and 30,984,523 12,554,553 313,403 43,225,673
Improvements
62 (362)Station Equipment 173,171,958 18,601,024 5,354,216 186.418,766
63 (363)Energy Storage
Equipment—Distribution
64 (364)Poles,Towers, 585,744,330 35,580,122 1,261,759 620,062,693
and Fixtures
65 (365)Overhead 366,378,519 26,472,795 125,547 392,725,767
Conductors and Devices
66 (366)Underground 175,726,271 11,622,828 72,482 187,276,617
Conduit
67 (367)Underground 292,108,860 16,745,376 159,892 308,694,344
Conductors and Devices
68 (368)Line Transformers 358,348,464 32,137,314 68,245 390,417,533
69 (369)Services 225,979,671 10,626,097 37,664 236,568,104
70 (370)Meters 87,556,400 1,570,034 230,425 88,896,009
71 (371)Installations on 10,632,944 2,355,480 12,988,424
Customer Premises
72 (372)Leased Property
on Customer Premises
73 (373)Street Lighting and 84,253,081 4,851,360 145,613 88,958,828
Signal Systems
(374)Asset Retirement
74 Costs for Distribution
Plant
TOTAL Distribution
75 Plant(Enter Total of 2,407,306,658 175,985,159 7,769,246 (2,534,734) 2,572,987,837
lines 60 thru 74)
FERC FORM No.1 (REV.12-05)
Page 204-207

ELECTRIC PLANT IN SERVICE(Account 101,102,103 and 106)
I3alanee Balance at End
Line Account Beginning of Additions Retirements Adjustments Transfers of Year
No. (a) Year (c) (d) (e) (f) (9)
(b)
5.REGIONAL
76 TRANSMISSION AND
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 I
Equipment
(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 6
86 (389)Land and Land 1,083,006 1,083,006
Rights
87 (390)Structures and 21,045,508 556,595 30,447 21,571,656
Improvements
88 (391)Office Furniture 3,976,622 709,001 554,085 4,131,538
and Equipment
89 (392)Transportation 62,357,831 4,063,624 1,494,213 (42,691) 64,884,551
Equipment
90 (393)Stores Equipment 472,784 472,784
91 (394)Tools,Shop and 9,005,539 1,813,913 208,301 10,611,151
Garage Equipment
92 (395)Laboratory 3,305,287 167,537 78,186 3,394,638
Equipment
93 (396)Power Operated 25,432,532 139,254 2,469,398 23,102,388
Equipment
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) (g)
94 (397)Communication 42,279,271 1,455,629 2,531,497 41,203,403
Equipment
95 (398)Miscellaneous 258,773 24,635 44,410 238,998
Equipment
96 SUBTOTAL(Enter Total 169,217,153 8,930,188 7,410,537 (42,691) 170,694,113
of lines 86 thru 95)
97 (399)Other Tangible
Property
(399.1)Asset
98 Retirement Costs for
General Plant
TOTAL General Plant
99 (Enter Total of lines96, 169,217,153 8,930,188 7,410,537 (42,691) 170,694,113
97,and 98)
100 TOTAL(Accounts 101 5,352,763,952 278,514,692 34,456,198
and 106) (2,577,425) 5,594,245,021
101 (102)Electric Plant
Purchased(See Instr.8)
102 (Less)(102)Electric
Plant Sold(See Instr.8)
103 (103)Experimental
Plant Unclassified
TOTAL Electric Plant in
104 Service(Enter Total of 5,352,763,952 278,514,692 34,456,198 (2,577,425) 5,594,245,021
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 04/18/2025 End of:2024/Q4
(2) El A Resubmission
ELECTRIC PLANT HELD FOR FUTURE USE(Account 105)
Lb" Description and Location of Property Date Originally Included in Date Expected to be used Balance at End of Year
No. (a) This Account in Utility Service (d)
(b) (c)
1 Land and Rights:
2 Distribution Plant Land,Carlin Bay,Idaho 12/01/2010 12/31/2027 162,352
3 Distribution Plant Land,Moscow,Idaho 08/01/2024 12/31/2028 2,639,261
4 Transmission Plant Land,Spokane, 12/01/2011 12/31/2028 411,202
Washington
5 Transmission Plant Land,Spokane, 12/01/2014 12/31/2025 62,168
Washington
6 Transmission Plant Land,Spokane, 01/01/2017 12/31/2026 56,311
Washington
7 Transmission Plant Land,Spokane, 03/01/2019 03/31/2028 323,427
Washington
8 Transmission Plant Land,Spokane, 03/01/2019 03/31/2028 546,503
Washington
9 Distribution Plant Land,Spokane, 06/01/2024 12/31/2029 1,571,448
Washington
10 Transmission Plant Land,Sandpoint,Idaho 07/01/2019 12/31/2027 486,299
11 Distribution Plant Land,Coeur d'Alene,Idaho 11/01/2020 12/31/2025 775,530
12 Distribution Plant Land,Lewiston,Idaho 06/01/2024 12/31/2027 1,634,708
21 Other Property:
22
23
24
25
26
27
28
29
30
31
32
33
FERC FORM No.1 (ED.12-96)
Page 214

' ELECTRIC PLANT HELD FOR FUTURE USE(Account 105)
Line Description and Location of Property Date Originally Included In Date Expected to be used
p p rtY This Account in Utility Service Balance at End of Year
No. (a) (d)
34
35
36
37
38
39
40
41
42
43
44
45
46
47 TOTAL 8,669,209
FERC FORM No.1 (ED.12-96)
Page 214

This report is:
Name of Respondent: (1)21 An Original Date of Report: Year/Period of Report
Avista Corporation 04/18/2025 End of.2024/Q4
(2) El A Resubmission
CONSTRUCTION WORK IN PROGRESS--ELECTRIC(Account 107)
Line Description of Project Construction work in progress-Electric:
L
in (a) (Account 107)
(b)
1 Long Lake Plant Upgrades 23,562,794
2 Metro 115kV Substation 23,557,874
3 PF North Channel Spillway Repl 20,913,103
4 LL HED Stability Enhancement 10,876,072
5 Substation Rebuilds 10,572,984
6 OMS/ADMS 10,114,951
7 CG HED Station Service Replacement 7,632,390
8 Substation-Capital Spares 6,707,209
9 Nine Mile Unit 3 Mechanical Overhaul 6,692,376
10 Garden Springs 230-115 kV Substation 5,297,286
11 Coyote Springs 2 CT Rotor Replacement 4,928,048
12 HMI Control Software 4,904,977
13 Lolo-Oxbow 230kV Transmission Line Rebuild Project 3,140,892
14 Nine Mile Units 3&4 Control Upgrade 3,108,991
15 Downtown Network-Performance&Capacity 2,917,865
16 Low Priority Ratings Mitigation 2,624,299
17 Noxon Rapids Gantry Crane Modernization 2,384,908
18 New Substations 2,246,176
19 Operational Safety and Compliance 2,021,719
20 Substation Asset Mgmt Capital Maintenance 1,827,493
21 Boulder Park Engine Controls Upgrade 1,705,022
22 Tribal Permits and Settlements 1,602,317
23 Distribution-Spokane North&West 1,548,350
24 Operational Sustainment 1,341,878
25 Idaho AMI 1,338,576
26 Distribution Line Relocations 1,201,568
27 Downtown Network Asset Condition 1,179,293
28 Generation Interconnection 1,178,939
FERC FORM No.1 (ED.12-87)
Page 216

CONSTRUCTION WORK IN PROGRESS--ELECTRIC(Account 107)
Construction work in progress-Electric
Line Description of Project No. (a) (Account 107)
(b)
29 KF 4160 V Station Service Replacement 1,160,542
30 Transportation Equip 1,107,751
31 Wildfire Resiliency 1,065,414
32 Post Falls Redevelopment 1,040,412
33 Minor Projects under$1,000,000 11,005,244
34 R&D/Strategic Initiatives 2,379,801
43 Total 184,887,514
FERC FORM No.1 (ED.12-87)
Page 216

This report is:
Name of Respondent: (1)0 An Original Date of Report: Year/Period of Report
Avista Corporation 04/18/2025 End of:2024/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 I6htf1e1d€®r'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 1,928,168,400 1,928,168,400 0 0
2 Depreciation Provisions for Year,
Charged to
3 (403)Depreciation Expense 153,386,157 153,386,157
4 (403.1)Depreciation Expense for 0
Asset Retirement Costs
5 (413)Exp.of Elec.Pit.Leas.to
Others
6 Transportation Expenses-Clearing 3,086,595 3,086,595
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 156,472,752 156,472,752 0 0
Total of lines 3 thru 9)
F11 Net Charges for Plant Retired:
12 Book Cost of Plant Retired (30,523,917) (30,523,917)
13 Cost of Removal (218,393) (218,393)
14 Salvage(Credit) 1,229,935 1,229,935
15 TOTAL Net Chrgs.for Plant Ret. (29,512,375) (29,512,375)
(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 inAPxAccrual 41,551 41,551
17.3 ARO Depreciation 3,564,346 3,564,346
FERC FORM No.1 (REV.12-05)
Page 219

ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT(Account 108)
Line ite Total(c+d+e) Electric Planfit -Elecfric Plant Held for Electric Plant Leased
No. (a) (b) Service Future Use To Others
(c) (d) (e)
17.4 Transfers 25,904 25,904
17.5 Change in RWIP (2,791,737) (2,791,737)
17.6 General Plant Common Allocated (17,533,971) (17,533,971)
17.7 Immaterial COR Costs (5,781) (5,781)
18 Book Cost or Asset Retirement
Costs Retired
19 Balance End of Year(Enter Totals of 2,038,316,809 2,038,316,809 0 0
lines 1,10,15,16,and 18)
Section B.Balances at End of Year According to Functional Classification
20 Steam Production 409,837,083 409,837,083
21 Nuclear Production
22 Hydraulic Production-Conventional 218,269,232 218,269,232
23 Hydraulic Production-Pumped
Storage
24 Other Production 187,457,469 187,457,469
25 Transmission 304,642,709 304,642,709
26 Distribution 838,447,340 838,447,340
27 Regional Transmission and Market
Operation
28 General 79,662,976 79,662,976
29 TOTAL(Enter Total of lines 20 thru 2,038,316,809 2,038,316,809 0 0
28)
FERC FORM No.1 (REV.12-05)
Page 219

This report is:
Date of Report: Year/Period of Report
Name of Respondent: (1) An Original
Avista Corporation 04/18/2025 End of:2024/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 Beginning of Earnings of for Year Date Acquired Date of Maturity Investment at Investment No. (a) (b) (c) Year Year (f) End of of Year Disposed of
(d) (e) (h)
1 Investment in 01/01/1997 256,138,971 0 256,138,971
Avista Capital
2 Avista Capital- (110,554,654) (6,721,766) (117,276,420)
Equity in Earnings
3 Investment in 07/01/2014 89,816.380 0 89,816,380
AERC
4 AERC-Equity in 29,809,944 8,253,337 5,000,000 33,063,281
Earnings
42 Total Cost of Total 265,210,641 1,531,571 5,000,000 261,742,212 0
Account 123.1 $ W.
FERC FORM No.1 (ED.12-89)
Page 224-225

This report is:
Name of Respondent: (1)21 An Original Date of Report: Year/Period of Report
Avista Corporation (2) ❑A Resubmission 04/18/2025 End of:2024/Q4
MATERIALS AND SUPPLIES
Line Account Balance Beginning of Balance End of Year Department or Departments which Use
No. (a) Year Material
(b) (c) (d)
1 Fuel Stock(Account 151) 4,683,150 6,331,080
2 Fuel Stock Expenses Undistributed 0 0
(Account152)
3 Residuals and Extracted Products 0 0
(Account 153)
4 Plant Materials and Operating Supplies
(Account154)
5 Assigned to-Construction(Estimated) 58,422,040 81,166,828 (1)Electric
6 Assigned to-Operations and
Maintenance
7 Production Plant(Estimated) 5,531,231 6,695,684 (1)Electric
8 Transmission Plant(Estimated) 114,052 136,004 (1)Electric
9 Distribution Plant(Estimated) 897,097 938,011 (1)Electric
10 Regional Transmission and Market
Operation Plant(Estimated)
11 Assigned to-Other(provide details in 14,528,108 12,640,173 1 Natural Gas
footnote) ( )Electric(2)
12 TOTAL Account 154(Enter Total of 79,492,528 101,576,700
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 84,175,678 107,907,780
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 04/18/2025 End of:2024/Q4
(2) ❑ A Resubmission
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)
1 Transmission Studies
2 NextEra Studies for TSRs 26,645 186200
3 ENEL Studies for TSR 100,421 186200
20 Total 127,066 0
21 Generation Studies
22 Martinsdale Wind Proj#83 4,435 186200
23 Jane Wind 2 Proj#96 2,013 186200
24 Jane Wind Proj#95 2,445 186200
25 Broadview IV Project#107 2,949 186200
26 Ursus Wind Project#108 3,681 186200
27 Gordon Butte South Wind Q116 3,227 186200
28 CS PV Q113 1,955 186200
29 CS Wind 2 Q115 1,618 186200
30 CS Wind 1 Q114 1,817 186200
31 Ursiane Wind#118 2,281 186200
32 Royal Slope-Juwi-ESA 11,856 186200
33 Colstrip Solar 2,535 186200
34 CS23-13 Facilities Study 26,804 186200
35 CS23-14 Facilities Study 20,234 186200
36 CS23-06 Facilities Study 24,939 186200
37 CS23-12 Facilities Study 24,396 186200
38 CA1 West Plains 2024 Phase 1 54,046 186200
39 CA1 West Plains 2024 Phase 2 21,213 186200
40 CA5 Palouse 2024 Phase 1 38,964 186200 9,696 186210
41 CA5 Palouse 2024 Phase 1 Restudy 11,865 186200
42 CA5 Palouse 2024 Phase 2 1,184 186200
43 CABD Third&Hatch 2024 Phase 1 9,052 186200
FERC FORM No.1 (NEW.03-07)
Page 231

Transmission Service and Generation Interconnection Study Costs
Costs Incurred During Account Reimbursements Account Credited
Line Description Period Charged Received During the With
No. (a) (b) (c) Period Reimbursement
(d) (e)
44 CABD Third&Hatch 2024 Faclty Stdy 13,454 186200
45 CABB Othello 2024 Phase 1 8,337 186200
46 CABB Othello 2024 Fclty Study 16,972 186200
47 CABC Othello 2024 Phase 1 8,573 186200
48 CABC Othello 2024 Fclty Stdy 8,982 186200
49 CABA S.Othello 2024 Phase 1 7,712 186200
50 CA7 Big Bend 2024 Phase 1 24,802 186200 24,802 186210
51 Haymaker Wind Proj#82 12,392 186200 12,392 186210
52 CA3A-CDA2024 Phase 1 21,093 186200 21,093 186210
53 CA313 Sandpoint 2024 Phase 1 19,015 186200 19,015 186210
39 Total 414,841 86,998
40 Grand Total -541,907 -86,998
FERC FORM No.1 (NEW.03-07)
Page 231

This report is:
Name of Respondent: (1)21 An Original Date of Report: Year/Period of Report
Avista Corporation 04/18/2025 End of:2024/Q4
(2) ❑A Resubmission
FOOTNOTE DATA
1a1 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)21 An Original Date of Report: Year/Period of Report
Avista Corporation (2) ❑ A Resubmission 04/18/2025 End of.2024/Q4
OTHER REGULATORY ASSETS(Account 182.3)
CREDITS Ckoft
Balance at Written off
Description and Purpose of Beginning of During Balance at end of
Line p p g g Written off During
Other Regulatory Assets Current Debits QyarterNear Current
No. 9 rY (c) Account the Period Amount
(a) QuartedYear (e) Quarter/Year
(b) Charged (f)
(d)
1 WA Excess Nat Gas Line 2,583,244 0 407 1,550,391 1,032,853
Extension Allowance
u
2 Reg Asset Post Ret Liabilility 112,462,393 1,008,986 228 11,386,178 102,085,201
LJ
3 Regulatory Asset FAS 109 Utility 78,172,454 638,386 283 5,280,347 73,530,493
Plant
4 Regulatory Asset FAS 109 DSIT 2,681,673 399,532 283 724,394 2,356,811
Non Plant
5 Regulatory Asset Lake CDA 36,692,352 0 407 1,116,805 35,575,547
Settlement-Varies
6 Reg Assets-Decoupling 2,435,722 29,867,538 456,495 25,632,120 6,671,140
Surcharges
�v
7 Reg Asset-Colstrip 19,428,968 7,424,361 407 1,547,703 25,305,626
L
8 Regulatory Asset FAS 143 Asset 2,298,569 139,782 0 2,438,351
Retirement Obligation
9 Regulatory Asset Workers Comp 1,930,165 535,342 242 560,236 1,905,271
W
10 Interest Rate Swap Asset 179,488,399 74,909 242 7,230,381 172,332,927
11 DSM Asset 10,257,486 31,617,768 0 41,875,254
12 Deferred ITC 3,602,106 13 283,410 102,352 3,499,767
13 Regulatory Asset MDMSystem 29,345,159 0 407 3,035,706 26,309,453
Lnj
14 Regulatory Asset BPA 1,550,215 1,311,195 407 2,449,182 412,228
Residential Exchange
15 Regulatory Asset FISERV 170,311 0 407 170,311 0
16 Regulatory Asset AFUDC 59,066,092 39,475,508 Various 38,914,609 59,626,991
(I PIS,WIP)&Equity DFIT
FERC FORM No.1 (REV.02-04)
Page 232

OTHER REGULATORY ASSETS(Account 182.3)
CREDITS CREDITS
Written off
Balance at During Balance at end of
Line Description and Purpose of Beginning of Debits Quart Written off During Current
Other Regulatory Assets Current Account
Quarter/Year
r the Period Amount
No. (a) Quarter/Year (c) Accoount (e) �
(b) Charged M
(d)
17 Regulatory Asset ID PCA 7,627,491 0 557 7,627,491 0
Deferral
18 Existing Meters/ERTS 17,635,170 0 407 1,824,328 15,810,842
Retirement Def
19 Regulatory Asset Colstrip 750,000 0 407 750,000 0
Community Fund
20 Lsj Regulatory Asset COVID-1 9 657,789 280,301 407 674,974 263,116
E)
21 Regulatory Asset Energy 582,599 0 407 349,559 233,040
Imbalance Market
22 Regulatory Asset-Wildfire 23,737,455 8,506,283 407 9,768,051 22,475,687
Resiliency&Balancing
i
23 Deferral for CS2&Colstrip 2,018,257 3,250,141 407 1,397,496 3,870,902
(O&M,Excess Depr)
Lwj
24 Regulatory Asset Tax Basis 145,169,206 7,349,256 282,283 2,870,669 149,647,793
Flow through
25 Regulatory Asset Commodity 69,139,449 177,234,474 244,175 205,809,844 40,564,079
MTM ST&LT
L
26 Regulatory Asset Energy 1,301,000 264,081 182 1,565,081 0
Affordability Act I
Lj
27 Reg Asset-Insurance Balancing 288,789 11,461,312 407 681,480 11,068,621
Acct
28 Reg Asset-Energy Efficiency 594,833 609,466 242 778,348 425,951
i
29 Deferred Regulatory Fees 1,915,416 2,212,454 407 86,100 4,041,770
L
30 Regulatory Asset Pension 10,841,956 0 407 985,632 9,856,324
Settlement Deferral
31 14 Reg Asset-CCA 46,022,329 I 33,285,653 407 29,660,212 49,647,770
32 WA ERM Deferral 25,478,297 17,504,772 557 17,607,876 25,375,193
33 Reg Asset-MT Riverbed 1,613,960 51,076 0 1,665,036
Escrow Int
FERC FORM No.1 (REV.02-04)
Page 232

OTHER REGULATORY ASSETS(Account 182.3)
CREDITS CREDITS
Balance at Written off
Line Description and Purpose of Beginning of During Written off During Balance at end of
Other Regulatory Assets Current Debits QuarterNear the Period Amount Current
No. (a) Quarter/Year (c) Account (e) Quarter/Year
(b) Charged (f)
(d)
34 RegAsset-Depreciation 511,800 0 407 511,800 0
35 Reg Asset-PPA Interest 0 383,630 0 383,630
Deferral
36 Reg Liab-Tax Customer Credit 0 2,926,457 0 2,926,457
37 Misc Reg Asset 141,003 185,974 407 129,522 197,455
44 TOTAL 898,192,107 377,998,650 382,779,178 893,411,579
FERC FORM No.1 (REV.02-04)
Page 232

This report is:
Name of Respondent: (1)0 An Original Date of Report: Year/Period of Report
Avista Corporation 04/18/2025 End of.2024/Q4
(2) El A Resubmission
FOOTNOTE DATA
kW 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 for a 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.
(c)Concept:DescriptionAndPurposeOfOtherRegulatoryAssets
Deferred tax flow through balance on utility plant.Amortization occurs over book life of respective utility plant assets.
11)Concept:DescdptionAndPurposeOfOtherRegulatoryAssets
Deferred tax flow through balance on utility plant.Amortization occurs overbook life of respective utility plant assets.
Ue Concept:DescdptionAndPurposeOfOtherRegulatoryAssets
WA Docket No UE-080416;ID order AVU-E-08-01.Amort duu 2059.
Mf Concept:DescdptionAndPurposeOfOtherRegulatoryAssets
Deeoupling 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.
Lq)Concept:DescdptionAndPurposeOfOtherRegulatoryAssets
For WA Elec,ammort 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.
U 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.
La Concept:DescriptionAndPurposeOfOtherRegulatoryAssets
Quarterly adjustments to workers comp reserve for current unpaid claims.
M Concept:DescriptionAndPurposeOfOtherRegulatoryAssets
Settled swaps are amortized over the life of the associated debt.
Concept:DescriptionAndPurposeOfOtherRegulatoryAssets
Amort period varies depending on timing of transactions.
U Concept:DescriptionAndPurposeOfOtherRegulatoryAssets
Amort period varies depending on underlying transactions.
IM Concept:DescdptionAndPurposeOfOtherRegulatoryAssets
WA Docket Nos UE-180418,UG-180419.
U Concept:DescriptionAndPurposeOfOtherRegulatoryAssets
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.
Lo)Concept:DescdptionAndPurposeOfOtherRegulatoryAssets
ID Order No 33494,Docket Nos.AVU-E-16-01 and Stipulation and Settlement Docket No AVU-E-19-04.
U Concept:DescriptionAndPurposeOfOtherRegulatoryAssets
Deferring the difference between FERC formula and State approved AFUDC rates from 2010 to present.
LW Concept:DescriptionAndPurposeOfOtherRegulatoryAssets
WA Docket No UE-002066 and ID Order No 28648.
fr)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.
Ls)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
1D PUC Order No 34606.Deferral of costs related to Avista's entry in the Energy Imbalance Market in March 2022.
.(u�Concept:DescdpbonAndPurposeOfOtherRegulatoryAssets
Deferral of O&M wildfire expenses as per ID PUC Order 34883 and WA Dockets UE-200900,UG-200901,and UE-200894.
Jv)Concept:DescriptionAndPurposeOfOtherRegulatoryAssets
WA Order 09,Docket Nos.UE-190334,UG-190335,and UE-190222.
U Concept:DescdptionAndPurposeOfOtherRegulatoryAssets
A 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
No 21-131-Accounting method Change for federal income tax expense associated with Industry Director Directive No.5 mixed service costs for meters.
Lx)Concept:DescdptionAndPurposeOfOtherRegulatoryAssets
WA Docket No UE-002066 and ID Order No 28648.
W Concept:DescdptionAndPurposeOfOtherRegulatoryAssets
Deferral of costs associated with OR House Bill 2475.
Lz)Concept:DescriptionAndPurposeOfOtherRegulatoryAssets
To defer costs above or below the baseline in accordance with Order No 10/04 Docket Nos UE-220053,UE-210854,and UG-220054.
as Concept:DescdptionAndPurposeOfOtherRegulatoryAssets
o defer costs of compliance for CPP(OR-UM 2254)and CCA(WA-Doc.UG-220803)in relation to energy efficiency programs to reduce
GHG for natural gas customers.
ab Concept:DescriptionAndPurposeOfOtherRegulatoryAssets
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.
ac Concept:Descr ptionAndPurposeOfOtherRegulatoryAssets
To 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.
Lad)Concept:DescriptionAndPurposeOfOtherRegulatoryAssets
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.
ae Concept:DescriptionAndPurposeOfOtherRegulatoryAssets
Washington Energy Recovery Mechanism
of 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.
k@W Concept:DescriptionAndPurposeOfOtherRegulatoryAssets
(Difference between depreciation rates in GRC verses effective date based on ID Order 35909 Dockets AVU-E-23-01 and AVU-G-23-01.
ah Concept:DescriptionAndPurposeOfOtherRegulatoryAssets
Accrued interest on power purchase agreements in connection with the clean energy action plan per RCW 80.28.410.
ai Concept:DescdptionAndPurposeOfOtherRegulatoryAssets
Deferral and Amortization resulting from the approval of flow through tax treatment for IDD#5 and meters basis adjustments.
jaj)Concept:DescdptionAndPurposeOfOtherRegulatoryAssets
Grouped minor items.
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 (2) El A Resubmission 04/18/2025 End of:2024/Q4
MISCELLANEOUS DEFFERED DEBITS(Account 186)
CREDITS CREDITS
Line Description of Miscellaneous Balance at Credits Balance at End of '
Deferred Debits Beginning of Year Debits Account Credits Amount Year
No. (a) (b) (c) Charged (e)
(d) M
1 Reg Asset-Battery Storage 3,422,093 0 3,422,093
2 Plant Alloc of Clearing Journal 6,207,998 5,038,606 11,246,604
3 Reg Asset-ERM 12,160,663 VAR 1,654,718 10,505,945
4 WA REC Deferral 412,639 557 412,639 0
5 Reg Asset-Decoupling 9,112,109 9,988,171 19,100,280
Deferred
6 Reg Asset-COVID 19 Deferral 11,484,555 0 11,484,555
7 Reg Asset-CEIP 1,033,207 1,811,891 2,845,098
8 Reg Asset-Williams Outage 10,297,716 VAR 646,170 9,651;546
9 Misc Deferred Debits-Pension 33,003,989 2,395,079 35,399,068
10 Nez Perce Settlement 103,561 557 5,188 98,373
11 City of Post Falls Lease Pay 126,851 VAR 126,851 0
12 I Post Falls HED Project63 101,121 VAR 101,121 0
13 DCL Inter Study 3 DsnConst 0 372,096 372,096
14 ENEL Studies for TSR 0 100,421 100,421
15 Network Future State 0 254,378 254,378
16 Misc.Deferred Debits<$100,000 51,402 VAR 459,536 (408,134)
47 Miscellaneous Work in Progress
48 Deferred Regulatory Comm.
Expenses(See pages 350-351)
49 TOTAL 87,517,904 I 104,072,323
FERC FORM No.1 (ED.12-94) III
Page 233

This report is:
Name of Respondent: (1)®An Original Date of Report: Year/Period of Report
Avista Corporation 04/18/2025 End of.2024/Q4
(2) El A Resubmission
i
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 84,418,866 58,173,189
7 Other
8 TOTAL Electric(Enter Total of lines 2 thru 7) 84,418,866 58,173,189
9 Gas
10 Gas 24,041,518 22,258,935
15 Other
16 TOTALGas(Enter Total of lines 10 thru 15) 24,041,518 22,258,935
17.1 Lai Other105,691,804 73,690,794
17 Other(Specify)
18 TOTAL(Acct 190)(Total of lines 8,16 and 17) 214,152,188 154,122,918
FERC FORM NO.1 (ED.12-88)
Page 234
Notes

This report is:
Name of Respondent: (1)0 An Original Date of Report: Year/Period of Report
Avista Corporation (2) El A Resubmission 04/18/2025 End of:2024/Q4
FOOTNOTE DATA
Ja)Concept:DescdptionOfAccumulatedDeferredlncomeTax
Beg.Balance End.Balance
Pension,Medical,and SERP 34,671,763 31,876,832
Federal Income Tax Carryforwards 27,406,304 1,202,010
State Income Tax Carryforwards 17,952,286 21,234,188
Derivative Instruments 16,269,451 10,631,115
Compensation and Payroll 6,986,432 7,010,014
Plant Excess Deferred Gross Up 3,951,713 3,340,097
Other Common Deferred Tax Assets (1,546,146) (1,603,462)
Total 105,691,803 73,690,794
FERC FORM NO.1 (ED.12-88)
Page 234

This report is:
Name of Respondent: (1)® Date of Report: Year/Period of Report
An Original
Avista Corporation 04/18/2025 End of:2024/Q4
(2) ❑A Resubmission
CAPITAL STOCKS(Account 201 and 204)
Outstanding per Outstanding per
Bal.Sheet(Total Bal.Sheet(Total
amount
amount outstanding
Number of Shares 9
Line
Class and Series of Stock and Authorized by Par or Stated Value Call Price at End of outstanding without
No. Name of Stock Series Charter per Share Year without reduction reduction for
(a) (b) (c) (d) for amounts held amounts held by
by respondent) respondent)
Shares Amount
(e) (f)
1 Common Stock(Account 201)
2 No Par Value 200,000,000 80,039,000 1,667,222,874
3 Restricted Shares
13 Total 200,000,000 80,039,000 1,667,222,874
14 Preferred Stock(Account 204)
15 Cumulative 10,000,000
18 Total 10,000,000 0 0
FERC FORM NO.1 (ED.12-91)
Page 250-251

CAPITAL STOCKS(Account 201 and 204)
Held it Respondent 2 Held it RStock ec Held by Respondent In Sinking Held by Respondent In Sinking
Line Reacquired Stock(Acct 217) Reacquired Stock(Acct 217)
No. Shares Cost and Other Funds Shares and Other Funds Amount
(g) (h)
1
2
3 158,464 5,958,729
13 I —
14
15
18 � - -
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 2025-04-18 End of-2024/Q4
(2) El A Resubmission
Other Paid-in Capital
Line Item Amount
No. (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) i ;;: i f ,-�'- ` i-•l
14 Beginning Balance Amount (2,732,405)
15 Increases(Decreases)Due to Miscellaneous Paid-In Capital
16 Ending Balance Amount (2,732,405)
17 Other Paid in Capital
18 Beginning Balance Amount
19 Increases(Decreases)in Other Paid-In Capital
20 Ending Balance Amount 0
40 Total (2,732,405)
FERC FORM No.1 (ED.12-87)
Page 253

This report is:
Name of Respondent: (1)®An Original Date of Report: Year/Period of Report
Avista Corporation (2) ❑ A Resubmission 04/18/2025 End of.2024/Q4
CAPITAL STOCK EXPENSE(Account 214)
Class and Series of Stock Balance at End of
Line No. (a) Year
(b)
1 Common Stock-no par (55,172,369)
22 TOTAL (55,172,369)
FERC FORM No.1 (ED.12-87)
Page 254b

This report is:
Name of Respondent: (1)21 An Original Date of Report: Year/Period of Report
Avista Corporation 04/18/2025 End of.2024/Q4
(2) El A Resubmission
LONG-TERM DEBT(Account 221,222,223 and 224)
Class and Series of
ObNgettoti, oepotr;Rate(For idetoWd Total Expense, Total
Principal Amount
Line ne55�viatE,glNe st�is¢Siae Ek ��a3 Premium or Total Expense Total Premium Discount
of Deb(;isslued
No. g4i>£�oriz.�t irit raft wtbe4s id #�u�f�er Discount (e) (� t
dates) (b) (c) (d) (J)
(a)
1 Bonds(Account 221)
2 FMBS-SERIES C-6.37% 221300 25,000,000 158,304
DUE 06/18/2028
3 35 BS-6.25%DUE 12-01- 221400 150,000,000 1,812,935 900,500
4 FMBS-5.70%DUE 07-01- 221420 150,000,000 4,702,304 222,000
2037
5 5.55%SERIES DUE 12-20- 221540 35,000,000 258,834
2040
6 4.45%SERIES DUE 12-14- 221560 85,000,000 692,833
2041
7 4.11%SERIES DUE 12-1- 221610 60,000,000 428,205
2044
8 4.37%SERIES DUE 12-1- 221620 100,000,000 590,761
2045
9 4.23%SERIES DUE 11-29- 221580 80,000,000 730,832
2047
10 3.91%SERIES DUE 12-1-2047 221640 90,000,000 552,539
11 4.35%SERIES DUE 6-1- 221650 375,000,000 4,246,448 378,750
2048
12 3.43%SERIES DUE 12-1- 221660 180,000,000 1,108,340
2049
13 3.07%SERIES DUE 9-1- 221670 165,000,000 1,074,990
2050
14 2.90%SERIES DUE 221680 140,000,000 1,083,452
10/01/2051
15 3.54%SERIES DUE 2051 221630 175,000,000 1,042,569
16 4.00%SERIES DUE 221690 400,000,000 4,579,993 144,000
4/1/2052
17 5.66%SERIES DUE 04-01- 221710 250,000,000 1,444,302
2053
18 COLSTRIP 2010A PCR13s 221350 66,700,000 965,618
DUE 2032
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 of Debt Issued Premium or Total Expense Total Premium
No. Authorization numbers and Number Discount (e) Discount
(f)
dates) (b) (c) (d) (g)
(a)
19 COLSTRIP 2010E PCRBs 221360 17,000,000 I 264,085
DUE 2034
20 Subtotal 2,543,700,000 _ 25,737,344 0 1,645,250
21 Reacquired Bonds(Account
222)
22
23
24
25 Subtotal
26 Advances from Associated - -
Companies(Account 223) -
27 ADVANCE ASSOCIATED 223011 51,547,000 1,296,086
AVISTA CAPITAL II(ToPRS)
28 Subtotal 51,547,000 1,296,086
Other Long Term Debt ?r T
29 (Account 224)
30
31
32
33 Subtotal
33 TOTAL 2,595,247,000
FERC FORM No.1 (ED.12-96)
Page 256-257

LONG-TERM DEBT(Account 221,222,223 and 224)
Nominal Date of - u Interest for Year
Line Issue Date of Maturity PERIOD Date From PERIOD Date To w7haut Q Amount
No. �h) () G) (k) amounts ti (m)
respondent)
(1}
-
2 06/19/1998 06/19/2028 06/19/1998 06/19/2028 25,000,000 I 1,592,500
3 11/17/2005 12/01/2035 11/17/2005 12/01/2035 150,000,000 9,375,000
4 12/15/2006 07/01/2037 12/15/2006 07/01/2037 150,000,000 8,550,000
5 12/20/2010 12/20/2040 12/20/2010 12/20/2040 35,000,000 1,942,500
6 12/14/2011 12/14/2041 12/14/2011 12/14/2041 85,000,000 3,782,500
7 12/18/2014 12/01/2044 12/18/2014 12/01/2044 60,000,000 2,466,000
8 12/16/2015 12/01/2045 12/16/2015 12/01/2045 100,000,000 4,370,000
9 11/30/2012 11/29/2047 11/30/2012 11/29/2047 80,000,000 3,384,000
10 12/14/2017 12/01/2047 12/14/2017 12/01/2047 90,000,000 3,519,000
11 05/22/2018 06/01/2048 05/22/2018 06/01/2048 375,000,000 16,312,500
12 11/26/2019 12/01/2049 11/26/2019 12/01/2049 180,000,000 6,174,000
13 09/30/2020 09/30/2050 09/30/2020 09/30/2050 165,000,000 5,065,500
14 09/28/2021 10/01/2051 09/28/2021 10/01/2051 140,000,000 4,060,000
15 12/15/2016 12/01/2051 12/15/2016 12/01/2051 175,000,000 6,195,000
16 03/17/2022 04/01/2052 03/17/2022 04/01/2052 400,000,000 16,000,000
17 03/29/2023 04/01/2053 03/29/2023 04/01/2053 250,000,000 14,150,000
18 04/01/2024 10/01/2032 04/01/2024 10/01/2032 66,700,000 1,292,313
19 04/01/2024 03/01/2034 04/01/2024 03/01/2034 17,000,000 329,375
20 2,543,700,000 108,560,188
21
22
23
24
25 0
26
27 06/03/1997 06/01/2037 06/03/1997 06/01/2037 51,547,000 2,575,297
28 51,547,000 2,575,297
29 I -
FERC FORM No.1 (ED.12-96)
Page 256-257

LONG-TERM DEBT(Account 221,222,223 and 224)
Outstanding(Total
Nominal Date of AMORTIZATION AMORTIZATION amount outstanding Interest for Year
Line Date of Maturity without reduction for
Issue PERIOD Date From PERIOD Date To Amount
No. (h) W ()) (k) amounts held by (m)
respondent)
(I)
30
31
32
33 0
33 2,595,247,000 111,135,485
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 04/18/2025 End of:2024/Q4
(2) El A Resubmission
RECONCILIATION OF REPORTED NET INCOME WITH TAXABLE INCOME FOR FEDERAL INCOME TAXES
Line Particulars(Details) Amount
No. (a) (b)
1 Net Income for the Year(Page 117) 180,135,566
2 Reconciling Items forthe Year
3
4 Taxable Income Not Reported on Books
5 Contributions in Aid of Construction 14,886,504
6 Other 36,294,996
9 Deductions Recorded on Books Not Deducted for Return
10 Book Depreciation 273,381,876
11 Federal Income Tax Expense 287,918
12 State Income Tax Expense (31,149)
13 Subsidiary Overheads 725,157
14 Other 146,643,628
14 Income Recorded on Books Not Included in Return
15 Subsidiary Earnings 1,531,571
16 Other 34,892,415
19 Deductions on Return Not Charged Against Book Income
20 Tax Depreciation 248,402,156
21 Plant Basis Adjustment 101,845,755
22 Other 167,349,813
27 Federal Tax Net Income 98,302,786
28 Show Computation of Tax:
29 Federa I Tax at 21% 20,643,585
30 Business Credits Utilized (17,264,409)
31 Prior Year True Ups 746,791
32 Total Federal Current Tax Expense 4,125,967
FERC FORM NO.1 (ED.12-96)
Page 261

This report is:
Name of Respondent: (1)21 An Original Date of Report: Year/Period of Report
Avista Corporation (2) El A Resubmission 04/18/2025 End of:2024/Q4
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)
M
1 Income Tax Federal Tax 2020
2 Income Tax Federal Tax 2023
3 Income Tax Federal Tax 2024
4 Subtotal Federal Tax 0 0
5 Property Tax Property Tax WA 2023 14,233,320
6 Property Tax Property Tax WA 2024
7 Property Tax Property Tax ID 2023 2,048,214
8 Property Tax Property Tax ID 2024
9 Property Tax Property Tax MT 2023 3,675,530
10 Property Tax Property Tax MT 2024
11 Property Tax Property Tax OR 2023 4,233,606
12 Property Tax Property Tax OR 2024
13 Subtotal Property Tax 19,957,064 4,233,606
14 Excise Tax Excise Tax WA 2018
15 Excise Tax Excise Tax WA 2019
16 Excise Tax Excise Tax WA 2020
17 Excise Tax Excise Tax WA 2021
18 Excise Tax Excise Tax WA 2023 3,960,799
19 Excise Tax Excise Tax WA 2024
20 Corp Activities Tax-CAT Excise Tax OR 2023
21 Corp Activities Tax-CAT Excise Tax OR 2024
22 Subtotal Excise Tax 3,960,799 0
23 Natural Gas Use Tax Sales And Use Tax WA 2023 5,824
24 Natural Gas Use Tax Sales And Use Tax WA 2024
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) 2()) 165)
M
25 Use Tax Sales And Use Tax WA 2018
26 Use Tax Sales And Use Tax WA 2019
27 Use Tax Sales And Use Tax WA 2020
28 Use Tax Sales And Use Tax WA 2021
29 Use Tax Sales And Use Tax WA 2023 241,889
30 Use Tax Sales And Use Tax WA 2024
31 Use Tax Sales And Use Tax ID 2023 52,694
32 Use Tax Sales And Use Tax ID 2024
33 Subtotal Sales And Use 300,407 0
Tax
34 Municipal Occupation Tax Local Tax WA 2023 3,823,700
35 Municipal Occupation Tax Local Tax WA 2024
36 Subtotal Local Tax 3,823,700 0
37 KWH Tax Other Taxes ID 2023 22,224
38 KWH Tax Other Taxes ID 2024
39 KWH Tax Other Taxes MT 2023 219,378
40 KWH Tax Other Taxes MT 2024
41 WA Renewable Energy Other Taxes WA 2024
Credits
42 Subtotal Other Taxes 241,602 0
43 Income Tax State Tax ID 2023
44 Income Tax State Tax ID 2024
45 Income Tax State Tax MT 2023
46 Income Tax State Tax MT 2024
47 Income Tax State Tax OR 2023
48 Income Tax State Tax OR 2024
49 Income Tax State Tax Misc 2024
50 Subtotal State Tax 0 0
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)
M
51 Payroll Taxes Payroll Tax ID 2023 3,747
52 Payroll Taxes Payroll Tax ID 2024
53 Payroll Taxes Payroll Tax MT 2023 239
54 Payroll Taxes Payroll Tax MT 2024
55 Payroll Taxes Payroll Tax OR 2023 10,829
56 Payroll Taxes Payroll Tax OR 2024
57 Payroll Taxes Payroll Tax WA 2023 (125,238)
58 Payroll Taxes Payroll Tax WA 2024
59 Payroll Taxes Payroll Tax MISC 2023 720
60 Payroll Taxes Payroll Tax MISC 2024
61 Payroll Taxes Payroll Tax FED 2023 1,052,854
62 Payroll Taxes Payroll Tax FED 2024
63 Subtotal Payroll Tax 943,151 0
64 Franchise Tax Franchise Tax ID 2023 1,372,780
65 Franchise Tax Franchise Tax ID 2024
66 Franchise Tax Franchise Tax OR 2023 1,279,644
67 Franchise Tax Franchise Tax OR 2024
68 Subtotal Franchise Tax 2,652,424 0
69 Consumer Council Fee TOther License And Fees MT 2023 10
70 Consumer Council Fee TOther License And Fees MT 2024
71 Public Commission Fee TOther License And Fees MT 2023 50
72 Public Commission Fee Other License And Fees MT 2024
Tax
73 Subtotal Other License 60 0
And Fees Tax
40 TOTAL 31,879,207 4,233,606
FERC FORM NO.1 (ED.12-96)
Page 262-263

TAXES ACCRUED,PREPAID AND CHARGES DURING YEAR
BALANCE AT END f 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 (Account236) 165) 408.1,409.1)
No. (9) (h) (�) U) (k) (I)
1 (847,386) (847,386) 0
2 746,790 1,271,415 524,625 0 2,744,271
3 3,226,894 7,201,000 3,974,106 ! 0 (13,973,028)
4 3,973,684 7,625,029 3,651,345 0 0 (11,228,757)
5 (452,595) 13,780,724 (1) 0 (386,070)
6 14,250,327 1 14,250,328 10,703,475
7 (634,704) 1,413,509 (1) 0 421
8 2,579,148 651,106 1,928,042 1,487,340
9 309,549 3,985,078 (1) 0 309,549
10 6,514,446 3,273,648 1 3,240,799 6,514,446
11 4,233,606 0 1,690,104
12 4,001,392 8,002,628 0 4,001,236 1,609,146
13 30,801,169 31,106,693 (1) 19,419,169 4,001,236 21,928,411
14 164,708 164,708 87,897
15 1,789,049 1,789,049 89,686
16 169,866 169,866 87,688
17 (64,551) (64,551) (30,537)
18 105,993 4,066,792 0 96,368
19 37,934,731 33,751,857 4,182,874 27,135,228
20 85,864 100,276 14,412 0
21 1,000,000 1,000,000 0
22 41,185,660 38,918,925 14,412 6,241,946 0 27,466,330
23 4,039 9,864 1 0 4,039
24 122,674 122,590 84 3,253
25 (174,420) (174,420)
26 (381,322) (381,322)
27 (625,368) (625,368)
28 (335,436) (335,436)
29 (4,416) 237,473 0
FERC FORM NO.1 (ED.12-96)
Page 262-263

TAXES ACCRUED,PREPAID AND CHARGES DURING YEAR
BALANCE ATEND 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. (9) (h) (i) (1) 16 ) (I)
30 2,860,132 2,253,199 T 606,933
31 52,693 (1) 0
32 235,387 181,737 1 53,651
33 1,701,270 2,857,556 1 (855,878) 0 7,292
34 (10,824) 3,812,877 1 0 (9,469)
35 31,779,742 27,647,417 4,132,325 22,389,328
36 31,768,918 31,460,294 1 4,132,325 0 22,379,859
37 103 22,368 41 0 103
38 342,367 324,109 (40) 18,218 342,367
39 (4) 219,374 0 (4)
40 923,826 704,269 219,557 923,826
41 622,440 622,440 0 0
42 1,888,732 1,892,560 1 237,775 0 1,266,292
43 10 (10) 0 9
44 120 100 (20) 0 102
45 0
46 50 50 0 50
47 0
48 100,000 100,000 0 20,000
49 975 975 0 123
50 101,155 101,125 (30) 0 0 20,284
51 2,117 (1,630) 0
52 79,756 59,365 20,391 24,096
53 239 0
54 5,153 5,019 134 1,557
55 (10,829) 0
56 69,682 58,417 11,265 21,053
57 125,238 0
58 1,147,321 627,177 520,144 346,634
FERC FORM NO.1 (ED.12-96)
Page 262-263

TAXES ACCRUED,PREPAID AND CHARGES DURING YEAR 1
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 During Year Year Adjustments (Account 236) (included in Account 408A,409.1)
No. (g) (h) (i) G) 16 ) 0)
59 (720) 0
60 1,994 1,944 50 602
61 (170,384) 1,012 (881,458) 0 (51,477)
62 17,943,947 17,943,947 769,400 769,400 5,421,312
63 19,077,469 18,699,237 1 1,321,384 0 5,763,777
64 9 1,372,789 0 50
65 6,101,860 4,818,900 1,282,960 4,225,509
66 1,376 1,281,022 2 0
67 5,035,862 3,574,329 (1) 1,461,532
68 11,139,107 11,047,040 1 2,744,492 0 4,225,559
69 8 (2) 0
70 40 32 2 10 40
71 50 0
72 240 195 1 46 240
73 280 285 1 56 0 280
40 141,637,444 143,708,744 3,665,732 33,241,269 4,001,236 71,829,327
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) 439) (o)
1
2 (1,997,481)
3 J 17,199,922
4 0 0 15,202,441
5 (66,525)
6 3,546,852
7 (635,125)
l 1,091,808
9
10
11 2,543,502
12 2,392,246
13 0 0 8,872,758
14
76,811
15
1,699,363
16
82,178
17 (34,014)
18
9,625
19 10,799,503
20
85,864
21
1,000,000
22 0 0 13,719,330
23
24
119,421
25 (174,420)
26 (381,322)
27 (625,368)
28 (335,436)
29
(4,416)
30 2,860,132
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)
31
32 235,387
33 0 0 1,693,978
34 (1,355)
35 9,390,414
36 0 9,389,059
37
38
39
40
41 622,440
42 0 0 622,440
43 1
44 18
45
46
47
48 80,000
49 852
50 0 0 80,871
51
52 55,660
53
54 3,596
55
56 48,629
57
58 800,687
59
60 1,392
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) 439) (o)
(n)
61 (118,907)
62 F 12,522,635
63 0 0 13,313,692
64 (41)
65 1,876,351
66 1,376
67 5,035,862
68 0 0 6,913,548
69
70
71
72
73 0 0 0
40 0 0 69,808,117
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 04/18/2025 End of:2024/Q4
(2) ❑ A Resubmission
ACCUMULATED DEFERRED INVESTMENT TAX CREDITS(Account 255)
Allocations to Allocations to
Deferred for Der-erred for Year Current Current Year's
Year Year's Income
Balance at
Income
Line Account Subdivisions Account No. Amount Account No. Amount
No. (a) Beginning
of Year (c) (d) (e) (f)
1 Electric Utility
2 3%
3 10%
4 Fed ITC 27,101,607 411.4 695,705 411.4 799,869
5 Idaho ITC 960,335 411.4 51 411.4 26,511
8 TOTAL Electric(Enter Total of lines 28,061,942 695,756 826,380
2 thru 7)
9 Other(List separately and show
3%,4%,7%,10%and TOTAL)
10 Gas Property(100%
11 Idaho ITC 171,220 411.4 9 411.4 4,728
47 OTHERTOTAL 171,220 9 4,728
48 GRAND TOTAL 28,233,162
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)
(h) G)
1
2
3
4 26,997,443
5 933,875
8 27,931,318
9
10
11 166,501
47 166,501
48 28,097,819
FERC FORM NO.1 (ED.12-89)
Page 266-267

This report is:
Name of Respondent: (1)21 An Original Date of Report: Year/Period of Report
Avista Corporation 04/18/2025 End of.2024/Q4
(2) ❑ A Resubmission
OTHER DEFERRED CREDITS(Account 253)
DEBITS DEBITS
Line Description and Other Deferred Balance at Contra A Balance at End of
d
No. Credits Beginning of Year Account ( )nt Cr(e)its Year
(a) (b) (c) , (f)
1 Deferred Gas Exchange 1,406,250 495 5,625,000 5,625,000 1,406,250
2 Bills Pole Rentals 666,361 454 1,680,627 1,748,552 734,286
3 Defer Comp Active Execs 7,793,908 128 494,678 2,081,070 9,380,300
4 Unbilled Revenue 4,654,027 908 49,864,716 55,527,842 10,317,153
5 L 8,466,683 182,456, 8,466,683 0
Decoupling Deferred Credits 495
Lei 7,749,100 407,236 214,234 823,589 8,358,455
6 Reg Liability-COVID-19 Deferral
7 Ldl WA REC Deferrals 0 186,431, 2,810,569 3,950,992 1,140,423
557
8 Timber Harvest 226,796 226,796
9 Other DeriCr-FISERV 870,702 903 316,667 304,298 858,333
10 Accts Pay-Software Licenses- 1.077,496 242 1,098,874 1,226,661 1,205,283
LT
11 Misc.Deferred Credits 6,920 407,186 400,554 471,777 78,143
47 TOTAL 32,918,243110 70,972,602 71,759,781 33,705,422
FERC FORM NO.1 (ED.12-94)
Page 269

This report is:
Name of Respondent: (1)0 An Original Date of Report: Year/Period of Report
Avista Corporation (2) ❑ A Resubmission 04/18/2025 End of:2024/Q4
FOOTNOTE DATA
!a)Concept:DescdptionOfOtherDeferredCredits
FortisBC and Avista exchange volumes of gas on a firm delivery basis during differenttime periods.Amortization is recorded monthly every
year.This contract ends April 2025.
Concept:DescdptionOfOtherDeferredCredits
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.
LQ Concept:DescdptionOfOtherDeferredCredits
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.
Ldl Concept:DescriptionOfOtherDeferredCredits
WA Docket UE-190334,Schedule 98.
.(e)Concept:DescdptionOfOtherDeferredCredits
Other Deferred Credit-Fisery
Mt Concept:DescdptionOfOtherDeferredCredits
Deferred Liability for Software Licenses
FERC FORM NO.1 (ED.12-94)
Page 269

This report is:
Name of Respondent: (1)0 An Original Date of Report: Year/Period of Report
Avista Corporation 04/18/2025 End of:2024/Q4
(2) ❑ A Resubmission
ACCUMULATED DEFERRED INCOME TAXES-OTHER PROPERTY(Account282)
CHANGES' CHANGES CHAN $ 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) Account411.2M
1 Account282
2 Electric 439,198,735 460,906 0
3 Gas 157,037,181 2,421,002 0
4 Other(Specify) 56,983,954 (1,523,849) 1,245,646
5 Total(Total of lines 2 thru 4) 653,219,870 1,358,059 1,245,646
6
7
8
9 TOTAL Account282(Total of 653,219,870 1,358,059 1,245,646
Lines 5 thru 8)
10 Classification of TOTAL
11 Federal Income Tax 653,219,870 1,358,059 1,245,646
12 State Income Tax
13 Local Income Tax
FERC FORM NO.1 (ED.12-96)
Page 274-275

ACCUMULATED DEFERRED INCOME TAXES-OTHER PROPERTY(Account 282)
ADJUSTMENTS DJUSTMENTS ADJUSTMENTS ADJUSTMENTS
Debits Debits Credits Credits
Line Account Credited Amount Account Debited Amount Balance at End of Year
No. (g) (h) (i) G) (k)
1
2 182.3 656,968 440,316,609
3 182.3 2,881,115 162,339,298
4 182.3 457,540 54,671,999
5 0 3,995,623 657,327,906
6
7
8 0
9 0 3,995,623 657,327,906
10
11 3,995,623 657,327,906
12
13
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 04/18/2025 End of:2024/Q4
(2) El A Resubmission
ACCUMULATED DEFERRED INCOME TAXES-OTHER(Account283)
CHANGES d-VAk S 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) Account 411.2
(b) (c) (d) (e) M
1 Account283
2 Electric
2 822 5,360,201 136 648 198,277
3 Electric 50,155,679 5,78 ( )
9 TOTAL Electric(Total of lines 3 50,155,679 5,782,822 5,360,201 136,648 (198,277)
thru 8)
10 Gas
11 Gas 22,133,532 (609,090) 21,009,561 328,400 (133,561)
17 TOTAL Gas(Total of lines 11 22,133,532 (609,090) 21,009,561 328,400 (133,561)
thru 16)
18 TOTAL Other 184,421,504 3,052,828 3,129,109 68,781 0
19 TOTAL(Acct 283)(Enter Total 256,710,715 8,226,560 29,498,871 533,829 (331,838)
of lines 9,17 and 18)
20 Classification of TOTAL
21 Federal Income Tax 256,710,715 8,226,560 29,498,871 533,829 (331,838)
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) (J) (k)
1
2 1
3 F 182/254 182,499 J 51,095,724
9 0 182,499 51,095,724
10
11 182/254 765,866 1,742,708
17 0 765,866 1,742,708
18 182/254 10,807,552 173,606,452
19 10,807,552 948,365 226,444,884
�errr
20
21 10,807,552 948,365 226,444,884
22
23
NOTES
FERC FORM NO.1 (ED.12-96)
Page 276-277

This report is:
Name of Respondent: (1)Z An Original Date of Report: Year/Period of Report
Avista Corporation 04/18/2025 End of:2024/Q4
(2) El A Resubmission
OTHER REGULATORY LIABILITIES(Account 254)
-- -- DEBITS DEBITS
Balance at Balance at End of
Line Description and Purpose of Beginning of Account Amount Credits Current
No. Ottier Regulatory Liablfities Current Credited (d) (e) Quarter/Year
(a) Quarter/Year (c) (fl
(b)
1 Idaho Investment Tax Credit 7,105,476 190 8,287 4,320,338 11,417,527
2 Lbj Interest Rate Swaps 23,751,628 175,427 3,908,282 4,397,000 24,240,346
3 Nez Perce 440,276 557 22,008 0 418,268
4 Idaho Earnings Test 572,475 407 343,485 0 228,990
5 Decoupling Rebate 17,998,342 495,182 20,977,937 8,424,296 5,444,701
6 Deferred Federal ITC-Varies 7,204,302 190 204,794 27 6,999,535
7 Plant Excess Deferred 301,619,229 190,282 297,908,665 283,963,634 287,674,198
8 4,987,044 182,431, 7,260,923 4,079,552 1,805,673
DSM Tariff Rider 908
9 LW
Low Income Energy Assistance 51734,024 242,908 11,038,765 10,259,367 4,954,626
IJ f
10 Reg Liability-OR Tax Strategy 569,566 407 481,897 11,201 98,870
Deferral
11 Reg Liability-Tax Reform 139,305 407 95,175 5,320 49,450
Amortization
m
12 Reg Liability-Energy Efficiency 714,598 232 514,282 7,673 207,989
Assistance
11
13 Reg Liability-COVID-19 2,807,374 407 1,843,711 512,139 1,475,802
Deferral
14 Reg Liability-Tax Customer 56,253,863 410,190 31,804,782 10,525,190 34,974,271
Credit
15 CS2 Insurance Proceeds 867,237 0 76,656 943,893
Deferral
16 Misc.Regulatory Liabilities 11,238,054 190,143 1,162,690 33,802 10,109,166
17 Reg Liability-CCA 37,231,122 407 15,496,504 22,064,809 43,799,427
18 Depreciation Regulatory Liability 0 0 2,732,550 2,732,5 00
FERC FORM NO.1 (REV 02-04)
Page 278

OTHER REGULATORY LIABILITIES(Account 254)
DEBITS DEBITS
Balance at Balance at End of
Line Description and Purpose of Beginning of Account n r
Am t
ount Credits Cure
No. Other Regulatory Liabilities Current Credited ( (e) Quarter/Year
Current
(a) Quarter[Year (c)
(b) M
19 Idaho PCA Deferral 0 557,419 10,976,381 25,888,417 14,912,036
20 Battery Storage ITC 0 190 7,933 184,934 177,001
41 TOTAL 479,233,915 I 404,056,501 377,486.905 452,664,319
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 04/18/2025 End of:2024/Q4
(2) ❑ A Resubmission
FOOTNOTE DATA
1a)Concept:DescdptionAndPurposeOfOtherRegulatoryLiabilities
Not amortized.
Jb)Concept:DescdptionAndPurposeOfOtherRegulatoryLiabilities
Mark-to-Markel 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.
(c)Concept:DeschptionAndPurposeOfOtherRegulatoryLiabilities
Decoupling rebates are recognized during the period they occur,subject to certain limitations.Rebates are returned to customers within 24 months of the
deferral.
Concept:DescdptionAndPurposeOfOtherRegulatoryLiabilities
Noxon ITC-65yr amort,ends 2077
Community Solar ITC-20yr amoM ends 2035
Nine Mile ITC-65yr amoM ends 2080.
Le)Concept:DescdptionAndPurposeOfOtherRegulatoryLiabilities
Amortized over remaining book life of plant,estimated 36 years.
Mt Concept:DescriptionAndPurposeOfOtherRegulatoryLiabilities
\VA Orders Dockets UE-190912 and UG-190920,Idaho Docket AVU-E-I8-12 and AVU-G-18-08,OR Order No. 19-424.
�W 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)
Lh)Concept:DescdptionAndPurposeOfOtherRegulatoryLiabilities
OR Docket No UM 2124.Deferral of associated state tax savings.
Concept:DescriptionAndPurposeOfOtherRegulatoryLiabilities
WA Docket No.UG-170486
ID Docket No.AVU-E-23-01
W Concept:DescdptionAndPurposeOfOtherRegulatoryLiabilities
Avista's contribution in the Energy Assistance Fund as per ID Settlement Stipulation Case#AVU-E-19-04
Concept:DescriptionAndPurposeOfOtherRegulatoryLiabilities
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.
-W Concept:DescriptionAndPurposeOfOtherRegulatoryLiabilities
WA Order 0l,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 nonnalization flow-through for Industry Director Directive No.5 mixed service costs and meters.
Lm)Concept:DescdptionAndPurposeOfOtherRegulatoryLiabilities
Insurance proceeds for failed transformer at Coyote Springs per WA Order UE-210893 Order 01_
Ln)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_
U Concept:DescdptionAndPurposeOfOtherRegulatoryLiabilities

0 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.
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 04/18/2025 End of:2024/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) Previous year Current Year
Quarterly/Annual Quarterly) Quarterly/Annual Year(no
(b) (c) (d) (no Quarterly) (no Quarterly)(E) (fl Quarterly)
(g)
1 Sales of Electricity
2 (440)Residential Sales 473,446,187 425,258,195 4,017,618 4,020,329 371,076 366,450
(442)Commercial and
3 Industrial Sales -
4 Small(or Comm.)(See 369,033,306 343,522,797 3,166,267 3,159,672 45,794 45,341
Instr.4)
5 Large(or Ind.)(See Instr. 145,879,427 120,123.256 2,195,428 2,096,554 1,175 1,188
6 (444)Public Street and 8,819,256 7,975,679 16,978 16,839 739 690
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 1,993,992 1,606,948 16,560 14,475 179 162
Sales
10 TOTAL Sales to Ultimate 99g 172,168 898,486,875 9,412,851 9,307,869 418,963 413,831
Consumers
11 (447)Sales for Resale 231,161,008 253,658,001 3,788,593 3,521,491
12 TOTAL Sales of 1,230,333,176 1,152,144,876 13,201,444 12,829,360 418,963 413,831
Electricity
13 (Less)(449.1)Provision 0 0 0
for Rate Refunds
14 TOTAL Revenues 1,230,333,176 1,152,144,876 13,201,444 12,829,360 418,963 413,831
Before Prov.for Refunds
15 Other Operating
Revenues
16 (450)Forfeited 0
Discounts
17 (451)Miscellaneous 164,999 129,396
Service Revenues
18 (453)Sales of Water and 586,004 688,332
Water Power
FERC FORM NO.1 (REV.12-05)
Page 300-301

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 PER MONTH
Amount PER MONTH
Date Previous year(no Year to Date Previous
No. (a) Quarterly/Annual Quarterly) Quarterly/Annual Previous year Current Year Year(no
(no Quarterly) (no Quarterly)
(b) (c) (d) (e) (f) Quarterly)
_ (g)
19 (454)Rent from Electric 6,261,512 7,542,853
Property
(455)Interdepartmental
20 Rents 0 0
21 (456)Other Electric 53,721,330 2,198,927
Revenues
(456.1)Revenues from
22 Transmission of 35,825,135 30,969,981
Electricity of Others
23 (457.1)Regional Control 0 0
Service Revenues
24 (457.2)Miscellaneous 0
Revenues
25 Other Miscellaneous
Operating Revenues
26 TOTAL Other Operating 96,558,980 41,529,489
Revenues
27 TOTAL Electric 1,326,892,156 1,193,674,365
Operating Revenues
Line12,column(b)includes$(812,253)of unbilled revenues.
Line12,column(d)includes(11,695)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 04/18/2025 End of:2024/Q4
(2) El A Resubmission
SALES OF ELECTRICITY BY RATE SCHEDULES
Line
Number and Title of Rate MWh Sold Revenue Average Number KWh of Sales Per Revenue Per
Schedule of Customers Customer KWh Sold
No. (a) (b) (c) (d) (e) (�
1 01 Residential Service 3,885,230 438,367,692 351,388 11,056.809 0.1128
2 07 Time-of-Use-Residential 203 21,062 13 15,615.3846 0.1038
Service
08 Time-of-Use with Morning
3 D 92 9,844 7 13,142.8571 0.107
Discount Service
4 11 General Service 0 478 0
5 12 Residential&Farm General 107,413 17,159,560 17,725 6,059.9718 0.1598
Service
22 Residential and Farm Large
6 38,529 4,158,808 61 631,622.9508 0.1079
General Service
7 30 Pumping Service 51 6,597 7 7,285.7143 0.1294
8 32 Residential and Farm 10,819 1,646,167 1,875 5,770.1333 0.1522
Pumping Service
9 48 Residential and Farm Area 2,888 1,401,782 0 0.4854
Lighting
10 58 Tax Adjustment 0 12,588,057 0
11 95 Optional Renewable Power 0 221,974 0
41 TOTAL Billed Residential 4,045,225 475,582,021 371,076 10,901.3383 0.1176
Sales
42 TOTAL Unbilled Rev.(See (27,607) (2,135,834) 0.0774
Instr.6)
[43 TOTAL 4,017,618 473,446,187 371,076 10,826.9411 0.1178
FERC FORM NO.1 (ED.12-95)
Page 304

This report is:
Name of Respondent: (1)21 An Original Date of Report: Year/Period of Report
Avista Corporation (2) ❑ A Resubmission 04/18/2025 End of:2024/Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
Number and Title of Average Number KWh of Sales Per Revenue Per
Line Schedule MWh Sold Revenue of Customers Customer KWh Sold
No. (a) (b) (cI (d) (e) M
1 11 General Service 1,250,063 151,416,815 42,605 29,340.7581 0.1211
13 Optional Commercial
2 Electric Vehicle Rate-General 1,117 162,928 25 44,680 0.1459
Service
3 17 Time-of-Use-General 3 409 0.1363
Service
4 18 Time-of-Use with Morning 1 307 0.307
Discount-General Service
5 21 Large General Service 1,463,034 163,835,178 1,781 821,467.7148 0.112
23 Optional Commercial
6 Electric Vehicle Rate-Large 3,699 442,931 5 739,800 0.1197
General Service
7 25 Extra Large General 340,345 26,894,278 13 26,180,384.6154 0.079
Service
8 31 Pumping Service 116,471 12,872,702 1,365 85,326.7399 0.1105
9 47 Area Light 4,013 1,816,460 0 0.4526
10 49 Area Lighting 2,037 817,358 0 0.4013
11 58 Tax Adjustment 0 12,790,273 0
12 95 Optional Renewable Power 0 164,461 0
TOTAL Billed Small or
41 Commercial 3,180,783 371,214,100 45,794 69,458.5098 0.1167
42 TOTAL Unbilled Rev.Small or (14,516) (2,180,794) 0.1502
Commercial(See Instr.6)
43 TOTAL Small or Commercial 3,166,267 369,033,306 45,794 69,141.5251 0.1166
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 04/18/2025 End of:2024/Q4
(2) El A Resubmission
SALES OF ELECTRICITY BY RATE SCHEDULES
Number and Title of Rate MWh Sold Revenue Average Number KWh of Sales Per Revenue Per
Line Schedule of Customers Customer KWh Sold
No. (a) (b) (c) (d) (e) M
1 11 General Service 17,435 1,991,430 229 76,135.3712 0.1142
2 21 Large General Service 139,513 15,261,753 90 1,550,144.4444 0.1094
3 25 Extra Large General 1,922,646 115,202,119 25 76,905,840 0.0599
Service
4 30 Pumping Service 33,048 3,082,228 50 660,960 0.0933
5 31 Pumping Service 48,431 5,439.003 669 72,393.1241 0.1123
6 32 Residential and Farm 3,776 427,895 112 33,714.2857 0.1133
Pumping Service
7 47 Area Lighting Comm/Ind 104 34,172 0 0.3286
8 48 Residential and Farm Area 0 287 0 0.6048
Lighting
9 49 Area Lighting 47 15,500 0 0.3298
10 58 Tax Adjustment 0 919,701 0
11 95 Optional Renewable Power 0 964 0
41 TOTAL Billed Large(or Ind.) 2,165,000 142,375,052 1,175 1,842,553.1915 0.0658
Sales
42 TOTAL Unbilled Rev.Large(or 30,428 3,504,375 0.1152
Ind.)(See Instr.6)
43 TOTAL Large(or Ind.) 2,195,428 145,879,427 1,175 I 1,868,449.3617 0.0664
FERC FORM NO.1 (ED.12-95) III
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 04/18/2025 End of:2024/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 42 Company Owned Steet 14,360 8,148,201 645 22,263.5659 0.5674
Light Service
44 Company Owned Steet
2 Light Energy&Maintenance 386 77,124 23 16,782.6087 0.1998
Service-High Pressure
Sodium Vapor
3 45 Company Owned Steet 567 62,802 11 51,545.4545 0.1108
Light Energy Service
4 46 Company Owned Steet 1,665 233,262 60 27,750 0.1401
Light Energy Service
5 58 Tax Adjustment 0 297,867 0
41 TOTAL Billed Public Street and 16,978 8,819,256 739 22,974.2896 0.5195
Highway Lighting
42 TOTAL Unbilled Rev.(See
Instr.6)
43 TOTAL 16,978 8,819,256 739 22,974.2896 0.5195
FERC FORM NO.1 (ED.12-95)
Page 304

report is:e This rpo
Name of Respondent: Th Th po Original Date of Report: Year/Period of Report
Avista Corporation 04/18/2025 End of.2024/Q4
(2) ❑A Resubmission
SALES OF ELECTRICITY BY RATE SCHEDULES
Number and Title of Rate Average Number of KWh of Sales Per Revenue Pcr
Line MWh Sold Revenue Customers Customer KWh Sold
No. Schedule (b) (c)
(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
FERC FORM NO.1 (ED.12-95)
Page 304

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 ( Customers Customer KWh Sold
29
30
31
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 l 0 0
FERC FORM NO.1 (ED.12-95) l
Page 304

This report is:
Date of Report: Year/Period of Report
Name of Respondent: (1) An Original
Avista Corporation 04/18/2025 End of:2024/Q4
(2) ❑A Resubmission
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 Custome Customer KWh Sold
1 Customers Customer
(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
FERC FORM NO.1 (ED.12-95)
Page 304

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) (>7
29
30
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:
Name of Respondent: (1)®An Original Date of Report: Year/Period of Report
Avista Corporation 04/18/2025 End of:20241 Q4
(2) El A Resubmission
SALES OF ELECTRICITY BY RATE SCHEDULES
Number and Title of Rate Average Number KWh of Sales Per Revenue Per
Line Schedule MWh Sold Revenue of Customers Customer KWh Sold
No. (a) (b) (c) (d) (e) (1)
1 01 Residential Service 172 18,450 15 11,661.0169 0.1073
2 11 General Service 4,452 580,248 123 36,195.122 0.1303
3 12 Residential&Farm General 14 2,117 1 14,000 0.1512
Service
13 Optional Commercial
4 Electric Vehicle Rate-General 447 67,149 17 26,294.1176 0.1502
Service
5 21 Large General Service 10,548 1,180.979 17 620,470.5882 0.112
6 31 Pumping Service 794 84,069 5 158,800 0.1059
7 32 Residential and Farm 24 3,037 1 24,000 0.1265
Pumping Service
8 47 Area Light 104 54,770 0 0.5266
9 48 Residential and Farm Area 1 417 0 0.417
Lighting
10 49 Area Lighting 4 1,764 0 0.441
11 58 Tax Adjustment 0 992 0
41 TOTAL Billed Interdepartmental 16,560 1,993,992 179 92,513.9665 0.1204
Sales
42 TOTAL Unbilled Rev.(See
Instr.6)
43 TOTAL 16,560 1,993,992 179 92,513.9665 0.1204
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 (2)El A Resubmission 04/18/2025 End of:2024/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) M
1
2 l
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
FERC FORM NO.1 (ED.12-95)
Page 304

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) (fl
29
30
31
32
33
34
35
36
37
38
39
40
41 TOTAL Billed Provision For
Rate Refunds
42 TOTAL Unbilled Rev.(See
Instr.6)
43 TOTAL 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 04/18/2025 End of:2024/Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
Line Number and Title of Rate MWh Sold Revenue Average Number of KWh of Sales Per Revenue Per
Schedule Customers Customer KWh Sold
No. (a) (b) (c) (d) (e) (fl
41 TOTAL Billed-All Accounts 9,424,546 999,984,421 418,963 22,494.9363 0.1061
42 TOTAL Unbilled Rev.(See (11,695) (812,253) 0.0695
Instr.6)-All Accounts
43 TOTAL-AII Accounts 9,412,851 999,172,168 418,963 22,467.0221 0.1061
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 04/18/2025 End of.2024/Q4
(2) El A Resubmission
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 Affifiational Class1111cation Schedule or Billing Demand NCP Demand Demand
No, (a) (b) Tariff Number (few) (e) M
(c) (d)
1 Altop Energy Trading SF Tariff
2 Avangrid Renewables,LLC SF Tariff 9
2W
3 Avangrid Renewables,LLC LF Tariff 12
4 Avangrid Renewables,LLC of Tariff 9
5 Avangrid Renewables,LLC IF Tariff 9
LW
6 BHE Power Watch,LLC LF Tariff 12
7 BP Energy Company SF Tariff
�:8 ] Bonneville Power Administration SF Tariff
9 Bonneville Power Administration LF Tariff 12
10 Bonneville Power Administration uLF Tariff9
11 Bonneville Power Administration LF Tariff
12 British Columbia Hydro and LF
Power Authority Tariff 12
13 Brookfield Energy Marketing LP SF Tariff 9
14 CP Energy Marketing(US)Inc. SF Tariff 9
15 California Independent System SF Tariff
Operator Corporation
16 Calpine Energy Services,LP SF Tariff 9
Lto
17 Chelan County PUD No.1 LF Tariff 12
18 Clatskanie Peoples PUD SF Tariff
19 ConocoPhillips Company SF Tariff
20 Constellation Energy Generation, SF Tariff 9
Con
21 Constellation Energy Generation, Tariff 9
LLC LF
FERC FORM NO.1 (ED.12-90)
Page 310-311

SALES FOR RESALE(Account447)
ACTUAL DEMAND ACTUAL DEMAND
(MW) (MW)
Line Name of Company or Public Statistical FERC Rate Average Monthly Average Monthly Average Monthly CP
Authority(Footnote Affiliations) Classification 'Schedule or Billing Demand NCP Demarud Demand
No. (a) (b) Tariff Number (MW) (e) M
(c) (d)
22 Douglas County PUD No.1 IF Tariff 9
23 Dynasty Power,Inc. SF Tariff 9
24 Dynasty Power,Inc. LF Tariff 9
25 EDF Trading North America,LLC SF Tariff 9
26 EDF Trading North America,LLC LF Tariff 9
27 EDF Trading North America,LLC SF Tariff 9
28 Energy Keepers,Inc. SF Tariff 9
29 Energy Keepers,Inc. LF Tariff 9
30 Eugene Water Electric Board SF Tariff 9
Gridforce Energy Management,
31 LLC LF Tariff 12
32 Guzman Energy,LLC SF Tariff
33 Guzman Energy,LLC LF Tariff 9
34 Idaho Power Company SF Tariff 9
35 Idaho Power Company LF A
Tariff 12
36 Idaho Power Company Balancing SF Tariff 9
lu
37 Idaho Power Company Balancing LF Tariff 9
38 Idaho Power Company Balancing LF Tariff 9
39 Idaho Power Company Balancing LF Tariff 9
40 Idaho Power Company Balancing LF Tariff 9
41 J.Aron&Company SF Tariff 9
42 Kootenai Electric Cooperative IF Tariff 9
43 Kootenai Renewable Energy LLC IF Tariff 9
44 Macquarie Energy LLC SF Tariff 9
45 Macquarie Energy LLC LF Tariff 9
FERC FORM NO.1(ED.12-90)
Page 310-311

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 NCP Demand Demand
No. (a) (b) Tariff Number (MW) (e) M
(c) (d)
46 MAG Energy Solutions SF Tariff 9
47 MAG Energy Solutions IF Tariff 9
u
48 Mercuria Energy America,LLC LF Tariff 9
49 Mercuria Energy America,LLC SF Tariff 9
50 Merrill Lynch Commodities,Inc. SF Tariff
u
51 Mizuho Securities USA Inc. OS NA
Morgan Stanley Capital Group
52 Inc. SF Tariff 9
53 Morgan Stanley Capital Group Tariff 9
Inc. LF
54 Morgan Stanley Capital Group u Tariff 9
Inc. LF
55 Morgan Stanley Capital Group SF Tariff 9
Inc.
56 Morgan Stanley Capital Group SF Tariff 9
Inc.
57 Nevada Power Company SF Tariff
58 Nevada Power Company IIF Tariff 9
59 NorthWestern Energy SF Tariff
60 NorthWestern Energy LF Tariff 9
61 NorthWestern Energy LF Tariff 12
62 NorthWestern Energy LF Tariff
63 NorthWestem Energy LF Tariff 9
64 PacifiCorp SF Tariff
65 PacifiCorp LF Tariff 9
LW
66 PacifiCorp LF Tariff 12
67 PacifiCorp LF Tariff 9
FERC FORM NO.1 (ED.12-90)
Page 310-311

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 NCP Demand Demand
No. (a) (b) Tariff Number (MW) (e) (�
(c) (d)
68 PacifiCorp ITLF Tariff 9
69 Pend Oreille County Public Utility LF Tariff 9
District#1
Pend Oreille County Public Utility
70 District#1 LF Tariff9
Pend Oreille County Public Utility
71 District#1 LF Tariff9
72 Pend Oreille County Public Utility SF Tariff 9
District#1
73 Phillips 66 Energy Trading,LLC SF Tariff 9
74— Phillips 66 Energy Trading,LLC IF Tariff 9
75 Portland General Electric SF Tariff9
76 Portland General Electric LF Tariff 12
77 Portland General Electric LF Tariff 9
78 Portland General Electric IF Tariff 9
79 Power Ex SF Tariff 9
80 Power Ex LF Tariff 9
81 Puget Sound Energy LF Tariff 9
82 Puget Sound Energy SF Tariff 9
83 Puget Sound Energy LF Lbij
Tariff 12
84 Puget Sound Energy LF Tariff 9
85 Rainbow Energy Marketing SF Tariff 9
86 Rainbow Energy Marketing LF Tariff 9
87 Sacramento Municipal Utility LF
District Tariff 12
88 Seattle City Light SF Tariff 9
89 Seattle City Light LF Tariff 9
FERC FORM NO.1 (ED.12-90)
Page 310-311

SALES FOR RESALE(Account447)
ACTUAL DEMAND A•MIAL DEMAND
(MW) (MW)
Name of Company or Pubtla Statistical FERC Rate Average Monthly Averaye Monthly Average Monthly CP
Line Schedule or Billing Demand NCP Demand Demand
Autttortty(FootnotcAffiFiations) Classification
No. (a) (b) Tariff Number (MW)Number (�
(c) (d)
90 Seattle City Light LF Tariff 9
91 Seattle City Light LF Tariff 12
92 Shell Energy N.A. SF Tariff
93 Shell Energy N.A. LF Tariff 9
94 Snohomish County PUD SF Tariff
95 Sovereign Power LF Tariff 9
96 Sovereign Power LF Tariff 9
97 Tacoma Power SF Tariff9
98 Tacoma Power LF Tariff 9
u
99 Tacoma Power LF Tariff 12
100 Talen Energy Montana,LLC LF Tariff 9
101 Tenaska Power Services Co. LF Tariff 9
102 The Energy Authority SF Tariff 9
103 The Energy Authority LF Tariff 9
104 TransAlta Energy Marketing SF Tariff
105 5TransAlta Energy Marketing LF Tariff 9
106 Vitol,Inc. SF Tariff
107 Vitol,Inc. LF Tariff 9
108 Wells Fargo Securities,LLC OAS NA
109 IntraCompany Wheeling LF
u
110 IntraCompany Generation LF
111 California Independent System Lbal Tariff 9
Operator Corporation OS
112 jaj Powerdex Pricing Accrual SF Tariff 9
FERC FORM NO.1 (ED.12-90)
Page 310-311

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 NCP Demand Demand
No. a (b) Tariff Number (MW) (e) (fl
(c) (d)
15 Subtotal-RQ
16 Subtotal-Non-RQ
17 Total
FERC FORM NO.1 (ED.12-90)
Page 310�311

SALES FOR RESALE(Account447)
REVENUE REVENUE REVENUE
Line Megawatt Hours Sold Demand Charges(S) Energy Charges(S) Other Charges(5) Total($)(h+i+j)
No. (g) _ (h) (i) G) (k)
1 7,328 402,081 402,081
2 167,697 6,485,026 6,485,026
3 33 1,546 1,546
4 208 6,226 6,226
5 47,360 0 0
6 13 375 375
7 229,853 14,830,048 14,830,048
8 703,420 53,759,020 53,759,020
9 112 2,968 2,968
10 62,787 3,290,804 3,290,804
11 111,091 0 0
12 4 180 180
13 16,911 607,117 607,117
14 9 135 135
15 186 170,561 170,561
16 23,328 741,813 741,813
17 4 76 76
18 668 28,614 28,614
19 17,675 867,579 867,579
20 106,878 7,564,969 7,564,969
21 32 1,260 1,260
22 1,103 1,103
23 F
49,290 3,212,131 3,212,131
24 49 2,287 2,287
25 4,403 202,806 202,806
26 248 7,475 7,475
27 0 L2)300 300
28 43,998 3,946,510 3,946,510
29 1,583 82,505 82,505
30 6,062 200,916 200,916
FERC FORM NO.1 (ED.12-90)
Page 310-311

SALES FOR RESALE(Account 447)
REVENUE REVENUE REVENUE
Line Megawatt Hours Sold Demand Charges($) Energy Charges($) Other Charges($) Total($)(h+i+j)
No. (9) (h) (i) U) (k)
31 443 61,849 61,849
32 4,352 264,923 264,923
33 3,662 169,609 169,609
34 375 15,000 15,000
35 29 2,940 2,940
36 150 9,750 9,750
37 8,827 371,326 371,326
38 64 0 0
39 69,719 0 0
40 77,402 0 0
41 400 20,496 20,496
42 135 8,792 8,792
43 461 11,922 11,922
44 36,287 2,011,982 2,011,982
45 1,922 203,261 203,261
46 696 37,370 37,370
47 10 518 518
48 328 10,287 10,287
49 6,980 429,460 429,460
50 2,000 113,400 113,400
-F
51 16,032,993 16,032,993
52 324,325 21,551,369 21,551,369
53 9,187 256,475 256,475
54 381,265 18,895,505 18,895,505
55 0 -276,696 276,696
56 0 -276,696 276,696
57 300 21,000 21,000
58 4 4
59 29,035 1,393,864 1,393,864
60 179 9,397 9,397
FERC FORM NO.1 (ED.12-90)
Page 310-311

SALES FOR RESALE(Account 447)
REVENUE REVENUE REVENUE
Line Megawatt Hours Sold Demand Charges($) Energy Charges(S) Other Charges(S) Total($)(h+i+j)
No. (9) (h) (i) (k) -
61 2 98 98
62 8,301 490,634 490,634
63 111,230 0 0
64 136,170 7,852,246 7,852,246
65 44,793 0 0
66 67 13,800 13,800
67 1,048 24,842 24,842
68 5,536 327,089 327,089
69 0 -495,815 495,815
70 10,127 705,198 705,198
71 673 113,414 113,414
72 24,562 1,909,798 1,909,798
73 30,811 1,029,326 1,029,326
74 22,501 1,085,143 1,085,143
75 201,317 10,144,501 10,144,501
76 28 1,333 1,333
77 396 12,848 12,848
78 11,070 654,178 654,178
79 195,845 6,116,799 6,116,799
80 7,437 266,719 266,719
81 13,837 817,723 817,723
82 14,740 1,298,080 1,298,080
83 14 780 780
84 168 4,761 4,761
85 23,004 878,868 878,868
86 1,350 99,654 99,654
87 40 1,075 1,075
88 4,670 194,800 194,800
89 600 23,662 23,662
90 11 323 323
FERC FORM NO.1 (ED.12-90)
Page 310-311

SALES FOR RESALE(Account 447)
REVENUE- REVENUE REVENUE
Line Megawatt Hours Sold Demand Charges Energy Charges($) Other Charges Total($)(h+i+j)
No. (g) (h) (I) U) (k)
91 13 451 451
92 76,619 4,031,501 4,031,501
93 2,250 48,692 48,692
94 18,826 1,590,289 1,590,289
95 0 °'89,205 89,205
96 10,525 897,845 897,845
97 1,460 48,650 48,650
98 1,551 63,659 63,659
99 8 290 290
100 8,301 490,634 490,634
101 9 0 0
102 40,983 2,741,262 2,741,262
103 290 14,305 14,305
104 135,946 7,945,622 7,945,622
105 134 2,688 2,688
106 61,567 3,620,248 3,620,248
107 0 1,849 1,849
108 0 9,155,647 9,155,647
109 (40,937,991) 40,937,991 0
110 1,162,365 1,162,365
111 5,791,068 5,791,068
112 27,916 27,916
15 0
16 3,788,593 1,138,712 156,942,232 73,080,064 231,161,008
Fl 7 3,788,593 1,138,712 156,942,232 73,080,064 231,161,008
FERC FORM NO.1 (ED.12-90)
Page 310311

This report is:
Name of Respondent: (1)®An Original Date of Report: Year/Period of Report
Avista Corporation 04/18/2025 End of:2024/Q4
(2) ❑ A Resubmission
FOOTNOTE DATA
U Concept:NameOfCompanyOrPublicAuthodtyReceivingElectricityPurchasedForResale
To accrue for missing Powerdex Prices at year end 2024
lbl Concept:StatisticalClassificationCode
Financially Settled Transmission Losses effective 01/01/2016-12/31/2027
Jc)Concept:StatisticalClassificationCode
03/06/2023-12/31/2027 ETSR is an export resource associated with EIM
kW Concept:StatisticalClassificationCode
Financially Settled Transmission Losses effective 03/02/2022-12/31/2027
fe)Concept:StatisticalClassificationCode
03/02/2022-12/31/2027 ETSR is an export resource associated with EIM
kf Concept:StatisticalClassificationCode
Financially Settled Transmission Losses effective 05/01/2022-12/31/2027
&Concept:StatisticalClassificationCode
Financially Settled Transmission Losses
U Concept:StatisticalClassificationCode
Financially Settled Transmission Losses effective 06/01/2021-12/31/2027
U Concept:StatisticalClassificationCode
Financially Settled Transmission Losses effective 02/01/2022-12/31/2027
W Concept:StatisticalClassificationCode
Financially Settled Transmission Losses effective 01/01/2016-12/31/2027
Concept:StatisticalClassificationCode
Financially Settled Transmission Losses effective 05/01/2021-12/31/2027
_II)Concept:StatisticalClassificationCode
Financially Settled Transmission Losses effective 01/01/2016-12/31/2027
U Concept:StatisticalClassificationCode
03/02/2022-12/31/2027 ETSR is an export resource associated with EIM
_(n)Concept:StatisticalClassificationCode
03/02/2022-12/31/2027 ETSR is an export resource associated with EIM
fo)Concept:StatisticalClassificationCode
03/02/2022-12/31/2027 ETSR is an export resource associated with EIM
kpj Concept:StatisticalClassificationCode
Financially Settled Transmission Losses effective 02/01/2022-03/31/2024
kM Concept:StatisticalClassificationCode
Financially Settled Transmission Losses effective 04/01/2024-12/31/2026
®Concept:StatisticalClassificationCode
Financially Settled Transmission Losses effective 07/18/2018-12/31/2024
,(s)Concept:StatisticalClassificationCode
Financially Settled Transmission Losses effective 01/16/2024-12/31/2026
Concept:StatisticalClassificationCode

Financially Settled Transmission Losses effective 06/01/2021-12/31/2027
Lu)Concept:StatisticalClassificationCode
Financial SWAP
Jv)Concept:StatisticalClassificationCode
Financially Settled Transmission Losses effective 01/01/2016-12/31/2027
Lw)Concept:StatisticalClassificationCode
Resource Contingent Bundled REC-Energy and Green Attributes 03/01/2019-12/31/2026
kx1 Concept:StatisticalClassificationCode
Financially Settled Transmission Losses
Wi Concept:StatisticalClassificationCode
Financially Settled Transmission Losses effective 01/01/2016-12/31/2027
Lz)Concept:StatisticalClassificationCode
NorthWestem Energy LLC sale expires December 31,2025
as Concept:StatisticalClassificationCode
01/26/2022-12/31/2027 ETSR is an export resource associated with EIM
ab Concept:StatisticalClassificationCode
01/27/2022-12/31/2027 ETSR is an export resource associated with EIM
ac Concept:StatisticalClassificationCode
Financially Settled Transmission Losses effective 02/01/2022-12/31/2027
ad Concept:StatisticalClassificationCode
PacifiCorp sale expires December 31,2025
ae Concept:StatisticalClassificationCode
Deviation Energy
aft Concept:StatisticalClassificationCode
Contract Expires September 30,2026
Lag)Concept:StatisticalClassificationCode
Financially Settled Transmission Losses effective 08/01/2023-12/31/2027
ah Concept:StatisticalClassificationCode
Financially Settled Transmission Losses effective 02/01/2022-12/31/2027
ai Concept:StatisticalClassificationCode
Portland General Electric sale expires December 31,2025
W Concept:StatisticalClassificationCode
Financially Settled Transmission Losses effective 05/01/2019-12/31/2027
yak)Concept:StatisticalClassificationCode
Puget Sound Energy sale expires December 31,2025
(al)Concept:StatisticalClassificationCode
Financially Settled Transmission Losses effective 02/01/2022-12/31/2027
am Concept:StatisticalClassificationCode
Financially Settled Transmission Losses effective 01/01/2016-12/31/2027
an Concept:StatisticalClassificationCode
Financially Settled Transmission Losses effective 03/1912008-10/31/2026
ao Concept:StatisticalClassificationCode
Financially Settled Transmission Losses effective 02/01/2022-12/31/2027
taps Concept:StatisticalClassificationCode

Financially Settled Transmission Losses effective 02/01/2022-12/31/2027
aW Concept:StatisticalClassificationCode
Deviation Energy
ar Concept:StatisticalClassificationCode
Financially Settled Transmission Losses effective 03/19/2008-10/31/2026
as Concept:StatisticalClassificationCode
Talen Energy Montana,LLC sale expires December 31,2025
at Concept:StatisticalClassificationCode
Financially Settled Transmission Losses effective 01/01/2016-12/31/2027
au Concept:StatisticalClassificationCode
Financially Settled transmission Losses effective 01/01/2016-12/31/2027
av Concept:StatisticalClassificationCode
Financially Settled Transmission Losses effective 01/01/2016-12/31/2027
faw Concept:StatisticalClassificationCode
Financially Settled Transmission Losses effective 06/01/2022-12/31/2027
ax Concept:StatisticalClassificationCode
Financial SWAP
kay)Concept:StatisticalClassificationCode
Intra Company Wheeling
az Concept:StatisticalClassificationCode
Intra Company Generation-Sale of Ancillary Services
ba Concept:StatisticalClassificationCode
Energy Imbalance Market(EIM)Sales
bb Concept:RateScheduleTariffNumber
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement
Concept:RateScheduleTariffNumber
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement
kbd)Concept:RateScheduleTadffN umber
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement
be Concept:RateScheduleTadffNumber
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement
M Concept:RateScheduleTariffNumber
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement
kbM Concept:RateScheduleTariffNumber
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement
Ibh)Concept:RateScheduleTariffNumber
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement
jbi)Concept:RateScheduleTariffNumber
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement
M Concept:RateScheduleTariffNumber
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement
fkkj Concept:RateScheduleTariffNumber
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement
kbl)Concept:RateScheduleTariffNumber
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement

tbm�Concept:RateScheduleTariffNumber
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement
ft)Concept:RateScheduleTariffNumber
Reserve Sharing underthe NorthWest Power Pool Reserve Sharing Agreement
bo Concept:RateScheduleTadffNumber
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement
kW Concept:DemandChargesRevenueSalesForResale
Reserves
fbq)Concept:DemandChargesRevenueSalesForResale
Capacity
M Concept:DemandChargesRevenueSalesForResale
Capacity
jbsj Concept:DemandChargesRevenueSalesForResale
Contract expires September 30,2026
bt Concept:DemandChargesRevenueSalesForResale
Capacity
FERC FORM NO.1 (ED.12-90)
Page 310-311

This report is:
Name of Respondent: (1)0 An Original Date of Report: Year/Period of Report
Avista Corporation 04/18/2025 End of:2024/Q4
(2) ❑ A Resubmission
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
Line No. Account Amount for Current Year Amount for Previous Year(c)
(a) y (b) = 3�C)� -
1 1.POWER PRODUCTION EXPENSES
2 A.Steam Power Generation
3 Operation
4 (500)Operation Supervision and Engineering 211,674 177,149
5 (501)Fuel 41,962,181 46,052,299
6 (502)Steam Expenses 3.939,808 4,221,985
7 (503)Steam from Other Sources 27,702 0
8 (Less)(504)Steam Transferred-Cr. 0 0
9 (505)Electric Expenses 785,795 754,146
10 (506)Miscellaneous Steam Power Expenses 6,252,999 6,447,460
11 (507)Rents 0 0
12 (509)Allowances 2,035,905 662,437
13 TOTAL Operation(Enter Total of Lines 4 thru 12) 55,216,064 58,315,476
14 Maintenance
15 (510)Maintenance Supervision and Engineering 515,870 408,706
16 (511)Maintenance of Structures 1,022,336 869,388
17 (512)Maintenance of Boiler Plant 9,714,776 7,090,052
18 (513)Maintenance of Electric Plant 2,973,167 849,384
19 (514)Maintenance of Miscellaneous Steam Plant 1,959,793 1,345,536
20 TOTAL Maintenance(Enter Total of Lines 15 thru 19) 16,185,942 10,563,066
21 TOTAL Power Production Expenses-Steam Power 71,402,006 68,878,542
(Enter 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
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)
29 (Less)(522)Steam Transferred-Cr. 0 0
30 (523)Electric Expenses 0 0
31 (524)Miscellaneous Nuclear Power Expenses 0
32 (525)Rents 0
33 TOTAL Operation(Enter Total of lines 24 thru 32) 0 0
34 Maintenance
35 (528)Maintenance Supervision and Engineering 0 0
36 (529)Maintenance of Structures 0 0
37 (530)Maintenance of Reactor Plant Equipment 0 0
38 (531)Maintenance of Electric Plant 0 0
39 (532)Maintenance of Miscellaneous Nuclear Plant 0 0
40 TOTAL Maintenance(Enter Total of lines 35 thru 39) 0 0
41 TOTAL Power Production Expenses-Nuclear.Power 0 0
(Enter Total of lines 33&40)
42 C.Hydraulic Power Generation
43 Operation
44 (535)Operation Supervision and Engineering 2,763,467 MPE2,459,290
45 (536)Water for Power 1,174,129 1,184,579
46 (537)Hydraulic Expenses 10,193,403 9,863,917
47 (538)Electric Expenses 6,783,801 6,629,557
48 (539)Miscellaneous Hydraulic Power Generation 1,345,977 2,203,306
Expenses
49 (540)Rents 7,756,327 7,611,335
50 TOTAL Operation(Enter Total of Lines 44 thru 49) 30,017,104 29,951,984
51 C.Hydraulic Power Generation(Continued)
52 Maintenance
53 (541)Mainentance Supervision and Engineering 445,155 714,032
54 (542)Maintenance of Structures 318,781 498,079
55 (543)Maintenance of Reservoirs,Dams,and Waterways 252,728 497,535
56 (544)Maintenance of Electric Plant 2,858,446 3,128,062
57 (545)Maintenance of Miscellaneous Hydraulic Plant 650,044 663,385
58 TOTAL Maintenance(Enter Total of lines 53 thru 57) 4,525,154 5,501,093
FERC FORM NO.1 (ED.12-93)
Page 320-323

ELECTRIC OPERATION AND MAINTENANCE EXPENSES
Line No. Account Ain& tfo-RC rrefi ear Amount for Previous Year(c)
(a)_ (b) (c)
59 TOTAL Power Production Expenses-Hydraulic Power 34,542,258 35,453,077
(Total of Lines 50&58)
60 D.Other Power Generation
61 Operation
62 (546)Operation Supervision and Engineering 529,903 893,882
63 (547)Fuel 111,227,168 116,227,146
64 (548)Generation Expenses 5,165,896 3,899,765
64.1 (548.1)Operation of Energy Storage Equipment 0 0
65 (549)Miscellaneous Other Power Generation Expenses 1,421,816 945,276
66 (550)Rents 76,438 103,105
67 TOTAL Operation(Enter Total of Lines 62 thru 67) 118,421,221 122,069,174
68 Maintenance
69 (551)Maintenance Supervision and Engineering 756,654 768,609
70 (552)Maintenance of Structures 131,043 138,993
71 (553)Maintenance of Generating and Electric Plant 2,807,857 2,012,409
71.1 (553.1)Maintenance of Energy Storage Equipment 0
72 (554)Maintenance of Miscellaneous Other Power 889,234 862,263
Generation Plant
73 TOTAL Maintenance(Enter Total of Lines 69 thru 72) 4,584,788 3,782,274
74 TOTAL Power Production Expenses-Other Power(Enter 123,006,009 125,851,448
Total of Lines 67&73)
75 E.Other Power Supply Expenses
76 (555)Purchased Power 249,851,190 209,295,625
76.1 (555.1)Power Purchased for Storage Operations 7,132,090
77 (556)System Control and Load Dispatching 961,071 764,664
78 (557)Other Expenses 57,758,008 38,247,947
79 TOTAL Other Power Supply Exp(Enter Total of Lines 76 308,570,269 255,440,326
thru 78)
80 TOTAL Power Production Expenses(Total of Lines 21, 537,520,542 485,623,393
41,59,74&79)
81 2.TRANSMISSION EXPENSES
82 Operation
83 (560)Operation Supervision and Engineering 2,363,205 2,084,569
85 (561.1)Load Dispatch-Reliability 32,427 45,236
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 Yew(c)'
(a) (b) (G)
86 (561.2)Load Dispatch-Monitor and Operate 1,377,075 1,503,318
Transmission System
87 (561.3)Load Dispatch-Transmission Service and 971,187 965,836
Scheduling
88 (561.4)Scheduling,System Control and Dispatch 0 0
Services
89 (561.5)Reliability,Planning and Standards 554,980 565,721
Development
90 (561.6)Transmission Service Studies 0 0
91 (561.7)Generation Interconnection Studies 0 0
(561.8)Reliability,Planning and Standards
92 Development Services 0 0
93 (562)Station Expenses 360,820 397,216
93.1 (562.1)Operation of Energy Storage Equipment 0 0
94 (563)Overhead Lines Expenses 550,123 324,854
95 (564)Underground Lines Expenses 0
96 (565)Transmission of Electricity by Others 22,557,221 19,063,436
97 (566)Miscellaneous Transmission Expenses 4,279,905 4,242,693
98 (567)Rents 88,928 97,830
99 TOTAL Operation(Enter Total of Lines 83 thru 98) 33,135,871 29,290,709
100 Maintenance
101 (568)Maintenance Supervision and Engineering 403,566 369,375
102 (569)Maintenance of Structures 455,239 572,864
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 595,153 1,160,838
107.1 (570.1)Maintenance of Energy Storage Equipment 0 0
108 (571)Maintenance of Overhead Lines 1,924,515 2,198,739
109 (572)Maintenance of Underground Lines 7,133 965
110 (573)Maintenance of Miscellaneous Transmission Plant 122,348 72,128
111 TOTAL Maintenance(Total of Lines 101 thru 110) 3,507,954 4,374,909
FERC FORM NO.1 (ED.12-93)
Page 320-323

ELECTRIC OPERATION AND MAINTENANCE EXPENSES
Line No. Ac3&urft Amount'llbrOdfi ntya-r Amount for Previous Year(c)
(a) (b) (o)
112 TOTAL Transmission Expenses(Total of Lines 99 and 36,643,825 33,665,618
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
121 (575.7)Market Facilitation,Monitoring and Compliance 0 0
Services
122 (575.8)Rents 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 3,768,183 4,183,113
135 (581)Load Dispatching 0 0
136 (582)Station Expenses 1,000,594 945,603
137 (583)Overhead Line Expenses 2,779,384 3,151,705
138 (584)Underground Line Expenses 2,583,804 2,546,406
138.1 (584.1)Operation of Energy Storage Equipment 0 0
139 (585)Street Lighting and Signal System Expenses 16,533 6,950
FERC FORM NO.1 (ED.12-93)
Page 320-323

ELECTRIC OPERATION AND MAINTENANCE EXPENSES
Line No. Account- - Arrtounffdr Cuff`fear Amount for Previous Year(t)
(a) (b) (c)
140 (586)Meter Expenses 2,179,506 2,133,258
141 (587)Customer Installations Expenses 816,250 801,450
142 (588)Miscellaneous Expenses 9,328,670 9,401,777
143 (589)Rents 252,435 258,811
144 TOTAL Operation(Enter Total of Lines 134 thru 143) 22,725,359 23,429,073
145 Maintenance
146 (590)Maintenance Supervision and Engineering 1,444,330 1,361,055
147 (591)Maintenance of Structures 331,882 411,657
148 (592)Maintenance of Station Equipment 704,181 779,672
148.1 (592.2)Maintenance of Energy Storage Equipment 0 0
149 (593)Maintenance of Overhead Lines 24,355,102 27,486,692
150 (594)Maintenance of Underground Lines 813,168 861,884
151 (595)Maintenance of Line Transformers 335,588 443,255
152 (596)Maintenance of Street Lighting and Signal 52,732 91,567
Systems
153 (597)Maintenance of Meters 47,211 60,470
154 (598)Maintenance of Miscellaneous Distribution Plant 954,667 1,099,461
155 TOTAL Maintenance(Total of Lines 146 thru 154) 29,038,861 32,595,713
156 TOTAL Distribution Expenses(Total of Lines 144 and 51,764,220 56,024,786
155)
157 5.CUSTOMER ACCOUNTS EXPENSES
158 Operation
159 (901)Supervision 143,348 135,418
160 (902)Meter Reading Expenses 626,676 643,428
161 (903)Customer Records and Collection Expenses 9,048,196 8,464,586
162 (904)Uncollectible Accounts 5,768,159 5,102,188
163 (905)Miscellaneous Customer Accounts Expenses 185,602 277,721
164 TOTAL Customer Accounts Expenses(Enter Total of 15,771,981 14,623,341
Lines 159 thru 163)
165 6.CUSTOMER SERVICE AND INFORMATIONAL
EXPENSES {,4
166 Operation
1,
167 (907)Supervision 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)
168 (908)Customer Assistance Expenses 44,289,899 31,870,071
169 (909)Informational and Instructional Expenses 910,185 866,879
170 (910)Miscellaneous Customer Service and Informational 62,711 229,071
Expenses
171 TOTAL Customer Service and Information Expenses 45,262,795 32,966,021
(Total Lines 167 thru 170)
172 7.SALES EXPENSES
173 Operation
174 (911)Supervision 0 0
175 (912)Demonstrating and Selling Expenses 0 43,646
176 (913)Advertising Expenses 0 0
177 (916)Miscellaneous Sales Expenses 0 0
178 TOTAL Sales Expenses(Enter Total of Lines 174 thru 0 43,646
177)
179 8.ADMINISTRATIVE AND GENERAL EXPENSES
180 Operation
181 (920)Administrative and General Salaries 32,528,109 "32,491,999
182 (921)Office Supplies and Expenses 3,924,506 3,924,958
183 (Less)(922)Administrative Expenses Transferred-Credit 114,045 114,022
184 (923)Outside Services Employed 16,406,375 14,933,869
185 (924)Property Insurance 3,128,985 2,806,701
186 (925)Injuries and Damages 21,673,946 10,784,299
187 (926)Employee Pensions and Benefits 31,491,165 28,096,654
188 (927)Franchise Requirements 1,231 1,200
189 (928)Regulatory Commission Expenses 8,737,417 8,387,545
190 (929)(Less)Duplicate Charges-Cr. 0 0
191 (930.1)General Advertising Expenses 0 0
192 (930.2)Miscellaneous General Expenses 5,706,421 5,644,865
193 (931)Rents 1,021,020 938,930
194 TOTAL Operation(Enter Total of Lines 181 thru 193) 124,505,130 107,896,998
195 Maintenance
196 (935)Maintenance of General Plant 14,048,526 14,630,422
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)
197 TOTAL Administrative&General Expenses(Total of 138,553,656 122,527,420
Lines 194 and 196)
198 TOTAL Electric Operation and Maintenance Expenses 825,517,019 745,474,225
(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)®An Original Date of Report: Year/Period of Report
Avista Corporation 04/18/2025 End of:2024/Q4
(2) El A Resubmission
PURCHASED POWER(Account 555)
Actual Demand Actual Demand
(MW) (MW)
MegaWatt
Hours
Statistical
Name of Company or Public Ferc Rate Average Monthly Average Monthly Average Monthly Purchased
Line Authority(Footnote Schedule or Billing Demand
Classification NCP Demand CP Demand (Excluding
No. Affiliations) (b) Tariff Number (MW) (e) (f) for Energy
(a) (c) (d) Storage)
(g)
1 Adams Nielson Solar,LLC LU PURPA 40,831
2 Altop Energy Trading SF Tariff 10,425
3 Avangrid Renewables,LLC SF Tariff 9 16,423
Lai LF 4 Avangrid Renewables,LLC LF NWPP
5 Avangrid Renewables,LLC IF Tariff 9 56,768
6 BP Energy SF Tariff 900
7 Bonneville Power OS 6PAOATT
Administration
8 Bonneville Power LF Tariff 8 427
Administration
9 Bonneville Power SF Tariff 41,260
Administration
ii
10 Bonneville Power LF NWPP 215
Administration
11 Bonneville Power OS BPA OATT
Administration
iv
12 Bonneville Power IF Tariff 91,474
Administration
Lhj
13 Bonneville Power OS BPA OATT
Administration
N
14 Bonneville Power LF Tariff 9 54,590
Administration
15 Brookfield Energy Marketing SF Tariff 1,400
LP
16 California Independent SF Tariff 9 2,916
System Operator
17 Calpine Energy Services,LP SF Tariff 9 125
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
NCP Demand CP Demand (Excluding
Classification
No. Affiliations) Tariff Number (MW)
(a) (b) (c) (d) (e) (f) for Energy
Storage)
(g)
18 Chelan County PUD IU Rocky Reach 48,270
m
19 Chelan County PUD IU Rocky Reach (40,807)
201 Chelan County PUD SF Tariff 9 16,600
li
21 Chelan County PUD LF NWPP g
22 Chelan County PUD IU Chelan Sys 689,151
23 Chelan County PUD EX Rocky Reach
24 City of Spokane IU PURPA 48,380
25 City of Spokane IU PURPA 132,380
26 Clark Fork Hydro LU PURPA 1,061
27 Clatskanie PUD SF Tariff 3,582
28 Clearwater Paper Company IU PURPA 410,105
29 Clearwater Wind III Project LU PURPA 152,702
30 Community Solar LU PURPA 447
31 ConocoPhillips Company SF Tariff 18,516
32 Constellation Energy SF Tariff 7,889
Generation,LLC
33 Deep Creek Energy,LLC IU PURPA
223
34 Douglas County PUD No.1 LU Wells 39,964
35 Douglas County PUD No.1 LF NWPP 3
L
36 Douglas County PUD No.1 OS Tariff 9
37 Dynasty Power,Inc. SF Tariff 9 60,682
East,South,Quincy
38 Columbia Basin Irrigation LU PURPA 20,286
Districts
39 EDF Trading No America SF Tariff 9 1,249
40 Enel X North America,Inc. LU PURPA 17
41 Energy Keepers,Inc. SF Tariff 9 10,944
FERC FORM NO.1 (ED.12-90)
Page 326-327

PURCHASED POWER(Account 555)
Actual Demand Actual Demand
(MW) (MW)
MegaWatt
Hours
Statistical
Name of Company or Public Ferc Rate Average Monthly
Line Authority(Footnote Schedule or Billing Demand Average Monthly Average Monthly Purchased
n Affiliations) Classification Tariff Number De NCP Demand CP Demand (Excluding
(a) (b) (d) (e) (f) for Energy
Storage)
(g)
42 Eugene Water&Electric SF Tariff 9 1,404
Board
43 Ford Hydro Limited LU PURPA 3,760
Partnership
44 Grant County PUD No.2 LU Priest Rapids 257,791
45 Grant County PUD No.2 LF NWPP 15
46 Grant County PUD No.2 EX FERC#104
47 Grant County PUD No.2 EX Priest Rapids
48 Great Northern Spokane, LU PURPA 55
LLC.
49 Gridforce Energy LF NWPP 20
Management,LLC
50 Guzman Energy,LLC SF Tariff 1,921
51 Heartland Generation Ltd. SF Tariff 1,217
52 Hydro Technology Systems IU PURPA 8,802
53 Idaho County Power&Light LU PURPA 2,336
Idaho Power
54 Idaho Power Company OS Co OATT
55 Idaho Power Company SF Tariff 39,120
u
56 Idaho Power Company LF Tariff 9 342
Balancing
57 Idaho Power Company LF Tariff 9 287,186
Balancing
58 Inland Power&Light RQ 208 192
Company
59 Macquarie Energy,LLC SF Tariff 9 15,177
60 MAG Energy Solutions SF Tariff 9 1,764
61 M r uda Energy America, SF Tariff 1,600
LLC
62 Merrill Lynch Commodities, SF Tariff 1,600
Inc.
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)
63 Mizuho Securities USA,Inc. OS NA
64 Morgan Stanley Capital SF Tariff 9 37,491
Group
65 NorthWestem Energy SF Tariff 21,269
u
66 NorthWestem Energy LF NWPP 30
67 NorthWestem Energy LF Tariff 5,633
68 NorthWestem Energy LF Tariff 193,401
69 NorthWestem Energy OS NorthWestem Energy OATT
70 PacifiCorp SF Tariff 5,425
71 PacifiCorp LF Tariff 9 92,078
(ab)
72 PacifiCorp LF NWPP 55
73 PacifiCorp LF Tariff 2
'aca PacifiCorp
74 PacifiCorp OS OATT
75 Palouse Wind,LLC LU PPA 325,878
76 Pend Oreille County PUD SF Pend O' 48,167
No.1
77 Pend Oreille County PUD LF Pend O' 8,873
No.1
78 Pend Oreille County PUD LF Pend O' 6,438
No.1
79 Phillips 66 Energy Trading, SF Tariff 9
LLC 14,610
80 Portland General Electric SF Tariff9 21,150
Company
81 Portland General Electric LF NWPP 67
Company
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
Line
Affiliations)(Footnote
Classification Tariff Number (MW) NCP Demand CP Demand (Excluding
(a) (b) N (d) (e) (f) for Energy
Storage)
r
(g)
82 Portland General Electric LF Tariff 9 4,833
Company
Portland
83 Portland General Electric OS General
Company OATT
84 Powerex Corp SF Tariff 9 33,075
85 Puget Sound Energy SF Tariff 9 76,515
86 Puget Sound Energy LF NWPP 70
87 Puget Sound Energy LF Tariff 9
88 Rainbow Energy Marketing SF Tariff 9 18,091
Co.
89 Rathdrum Power,LLC LU Lancaster 1,369,222
90 Rattlesnake Flat,LLC LU PPA 415,513
91 Seattle City Light SF Tariff 11,100
92 Liu Seattle City Light LF NWPP 20
93 Sheep Creek Hydro IU PURPA 7,847
94 Shell Energy SF Tariff 9 40,927
95 1 Snohomish County PUD No. SF Tariff 9 7,925
96 Sovereign Power LF Sovereign 3,576
97 Spokane Eco District 1,LLC. LU PURPA 5
98 Stimson Lumber IU PURPA (39)
99 Tacoma Power SF Tariff 11,350
100 Tacoma Power LF NWPP 10
101 The City of Cove LU PURPA 2,901
102 The Energy Authority SF Tariff 9 27,063
103 TransAlta Energy Marketing SF Tariff 9 44,736
104 Turlock Irrigation District SF Tariff 2,102
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) ( ) (c) (d) (e) {f) for Energy
Storage)
_-- (g)
105 Vitol Inc. SF Tariff 9 3,250
li
106 Wells Fargo Securities,LLC OS NA
u
107 IntraCompany Generation OS OATT
Services
108 Other-Inadvertent EX
Interchange
109 California Independent OS Tariff 9
System Operator
110 Powerdex Pricing Accrual SF Tariff 9
15 TOTAL 5,424,379
FERC FORM NO.1 (ED.12-90)
Page 326-327

PURCHASED POWER(Account 555)
POWER POWER COBT)SIITTL�EMENTCOSTI$ffiEgWNTtWf LEgffffeb6TISETTLEMEWT
EXCHANGES EXCHANGE$ OFPOWER OFPOWER OFPOWER OFPOWER
Megawatt
Hours Megawatt Megawatt Total(k+l+m)of
Line Purchased Hours Hours Demand Charges($) Enorgy Charges($) Other Charges($) Settlement($)
No. for Energy Received Deiivercd (k) (1) (m) N
Storage V) U)
�h)
1 1,753,691 1,753,691
2 1,050,289 1,050,289
3 786,921 786,921
4 566 566
5 0
6 90,491 90,491
7 (39,897) (39,897)
8 0
9 5,600,628 5,600,628
10 10,653 10,653
11 64,941 64,941
12 4,888,021 4,888,021
13 1 1
14 0
15 86,800 86,800
16 365,386 365,386
17 24,375 24,375
18 0
19 0
20 691,082 691,082
21 436 436
22 37,154,199 37,154,199
23 219,525 219,525
24 2,477,413 2,477,413
25 6,384,627 6,384,627
26 65,814 65,814
27 206,435 206,435
28 14,833,498 14,833,498
FERC FORM NO.1 (ED.12-90)
Page 326-327

PURCHASED POWER(Account 555)
POWER POWER COST/SETTLEMENTCOSTISETTLEMENTCOSTlSETTLEMENTCOSTISETTLEMENT
EXCHANGES EXCHANGES OF POWER OF POWER OF POWER OF POWER
MegaWatt
Hours MegaWatt MegaWatt Total(k+l+m)of
Line Purchased Hours Hours Demand Charges($) Energy Charges($) Other Charges($)
Settlement($)
No. for Energy Received Delivered (k) (I) (m) (n)
Storage (i) Q)
(h)
29 4,626,157 4,626,157
30 0
31 1,469,021 1,469,021
32 183,081 183,081
33 13,240 13,240
34 1,550,659 1,550,659
35 150 150
36 8,509 8,509
37 7,958,945 7,958,945
38 875,747 875,747
39 44,696 44,696
40 0
41 1,244,629 1,244,629
42 781,940 781,940
43 169,033 169,033
44 34,422,624 34,422,624
45 768 768
46 (24,259) (24,259)
47 51,173 51,173
48 1,943 1,943
49 1,002 1,002
50 107,645 107,645
51 63,258 63,258
52 400,824 400,824
53 119,058 119,058
54 (313) (313)
55 2,397,776 2,397,776
56 0
FERC FORM NO.1 (ED.12-90)
Page 326327

PURCHASED POWER(Account 555)
POWER POWER COSTISETTLEMENTCOST/SETTLEMENT COST/SETTLE MEN TCOST/SETTLEMENT
EXCHANGES EXCHANGES OF POWER OF POWER OF POWER OF POWER
MegaWatt
Hours MegaWatt MegaWatt Total(k+l+m)of
Line Purchased Hours Hours Demand Charges($) Energy Charges($) Other Charges($) Settlement($)
No. for Energy Received Delivered (k) (I) (m) (n)
Storage (i) (j)
(h) _
57
0
58 11,542 11,542
59 2,574,206 2,574,206
60 1,223,517 1,223,517
61 144,400 144,400
62 62,000 62,000
63 1,181,052 1,181,052
64 2,154,950 2,154,950
65 547,135 547,135
66 1,508 1,508
87 230,363 230,363
68 0
69 64,023 64,023
70 134,925 134,925
71 0
72 2,707 2,707
73 51 51
74 1 1
75 22,042,388 22,042,388
76 1,969,307 1,969,307
77 343,610 343,610
78 197,187 197,187
79 869,981 869,981
80 1,412,277 1,412,277
81 3,060 3,060
82 123,546 123,546
83 230,263 230,263
84 12,029,854 12,029,854
FERC FORM NO.1 (ED.12-90)
Page 326-327

PURCHASED POWER(Account 555)
POWER POWER COST/SETTLEMENTCOST/SETTLEMENT COST/SETTLEMENTCOST/SETTLEMENT
EXCHANGES EXCHANGES OF POWER OF POWER OF POWER OF POWER
MegaWatt
Hours MegaWatt MegaWatt Total(k+l+m)of
Line Purchased Hours Hours Demand Charges($) Energy Charges($) Other Charges($) Settlement($)
No. for Energy Received Delivered (k) (1) (m)
Storage (i) Q) (n)
(h)
85 3,791,875 3,791,875
86 3,490 3,490
87 (821) (821)
88 4,292,460 4,292,460
89 28,939,535 28,939,535
90 12,552,814 12,552,814
91 564,030 564,030
92 1,036 1,036
93 326,054 326,054
94 1,454,031 1,454,031
95 270,760 270,760
96 160,726 160,726
97 176 176
98 0
99 994,252 994,252
100 514 514
101 120,062 120,062
102 1,237,481 1,237,481
103 2,049,219 2,049,219
104 45,075 45,075
105 86,188 86,188
106 1,380,793 1,380,793
107 1,162,365 1,162,365
108 935 0
109 9,669,126 9,669,126
110 12,895 12,895
15 0 0 935 73,127,482 162,756,405 13,967,303 249,851,190
FERC FORM NO.1 (ED.12-90)
Page 326-327

This report is:
Date of Report: Year/Period of Report
Name of Respondent: (1) An Original
Avista Corporation 04/18/2025 End of:2024/Q4
(2) A Resubmission
FOOTNOTE DATA
La)Concept:NameOfCompanyOrPublicAuthodtyProvidingPurchasedPower
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement
Concept:NameOfCompanyOrPublicAuthorityProvidingPurchasedPower
06/26/2023-12/31/2027 ETSR is an import resource associated with an EIM intertie with another EIM BAA,or a CISO intertie with the CISO
U Concept:NameOfCompanyOrPublicAuthodtyProvidingPurchasedPower
Energy Imbalance Charges
Concept:NameOfCompanyOrPublicAuthorityProvidingPurchasedPower
BPA Self Supply for N ITSA Customers
Le)Concept:NameOfCompanyOrPublicAuthodtyProvidingPurchasedPower
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement
jt Concept:NameOfCompanyOrPublicAuthorityProvidingPurchasedPower
Ancillary Services-Spinning&Supplemental Reserves
kW Concept:NameOfCompanyOrPublicAuthodtyProvidingPurchasedPower
Financially Settled Transmission Losses
(h)Concept:NameOfCompanyOrPublicAuthodtyProvidingPurchasedPower
Oversupply Charges
0 Concept:NameOfCompanyOrPublicAuthorityProvidingPurchasedPower
03/02/2022-12/31/2027 ETSR is an import resource associated with an EIM intertie with another EIM BAA or a CISO intertie with the CISO
M Concept:NameOfCompanyOrPublicAuthorityProvidingPurchasedPower
Canadian Entitlement
U Concept:NameOfCompanyOrPublicAuthorityProvidingPurchasedPower
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement
ki)Concept:NameOfCompanyOrPublicAuthorityProvidingPurchasedPower
Canadian Entitlement
()Concept:NameOfCompanyOrPublicAuthorityProvidingPurchasedPower
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement
U Concept:NameOfCompanyOrPublicAuthorityProvidingPurchasedPower
Energy Imbalance Market Purchases
fo)Concept:NameOfCompanyOrPublicAuthorityProvidingPurchasedPower
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement
�W Concept:NameOfCompanyOrPublicAuthorityProvidingPurchasedPower
Canadian Entitlement
LW Concept:NameOfCompanyOrPublicAuthorityProvidingPurchasedPower
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement
Lr)Concept:NameOfCompanyOrPublicAuthorityProvid1ng Purchased Power
Energy Imbalance Charges
Ls)Concept:NameOfCompanyOrPublicAuthorityProvidingPurchasedPower
03/02/2022-12/31/2027 ETSR is an import resource associated with an EIM intertie with another EIM BAA,ora CISO intertie with the CISO
Concept:NameOfCompanyOrPublicAuthorityProvidingPurchasedPower

03/02/2022-12/31/2027 ETSR is an import resource associated with an EIM intertie with another EIM BAA,or a CISO intertie with the CISO
Luj Concept:NameOfCompanyOrPublicAuthodtyProvidingPurchasedPower
Service to Deer Lake from Inland Power and Liaht.No demand charges associated with the agreement.
Lv)Concept:NameOfCompanyOrPublicAuthorityProvidingPurchasedPower
Financial SWAP
L)Concept:NameOfCompanyOrPublicAuthorityProvidingPurchasedPower
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement
Lx)Concept:NameOfCompanyOrPublicAuthodtyProvidingPurchasedPower
Financially Settled Transmission Losses
W Concept:NameOfCompanyOrPublicAuthorityProvidingPurchasedPower
01/26/2022-12/31/2027 ETSR is an import resource associated with an EIM intertie with another EIM BAA,or a CISO intertie with the CISO
kz)Concept:NameOfCompanyOrPublicAuthorityProvidingPurchasedPower
Energy Imbalance Charges
as Concept:NameOfCompanyOrPublicAuthodtyProvidingPurchasedPower
01/27/2022-12/31/2027 ETSR is an import resource associated with an EIM intertie with another EIM BAA,or a CISO intertie with the CISO
Lajb Concept:NameOfCompanyOrPublicAuthorityProvidingPurchasedPower
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement
ac Concept:NameOfCompanyOrPublicAuthodtyProvidingPurchasedPower
Financially Settled Transmission Losses
L"Concept:NameOfCompanyOrPublicAuthodtyProvidingPurchasedPower
Energy Imbalance Charges
ae Concept:NameOfCompanyOrPublicAuthorityProvidingPurchasedPower
Pend Oreille County PUD contract expires September 30,2026
W Concept:NameOfCompanyOrPublicAuthodtyProvidingPurchasedPower
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement
aL W Concept:NameOfCompanyOrPublicAuthodtyProvidingPurchasedPower
Financially Settled Transmission Losses
ah Concept:NameOfCompanyOrPublicAuthorityProvidingPurchasedPower
Energy Imbalance Charges
ai Concept:NameOfCompanyOrPublicAuthorityProvidingPurchasedPower
Reserve Sharing under the Northwest Power Pool Reserve Sharing Agreement
tC Concept:NameOfCompanyOrPublicAuthorityProvidingPurchasedPower
Financially Settled Transmission Losses
Jaj Concept:NameOfCompanyOrPublicAuthodtyProvidingPurchasedPower
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement
al Concept:NameOfCompanyOrPublicAuthodtyProvidingPurchasedPower
Deviation Energy
am Concept:NameOfCompanyOrPublicAuthorityProvidingPurchasedPower
Reserve Sharing underthe NorthWest Power Pool Reserve Sharing Agreement
an Concept:NameOfCompanyOrPublicAuthorityProvidingPurchasedPower
Financial SWAP
ao Concept:NameOfCompanyOrPublicAuthorityProvidingPurchasedPower
Ancillary Services
aW Concept:NameOfCompanyOrPublicAuthorityProvidingPurchasedPower

Energy Imbalance Market Purchases
Jag)Concept:NameOfCompanyOrPublicAuthodtyProvidingPurchasedPower
To accrue for missing Powerdex Prices at year end 2024
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 (2) ❑ A Resubmission 04/18/2025 End of:2024/Q4
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)Affiliation) (Substation (Substation
No. Footnote Authority)(Footnote Authority),(Footnote Classification of Tariff
(
Affiliation) Affiliation) (d) Number or Other or Other
(a) (b) (c) (e) Designation)Designation)';
M (g)
1 Bonneville Power Bonneville Power Bonneville Power FNO FERC Trf
Administration Administration Administration No 8 AVA.BPAT AVA.SYS
2 Bonneville Power Bonneville Power Bonneville Power OS RS No.
Administration Administration Administration T1110
3 Bonneville Power Bonneville Power Idaho Power Company NF FERC Trf
Administration Administration No.8
Bonneville Power Bonneville Power NF FERC Trf
4 Administration Avista Corporation Administration 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
Bonneville Power Northwestern Montana NF FERC Trf
7 Shell Energy Administration No.8
8 Shell Energy NorthWestem Montana Bonneville Power NF FERC Trf
Administration No.8
9 Shell Energy Idaho Power Company Chelan County PUD SFP FERC Trf
No.8
10 Shell Energy Idaho Power Company Grant County PUD SFP FERC Trf
No.8
11 Shell Energy Idaho Power Company PacifiCorp SFP FERC Trf
No.8
12 Shell Energy Idaho Power Company Puget Sound Energy SFP FERC Trt
No.8
13 Shell Energy Idaho Power Company Avista Corporation NF FERC Trf
No.8
14 Shell Energy Idaho Power Company Avista Corporation SFP FERC Trf
No.8
15 Deep Creek Hydro Deep Creek Avista Corporation OLF PURPA
16 Douglas County PUD Douglas County PUD Bonneville Power Administration SFP FERC Trf
No.8
17 Dynasty Power Bonneville Power NorthWestern Montana NF FERC Trt
Administration No.8
18 Dynasty Power Bonneville Power PacifiCorp 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 Roce-"d From Energy Delivcieil To Ferc Rafe of-— Pornt'of
Payment By(Company Receipt Delivery
Ling of Public Authority) (Company of Public (Company of Public Statistical Schedule (Substation (Substation
Line
(of Publicotnote Affiliation) Authority)(Footnote Authority)(Footnote Classification of Tariff or Other or Other
a Affiliation) Affiliation) (d) Number Designation)Designation)'.
O (b) (�) le) (f) (g)
19 Dynasty Power NorthWestern Montana Bonneville Power Administration NF FERC Trf
No.8
Bonneville Power FERC Trf
20 Dynasty Power NorthWestern Montana Administration SFP No.8
21 Dynasty Power NorthWestern Montana PacifiCorp NF FERC Trf
No.8
22 Dynasty Power Idaho Power Company Bonneville Power NF FERC Trf
Administration No.8
23 EDR Trading Bonneville Power NorthWestern Montana NF FERC Trf
Administration No.8
24 EDR Trading Bonneville Power NorthWestern Montana SFP FERC Trf
Administration No.8
25 EDR Trading NorthWestem Montana Bonneville Power NF FERC Trf
Administration No.8
26 EDR Trading NorthWestern Montana Bonneville Power SFP FERC Trf
Administration No.8
27 Energy Keepers NorthWestern Montana Bonneville Power Administration NF FERC Trf
No.8
28 Energy Keepers NorthWestem Montana Bonneville Power Administration SFP FERC Trf
No.8
29 Energy Keepers NorthWestern Montana Chelan County PUD NF FERC Trf
No.8
30 Energy Keepers NorthWestern Montana Idaho Power Company NF FERC Trf
No.8
31 Energy Keepers NorthWestern Montana Grant County PUD NF FERC Trf
No.8
32 Energy Keepers NorthWestern Montana Grant County PUD SFP FERC Trf
No.8
33 Energy Keepers NorthWestern Montana PacifiCorp NF FERC Trf
No.8
34 Energy Keepers NorthWestern Montana PacifiCorp SFP FERC Trf
No.8
35 Energy Keepers NorthWestern Montana Portland General SFP FERC Trf
Electric No.8
36 Energy Keepers Idaho Power Company Bonneville Power SFP FERC Trf
Administration No.8
37 Energy Keepers Idaho Power Company NorthWestern Montana NF FERC Trf
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 of Public Receipt Delivery
Line of Public Authority) (Company (Company of Public Statistical Schedule
No. Footnote Affiliation Authority)(Footnote Authority)(Footnote Classification of Tariff (Substation (Substation
( ) Affiliation) Affiliation) (d) Number or Other or Other
(a) (b) (c) (e) Designation)Designation)
(f) (g)
38 Energy Keepers Idaho Power Company NorthWestem Montana SFP FERC Trf
No.8
39 Exelon PacifiCorp Bonneville Power NF FERC Trf
Administration No.8
40 Exelon Idaho Power Company Bonneville Power NF FERC Trf
Administration No.8
RS No. Coulee
41 Grant County PUD Grant County PUD Grant County PUD OLF 104 Stratford City/Wilson
Creek
42 Guzman Energy Bonneville Power Idaho Power Company NF FERC Trf
Administration No.8
43 Guzman EnergyBonneville Power FERC Trf
SFP Administration Idaho Power Company No.8
44 Guzman Energy Bonneville Power NorthWestern Montana NF FERC Trf
Administration No.8
45 Guzman Energy NorthWestem Montana Bonneville Power NF FERC Trf
Administration No.8
46 Guzman Energy NorthWestern Montana Bonneville Power SFP FERC Trf
Administration No.8
47 Guzman Energy NorthWestern Montana Idaho Power Company NF FERC Trf
No.8
48 Guzman Energy NorthWestem Montana Grant County PUD NF FERC Trf
No.8
49 Guzman Energy NorthWestern Montana PacifiCorp NF FERC Trf
No.8
50 Guzman Energy NorthWestern Montana PacifiCorp SFP FERC Trf
No.8
51 Guzman Energy NorthWestern Montana Avista Corporation NF FERC Trf
No.8
52 Guzman Energy PacifiCorp Bonneville Power NF FERC Trf
Administration No.8
53 Guzman Energy PacifiCorp Bonneville Power SFP FERC Trf
Administration No.8
54 Guzman Energy PacifiCorp NorthWestern Montana NF FERC Trf
No.8
55 Guzman Energy PacifiCorp Avista Corporation NF FERC Trf
No.8
56 Guzman Energy Idaho Power Company 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")
Point of Point of
Energy Received From Energy Deflvered To Ferc Rate Payment By(Company Receipt Delivery
(Company of Public (Company of Public Statistical Schedule Substation Substation
Line of Public Authority) Authority)(footnote Authority)(Footnote Classification of Tariff
No. (Footnote Affiliation) Affiliation) Affiliation) (d) Number or Other or Other
(a) (b) (e) Designation)Designation)
(f) (g)
57 Guzman Energy Idaho Power Company Bonneville Power Administration SFP FERC Trf
No.8
58 Guzman Energy Idaho Power Company NorthWestern Montana NF FERC Trf
No.8
59 Guzman Energy Idaho Power Company NorthWestern Montana SFP FERC Trf
No.8
60 Guzman Energy Idaho Power Company Pac Cfi ri op NF FERC Trf
No.8
61 Guzman Energy Idaho Power Company PacifiCorp SFP FERC Trf
No.8
62 Guzman Energy Idaho Power Company Puget Sound Energy NF FERC Trf
No.8
63 Guzman Energy Idaho Power Company Avista Corporation NF FERC Trf
No.8
64 Guzman Energy Idaho Power Company Avista Corporation SFP FERC Trf
No.8
65 Guzman Energy Avista Corporation Idaho Power Company SFP FERC Trf
No.8
66 Hydro Tech Industries Meyers Falls Avista Corporation OLF PURPA
Bonneville Power FERC Trf
67 Idaho Power Company Administration Idaho Power Company LFP No.8 MIDC LOLO
68 Idaho Power Company Bonneville Power Idaho Power Company LFP FERC Trf AVA.BPAT LOLO
Administration No.8
Bonneville Power FERC Trf
69 Idaho Power Company Administration Idaho Power Company NF No.8
Bonneville Power FERC Trf
70 Idaho Power Company Administration Idaho Power Company SFP No.8
71 Idaho Power Company Bonneville Power NorthWestern Montana SFP FERC Trf
Administration No.8
72 Idaho Power Company Puget Sound Energy Idaho Power Company NF FERC Trf
No.8
73 Idaho Power Company Puget Sound Energy NorthWestern Montana SFP FERC Trf
No.8
74 Idaho Power Company Idaho Power Company NorthWestern Montana NF FERC Trf
No.8
75 Idaho Power Company Chelan County PUD Idaho Power Company SFP 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 Fere Rate Point of Point of
Payment By(Company of Public Receipt Delivery
Line of Public Authority) (Company (Company of Public Statistical Schedule
No. (Footnote Affiliation) Authority)(Footnote Authority)(Footnote Classification of Tariff (Substation (Substation
or Other or Other
Affiliation) Affiliation) (d) Number
(a) (b) (c) (a) Designation)Designation)!
M (g)
76 Idaho Power Company Portland General Idaho Power Company SFP FERC Trf
Electric No.8
77 Idaho Power Company Avista Corporation Idaho Power Company SFP FERC Trf
No.8
78 Idaho Power Company Bonneville Power Idaho Power Company LFP FERC Trf
Administration No.8
79 Kootenai Electric Avista Corporation Idaho Power Company LFP FERC Trf AVA.SYS LOLO
No.8
80 Kootenai Renewable Avista Corporation Idaho Power Company LFP FERC Trf AVA.SYS LOW
Energy No.8
81 MAG Energy Solutions NorthWestern Montana Bonneville Power NF FERC Trf
Administration No.8
82 MAG Energy Solutions Idaho Power Company Bonneville Power SFP FERC Trf
Administration No.8
83 MAG Energy Solutions Idaho Power Company PacifiCorp SFP FERC Trf
No.8
84 MAG Energy Solutions Idaho Power Company Avista Corporation SFP FERC Trf
No.8
85 MAG Energy Solutions Avista Corporation PacifiCorp SFP FERC Trf
No.8
Bonneville Power FERC TrF
86 Macquarie Energy Administration NorthWestern Montana NF No.8
87 Macquarie Energy Bonneville Power NorthWestern Montana SFP FERC Trf
Administration No.8
88 Macquarie EnergyBonneville Power FERC Trf
q Administration Avista Corporation NF
No.8
89 Macquarie Energy NorthWestern Montana Bonneville Power NF FERC TrF
Administration No.8
I
90 Macquarie Energy NorthWestern Montana Bonneville Power SFP FERC Trf
Administration No.8
91 Macquarie Energy Idaho Power Company Bonneville Power NF FERC TrF
Administration No.8
92 Macquarie Energy Idaho Power Company Bonneville Power SFP FERC Trf
Administration No.8
93 Macquarie Energy Idaho Power Company NorthWestern Montana NF FERC Trf
No.8
i
94 Macquarie Energy Idaho Power Company NorthWestern Montana SFP 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 Fare Rate Point of Point of
Payment By(Company (Company of Public (Company of Public Statistical Schedule Receipt Delivery
Line of Public Authority) (Substation (Substation
No. (Footnote Affiliation) Affiliation)
(Footnote- Authority)(Footnote Classification of Tariff or Other or Other
(a) Affiliation) Affiliation) (d) Number Designation)Des_ignation)
(b) (c) (e) (� (g)
95 Macquarie Energy Idaho Power Company Avista Corporation SFP FERC Trf
No.8
96 Mercuria Energy Bonneville Power Idaho Power Company NF FERC Trf
America Administration No.8
Mercuria Energy Bonneville Power FERC Trf
97 America Administration Idaho Power Company SFP No.8
98 Mercuria Energy Bonneville Power NorthWestern Montana NF FERC Trf
America Administration No.8
Mercuria Energy Bonneville Power FERC Trf
99 America Administration NorthWestern Montana SFP No.8
100 Mercuria Energy Bonneville Power PacifiCorp NF FERC Trf
America Administration No.8
101 Mercuria Energy Idaho Power Company NorthWestern Montana NF FERC Trf
America No.8
Mercuria Energy Bonneville Power SFP FERC Trf
102 America Avista Corporation Administration No.8
103 Morgan Stanley Capital Bonneville Power Idaho Power Company NF FERC Trf
Group Administration No.8
104 Morgan Stanley Capital Bonneville Power Idaho Power Company SFP FERC Trf
Group Administration No.8
105 Morgan Stanley Capital Bonneville Power NorthWestern Montana NF FERC Trf
Group Administration No.8
Morgan Stanley Capital Bonneville Power FERC Trf
106 Group Administration Northwestern Montana SFP No.8
107 Morgan Stanley Capital Bonneville Power Grant County PUD NF FERC Trf
Group Administration No.8 T
108 Morgan Stanley Capital NorthWestern Montana Bonneville Power NF FERC Trf
Group Administration No.8
109 Morgan Stanley Capital NorthWestern Montana Bonneville Power SFP FERC Trf
Group Administration No.8
110 Morgan Stanley Capital NorthWestern Montana Idaho Power Company NF FERC Trf
Group No.8
111 Morgan Stanley Capital NorthWestern Montana Idaho Power Company SFP FERC Trf
Group No.8
112 Morgan Stanley Capital NorthWestern Montana Grant County PUD NF FERC Trf
Group No.8
113 Morgan Stanley Capital NorthWestern Montana Grant County PUD SFP FERC Tr,
Group 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 of Public Receipt Delivery
Line of Public Author! (Company (Company of Public Statistical Schedule
tY)
No. Footnote Affiliation) Authority)(Footnote Authority)(Footnote Classification of Tariff (Substation (Substation
( Affiliation) Affiliation) (d) Number or Other or Other
(a) (b) (c) (e) Designation)Designation)
lfl (g)
Morgan Stanley Capital Bonneville Power FERC Trf
114 Group PacifiCorp Administration NF No.8
115 Morgan Stanley Capital PacifiCorp Bonneville Power SFP FERC Trf
Group Administration No.8
116 Morgan Stanley Capital Grant County PUD Idaho Power Company NF FERC Trf
Group No.8
117 Morgan Stanley Capital Grant County PUD Idaho Power Company SFP FERC Trf
Group No.8
118 Morgan Stanley Capital Grant County PUD NorthWestem Mont NF FERC Trf
Group Montana No.8
119 I Morgan Stanley Capital Grant County PUD NorthWestem Montana SFP FERC Trf
Group No.8
120 Morgan Stanley Capital Idaho Power Company Bonneville Power NF FERC Trf
Group Administration No.8
121 Morgan Stanley Capital Idaho Power Company Bonneville Power SFP FERC Trf
Group Administration No.8
122 Morgan Stanley Capital Idaho Power Company NorthWestem Montana NF FERC Trf
Group No.8
123 Morgan Stanley Capital Idaho Power Company NorthWestern Montana SFP FERC Trf
Group No.8
124 Morgan Stanley Capital Idaho Power Company Grant County PUD NF FERC Trf
Group No.8
125 Morgan Stanley Capital Idaho Power Company Grant County PUD SFP FERC Trf
Group No.8
126 Nevada Power Puget Sound Energy Idaho Power Company NF FERC Trf
Company No.8
127 NorthWestern Energy Bonneville Power NorthWestern Montana NF FERC Trf
Administration No.8
128 NorthWestem Energy NorthWestern Montana Bonneville Power NF FERC Trf
Administration No.8
129 NorthWestem Energy Idaho Power Company NorthWestern Montana NF FERC Trf
No.8
130 NorthWestern Energy Avista Corporation NorthWestern Montana NF FERC Trf
No.8
Phillips 66 Energy Bonneville Power FERC Trf
131 Trading Administration NorthWestern Montana NF No.8
132 Phillips 66 Energy Bonneville Power NorthWestern Montana SFP FERC Trf
Trading Administration 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) (Substation (Substation
No. (Footnote Affiliation) Authority)(Footnote Authority)(Footnote Classification of Tariff or Other or Other
(a) Affiliation) Affiliation) (d) Number Designation)Designation),
(b) (�1 (e) M (g)
133 Phillips 66 Energy Bonneville Power PacifiCorp NF FERC Trf
Trading Administration No.8
Phillips 66 Energy Bonneville Power FERC Trf
134 Trading Administration PacifiCorp SFP FERC
135 Phillips 66 Energy NorthWestern Montana 1 Bonneville Power SFP FERC Trf
Trading Administration No.8
136 Phillips 66 Energy NorthWestem Montana PacifiCorp NF FERC Trf
Trading No.8
137 Phillips 66 Energy NorthWestern Montana PacifiCorp SFP FERC Trf
Trading No.8
Phillips 66 Energy FERC Trf
138 Trading PacifiCorp Idaho Power Company SFP No.8
139 Phillips 66 Energy PacifiCorp NorthWestern Montana SFP FERC Trf
Trading No.8
140 Phillips 66 Energy PacifiCorp PacifiCorp SFP FERC Trf
No.8
141 Phillips 66 Energy Puget Sound Energy Idaho Power Company SFP FERC Trf
Trading No.8
142 Phillips 66 Energy Puget Sound Energy NorthWestern Montana SFP FERC Trf
Trading No.8
SFP FERC Trf
143 Phillips 66 Energy Puget Sound Energy PacifiCorp
Trading No.8
144 Phillips 66 Energy Grant County PUD NorthWestem Montana SFP FERC Trf
Trading No.8
Phillips 66 Energy FERC Trf
145 Trading Grant County PUD PacifiCorp SFP No 8
Phillips 66 Energy Bonneville Power NF FERC Trf
146 Trading Idaho Power Company Administration No.8
Phillips 66 Energy Bonneville Power SFP FERC Trf
147 Trading Idaho Power Company Administration No.8
i
148 Phillips 66 Energy Idaho Power Company NorthWestern Montana LFP FERC Trf
Trading No.8
149 Phillips 66 Energy Idaho Power Company NorthWestern Montana NF FERC Trf
Trading No.8
150 Phillips 66 Energy Idaho Power Company NorthWestem Montana SFP FERC Trf
Trading No.8
151 Phillips 66 Energy Idaho Power Company PacifiCorp NF FERC Trf
Trading 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 of Public Receipt Delivery
Line of Public Authority) (Company {Company of Public Statistical Schedule
No. Footnote Affiliation) Authority)(Footnote Authority){Footnote Classification of Tariff (Substation (Substation
( Affiliation) Affiliation) (d) or Other or Other
Number
(a) (b) {�) m Designation)Designation)
_ __ lfl (g)
152 Phillips 66 Energy Idaho Power Company PacifiCorp SFP FERC Trf
Trading No.8
153 Phillips 66 Energy Idaho Power Company Portland General SFP FERC Trf
Trading Electric No.8
154 Phillips 66 Energy Chelan County PUD NorthWestern Montana SFP FERC Trf
Trading No.8
i
155 Phillips 66 Energy Chelan County PUD PacifiCorp SFP FERC Trf
Trading No.8
156 Phillips 66 Energy Portland General NorthWestem Montana SFP FERC Trf
Trading Electric No.8
157 Phillips 66 Energy Portland General PacifiCorp SFP FERC Trf
Trading Electric No.8
158 Phillips 66 Energy Avista Corporation NorthWestem Montana SFP FERC Trf
Trading No.8
159 Phillips 66 Energy Avista Corporation PacifiCorp SFP FERC Trf
Trading No.8
160 PacifiCorp Bonneville Power Idaho Power Company NF FERC Trf
Administration No.8
Bonneville Power FERC Trf
161 PacifiCorp Administration PacifiCorp NF No.8
162 PacifiCorp PacifiCorp Bonneville Power NF FERC Trf
Administration No.8
163 PacifiCorp PacifiCorp Bonneville Power SFP FERC Trf
Administration No.8
164 PacifiCorp PacifiCorp PacifiCorp OLF RS o' Dry Gulch Dry Gulch
182
165 PacifiCorp Idaho Power Company PacifiCorp NF FERC Trf
No.8
Portland General Bonneville Power FERC Trf
166 Electric Administration NorthWestem Montana NF No.8
Portland General Bonneville Power NF FERC Trf
167 Electric Northwestern Montana Administration No.8
Portland General Portland General NF FERC Trf
168 Electric Northwestern Montana Electric No.8
Portland General Bonneville Power NF FERC Trf
169 Electric Idaho Power Company Administration No.8
170 Avangrid Renewables 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(Account 456.1)(Including transactions referred to as"wheeling")
- - - . _
Energy Received From EnargyDeliveredTo Ferc Rate Point of Point of
Payment By(Company Receipt Delivery
(Company of Public (Company of Public Statistical Schedule Substation Substation
Line of Public Authority) ( (
No. (Footnote Affiliation) Authority)(Footnote Authority)(Footnote Classification of Tariff or Other or Other
(a) Affiliation) Affiliation) (d) Number Dosignafen)Designation)
(b) (c) (e) ( (g)
171 Avangrid Renewables Bonneville Power NorthWestern Montana NF FERC Trf
Administration No.8
172 Avangrid Renewables NorthWestern Montana Bonneville Power NF FERC Trf
Administration No.8
[173 Puget Sound Energy Bonneville Power Idaho Power Company NF FERC Trf
Administration No.8
Bonneville Power FERC Trf
Puget Sound Energy Administration NorthWestern Montana NF No.8
175 Puget Sound Energy NorthWestern Montana Bonneville Power NF FERC Trf
Administration No.8
i
176 Puget Sound Energy NorthWestern Montana Power FERC Trf
SFP Montana Administration No.8
177 Puget Sound Energy NorthWestern Montana Puget Sound Energy NF FERC Trf
No.8
178 Puget Sound Energy Idaho Power Company Bonneville Power NF FERC Trf
Administration No.8
179 Puget Sound Energy Idaho Power Company Puget Sound Energy NF FERC Trf
No.8
180 Powerex Bonneville Power Chelan County PUD LFP FERC Trf
Administration No.8
181 Powerex Bonneville Power Chelan County PUD NF FERC Trf
Administration No.8
182 Powerex Bonneville Power Idaho Power Company LFP FERC Trf AVA.BPAT LOLO
Administration No.8
Bonneville Power FERC Trf
183 Powerex Administration Idaho Power Company NF No.8
184 Powerex Bonneville Power Idaho Power Company SFP FERC Trf
Administration No.8
Bonneville Power FERC Trf
185 Powerex Administration NorthWestern Montana LFP No.8
186 Powerex Bonneville Power NorthWestern Montana NF FERC Trf
Administration No.8
187 Powerex Bonneville Power NorthWestern Montana SFP FERC Trf
Administration No.8
Bonneville Power FERC Trf
188 Powerex Administration PacifiCorp LFP No.8
I
r18 Powerex Bonneville Power PacifiCorp 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 of Public Receipt Delivery
Line of Public Author' (Company (Company of Public Statistical Schedule
Authority)
No. Footnote Affiliation Authority)(Footnote Authority)(Footnote Classification of Tariff (Substation (Substation
( ) Affiliation) Affiliation) (d) Number or Other or Other
(a) (b) (c) (e) Designation)Designation)
(f) (g)
190 FPO
werex Bonneville Power PacifiCorp SFP FERC Trf
Administration No.8
191 Powerex Bonneville Power Puget Sound Energy LFP FERC Trf
Administration No.8
192 Powerex Bonneville Power Puget Sound Energy NF FERC Trf
Administration No.8
193 Powerex NorthWestem Montana Bonneville Power LFP FERC Trf
Administration No.8
194 Powerex NorthWestem Montana Bonneville Power NF FERC Trf
Administration No.8
195 Powerex NorthWestern Montana Bonneville Power SFP FERC Tif
Administration No.8
196 Powerex NorthWestern Montana Chelan County PUD LFP FERC Trf
No.8
197 Powerex NorthWestern Montana Chelan County PUD NF FERC Trf
No.8
198 Powerex NorthWestem Montana Chelan County PUD SFP FERC Trf
No.8
199 Powerex NorthWestem Montana Puget Sound Energy LFP FERC Trf
No.8
200 Powerex PacifiCorp Bonneville Power LFP FERC Trf
Administration No.8
201 Powerex PacifiCorp Bonneville Power SFP FERC Trf
Administration No.8
202 Powerex Idaho Power Company Bonneville Power Administration LFP FERC Trf
No.8
203 Powerex Idaho Power Company Bonneville Power NF FERC Trf
Administration No.8
204 Powerex Idaho Power Company Bonneville Power SFP FERC Trf
Administration No.8
205 Powerex Idaho Power Company Chelan County PUD LFP FERC Trf
No.8
206 Powerex Idaho Power Company Chelan County PUD SFP FERC Trf
N o.8
207 Powerex Idaho Power Company NorthWestern Montana LFP FERC Trf
No.8
FERC Trf
208 Powerex Chelan County PUD Idaho Power Company NF 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 ReeraVed Fronv o Ferc Rate Point of Point of
Payment By(ContPaby (Company of Public y of 6tic Statistical Schedule Receipt Delivery
Line of Public Authority) (Substation (Substation
No. (Footnote Affiliation) Authority)(Footnote Authority)(Footnote Classfication of Tariff or Other or Other
(a) Affiliation) Affiliation) (d) Number Designation)Designation)
(b) (c) (e) (fl (9)
209 Powerex Chelan County PUD Idaho Power Company SFP FERC Trf
No.8
210 Rainbow Energy Bonneville Power Idaho Power Company NF FERC Trf
Marketing Administration No.8
211 Rainbow Energy Bonneville Power NorthWestern Montana NF FERC Trf
Marketing Administration No.8
Rainbow Energy Bonneville Power NF FERC Trf
212 Marketing NorthWestern Montana Administration No.8
213 Rainbow Energy PacifiCorp NorthWestern Montana NF FERC Trf
Marketing No.8
Rainbow Energy Bonneville Power NF FERC Trf
214 Marketing Idaho Power Company Administration No.8
Rainbow Energy Bonneville Power SFP FERC Trf
215 Marketing Idaho Power Company Administration No 8
Rainbow Energy FERC Trf
216 Marketing Idaho Power Company NorthWestem Montana NF No.8
Rainbow Energy FERC Trf
217 Marketing Idaho Power Company NorthWestern Montana SFP No.8
Rainbow Energy FERC Trf
218 Marketing Idaho Power Company PacifiCorp NF No.8
Rainbow Energy FERC Trf
219 Marketing Idaho Power Company PacifiCorp SFP No.8
Rainbow Energy FERC Trf
220 Marketing Idaho Power Company Avista Corporation NF No.8
I_
Rainbow Energy FERC Trf
221 Marketing Idaho Power Company Avista Corporation SFP No.8
222 Seattle City Light Seattle City Light Grant County PUD OLF FERC Trf Chelan- Stratford
No.8 Stratford
i
223 Seattle City Light NorthWestern Montana Bonneville Power Administration NF FERC Trf
No.8
224 Spokane Tribe Bonneville Power Spokane Tribe LFP FERC Trf AVA.BPAT AVA.SYS
Administration No.8
225 Stimson Plummer Avista Corporation OLF PURPA
226 The Energy Authority Administration Bonneville Power Idaho Power Company NF FERC Trf
No 8
Bonneville Power FERC Trf
227 The Energy Authority Administration Idaho Power Company SFP No.8
228 The Energy Authority Bonneville Power NorthWestern Montana 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 RoEnfof' Point of
Payment By(Company Receipt Delivery
Line of Public Author (Company of Public (Company
Authority) of Public StaUsticaT Schedule
(Substation (Substation
No. (Footnote Affiliation) Authority)(Footnote Authority)(Footnote Classification of Tariff or Other or Other
Affiliation) Affiliation) (d Number
(a) (b) (c) ) (e) Designation)Designation).
M (g)
229 The Energy Authority Bonneville Power NorthWestem Montana SFP FERC Trf
Administration No.8
230 The EnergyAuthority Bonneville Power FERC Trf
Administration Avista Corporation NF
No.8
i
231 The Energy Authority NorthWestem Montana Bonneville Power NF FERC Trf
Administration No.8
Bonneville Power FERC Trf
232 The Energy Authority NorthWestern Montana Administration SFP No.8
233 The Energy Authority PacifiCorp Avista Corporation NF FERC Trf
No.8
234 The Energy Authority Idaho Power Company Bonneville Power NF FERC Trf
Administration No.8
235 The Energy Authority Idaho Power Company Bonneville Power SFP FERC Trf
Administration No.8
236 The Energy Authority Idaho Power Company NorthWestern Montana SFP FERC Trf
No.8
237 The Energy Authority Idaho Power Company Avista Corporation NF FERC Trf
No.8
238 The Energy Authority Avista Corporation Bonneville Power NF FERC Trf
Administration No.8
239 The Energy Authority Avista Corporation 1 Avista Corporation NF FERC Trf
No.8
240 TransAlta Energy Bonneville Power Idaho Power Company NF FERC Trf
Marketing Administration No.8
241 TransAlta Energy Bonneville Power Idaho Power Company SFP FERC Trt
Marketing Administration No.8
242 TransAlta Energy Bonneville Power NorthWestern Montana NF FERC Trf
Marketing Administration No.8
243 TransAlta Energy Bonneville Power NorthWestern Montana SFP FERC Trf
Marketing Administration No.8
TransAlta Energy Bonneville Power FERC Trf
244 MarketingNorthWestern Montana NF
Administration No.8
245 TransAlta Energy NorthWestern Montana Bonneville Power SFP FERC Trf
Marketing Administration No.8
246 TransAlta Energy NorthWestem Montana PacifiCorp SFP FERC Trf
Marketing No.8
TransAlta Energy Bonneville Power FERC Trf
247 MarketingIdaho Power Company NF
Administration 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")
Point of Point of
Energy Received From Energy Delivered To Ferc Rate
Payment By(Company (Company of Public (Company of Public Statistical Schedule Receipt Delivery
Line of Public Authority) (Substation (Substation
No. (Footnote Affiliation)
Authority)(Footnote Authority)(Footnote Classification of Tariff or Other or Other
Affiliation) Affiliation) (d) Number
(a) (b) (c) (e) Designation)Designation)1
(f) (g)
TransAlta Energy Bonneville Power FERC Trf
248 SFP Marketing Idaho Power Company Administration No.8
249 TransAlta Energy Avista Corporation Idaho Power Company NF FERC Trf
Marketing No.8
250 Tenaska Power Bonneville Power Bonneville Power SFP FERC Trf
Services Administration Administration No.8
251 Tacoma Power Tacoma Power Grant County PUD OLF FERC Trf Chelan- Stratford
No.8 Stratford
252 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 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 Demand Charges Energy Charges r Total Revenues
(MW) Received Delivered $ Other Charges($) +l+m
No. ( ) (5) (�)(k )
(h) (1) Q) (k) (l) (m) (n)
1 2,227,259 2,227,259 8,690,498 -1,113,135 9,803,633
2 0 0 0 -924,000 924,000
3 8,703 8,703 74,098 0 74,098
4 0 0 793 0 793
5 0 0 0 27,973 27,973
6 4 6,982 6,982 32,980 9,881 42,861
7 118 118 2,716 0 2,716
8 1,299 1,299 11,146 0 11,146
9 2,955 2,955 11,159 0 11,159
10 2,465 2,465 9,200 0 9,200
11 59,617 59,617 224,142 0 224,142
12 6,049 6,049 22,670 0 22,670
13 0 0 198 0 198
14 2,068 2,068 7,829 0 7,829
15 0 0 0 LJ603 603
16 1,288 1,288 11,222 0676 11,898
17 505 505 4,837 0 4,837
18 1,020 1,020 19,349 0 19,349
19 45 45 357 0 357
20 0 0 12,807 0 12,807
21 40 40 317 0 317
22 50 50 397 0 397
23 3,631 3,631 38,524 0 38,524
24 3,040 3,040 20,288 0 20,288
25 400 400 3,394 0 3,394
26 1,200 1,200 6,340 0 6,340
27 5,808 5,808 49,172 0 49,172
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($) Total Revenues
(MW) Received Delivered ($) W ($)(k+l+m)
No. (h) (i) G) (k) p) Im) (n) - I
28 25,597 25,597 173,307 0 173,307
29 1,520 1,520 12,631 0 12,631
30 551 551 4,903 0 4,903
31 4,928 4,928 46,195 0 46,195
32 4,632 4,632 35,486 0 35,486
33 800 800 7,499 0 7,499
34 400 400 3,064 0 3,064
35 2,800 2,800 21,451 0 21,451
36 2,315 2,315 12,669 0 12,669
37 1,617 1,617 14,778 0 14,778
38 2,204 2,204 12,062 0 12,062
39 1 1 8 0 8
40 1,081 1,081 11,038 0 11,038
41 93,308 93,308 27,776 0 27,776
42 9 9 71 0 71
43 431 431 32,202 0 32,202
44 800 800 8,064 0 8,064
45 1,247 1,247 13,828 0 13,828
46 4,443 4,443 35,162 0 35,162
47 583 583 6,747 0 6,747
48 75 75 696 0 696
49 415 415 3,776 0 3,776
50 405 405 5,480 0 5,480
51 60 60 958 0 958
52 11,108 11,108 110,203 0 110,203
53 4,665 4,665 29,518 0 29,518
54 61 61 575 0 575
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 Demand Charges Energy Charges Other Charges($) Total Revenues
No. (MW) Received Delivered ($) ($) ($)(k+l+m)
(h) l!) G) (k) P) (m) (n)
55 130 130 1,504 0 1,504
56 3,512 3,512 39,391 0 39,391
57 91,744 91,744 723,043 0 723,043
58 90 90 1,042 0 1,042
59 563 563 28,118 0 28,118
60 275 275 3,228 0 3,228
61 555 555 5,240 0 5,240
62 50 50 434 0 434
63 61 61 722 0 722
64 515 515 3,069 0 3,069
65 125 125 15,189 0 15,189
66 0 0 0 5,772 5,772
67 100 207,295 207,295 3,298,000 0 3,298,000
68 100 64,287 64,287 3,298,000 0 3,298,000
69 400 400 6,146 0 6,146
70 650 650 3,434 0 3,434
71 900 900 3,356 0 3,356
72 350 350 12,926 0 12,926
73 50 50 186 0 186
74 27 27 214 0 214
75 400 400 2,113 0 2,113
76 1,600 1,600 5,967 0 5,967
77 150 150 793 0 793
78 0 0 (1,800) 0 (1,800)
79 4,840 4,840 24,735 L5,637 30,372
80 3 15,385 15,385 74,205 016,911 91,116
81 25 25 7,240 0 7,240
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 0 NSFER OF TRANSMISSION TRANSMISSION TRANSMISSION TRANSMISSIOI
ENERGY IENERGY, OF ELECTRICITY OF ELECTRICITY OF ELECTRICITY OF
FOR OTHERS FOR OTHERS FOR OTHERS ELECTRICITY
FOR OTHERS
Line Billing Demand Megawatt Hours Megawattkours Demand Charges Energy Charges Other Charges($) Total Revenue
No. (MW) Received Delivered M ($) (m) (§)((n)
(h) (i) (i) (k) (I) (
82 0 0 27,500 0 27,500
83 80 80 6,875 0 6,875
84 80 80 6,875 0 6,875
85 160 160 27,500 0 27,500
86 2,128 2,128 20,560 0 20,560
87 1,712 1,712 13,778 0 13,778
88 4 4 35 0 35
89 11,183 11,183 95,519 0 95,519
90 22,423 22,423 189,979 0 189,979
91 2,670 2,670 23,927 0 23,927
92 21,250 21,250 203,078 0 203,078
93 405 405 4,677 0 4,677
94 1,677 1,677 18,778 0 18,778
95 610 610 4,995 0 4,995
96 39 39 233 0 233
97 8 8 43 0 43
98 6,454 6,454 38,832 0 38,832
99 3,732 3,732 20,199 0 20,199
100 80 80 478 0 478
101 575 575 3,438 0 3,438
102 56 56 299 0 299
103 881 881 8,790 0 8,790
104 2,829 2,829 35,709 0 35,709
105 2,619 2,619 25,527 0 25,527
106 1,597 1,597 17,060 0 17,060
107 100 100 820 0 820
108 88,503 88,503 831,883 0 831,883
FERC FORM NO.1 (ED.12-90)
Page 328-330

TRANSMISSION OF ELECTRICITY FOR OTHERS(Account456.1)(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($j Total Revenues
No. (MW) Received Delivered ($) ($) (�)(k+I+m)
(h) (i) l)) (k) (l) (mj (n)
109 93,713 93,713 875,863 0 875,863
110 3,393 3,393 33,056 0 33,056
111 15,715 15,715 166,935 0 166,935
112 27,419 27,419 270,446 0 270,446
113 12,018 12,018 155,250 0 155,250
114 497 497 4,375 0 4,375
115 106 106 651 0 651
116 3,828 3,828 37,720 0 37,720
117 25,926 25,926 294,992 0 294,992
118 2,913 2,913 28,414 0 28,414
119 531 531 8,360 0 8,360
120 2,226 2,226 22,588 0 22,588
121 8,544 8,544 85,443 0 85,443
122 917 917 9,028 0 9,028
123 1,584 1,584 21,678 0 21,678
124 1,231 1,231 12,225 0 12,225
125 9,169 9,169 113,815 0 113,815
126 5 5 40 0 40
127 5,637 5,637 58,442 0 58,442
128 60 60 494 0 494
129 250 250 1,983 0 1,983
130 1 0 0 595 0 595
131 263 263 3,806 0 3,806
132 5,331 5,331 31,699 0 31,699
133 5 5 1,308 0 1,308
134 3,661 3,661 21,358 0 21,358
135 1,678 1,678 7,252 0 7,252
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($) Total Revenues
(MW) Received Delivered M ($) ($)(k+l+m)
No. (h) (i) l)) (k) (I) (m) (n)
136 38 38 301 0 301
137 11,134 11,134 51,617 0 51,617
138 200 200 929 0 929
139 51,557 51,557 388,495 0 388,495
140 34,027 34,027 259,535 0 259,535
141 825 825 3,921 0 3,921
142 17,587 17,587 115,621 0 115,621
143 14,273 14,273 88,598 0 88,598
144 695 695 4,897 0 4,897
145 440 440 2,271 0 2,271
146 101 101 806 0 806
147 14,884 14,884 124,509 0 124,509
148 0 0 1,800 0 1,800
149 1,149 1,149 31,011 0 31,011
150 40,423 40,423 306,950 0 306,950
151 48 48 2,036 0 2,036
152 537,230 537,230 3,837,805 0 3,837,805
153 200 200 1,608 0 1,608
154 3,200 3,200 18,862 0 18,862
155 995 995 7,189 0 7,189
156 1,080 1,080 5,199 0 5,199
157 960 960 4,956 0 4,956
158 720 720 5,202 0 5,202
159 1,200 1,200 8,670 0 8,670
160 0 0 11,895 0 11,895
161 571 571 6,449 0 6,449
162 15,904 15,904 171,592 0 171,592
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-
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
(MVO Received Delivered +I+m
(h) (i) G) (k) (I) (m) (n)
163 4,116 4,116 60,864 0 60,864
164 25,660 25,660 244,311 0 244,311
165 1,040 1,040 13,650 0 13,650
166 2,307 2,307 23,665 0 23,665
167 10,809 10,809 107,738 0 107,738
168 60 60 481 0 481
169 1 1 8 0 8
170 90 90 838 0 838
171 26 26 226 0 226
172 6,808 6,808 56,326 0 56,326
173 0 0 24 0 24
174 757 757 6,502 0 6,502
175 1,822 1,822 15,110 0 15,110
176 1,800 1,800 12,680 0 12,680
177 525 525 4,214 0 4,214
178 235 235 3,076 0 3,076
179 43 43 391 0 391
180 2,517 2,517 36,093 0 36,093
181 206 206 1,902 0 1,902
182 137 64,022 64,022 1,519,632 0 1,519,632
183 249 249 2,591 0 2,591
184 18,518 18,518 94,559 0 94,559
185 1,241 1,241 20,321 0 20,321
186 150 150 1,335 0 1,335
187 785 785 612 0 612
188 1 1 24 0 24
189 48 48 381 0 381
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
Billing Demand Megawatt Hours Megawatt Hours Demand Charges Energy Charges Other Charges(5) Total Revenues
Line MW) Received Delivered ($) ($) (5)(k+l+m)
No. ((h) (i) _ (i) (k) (I) (m) (n)
190 4,633 4,633 104,234 0 104,234
191 151 151 2,462 0 2,462
192 45 45 423 0 423
193 84,885 84,885 1,451,091 0 1,451,091
194 4,508 4,508 37,421 0 37,421
195 27,382 27,382 60,283 0 60,283
196 695 695 16,013 0 16,013
197 5 5 40 0 40
198 178 178 2,097 0 2,097
199 386 386 9,195 0 9,195
200 368 368 5,779 0 5,779
201 13 13 101 0 101
202 80,916 80,916 1,451,474 0 1,451,474
203 1,694 1,694 14,018 0 14,018
204 13,138 13,138 45,007 0 45,007
205 134 134 1,731 0 1,731
206 34 34 0 0 0
207 344 344 4,444 0 4,444
208 432 432 3,426 0 3,426
209 18 18 1,108 0 1,108
210 369 369 4,988 0 4,988
211 1,756 1,756 47,407 0 47,407
212 1,233 1,233 11,175 0 11,175
213 418 418 3,569 0 3,569
214 243 243 2,246 0 2,246
215 30,935 30,935 223,304 0 223,304
216 390 390 4,151 0 l 4,151
FERC FORM NO.1 (ED.12-90) 111
Page 328-330

TRANSMISSION OF ELECTRICITY FOR OTHERS(Account 456.1)(Including transactions referred to as"wheeling")
REVENUE
REVENUEFROM REVENUEFROM 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
No. ($) ($) Other Charges(5) (5)(k+l+m)
(MY1� Received Delivered
(h) (i) G) (k) O) (m) (n)
217 2,321 2,321 15,683 0 15,683
218 234 234 2,345 0 2,345
219 182 182 2,071 0 2,071
220 285 285 2,856 0 2,856
221 6,641 6,641 69,358 0 69,358
222 117,355 117,355 203,943 w75,191 279,134
223 375 375 2,974 0 2,974
224 3 3,723 3,723 24,735 -7,941 32,676
225 0 0 0 -(2,112 (2,112)
226 95 95 933 0 933
227 675 675 13,463 0 13,463
228 1,611 1,611 16,620 0 16,620
229 295 295 5,884 0 5,884
230 130 130 1,056 0 1,056
231 3,381 3,381 35,124 0 35,124
232 777 777 20,569 0 20,569
233 0 0 8 p g
234 1,013 1,013 8,637 0 8,637
235 1,025 1,025 20,444 0 20,444
236 675 675 13,463 0 13,463
237 0 0 16 0 16
238 0 0 8 p 8
239 0 0 8 0 8
240 150 150 1,586 0 1,586
241 84 84 12.006 0 12,006
242 498 498 3,941 0 3,941
243 75 75 6,875 0 6,875
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($) Total Revenues
(MW) Received Delivered (5) ($) (m) ($)(k+l+m)
No. (h) (i) 0) (k) (I) (n)
244 2,080 2,080 21,522 0 21,522
245 225 225 78,831 0 78,831
246 25 25 7,957 0 7,957
247 696 696 9,770 0 9,770
248 605 605 102,609 0 102,609
249 1 1 2,300 0 2,300
250 320 320 2,536 0 2,536
251 117,333 117,333 296,820 -75,190 372,010
252 3 3,862 3,862 15,459 -8,184 23,643
35 350 4,708,379 4,708,379 33,556,153 0 2,268,982 35,825,135
FERC FORM NO.1 (ED.12-90) 111
Page 328330

This report is:
Name of Respondent: (1)0 An Original Date of Report: Year/Period of Report
Avista Corporation (2) 0 A Resubmission 04/18/2025 End of.2024/Q4
FOOTNOTE DATA
fa)Concept:OtherChargesRevenueTransmissionOfElectricityForOthers
Ancillary services
Concept:OtherChargesRevenueTransmissionOfElectricityForOthers
Parallel Capacity Support Agreement
Lc)Concept:OtherChargesRevenueTransmissionOfElectricityForOthers
Use of facilities
(d)Concept:Oth erC ha rg esReven u eTra nsm iss ion OfE I ectri cityForOthe rs
Ancillary services
Le)Concept:OtherChargesRevenueTransmissionOfElectricityForOthers
Use of facilities
(fD Concept:OtherChargesRevenueTransmissionOfElectricityForOthers
Ancillary services
&Concept:OtherChargesRevenueTransmissionOfElectricityForOthers
Use of facilities
Lhj Concept:OtherC ha rg esReven u eTra nsmiss ion OfE I ectri cityForOthe rs
Ancillary services
ai Concept:OtherChargesRevenueTransmissionOfElectricityForOthers
Ancillary services
W Concept:Othe rC h arges Reven ueTran s miss io nOfE I ectri cityForOth ers
Use offacilties
Ikl Concept:OtherChargesRevenueTransmissionOfElectricityForflthers
Ancillary services
Jl)Concept:OtherChargesRevenueTransmissionOfElectricityForOthers
Use of facilities(contract terminated 9/11/24.Wrote off202310-202409 charges due to company closure)
Lm)Concept:OtherChargesRevenueTransmissionOfElectricityForOthers
Use of facilities
_(n2 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 04/18/2025 End of:2024/Q4
(2) ❑ A Resubmission
TRANSMISSION OF ELECTRICITY BY OTHERS(Account 565)
TRANSFER OF ENERGY TRANSFER OF ENERGY
Line Name of Company or Pubfic Authority Statistical MegaWatt Hours Rocelved MegaWatt Hours Delivered
No (Footnote Affl!€afigns) Classification (c) (d)
(a) (b)
1 Bonneville Power Admin LFP
2 Bonneville Power Admin LFP
3 Bonneville Power Admin OS
4 Bonneville PowerAdmin FNS
5 Bonneville Power Admin NF 32,598 32,598
6 Energy Keepers,Inc. NF 24,622 24,622
7 Kaiser Aluminum NF 1,320 1,320
8 Kootenai Electric Coop LFP
9 Northern Lights,Inc LFP
10 NorthWestem Energy NF 29,794 29,794
11 NorthWestem Energy SFP
12 NorthWestem Energy LFP
13 Portland General Elect NF 2,312 2,312
14 Portland General Elect LFP
15 Puget Sound Energy NF 138 138
16 Seattle City Light NF 18,673 18,673
17 Snohomish County PUD NF 36,951 36,951
TOTAL 146,408 146,408
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(5) Other Charges($) Total Cost of Transmission(S)
No. (e) (f) (g) (h)
1 1,426,518 I 1,426,518
2 12,221,568 -2,343,456 14,565,024
3 -58,755 58,755
4 1,863,995 -381,782 2,245,777
5 184,181 184,181
6 112,268 112,268
7 59,400 59,400
8 57,107 57,107
9 145,355 145,355
10 178,202 178,202
11 130,012 -15,014 145,026
12 1,811,500 33,900 1,845,400
13 4,046 4,046
14 1,359,114 -86,185 1,445,299
15 310 -(33) 277
16 31,857 31,857
17 52,729 52,729
19,015,169 622,993 2,919,059 22,557,221
FERC FORM NO.1 (REV.02-04)
Page 332

FOOTNOTE DATA
U Concept:OtherChargesTransmissionOfElectricityByOthers
Ancillary Services
U Concept:OtherChargesTransmissionOfElectricityByOthers
Use of Facilities
Jc)Concept:OtherChargesTransmissionOfElectdcityByOthers
Ancillary Services
Concept:OtherChargesTransmissionOfElectdcityByOthers
Ancillary Services and Regulation&Frequency Response
Le)Concept:OtherChargesTransmissionOfElectricityByOthers
Ancillary Services
Mf Concept:OtherChargesTransmissionOfElectricityByOthers
Ancillary Services
LW Concept:OtherChargesTransmissionOfElectricityByOthers
Schedule 11 WA Tax 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 (2) ❑A Resubmission 04/18/2025 End of:2024/Q4
MISCELLANEOUS GENERAL EXPENSES(Account 930.2)(ELECTRIC)
Line Description Amount
No. (a) (b)
1 Industry Association Dues 674,728
2 Nuclear Power Research Expenses
3 Other Experimental and General Research Expenses
4 Pub and Dist Info to Stkhldrs...expn servicing outstanding Securities 794,859
5 Oth Expn greater than or equal to 5,000 show purpose,recipient,amount.Group
if less than$5,000
6 Board of Director Activities 1,533,300
7 Community Relations 591,407
8 Compliance 56,333
9 Education,Information&Training 656,728
10 Emergency Operating Procedure Events 71,350
11 Misc.Employee Expenses 55,758
12 Misc.Labor 724,088
13 Misc.Legal,Professional,and General Services 219,565
14 Misc.Transportation 252,563
15 Other Misc.Expenses<$5k 75,742
46 TOTAL 5,706,421
FERC FORM NO.1 (ED.12-94)
Page 335

This report is:
Name of Respondent: (1)®An Original Date of Report: Year/Period of Report
Avista Corporation 04/18/2025 End of:2024/Q4
(2) ❑ A Resubmission
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 Amortization of
Depreciation Amortization of
Line Functional Classification Expense(Account Expense for Asset Limited Term Other Electric Plant Total
No. (a) 403) Retirement Costs Electric Plant (Acc 405) (f)
(b) (Account403.1) (Account404) ( )
1 Intangible Plant 11,123,237 11,123,237
2 Steam Production Plant 17,432,893 17,432,893
3 Nuclear Production Plant
4 Hydraulic Production Plant- 17,494,070 17,494,070
Conventional
5 Hydraulic Production Plant-
Pumped Storage
6 Other Production Plant 10,184,475 10,184,475
7 Transmission Plant 24,786,980 24,786,980
8 Distribution Plant 60,912,860 60,912,860
9 Regional Transmission and
Market Operation
10 General Plant 5,040,909 422,432 5,463,341
11 Common Plant-Electric 17,533,970 37,633,485 55,167,455
12 TOTAL 153,386,157 49,179,154 202,565,311
FERC FORM NO.1 (REV.12-03)
Page 336-337
CB.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
Service Life Rates Curve Type Remaining Life
No. (a) Thousands) (c) (Percent) (Percent) (f) (g)
(e)
12 STEAM PLANT
13 Colstrip No.3
14 311.I1D 20.072 75 years (3)% 3.12% S1.5 6 years
15 311.WA 37.849 75 years (3)% 3.81% S1.5 4 years
16 312.ID 31.418 55 years (3)% 3.77% R1 6 years
17 312.WA 55.497 55 years (3)% 4.26% R1 4 years

18 313.I1D 0.118 50 years (3)% 16.04% R2.5 6 years
19 313.WA 0.213 50 years (3)% 23.02% R2.5 4 years
20 314.I1D 8.123 37 years (3)% 4.29% R0.5 6 years
21 314.WA 15.314 37 years (3)% 7.42% R0.5 4 years
22 315.I1D 3.791 50 years (3)% 4.42% S1 6 years
23 315.WA 7.198 50 years (3)% 6.15% S1 4 years
24 316.I1D 3.633 60 years (3)% 2.67% R2 6 years
25 316.WA 6.846 60 years (3)% 4.47% R2 4 years
26 Subtotal 190.071
27 Colstrip No.4
28 311.I1D 19.058 75 years (4)% 2.75% S1.5 6 years
29 311.WA 35.878 75 years (4)% 4.14% S1.5 4 years
30 312.I1D 22.289 55 years (4)% 5.15% R1 6 years
31 312.WA 38.395 55 years (4)% 7.25% R1 4 years
32 313.I1D 0.319 50 years (4)% 5.91% R2.5 6 years
33 313.WA 0.578 50 years (4)% 0% R2.5 4 years
34 314.I1D 5.998 i 37 years (4)% 7.49% R0.5 6 years
35 314.WA 11.301 37 years (4)% 11.48% R0.5 4 years
36 315.I1D 2.902 50 years (4)% 4.88% S1 6 years
37 315.WA 5.388 50 years (4)% 6.74% S1 4 years
38 316.I1D 1.882 60 years (4)% 2.88% R2 6 years
39 316.WA 3.526 60 years (4)% 4.87% R2 4 years
40 Subtotal 147.515
i
41 Kettle Falls
i
42 310 0.427 0.53% SQ 17 years
43 311 29.021 75 years (5)% 1.38% S1.5 16 years
44 312 79.932 55 years (5)% 2.62% R1 16 years
45 314 18.754 37 years (5)% 2.79% R0.5 14 years
46 315 12.605 50 years (5)% 3.13% S1 15 years
47 316 2.623 60 years (5)% 1.52% R2 16 years
48 Subtotal 143.363
49 HYDRO PLANT
50 Cabinet Gorge
51 330 9.395 100 years 1.85% R4 34 years

52 331 29.232 55 years (13)% 1.96% R1.5 41 years
53 332 114.561 65 years (13)% 1.87% R1 41 years
54 333 48.116 70 years (13)% 2.34% SO 40 years
55 334 27.586 40 years (13)% 2.74% SO.5 33 years
56 335 6.557 55 years (13)% 1.65% R1 42 years
57 336 1.898 60 years (13)% 1.27% S2.5 36 years
58 Subtotal 237.344
59 Noxon Rapids
60 330 30.747 100 years 1.74% R4 39 years
61 331 25.587 55 years (21)% 2.22% R1.5 43 years
62 332 42.681 65 years (21)% 1.97% R1 44 years
63 333 89.373 70 years (21)% 2.2% SO 43 years
64 334 21.521 40 years (21)% 3.55% SO.5 29 years
65 335 4.57 55 years (21)% 1.94% R1 42 years
66 336 0.306 60 years (21)% 2.25% S2.5 30 years
67 Subtotal 214.784
68 Post Falls
69 330 2.908 90 years 1.21% R4 28 years
70 331 8.289 55 years (4)% 2.22% R1.5 36 years
71 332 26.064 65 years (4)% 2.6% R1 35 years
72 333 2.234 70 years (4)% 0.11% SO 32 years
73 334 3.342 40 years (4)% 2.52% SO.5 29 years
74 335 1.053 65 years (4)% 2.64% R1 36 years
75 336 0.578 60 years (4)% 2.52% S2.5 38 years
76 Subtotal 44.468
77 Long Lake
78 330 0.418 90 years 0.73% R4 25 years
79 331 11.22 55 years (6)% 1.9% R1.5 30 years
80 332 39.073 65 years (6)% 1.72% R1 31 years
81 333 8.892 70 years (6)% 0.26% SO 29 years
82 334 4.55 40 years (6)% 1.6% SO.5 27 years
83 335 1.058 65 years (6)% 2.83% R1 32 years
84 336 0
85 Subtotal 65.21

86 Little Falls
87 330 4.217 90 years 1.25% R4 17 years
88 331 6.161 110 years (5)% 2.32% R1.5 36 years
89 332 6.408 110 years (5)% 1.33% R1 33 years
90 333 39.332 70 years (5)% 2.54% SO 34 years
91 334 14.638 40 years (5)% 2.99% SO.5 29 years
92 335 0.549 65 years (5)% 2.4% R1 34 years
93 Subtotal 71.305
94 Upper Falls
95 330 0.064 100 years 0.85% R4 16 years
96 331 4.96 50 years (6)% 1.57% R1.5 37 years
97 332 10.081 110 years (6)% 1.78% R1 36 years
98 333 0.774 70 years (6)% 0.1% SO 35 years
99 334 5.096 40 years (6)% 2.98% SO.5 26 years
100 335 0.113 65 years (6)% 2.03% R1 32 years
101 336 0.508 60 years (6)% 2.48% S2.5 37 years
102 Subtotal 21.597
103 Nine Mile
104 330 0.011 90 years 0.58% R4 38 years
105 331 24.352 50 years (4)% 2.43% R1.5 36 years
106 332 30.934 65 years (4)% 2.84% R1 35 years
107 333 41.143 70 years (4)% 3.17% SO 35 years
108 334 18.799 40 years (4)% 3.31% SO.5 28 years
109 335 1.041 65 years (4)% 2.8% R1 35 years
110 336 0.595 60 years (4)% 2.35% S2.5 29 years
111 Subtotal 116.874
112 Monroe Street
113 331 12.262 50 years (7)% 2.11% R1.5 42 years
114 332 10.01 110 years (7)% 1.9% R1 46 years
115 333 11.707 70 years (7)% 2.13% SO 38 years
116 334 3.258 40 years (7)% 3.74% SO.5 27 years
117 335 0.034 65 years (7)% 2.16% R1 39 years
118 336 0.05 60 years (7)% 2.51% S2.5 31 years
119 Subtotal 37.32

120 OTHER
PRODUCTION
Northeast
121 Turbine
122 341 0.748 55 years (7)% 0.23% R4 14 years
123 342 0.037 55 years (7)% 0.58% R3 14 years
124 343 9.058 60 years (7)% 0.31% S2 14 years
125 344 2.857 50 years (7)% 0.96% R1 13 years
126 345 1.249 30 years (7)% 0.09% S0.5 12 years
127 346 0.399 35 years (7)% 0.2% R2 12 years
128 Subtotal 14.347
129 Rathdrum
Turbine
130 341 3.734 55 years (7)% 3.92% R4 13 years
131 342 1.696 55 years (7)% 3.52% R3 13 years
132 343 3.646 60 years (7)% 1.74% S2 13 years
133 344 51.269 50 years (7)% 3.86% R1 12 years
134 345 4.925 30 years (7)% 6.61% S0.5 12 years
135 346 0.249 35 years (7)% 5.96% R2 12 years
136 Subtotal 65.519
137 Kettle Falls CT
138 341 0.013 55 years (1)% 3.81% R4 17 years
139 342 0.089 55 years (1)% 1.35% R3 16 years
140 343 8.67 60 years (1)% 1.63% S2 16 years
141 344 0.234 50 years (1)% 4.71% R1 16 years
142 345 0.539 30 years (1)% 6.23% S0.5 16 years
143 Subtotal 9.545
144 Boulder Park
145 341 1.344 55 years (1)% 2.63% R4 21 years
146 342 0.162 55 years (1)% 4.42% R3 21 years
147 343 0.021 60 years (1)% 2.35% S2 20 years
148 344 32.046 50 years (1)% 2.25% R1 19 years
149 345 1.518 30 years (1)% 4.39% S0.5 17 years
150 346 0.065 35 years (1)% 4.52% R2 19 years
151 Subtotal 35.155

152 Coyote Springs 2
153 341 11.765 55 years (3)% 2.52% R4 21 years
154 342 19.004 55 years (3)% 2.36% R3 21 years
155 344 155.548 50 years (3)% 3.4% R1 20 years
156 345 18.868 30 years (3)% 2.46% S0.5 16 years
157 346 0.919 35 years (3)% 4.39% R2 18 years
158 Subtotal 206.104
159 Solar Power
160 344 0.449 25 years (3)% 7.11% S2.5 8 years
161 345 0.033 25 years (3)% 8.92% S2.5 8 years
162 Subtotal 0.482
163 Lancaster
164 342 0.092 55 years (3)% 2.88% R3 19 years
165 344 0.209 50 years (3)% 3.17% R1 18 years
166 345 0.308 30 years (3)% 5.55% S0.5 17 years
167 Subtotal 0.609
168 TRANSMISSION
PLANT
169 350 23.163 80 years 0% 1.04% R4 44 years
170 352 40.858 65 years (15)% 1.76% S2.5 51 years
171 353 415.749 46 years (10)% 2.36% R2 35 years
172 354 17.267 80 years (10)% 1.09% R4 42 years
173 355 403.486 60 years (40)% 2.4% R2.5 49 years
174 356 195.578 60 years (30)% 2.53% R3 40 years
175 357 3.727 60 years 0% 1.63% R4 45 years
176 358 7.348 50 years 0% 2.08% S3 42 years
177 359 2.651 75 years 0% 1.23% R4 50 years
178 Subtotal 1,109.828
179 DISTRIBUTION
PLANT
180 360 4.765 75 years 0% 1.34% R4 67 years
181 361 43.853 63 years (15)% 1.72% S1 50 years
182 362 187.8 44 years (5)% 2.32% R1.5 32 years
183 363 0 0% 0% L3
184 364-WA 411.083 63 years (60)% 2.69% R3 49 years

185 364-ID 209.752 63 years (50)% 2.48% R3 49 years
186 365-WA 247.262 65 years (55)% 2.46% R3 50 years
187 365-ID 146.313 65 years (55)% 2.46% R3 50 years
188 366-WA 125.02 65 years (25)% 1.82% S2.5 52 years
189 366-ID 62.688 70 years (25)% 1.65% S2.5 57 years
190 367-WA 205.197 40 years (25)% 2.43% S1.5 31 years
191 367-ID 104.201 40 years (25)% 2.43% S1.5 31 years
192 368 390.51 50 years (5)% 1.87% R2.5 37 years
193 369 237.325 70 years (5)% 0.96% R2.5 56 years
194 370-AN 0.157 12 years (2)% 7.86% L2.5 9 years
195 370-ID 24.661 33 years (2)% 5.57% 1-1.5 7 years
196 370-WA 64.147 12 years (2)% 7.86% L2.5 9 years
197 371 13.543 10 years 0% 10.87% S3 7 years
198 373 52.139 34 years (5)% 1.58% S1 25 years
199 373.4 20.164 34 years (5)% 3.2% S1 26 years
200 373.5 16.7 34 years (5)% 2.81% S1 30 years
201 Subtotal 2,567.28
202 GENERAL
PLANT
203 390.1 21.63 50 years (5)% 2.06% S1 45 years
204 391 0.033 15 years 6.67% SQ 14 years
205 391.1 4.223 5 years 20% SQ 3 years
206 393 0.473 25 years 4% SQ 14 years
207 394 10.619 20 years 5% SQ 14 years
208 395 3.451 15 years 6.67% SQ 13 years
209 397 42.214 15 years 6.67% SQ 7 years
210 398 0.239 10 years 10% SQ 5 years
211 Subtotal 82.881
212 MISC POWER
EQUIPMENT
213 392 12.23 17 years 3.81% L2.5 13 years
214 396 3.977 24 years 1.88% S1 14 years
215 Subtotal 16.207
E216 Total Company 5,397.807
FERC FORM NO.1 (REV.12-03)
Page 336-337

This report is:
Name of Respondent: (1) An Original Date of Report: Year/Period of Report
Avista Corporation (2) A Resubmission
04/18/2025 End of.2024/Q4
❑
REGULATORY COMMISSION EXPENSES
EXPENSES EXPENSES
INCURRED INCURRED
DURING YEAR DURING
YEAR
CURRENTLY CURRENTLY
CHARGEDTO CHARGED
TO
Description(Fumish name in Deferred
of regulatory commission Assessed by Expenses of Total Expenses Accounted in at
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 (f) (g)
of the case) (b) (c) (d) Year
(a) (e)
Federal Energy
Regulatory Commission-
Charges include annual
1 fee and license fees for 3,796,836 198,558 3,995,394 Electric 928
the 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 2,462,995 674,807 3,137,802 1,264,383 Electric 928
electric dockets
Gas-Includes annual fee
4 and various other natural 1,035,092 165,232 1,200,324 571,217 Gas 928
gas dockets
5 Idaho Public Utilities
Commission
Electric-Includes annual
6 fee and various other 621,446 208,785 830,231 Electric 928
electric dockets
Gas-Includes annual fee
7 and various other natural 229,886 39,137 269,023 Gas 928
gas dockets
8 Public Utility Commission
of Oregon
Includes annual fees and
9 various other natural gas 907,658 233,653 1,141,311 79,816 Gas 928
dockets
10 Not directly assigned 773,990 773,990 Electric 928
Electric
11 Not directly assigned 320,686 320,686 Gas 928
Natural Gas
46 TOTAL 9,053,913 2,614,848 11,668,761 1,915,416
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
End of Year
No. (h) (i) (1) (k) (I)
1 3,995,394
2
3 3,137,802 1,421,566 407 2,685,949
4 1,200,324 754,157 407 1,325,374
5
6 830,231
7 269,023
8
9 1,141,311 36,731 407 86,100 30,447
10 773,990
11 320,686
46 11,668,761 2,212,454 86,100 4,041,770
FERC FORM NO.1 (ED.12-96)
Page 350-351

This report is:
Name of Respondent: (1)0 An Original Date of Report: Year/Period of Report
Avista Corporation (2) ❑A Resubmission 04/18/2025 End of:20241 Q4
RESEARCH,DEVELOPMENT,AND DEMONSTRATION ACTIVITIES
Line Classification Description Costs Incurred Costs Incurred
No. (a) (b) Internally Current Year Externally Current Year
(c) (d)
1 A.Electric(3)Distribution Clean Energy 864,918 (23,471)
2 A.Electric(3)Distribution Clean Energy 14,685 0
3 A.Electric(3)Distribution Clean Energy 73,705 (88,183)
4 A.Electric(3)Distribution Clean Energy 49,443 33,000
5 A.Electric(3)Distribution Clean Energy 0 87,364
6 A.Electric(3)Distribution Clean Energy 0 18,481
7 A.Electric(3)Distribution Clean Energy 667 0
8 A.Electric(6)Other-Testing Lab& HUB-Morris Center Lab Test Facility 35,746 4,406
Facility
9 A.Electric(6)Other-Testing Lab& HUB-Moms Center Lab Test Facility 5,145 0
Facility
10 B.Electric(4)Research Support to Distributed Grid Sensor Service 13,850 37,255
Others(Distribution)
11 B.Electric(4)Research Support to Distributed Grid Sensor Service 41 0
Others(Distribution)
12 B.Electric(4)Research Support to Distributed Grid Sensor Service 4,668 1,009
Others(Distribution)
FERC FORM NO.1 (ED.12-87)
Page 352-353

RESEARCH,DEVELOPMENT,AND DEMONSTRATION ACTIVITIES
AMOUNTS CHARGED)
CURRENT YEAR AMOUNTS CHARGED IN CURRENT YEAR
Line Amounts Charged In Current Amounts Charged In Current Year:Amount Unamortized Accumulation
No. Year:Account (1) (g)
(e)
1 107 841,447
2 182 14,685
3 186 (14,478)
4 588 82,443
5 908 87,364
6 909 18,481
7 920 667
8 107 40,152
9 182 5,145
10 107 51,105
11 182 41
12 588 5,677
FERC FORM NO.1 (ED.12-87)
Page 352-353

This report is:
Name of Respondent: (1)0 An Original Date of Report: Year/Period of Report
Avista Corporation (2) ❑ A Resubmission 04/18/2025 End of:2024/Q4
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 15,700,218
4 Transmission 5,892,185
5 Regional Market 0
6 Distribution 12,378,149
7 Customer Accounts 7,095,274
8 Customer Service and Informational 349,066
9 Sales 0
10 Administrative and General 31,629,021
11 TOTAL Operation(Enter Total of lines 3 thru 73,043,913
10)
12 Maintenance
13 Production 4,398,381
14 Transmission 895,333
15 Regional Market 0
16 Distribution 4,431,644
17 Administrative and General 0
18 TOTAL Maintenance(Total of lines 13 thru 9,725,358
17)
19 Total Operation and Maintenance
20 Production(Enter Total of lines 3 and 13) 20,098,599
21 Transmission(Enter Total of lines 4 and 14) 6,787,518
22 Regional Market(Enter Total of Lines 5 and 0
15)
23 Distribution(Enter Total of lines 6 and 16) 16,809,793
24 Customer Accounts(Transcribe from line 7) 7,095,274
25 Customer Service and Informational 349,066
(Transcribe from line 8)
26 Sales(Transcribe from line 9) 0
FERC FORM NO.1 (ED.12-88)
Page 354355

DISTRIBUTION OF SALARIES AND WAGES
(location of Payroll
Line Classification Direct Payroll Distribution Charged for Clearing Total
No. (a) (b) Accounts (d)
(c)
27 Administrative and General(Enter Total of 31,629,021
lines 10 and 17)
i
28 TOTAL Oper.and Maint.(Total of lines 20 thru 82,769,271 7,827,270 90,596,541
27)
29 Gas f
30 Operation
31 Production-Manufactured Gas 0 1
32 Production-Nat.Gas(Including Expl.And 0
Dev.)
33 Other Gas Supply 1,240,514
34 Storage,LNG Terminaling and Processing 0
35 Transmission 0
36 Distribution 7,466,749
37 Customer Accounts 3,044,179
38 Customer Service and Informational 176,702
39 Sales 0
40 Administrative and General 12,015,074
41 TOTAL Operation(Enter Total of lines 31 thru 23,943,218
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 2,386,026
48 Distribution 3,217,694
49 Administrative and General 0
50 TOTAL Maint.(Enter Total of lines 43 thru 49) 5,603,720
51 Total Operation and Maintenance
52 Production-Manufactured Gas(Enter Total of 0
lines 31 and 43)
53 Production-Natural Gas(Including Expl.and 0
Dev.)(Total lines 32,
i
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) _ d
54 Other Gas Supply(Enter Total of lines 33 and 1,240,514
45)
55 Storage,LNG Terminaling and Processing 0
(Total of lines 31 thru
56 Transmission(Lines 35 and 47) 2,386,026
57 Distribution(Lines 36 and 48) 10,684,443
58 Customer Accounts(Line 37) 3,044,179
59 Customer Service and Informational(Line 38) 176,702
60 Sales(Line 39) 0
61 Administrative and General(Lines 40 and 49) 12,015,074
62 TOTAL Operation and Maint.(Total of lines
52 thru 61) 29,546,938 1,711,691 31,258,629
63 Other Utility Departments
64 Operation and Maintenance 0
65 TOTAL All Utility Dept.(Total of lines 28,62, 112,316,209 9,538,961 121,855,170
and 64)
66 Utility Plant
67 Construction(By Utility Departments)
68 Electric Plant 59,034,485 7,104,286 66,138,771
69 Gas Plant 16,885,126 2,031,978 18,917,104
70 Other(provide details in footnote): 0 0 0
71 TOTAL Construction(Total of lines 68 thru 70) 75,919,611 9,136,264 85,055,875
72 Plant Removal(By Utility Departments)
73 Electric Plant 2,463,236 131,593 2,594,829
74 Gas Plant 895,249 47,826 943,075
75 Other(provide details in footnote): 0
76 TOTAL Plant Removal(Total of lines 73 thru 3,358,485 179,419 3,537,904
75)
77 Other Accounts(Specify,provide details in
footnote):
78 Stores Expense(163) 3,068,445 (3,068,445) 0
79 Preliminary Survey and Investigation(183) 0 0 0
FERC FORM NO.1 (ED.12-88)
Page 354-355

DISTRIBUTION OF SALARIES AND WAGES
AI'location of Payroll J
Line Classification Direct Payroll Distribution Charged for Clearing Total
No. (a) (b) Accounts (d)
(c)
80 Small Tool Expense(184) 5,550,716 (5,550,716) 0
81 Miscellaneous Deferred Debits(186) 3,422,254 3,422,254
82 Non-operating Expenses(417) 437,167 437,167
83 Retirement Bonus/SERP/HRA(228) 10,199 10,199
84 Other Income Deductions(426) 1,128,800 1,128,800
85 Employee Incentive Plan(232380) 7,746,717 (7,746,717) 0
86 DSM Tariff Rider(242600) 2,488,766 (2,488,766) 0
87 Incentive/Stock Compensation(238000) 0 0
88 Payroll Equalization Liability(242700) 33,241,787 33,241,787
89 Miscellaneous Deferred Credits(253) 7,219 7,219
90
91
92
93
94
95 TOTAL Other Accounts 57,102,070 (18,854,644) 38,247,426
96 TOTAL SALARIES AND WAGES 248,696,375 0 248,696,375
FERC FORM NO.1 (ED.12-88)
Page 354-355

This report is:
Name of Respondent: (1)21 An Original Date of Report: Year/Period of Report
Avista Corporation (2) ❑ A Resubmission 04/18/2025 End of.2024/Q4
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 313,825,050
389 Land and Land Rights 14,939,075
390 Structures and Improvements 166,736,705
391 Office Furniture and Equipment 68,111,563
392 Transportation Equipment 14,394,315
393 Stores Equipment 6,247,653
394 Tools,Shop&Garage Equipment 18,181,937
395 Laboratory Equipment 1,254,754
396 Power Operated Equipment 1,895,320
397 Communications Equipment 160,680,538
398 Miscellaneous Equipment 623,830
399 Asset Retirement Cost 0
Total Common Plant 766,890,739
Const.Work in Progress 16,099,024
Total Utility Plant 782,989,763
Acc.Prov.for Dep.&Amort. 325,921,292
Net Utility Plant 457,068,471
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 274,566 143,348 131,218 #of Customers
902 Meter reading expenses 1,038,450 626,675 411,775 #of Customers
903 Cust rec&collectn expenses 16,796,672 8,911,320 7,885,352 #of Customers
904 Uncollectible accounts 203,403 106,207 97,196 #of Customers
905 Misc cust acct expenses 355,469 185,603 169,866 #of Customers
907 Cust svice&Info exp supervision 0 0 0 #of Customers
908 Cust assistance expenses 482,162 290,974 191,188 #of Customers
909 Info&instruct advert expenses 1,268,970 757,152 511,818 #of Customers
910 Misc cust sery&info expenses 120,136 62,712 57,424 #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 39,882,005 28,609,577 11,272,428 Four Factor
921 Office supplies&expenses 5,425,903 3,874,275 1,551,628 Four Factor
922 Admin expenses tranf-credit 0 0 0 Four Factor
923 Outside services employed 19,204,947 13,709,253 5,495,694 Four Factor
924 Property insurance 3,626,857 2,588,148 1,038,709 Four Factor
925 Injuries and damages 14,900,748 10,852,512 4,048,236 Four Factor
926 Employee pensions&benefits 90,195,846 64,441,755 25,754,091 Four Factor
927 Franchise requirement 0 0 0 Four Factor
928 Regulatory commission expenses 1,940,719 1,443,842 496,877 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 5,787,742 4,150,626 1,637,116 Four Factor
931 Rents 739,877 533,658 206,219 Four Factor
935 Maint of general plant 17,296,195 12,439,980 4,856,215 Four Factor
403 Depreciation 24,292,363 17,533,970 6,758,393 Four Factor
404 Amort of LTD term plant 52,693,101 37,633,485 15,059,616 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 (2) El A Resubmission 04/18/2025 End of:2024/Q4
AMOUNTS INCLUDED IN ISO/RTO SETTLEMENT STATEMENTS
Line DGSCM O"©fXem(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(Account555) 6,824,866 -8,127,383 -9,907,046 -11,735,424
2.1 Net Purchases(Account 555.1)
3 Net Sales(Account 447) (1,181,218) ID(2,649,866) -(3,870,406) -(5,746,058)
4 Transmission Rights
5 Ancillary Services 3,469 3,429 3,522 3,531
6 Other Items(list separately)
7 Other Charges-MRTU (5,398) (6,898) 25,181 134,914
8 OtherCharges-EIM (974,951) (1,600,645) (1,704,659) (1,916,482)
46 TOTAL 4,666,768 3,873,403 4,360,684 4,211,329
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 04/18/2025 End of:2024/Q4
(2) El A Resubmission
FOOTNOTE DATA
(a)Concept:IsoOrRtoSettlementsEnergyNetPurchasesPurchasedP owe r
CAISO-MRTU Purchases=$284,490
CAISO-EIM Purchases=$6,540,376
Lb)Concept:IsoOrRtoSettlementsEnergyNetPurchasesPurchasedPower
CAISO-MRTU Purchases=$285,165
CAISO-EIM Purchases=$7,842,218
Lc)Concept:IsoOrRtoSetdementsEnergyNetPurchasesPurchasedPower
CAISO-MRTU Purchases=$342,957
CAISO-EIM Purchases=$9,564,089
1W Concept:IsoOrRtoSettlementsE nergyN etPu rchasesPurchased Power
CAISO-MRTU Purchases=$365,387
CAISO-EIM Purchases=$11,370,037
Le)Concept:IsoOrRtoSettlementsEnergyNetSales
CAISO-MRTU Sales=$170,561
CAISO-EIM Sales=$1,010,657
Mf Concept:IsoOrRtoSettlementsEnergyNetSales
CAISO-MRTU Sales=$170,561
CAISO-EIM Sales=$2,479,305
kW Concept:IsoOrRtoSettlementsEnergyNetSales
CAISO-MRTU Sales=$170,561
CAISO-EIM Sales=$3,699,845
U Concept:IsoOrRtoSettlementsEnergyNetSales
CA ISO-MRTU Sales=$170,561
CAISO-EIM Sales=$5,575,497
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 (2) ❑ A Resubmission 04/18/2025 End of:2024/Q4
PURCHASES AND SALES OF ANCILLARY SERVICES
Amount Purchased for the 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
3 Regulation and Frequency Response
4 Energy Imbalance
5 Operating Reserve-Spinning
6 Operating Reserve-Supplement
7 Other 834 MW -10,453,155
8 Total(Lines 1 thru 7) 834 10,453,155
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 88 MW 1,133,304
4
5 1 MW 15,126
6 1 MW 13,936
7 834 MW -10,453,155
8 924 11,615,521
FERC FORM NO.1 (New2-04)
Page 398

This report is:
Name of Respondent: (1)21 An Original Date of Report: Year/Period of Report
Avista Corporation (2) ❑ A Resubmission 04/18/2025 End of:2024/Q4
FOOTNOTE DATA
(a)Concept:AncillaryServicesPurchasedAmount
Amounts reported are offsetting imputed amounts reflecting the self-provison of ancillary service for bundled retail native load customers under
state jurisdiction.
Concept:AncillaryServicesSoldAmount
Amounts reported are offsetting imputed amounts reflecting the self-provision 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)0 An Original Date of Report: Year/Period of Report
Avista Corporation 04/18/2025 End of:2024/Q4
(2) El A Resubmission
MONTHLY TRANSMISSION SYSTEM PEAK LOAD
Firm Long-Term OtherShort-Term
Monthly Day of Hour of Firm Network Long-
Networh Firm Point- Firm Pint- Other
Une Month Peak MW- Monthly Monthly Service for
Service for to-point Term to-pointService
Total Peak Peak Solt
(u) (c) (d) (e) Others Reservations Firm ServlcoRescrvatian
(fl (g) (h) (i)
NAME OF
SYSTEM:
AvistAvista
Corporation
1 January 3,581 13 18 1,734 519 769 7 559 957
2 February 2,976 16 8 1,393 369 769 13 445 216
3 March 3,021 5 8 1,370 362 783 21 506 126
4 Total for Quarter 1 4,497 1,250 2,321 41 1,510 1,299
5 April 2,888 17 8 1,177 304 784 12 623 413
6 May 2,700 8 8 1,099 270 781 19 550 348
7 June 3,059 11 18 1,156 262 779 24 862 188
8 Total for Quarter 2 3,432 836 2,344 55 2,035 949
9 July 3,686 9 18 1,682 378 788 21 838 346
10 August 3,590 2 18 1,710 382 782 23 716 229
11 September 3,282 5 18 1,461 317 770 15 734 364
12 Total for Quarter 3 4,853 1,077 2,340 59 2,288 939
13 October 2,872 30 9 1,209 287 768 8 608 30
14 November 3,103 7 8 1,222 312 759 9 810 108
15 December 3,217 5 18 1,476 339 759 9 643 89
16 Total for Quarter 4 3,907 938 2,286 26 2,061 227
17 Total 16,689 4,101 9,291 181 7,894 3,414
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 (2) ❑A Resubmission 2025-04-18 End of.2024/Q4
ELECTRIC ENERGY ACCOUNT
Line Item MegaWatt Hours Line Item MegaWatt Hours
(a) (b) No. (a) (b)
1 SOURCES OF ENERGY 21 DISPOSITION OF ENERGY
2 Generation(Excluding Station Use): 22 Sales to Ultimate Consumers
includin Interde artmental Sales 9,412,851
( 9 P )
3 Steam 1,665,736 23 Requirements Sales for Resale(See
instruction 4,page 311.)
4 Nuclear 24 Non-Requirements Sales for Resale 3,788,593
(See instruction 4,page 311.)
5 Hydro-Conventional 3,168,008 25 Energy Furnished Without Charge
Energy Used by the Company
6 Hydro-Pumped Storage 26 (Electric Dept Only,Excluding 14,531
Station Use)
7 Other 3,329,427 27 Total Energy Losses 370,640
8 Less Energy for Pumping 27.1 Total Energy Stored
Net Generation(Enter Total of lines TOTAL(Enter Total of Lines 22
9 3 through 8) 8,163,171 28 Through 27.1)MUST EQUAL LINE 13,586,615
20 UNDER SOURCES
10 Purchases(other than for Energy 5,424,379
Storage)
10.1 Purchases for Energy Storage 0
11 Power Exchanges:
12 Received 0
13 Delivered 935
14 Net Exchanges(Line 12 minus line (935)
13)
15 Transmission For Other(Wheeling)
16 Received 4,708,379
17 Delivered 4,708,379
18 Net Transmission for Other(Line 16 0
minus line 17)
19 Transmission By Others Losses
20 TOTAL(Enter Total of Lines 9,10, 13,586,615
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 04/18/2025 End of:2024/Q4
(2) El A Resubmission
MONTHLY PEAKS AND OUTPUT
Monthly Non-
Line Month Total Monthly AOqutrement Sales Monthly Peak- Monthly Peak-Day Monthly Peak-
Energy farltesale& Megawatts of Month Hour
NEC. (a) (b) AssedaWtl Lasses (d) (c) (fl
(C)
NAME OF SYSTEM:
AvistAvista Corporation
29 January 1,298,098 319,379 1,869 13 19
30 February 1,180,982 343,737 1,481 15 12
31 March 1,238,421 416,045 1,472 6 8
32 April 1,098,210 377,622 1,270 5 11
33 May 1,007,861 291,426 1,184 1 9
34 June 1,090,799 408,713 1,367 25 18
35 July 1,159,214 276,499 1,793 10 17
36 August 1,123,130 269,879 1,831 2 18
37 September 1,129,151 370,509 1,588 5 18
38 October 1,014,479 257,784 1,330 30 9
39 November 1,072,436 221,109 1,456 19 18
40 December 1,173,834 235,891 1,511 9 18
41 Total 13,586,615 3,788,593
FERC FORM NO.1 (ED.12-90)
Page 401b

This report is:
Name of Respondent: (1)21 An Original Date of Report: Year/Period of Report
Avista Corporation (2) El A Resubmission 04/18/2025 End of:2024/Q4
Steam Electric Generating Plant Statistics
1.Report data for plant in Service only.
2.Large plants are steam plants with installed capacity(name plate rating)of 25,000 Kw or more.Report in this page gas-turbine and
internal combustion plants of 10,000 Kw or more,and nuclear plants.
3.Indicate by a footnote any plant leased or operated as a joint facility.
4.If net peak demand for 60 minutes is not available,give data which is available,specifying period.
5.If any employees attend more than one plant,report on line 11 the approximate average number of employees assignable to each plant.
6.If gas is used and purchased on a therm basis report the Btu content orthe 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.Fora 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 unitfunctions 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 planttype fuel used,fuel enrichmenttype and quantity forthe report period and other physical and operating
characteristics of plant.
Line Plant Name: Plant
Item Plant Name: Plant Name: ote Plant Name: Plant Name: Namo:
No. (a) Boulder Park Colstrip Springs Kettle Falls Rathdrum Spokane
N.E.
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, Conventional Conventional Not Applicable Conventional
Outdoor,Boiler,etc) Applicable Applicable
3 Year Originally 2002 1984 2003 1983 1995 1978
Constructed
4 Year Last Unit was 2002 1985 2003 1983 1995 1978
Installed
Total Installed Cap
5 (Max Gen Name Plate 25 233 287 58 167 62
Ratings-MW)
Net Peak Demand on
6 Plant-MW(60 57 233 319 86 174 62
minutes)
7 Plant Hours Connected 5,090 8,085 8,261 6,560 6,695 21
to Load
8 Net Continuous Plant 25 222 322 53 166 65
Capability(Megawatts)
9 When Not Limited by 0 222 322 53 0 0
Condenser Water
10 When Limited by 0 222 322 53 0 0
Condenser Water

11 Average Number of 2 273 32 28 2 1
Employees
Net Generation,
12 Exclusive of Plant Use 99,023,000 1,373,013,000 2,325,857,000 292,723,000 866,302,000 1,189,000
-kWh
13 Cost of Plant:Land and 144,733 1,289,395 0 2,568,188 621,682 138,753
Land Rights
14 Structures and 1,343,508 112,856,789 11,764,991 29,020,873 3,733,866 747,662
Improvements
15 Equipment Costs 33,811,107 224,729,187 194,339,146 113,914,366 61,785,312 13,596,464
16 Asset Retirement 0 17,139,710 351,682 323,787 0 0
Costs
17 Total cost(total 13 thru 35,299,348 356,015,081 206,455,819 145,827,214 66,140,860 14,482,879
20)
Cost per KW of
119
Installed Capacity(line 1,411.9739 1,527.9617 719.3583 2,514.2623 396.0531 233.5948
17/5)Including
Production Expenses: 26,041 129,537 285,892 82,136 27,197 25,093
Oper,Supv,&Engr
20 Fuel 2,305,827 30,975,829 46,812,209 10,992,914 27,728,049 32,644
21 Coolants and Water
(Nuclear Plants Only)
22 Steam Expenses 0 3,301,866 0 637,950 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 457,399 (114,742) 4,158,080 904,296 445,282 28,514
Misc Steam(or
26 Nuclear)Power 32,251 5,603,378 1,049,085 515,255 18,786 8,104
Expenses
27 Rents 0 0 76,210 0 0 0
28 Allowances 0 0 0 0 0 0
Maintenance
29 Supervision and 46,036 414,022 382,957 75,241 65,940 17,277
Engineering
30 Maintenance of 0 852,394 128,156 170,362 2,883 0
Structures
31 Maintenance of Boiler 0 7,402,110 0 2,326,463 0 0
(or reactor)Plant
32 Maintenance of Electric 556,517 2,072,852 2,070,030 900,630 174,048 4,259
Plant
Maintenance of Misc
33 Steam(or Nuclear) 162,432 1,090,920 503,647 871,183 195,376 22,678
Plant
34 Total Production 3,586,503 51,728,166 55,466,266 17,476,430 28,657,561 138,569
Expenses

35 Expenses per Net kWh 0.0362 0.0377 0.0238 0.0597 0.0331 0.1165
35 Plant Name Boulder Colstrip Colstrip Coyote Kettle Falls Kettle Rathdrum Spokane
Park Springs 2 Falls 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) 882,017 866,030 3,421 15,260,415 5,022 479,313 10,077,699 14,215
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
(btu/indicate if
nuclear)
Avg Cost of
40 Fuel/unit,as 2.61 35.25 131.43 3.07 3.04 22.9 2.75 2.3
Delvd f.o.b.
during year
Average Cost of
41 Fuel per Unit 2.61 35.25 131.43 3.07 3.04 22.9 2.75 2.3
Burned
Average Cost of
42 Fuel Burned per 2.56 2.08 22.35 3.01 2.98 2.66 2.7 2.25
Million BTU
Average Cost of
43 Fuel Burned per 0.02 0.02 0 0.02 0.04 0.04 0.03 0.03
kWh Net Gen
Average BTU
44 per kWh Net 9,085 10,719 0 6,692 0 14,102 11,866 12,195
Generation
FERC FORM NO.1 (REV.12-03)
Page 402-403

This report is:
Name of Respondent: (1)0 An Original Date of Report: Year/Period of Report
Avista Corporation 04/18/2025 End of:2024/Q4
(2) ❑ A Resubmission
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 No. FERC Licensed Project No.
Line Item No. 2545 2545
No. (a) 2058 Plant Name: Plant Larne:
Plant Name: Little Falls Long Lake
Cabinet Gorge
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 265 43 70
Rating in MW)
6 Net Peak Demand on Plant-Megawatts 264 50 94
(60 minutes)
7 Plant Hours Connect to Load 8,718 6,848 7,053
8 Net Plant Capability(in megawatts)
9 (a)Under Most Favorable Oper 254.6 43.2 89.5
Conditions
10 (b)Under the Most Adverse Oper 294.8 43.2 89.5
Conditions
11 Average Number of Employees 1 1 1
12 Net Generation,Exclusive of Plant Use- 857,615,000 185,339,000 456,166,000
kWh
13 Cost of Plant
14 Land and Land Rights 18,643,682.11 4,325,371.4799999995 2,421,233.18
15 Structures and Improvements 29,231,968.37 6,160,658.41 10,950,082.3
16 Reservoirs,Dams,and Waterways 114,560,572.99 6,407,916.8 39,057,488.8
17 Equipment Costs 82,258,842.01 54,518,845.59 14,294,689.13
FERC FORM NO.1 (REV.12-03)
Page 406-407

Hydroelectric Generating Plant Statistics
FERC Licensed Project FERC Licensed Project No. FERC Licensed Project No.
Line Item No. 2545 2545
No. (a) 2058Plant Name: Plant Name: Plant Name:
Cabinet Gorge Little Falls Long Lake
18 Roads,Railroads,and Bridges 1,897,602.88 0 0
19 Asset Retirement Costs 0 0 0
20 l Total cost(total 13 thru 20) 246,592,668.36 71,412,792.28 66,723,493.410000004
21 Cost per KW of Installed Capacity(line 20 930.5384 1,660.7626 953.1928
/5)
22 Production Expenses
23 Operation Supervision and Engineering 137,782.5 603 51,855.8
24 Water for Power 0 0 0
25 Hydraulic Expenses 0 8,028.22 8,229.61
26 Electric Expenses 1,394,678.42 650,628.28 725,302.7
27 Misc Hydraulic Power Generation 185,417.37 35,282.13 173,110.54
Expenses
28 Rents 0 1,191,217 0
29 Maintenance Supervision and 21,370.93 5,135.06 3,748.21
Engineering
30 Maintenance of Structures 189,705.4 25,946.2 52,167.86
31 Maintenance of Reservoirs,Dams,and 34,262.94 17,101.23 22,970.07
Waterways
32 Maintenance of Electric Plant 278,740.09 234,827.53 388,700.94
33 Maintenance of Misc Hydraulic Plant 28,663.36 4,035.35 17,424.97
34 3 t I Production Expenses(total 23 thru 2,270,621.01 2,172,804 1,443,510.7
35 Expenses per net kWh 0.0026 0.0117 0.0032
FERC FORM NO.1 (REV.12-03)
Page 406-407

Hydroelectric Generating Plant Statistics
FERC Uemsed Project No. FEI2t:Licensed Project No. MC Licensed Project No. FERG LIW11sed Project`i+►o.
Line 250 2545 2058 2545
No. Mnt Name: Plant Name: Plant Name: Plant Name:
Mertrt4Street Nine Mile Falls Norton Rapids PostFalls
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
6 125 24 546 22
7 8,336 8,691 6,739 8,694
8
9 15 37.6 580.7 17.5
10 15 37.6 622.5 18
11 4 5 10 7
12 89,885,000 125,735,000 1,324,290,000 69,055,000
13
14 51,600.01 33,429.42 37,469,198.029999994 4,161,521.9500000007
15 12,241,335.61 23,961,094.23 25,587,016.28 8,288,813.23
16 10,010,069.24 30,933,635.729999997 42,680,756.54 26,063,988.38
17 14,640,490.07 60,982,535.06 115,463,531.46 6,629,370.46
18 50,448.44 594,870.06 305,776.91000000003 577,943.72
19 0 0 0 0
20 36,993,943.37 116,505,564.5 221,506,279.22 45,721,637.74
21 2,466.2629 3,065.9359 453.9063 3,048.1092
22
23 21,185.53 25,959.16 212,774.66 24,557.5
24 0 0 0 0
25 0 0.47 101,349.9 2,916.4
26 615,130.07 769,352.03 1,035,352.79 745,805.8
27 8,075.59 104,335.22 165,758.12 78,389.24
28 0 0 813 0
29 77,922.27 1,121.49 6,310.39 53,604.67
30 8,854.33 5,433.01 10,862.66 5,374.24
FERC FORM NO.1 (REV.12-03)
Page 406-407

Hydroelectric Generating Plant Statistics
FERC Licensed Project No. FERC Licensed Project No. FERC Llcensed Project No. FERC Licensed Project No.
Llne 2545 2545 2058 2545
No. Plant Name: Plant Name: Plant Name: Plant Name:
Monroe Street Nine Mile Falls Noxon Rapids Post Falls
31 9,830.65 40,063.04 7,686.28 89,861.09
32 69,100.37 256,506.55 619,366.91 76,737.76
33 524.85 22,408.85 88,470.76 37,041.19
34 810,623.6599999999 1,225,179.82 2,248,745.4699999997 1,114,287.89
35 0.009 0.0097 0.0017 0.0161
FERC FORM NO.1 (REV.12-03)
Page 406-407

Hydroelectric Generating Plant Statistics
FERC Licensed Project No.
2545
Line No.
Plant Name:
Upper Falls
1 Run-of-River
2 Conventional
3 l 1922
4 � 1922
5 10
6 11
7 8,760
8
9 10.2
10 10.2
11 4
12 59,923,000
13
14 1,081,854.49
15 4,960,223.97
16 10,081,370.3
17 5,983,372.54
18 508,242.34
19 0
20 22,615,063.64
21 2,261.5064
22
23 20,565.34
24 0
25 139.93
26 619,063.45
27 46,537.98
28 0
29 4.02
30 3,089.75
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
31
14,823.76
32 45,789.81
33
454.35
34 750,468.39
35
0.0125
FERC FORM NO.1 (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 04/18/2025 End of:2024/Q4
(2) El A Resubmission
GENERATING PLANT STATISTICS(Small Plants)
Installed Capacity Net Peak Demand Net Generation
Line Name of Plant Year Orig.Const. Name Plate Rating MW(60 min) Excluding Plant Cost of Plant
No. (a) (b) (MW} Use (f)
(c) (d) j (e)
1 Kettle Falls CT 2002 7 14 37,056,000 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 Operation Exc'I. Fuel Production Maintenance Fuel Costs(in
Line Asset Retire. Production Kind of Fuel cents(per
No. Costs Fuel Expenses Ex
)Per MW h (k) Million Btu)
(9) ( � (�) Expenses p6) (1)
1 1,323,903 93,004 1,163,160 32,089 I Natural Gas 277.91
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 04/18/2025 End of:2024/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 1,565
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 l 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
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 Numbeld
No. From To Operating Designated Supporting of Line Structures of of
Structure Designated Another Line Circuits
(a) (b) (c) (d) (e) (f) (g) (h)
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
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 2,255 0 44
FERC FORM NO.1 (ED.12-87)
Page 422-423

TRANSMISSION LINE STATISTICS
COST OF COST OF LINE COSTOF LINE
LINE(Include (Include in (Include in EXPENSES, EXPENSES, EXPENSES, EXPENSES,
in column 0) column 0) column 6) EXCEPT EXCEPT EXCEPT EXCEPT
Land,Land Land,Land Land,Land rights,and rights,and rights,and DEPRECIATION DEPRECIATION DEPRECIATION DEPRECIATION clearing right- clearing right- clearing right-
AND TAXES AND TAXES AND TAXES AND TAXES
of-way) of-way) of-way)
Line Size of
Conductor Land Construction Total Costs Operation Maintenance Rents Total Expenses
No. and Material Costs Expenses Expenses
(I) (1) (k) (I) (m) (n) (o) (p)
1 136,038 636,193 772,231 0
2 12,898,649 368,778,966 381,677,615 1,176,689 1,342,842 2,519,531
3 1272 ACSS 0 0
4 1272 ACSS 17,912 1,420,564 1,438,476 0 0 0
5 1272 ACSS 0 0
6 1272 ACSS 30,323 3,225,715 3,256,038 0 0 0
7 1590 ACSS 0 0
8 1590 ACSS 0 0
9 1590 ACSR 1,156,196 41,093,967 42,250,163 0 175,024 175,024
10 1590 ACSS 0 0
11 1590 ACSS 0 0
12 1272 AAC 0 0
13 1272 ACSS 196,836 34,876,983 35,073,819 0 44,717 44,717
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 954AAC 1,099,064 19,355,957 20,455,021 5,751 201,925 207,676
19 795 ACSR 0 0
20 954AAC 184,528 2,501,867 2,686,395 4,970 57,936 62,906
21 954 AAC 399,821 5,524,153 5,923,974 64,208 15,629 79,837
22 1590 ACSR 0 0
23 1272 AAC 169,117 21,627,264 21,796,381 4,522 1,995 6,517
24 1272 AAC 0 0
25 1272 ACSR 0 0
26 1272 ACSR 623,984 6,760,954 7,384,938 0 8,081 8,081
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 Q) 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 Land Costs Total Costs Expenses Expenses Rents Total Expenses
and Material
(1) (1) (k) (1) _ _ (m) _ _ (n) (o) _(p)
27 1272 ACSR 0 T 0
28 1272 ACSR 872,150 9,996,899 10,869,049 0 0 0
i
29 1590 ACSS 0 0
30 1272 ACSR 0 0
31 1272 AAC 316,135 13,676,773 13,992,908 0 0 0
32 1272 ACSR 0 0
33 1272 ACSR 0 18,772 18,772 0 0 0
34 1272 ACSR 0 0
35 1622 ACSS 0 0
36 1272 AAC 3,604,461 11,253,787 14,858,248 763 36,702 37,465
37 1272 ACSR 8,482 0 8,482 0 0 0
38 1272 ACSR 36,461 1,488,214 1,524,675 0 0 0
39 1590 ACSR 155,244 2,221,191 2,376,435 0 0 0
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 38,675,379 39,271,168 109,133 165,566 91,984 366,683
36 23,276,659 632,417,596 655,694,255 1,366,036 2,050,417 91,984 3,508,437
FERC FORM NO.1 (ED.12-87)
Page 422-423

This report is:
Name of Respondent: (1)21 An Original Date of Report: Year/Period of Report
Avista Corporation (2) ❑A Resubmission 04/18/2025 End of:2024/Q4
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) (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
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 From To Line Length in Type Average Number Present
No. Miles per Miles
(a) (b) (c) (d) (e) (>7
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44 TOTAL
FERC FORM NO.1 (REV.12-03)
Page 424-425

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

TRANSMISSION LINES ADDED DURING YEAR
CIRCUITS PER STRUCTURE CONDUCTORS CONDUCTORS CONDUCTORS LINE COST
Line Voltage KV Land and Land
No. Ultimate Size Specification Configuration and Spacing (Operating) Rights
(g) (h) (i) G) (k) (l)
30
31
32
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
No. Fixtures Devices Asset Retire.Costs Total Construction
(m) (n) (o) (p) (q)
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 (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)
31
32
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)0 An Original Date of Report: Year/Period of Report
Avista Corporation (2) El A Resubmission 04/18/2025 End of.2024/Q4
SUBSTATIONS
Character of Substation Cfu racbarc ubistation VOLTAGE(In VOL'AGE VOLTAGE
MVa) (in MVa) (In MVa)
Capacity
Secondary Tertiary of
Line Name and Location of Substation Distribution Transmission or Primary Voltage Substation.
Attended or Unattended Voltage(In Voltage
No. (a) (b) (b-1) (in(MVa) MVa) (In MVa) Service)
(d) (e) (in MVa)
1 Airway Heights(WA) Distribution Unattended 115 13.8 24
2 Barker Road(WA) Distribution Unattended 115 13.8 12
3 BAacon(Trans.&Dist.) Transmission Unattended 230 115 13.8 536
4 Boulder
A)er(Trans.&Dist.) Transmission Unattended 230 115 13.8 318
5 Chester(WA) Distribution Unattended 115 13.8 24
6 Chewelah 115Kv(WA) Distribution Unattended 115 13.2 12
7 Colbert(WA) Distribution Unattended 115 13.8 12
8 College&Walnut(WA) Distribution Unattended 115 13.8 36
9 Colville 115 Kv(WA) Distribution 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 Francis and Cedar(WA) 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 36
23 Greenwood(WA) Distribution Unattended 115 13.8 12
24 Hallett&White(WA) Distribution Unattended 115 13.8 36
FERC FORM NO.1 (ED.12-96)
Page 426-427

SUBSTATIONS
Charftftr of SubsWon Char tIictetOfS t VOLTAGE(in VOLTAGE VOLTAGE
MVa) (in MVa) (in MVa)
Capacity �
Secondary Tertiary of
Line Name and Location of Tr
ansmisslon or Attended or Unattended Primary Voltage Voltage(In Voltage Substation
No. Substation Dfaft4bution (b-�) (In MVa) MVa) (In MVa) (in
(a) (b) (c) (d) (e) Service)
(In MVa)
(fl
25 Indian Trail(WA) Distribution Unattended 115 13.8 24
26 Kettle Falls(WA) Distribution Unattended 115 13.8 12
27 Lee&Reynolds(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 TWA)Falls 115134 Kv Distribution Unattended 115 34 12
31 Lyons&Standard(WA) 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 Ninth&Central(WA) 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 Saddle Mountain(WA) 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
FERC FORM NO.1 (ED.12-96)
Page 426-427

SUBSTATIONS
Character of Substation Character of Substation VOLTAGE(In VOLTAGE VOLTAGE
MVa) (In MVa) (In MVa)
Capacity
Secondary Tertiary of
Line
Name and Location of Transmission or Attended or Unattended Primary Voltage Voltage(In Voltage Substation
Substation Distribution (In MVa) (In
No. (a) (b) (b-1) (c) MVa) (In MVa) Service)
(d) (e) (In MVa)
(f)
51 Spokane Industrial Park Distribution Unattended 115 13.8 24
52 Sunset(WA) Distribution Unattended 115 13.8 ( 36
53 Terre View(WA) Distribution Unattended 115 13.8 12
54 Third&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(ID) 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 30
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
FERC FORM NO.1 (ED.12-96)
Page 426-427

SUBSTATIONS
Character of Substation Character of Substation VIDETAXe_()ft VOLTAGE VOLTAGE
Mva) (In MVa) (In MVa)
Capacity
Secondary Tortlary of
Line Name and Location of Transmission or Attended or Unattended Primary Voltage Voltage(in Voltage Substation,
No.
Substation Distribution (b-1) (In MVa) MVa) (In MVa) (in
(b) (c) service
(a) )
(d) (e) (In MVa)
76 Kooskia(ID) Distribution Unattended 115 13.8 15
77 Lewiston Mill Rd(ID) Distribution Unattended 115 13.2 18
78 Lolo(Trans.&Dist.)(ID) Transmission Unattended 230 115 13.8 312
79 Moscow(ID) Distribution Unattended 115 13.8 24
80 Moscow 230 kV(Trans. Transmission Unattended 230 115 13.8 162
&Dist.)(ID)
81 North Lewiston 230kV Transmission Unattended 230 115 158
(Trans.&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
FERC FORM NO.1 (ED.12-96)
Page 426-427

SUBSTATIONS
Character of Substation Character of Substation VOLTAGE(In VOLTAGE VOLTAGE
MVa) (In MVa) (In MVa)
Capacity
Secondary Tertiary of
Line Name and Location of Transmission or Attended or Unattended Primary Voltage Voltage(In Voltage Substation
No Substation Distribution (In MVa) (In
(a) (b) (b-1) (c) MVa) (In MVa) Service)
(d) (e) (In MVa)
(f)
101 Other:13 Subs less than Distribution Unattended 72
10 MVA(ID)
102 Other:1 Sub less than Distribution Unattended 5
10 MVA(MT)
103 Boulder Park(WA Gen. Transmission Attended 115 13.8 36
Plant)
104 Kettle Falls(WA Gen. Transmission Attended 115 13.8 34
Plant)
105 Long Lake(WA Gen. Transmission Attended 115 4 72
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 Gen. Transmission Attended 13.8 4 35
Plant)
110 Cabinet Gorge(HE Transmission Attended 230 13.2 300
(ID Gen.Plant)
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.Plant) Transmission Attended 230 13.8 435
114 Coyote Springs II(OR Transmission Attended 500 13.8 18 270
Gen.Plant)
115 Distribution Substations 9,890 1,335.8 0 2,088
116 Distribution Substations 9,890 1,335.8 0 2,088
Unattended
117 Transmission 4,883.8 1,619.1 183.6 4,557
Substations
118 Transmission 1,893.8 124.1 18 1,410
Substations Attended
119 Transmission 2,990 1,495 165.6 3,147
Substations Unattended
FERC FORM NO.1 (ED.12-96)
Page 426-427

SUBSTATIONS
Character of Substation Character of Substation VOLTAGE(In VOLTAGE VOLTAGE
MVa) (In MVa) (In MVa)
Capacity
Secondary Tertiary of
Line
Name and Location of Transmission or Attended or Unattended Primary Voltage Voltage(In Voltage Substation
No. Substation Distribution (b 1) (In MVa) MVa) (In MVa) (In
(a) (b) (c) (d) (e) Service)
(In MVa)
-T (f)
120 Total 6,645
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)
(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 3 530
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 2 Two Stage Fan 2 60
23 1 Two Stage Fan 1 20
24 2 Two Stage Fan 2 60
25 2 Two Stage Fan 2 40
26 1 Frcd Oil&Air Fan 1 20
27 2 Two Stage Fan 2 60
28 2 Two Stage Fan 2 40
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 M
No. Service �) U) k)
29 1 Two Stage Fan 1 [ 20
30 1
31 2 Two Stage Fan 2 60
32 1 Two Stage Fan 1 30
33 2 Two Stage Fan 2 40
34 2 Frcd Oil&Air Fan 2 1 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
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 P Total Capacity(In
Line Transformers In Transformers Type of Equipment Number of Units MVa)
No. Service (h) (i) U) (k)
(g) _
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
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 2 Two Stage Fan 2 50
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 3 520
79 2 Fred 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
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 Trans(ormers (i) Mk))
(g)
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
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 Portable Fan,Frcd Oil&Air 4 39
98 1 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
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
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 p Total Capacity(In
Line Transformers In Transformers Type of Equipment Number of Units MVa)
No. Service (l�) (i) �) k
(g) ( )
112 2 1 Two Stage Fan 2 190
113 9 1 Two Stage Fan 6 635
114 3 1 Two Stage Fan 3 450
115 182 0 363 2,943
116 182 0 363 2,943
117 62 5 691 6,093
118 34 5 18 1,569
119 28 0 673 4,524
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 04/18/2025 End of.2024/Q4
(2) El A Resubmission
TRANSACTIONS WITH ASSOCIATED(AFFILIATED)COMPANIES
Account(s) Amount Charged or
Line Description of the Good orSorvice Name of Associated/Affitlated Company Charged or Credited
No. (a) ('b) Credited (d)
(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 35,563
22 Corporate Support Avista Capital 146000 76,304
23 Corporate Support AELP 146000 41,534
24 Corporate Support AJT 146000 1,205
25 Corporate Support Avista Edge 146000 2,352
42
FERC FORM NO.1 ((NEW))
Page 429